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Planning and prospects

for renewable power

NORTH AFRICA

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.

REPORT CITATION

IRENA (2023), Planning and prospects for renewable power: North Africa, International Renewable Energy Agency,

Abu Dhabi.

ISBN: 978-92-9260-485-1

ACKNOWLEDGEMENTS

This report was drafted by Sebastian Hendrik Sterl, Pablo Carvajal, Pauline Fulcheri and Mohamed A. Eltahir Elabbas

under the guidance of Asami Miketa (IRENA) and Dolf Gielen (ex-IRENA), in close collaboration with Mohamed

Bassam Ben Ticha (consultant), who conducted major development work with IRENA on the System Planning Test

model for North Africa and provided modelling support. The report also received input from Bilal Hussain, Daniel

Russo, Tommaso Tiozzo Bastianello and Farmata Diallo (IRENA).

Valuable review and consultation were provided by Chokri Zammali (Société Tunisienne de l’Électricité et du Gaz),

Naima Chabouni (Mines ParisTech), Arman Aghahosseini (Lappeenranta University of Technology), Bob van der

Zwaan (TNO), and IRENA colleagues Herib Blanco, Laura Al-Katiri, Ahmed Badr, Mirjam Reiner, Imen Gherboudj,

Mohammed Sanusi Nababa, Rabia Ferroukhi, Binu Parthan, Gayathri Nair, Simon Benmarraze, Barbara Jinks, Paul

Komor, Zoheir Hamedi and Reem Korban.

For further information or to provide feedback: info@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 ocials, agents or other third-party content providers provides a warranty of any kind, either expressed or

implied, and 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.

CONTENTS

ABBREVIATIONS ..........................................................................................................8

ABOUT THIS REPORT .................................................................................................... 9

KEY TAKEAWAYS ........................................................................................................ 11

1 REGIONAL OVERVIEW AND KEY DATA ....................................................................... 13

1.1 Contribution of this report ..................................................................................................13

1.2 North Africa’s energy supply is highly dependent on fossil fuels ....................................13

1.3 North African countries show diverging patterns of electricity in ﬁnal

energy demand ..................................................................................................................15

1.4 Electricity demand in North Africa is still growing strongly, requiring substantial

power sector investments ..................................................................................................16

1.5 Most North African countries have ambitious renewable electricity targets .................19

1.6 Solar and wind power in North Africa are expanding and getting cheaper ................ 22

1.7 Enhanced ﬂexibility promotes integration of solar and wind into North African

power systems .................................................................................................................... 25

2 SCENARIOS FOR NORTH AFRICA’S ELECTRICITY SYSTEMS ........................................ 31

2.1 SPLAT-N models capacity expansion in North Africa .......................................................31

2.2 Four scenarios for North Africa’s power sector were modelled ...................................... 36

2.3 The three Transition scenarios differ in their assumptions ...............................................41

2.4 If investment in fossil fuel projects is discontinued, least-cost capacity expansion

is dominated by solar and wind power............................................................................ 45

2.5 Battery storage and hydrogen production are conducive to greater integration

of solar PV, but they lower the need for CSP .................................................................... 51

2.6 Wind power is an attractive investment in all North African countries, especially

in combination with hydrogen production ...................................................................... 53

2.7 Battery storage and hydrogen production lower the need for additional

cross-border interconnectivity .......................................................................................... 54

2.8 The need for battery storage increases with the share of variable renewables

in the energy mix ............................................................................................................... 65

2.9 Green hydrogen production, combined with variable renewables and storage,

could become an integral part of an interconnected electricity system .................... 69

2.10 CSP storage will be important to ensure system adequacy ........................................... 75

2.11 Deployment of VRE with storage solutions can temper system costs if fossil fuel

investments are halted ..................................................................................................... 77

2.12 Holding down the levelised cost of electricity ................................................................. 79

2.13 The proposed transition towards VRE would substantially lower CO2 emissions

from power generation ...................................................................................................... 81

2.14 Additional studies could shed more light on the North African power system ............. 83

2.15 Pathways to lower-cost electricity generation in North Africa ....................................... 85

REFERENCES ..............................................................................................................86

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PlanningandprospectsforrenewablepowerNORTHAFRICA©IRENA2023Unlessotherwisestated,materialinthispublicationmaybefreelyused,shared,copied,reproduced,printedand/orstored,providedthatappropriateacknowledgementisgivenofIRENAasthesourceandcopyrightholder.Materialinthispublicationthatisattributedtothirdpartiesmaybesubjecttoseparatetermsofuseandrestrictions,andappropriatepermissionsfromthesethirdpartiesmayneedtobesecuredbeforeanyuseofsuchmaterial.REPORTCITATIONIRENA(2023),Planningandprospectsforrenewablepower:NorthAfrica,InternationalRenewableEnergyAgency,AbuDhabi.ISBN:978-92-9260-485-1ACKNOWLEDGEMENTSThisreportwasdraftedbySebastianHendrikSterl,PabloCarvajal,PaulineFulcheriandMohamedA.EltahirElabbasundertheguidanceofAsamiMiketa(IRENA)andDolfGielen(ex-IRENA),inclosecollaborationwithMohamedBassamBenTicha(consultant),whoconductedmajordevelopmentworkwithIRENAontheSystemPlanningTestmodelforNorthAfricaandprovidedmodellingsupport.ThereportalsoreceivedinputfromBilalHussain,DanielRusso,TommasoTiozzoBastianelloandFarmataDiallo(IRENA).ValuablereviewandconsultationwereprovidedbyChokriZammali(SociétéTunisiennedel’ÉlectricitéetduGaz),NaimaChabouni(MinesParisTech),ArmanAghahosseini(LappeenrantaUniversityofTechnology),BobvanderZwaan(TNO),andIRENAcolleaguesHeribBlanco,LauraAl-Katiri,AhmedBadr,MirjamReiner,ImenGherboudj,MohammedSanusiNababa,RabiaFerroukhi,BinuParthan,GayathriNair,SimonBenmarraze,BarbaraJinks,PaulKomor,ZoheirHamediandReemKorban.Forfurtherinformationortoprovidefeedback:info@irena.org.Thisreportisavailablefordownload:www.irena.org/publications.DISCLAIMERThispublicationandthematerialhereinareprovided“asis”.AllreasonableprecautionshavebeentakenbyIRENAtoverifythereliabilityofthematerialinthispublication.However,neitherIRENAnoranyofitsofficials,agentsorotherthird-partycontentprovidersprovidesawarrantyofanykind,eitherexpressedorimplied,andacceptnoresponsibilityorliabilityforanyconsequenceofuseofthepublicationormaterialherein.TheinformationcontainedhereindoesnotnecessarilyrepresenttheviewsofallMembersofIRENA.ThementionofspecificcompaniesorcertainprojectsorproductsdoesnotimplythattheyareendorsedorrecommendedbyIRENAinpreferencetoothersofasimilarnaturethatarenotmentioned.ThedesignationsemployedandthepresentationofmaterialhereindonotimplytheexpressionofanyopiniononthepartofIRENAconcerningthelegalstatusofanyregion,country,territory,cityorareaorofitsauthorities,orconcerningthedelimitationoffrontiersorboundaries.CONTENTSABBREVIATIONS...........................................................................................................8ABOUTTHISREPORT.....................................................................................................9KEYTAKEAWAYS.........................................................................................................111REGIONALOVERVIEWANDKEYDATA........................................................................131.1Contributionofthisreport...................................................................................................131.2NorthAfrica’senergysupplyishighlydependentonfossilfuels.....................................131.3NorthAfricancountriesshowdivergingpatternsofelectricityinfinalenergydemand��151.4ElectricitydemandinNorthAfricaisstillgrowingstrongly,requiringsubstantialpowersectorinvestments��161.5MostNorthAfricancountrieshaveambitiousrenewableelectricitytargets..................191.6SolarandwindpowerinNorthAfricaareexpandingandgettingcheaper.................221.7EnhancedflexibilitypromotesintegrationofsolarandwindintoNorthAfricanpowersystems��252SCENARIOSFORNORTHAFRICA’SELECTRICITYSYSTEMS.........................................312.1SPLAT-NmodelscapacityexpansioninNorthAfrica........................................................312.2FourscenariosforNorthAfrica’spowersectorweremodelled.......................................362.3ThethreeTransitionscenariosdifferintheirassumptions................................................412.4Ifinvestmentinfossilfuelprojectsisdiscontinued,least-costcapacityexpansionisdominatedbysolarandwindpower��452.5BatterystorageandhydrogenproductionareconducivetogreaterintegrationofsolarPV,buttheylowertheneedforCSP��512.6WindpowerisanattractiveinvestmentinallNorthAfricancountries,especiallyincombinationwithhydrogenproduction��532.7Batterystorageandhydrogenproductionlowertheneedforadditionalcross-borderinterconnectivity��542.8Theneedforbatterystorageincreaseswiththeshareofvariablerenewablesintheenergymix��652.9Greenhydrogenproduction,combinedwithvariablerenewablesandstorage,couldbecomeanintegralpartofaninterconnectedelectricitysystem��692.10CSPstoragewillbeimportanttoensuresystemadequacy............................................752.11DeploymentofVREwithstoragesolutionscantempersystemcostsiffossilfuelinvestmentsarehalted��772.12Holdingdownthelevelisedcostofelectricity��792.13TheproposedtransitiontowardsVREwouldsubstantiallylowerCO2emissionsfrompowergeneration��812.14AdditionalstudiescouldshedmorelightontheNorthAfricanpowersystem..............832.15Pathwaystolower-costelectricitygenerationinNorthAfrica........................................85REFERENCES...............................................................................................................86•4•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFIGURESFigure1‑1TotalprimaryenergysupplystructureinNorthAfrica,2019...................................................14Figure1‑2TotalfinalenergyconsumptioninNorthAfrica,1990-2019.....................................................15Figure1‑3ElectrificationpathoftheenergysectorinNorthAfrica:electricityintensityandnon-electricityenergyintensityinNorthAfricancountries,1990-2019.......................16Figure1‑4InstalledcapacityandgenerationinNorthAfricain2015and2019.....................................17Figure1‑5EvolutionofenergysectorinvestmentsinNorthAfrica,2015-2020......................................18Figure1‑6CommittedandplannedpowerinvestmentsinNorthAfrica,2021-2025.............................18Figure1‑7ExistingandcommittedcapacityinNorthAfricabytechnology,comparedwithprojectedpeakload,2020-2040........................................................................................................19Figure1‑8Renewableenergycapacityexpansionby2030accordingtoNDCsinNorthAfrica........21Figure1‑9Shareofenergysourcesinelectricitygenerationin2019andmostambitioustargetsforrenewableenergy(includinghydropower)inNorthAfrica.................................22Figure1‑10InstalledcapacityofsolarPVandCSPinNorthAfrica,2010-2020,andshareinindividualcountries,2020...................................................................................................................23Figure1‑11EvolutionoftheaverageinstallationcostsforsolarPVprojectsinNorthAfrica..............24Figure1‑12InstalledcapacityofonshorewindinNorthAfrica,2010-2020,andshareinindividualcountries,2020.....................................................................................................................24Figure1.13EvolutionofaverageinstallationcostsforonshorewindprojectsinNorthAfrica..........25Figure1‑14ExistingandplannedinterconnectioncapacityinNorthAfrica.............................................26Figure2‑1NormalisedloadcurvesonanaveragedayineachseasoninNorthAfrica(appliedforallyearsofthemodellingperiod)..............................................................................39Figure2‑2ExamplesofdiurnalprofilesofsolarphotovoltaicpowergenerationforsitesinMauritania(UTC),Algeria(UTC+1)andEgypt(UTC+2)...............................................................44Figure2‑3MonthlyaveragewindprofileofdifferentlocationsinEgyptandMorocco........................44Figure2‑4IdentifiedsolarphotovoltaicandwindmodelsupplyregionsfromresourcescreeninginNorthAfricawith8%and17%accountedlosses,respectively.........................45Figure2‑5CapacityexpansioninNorthAfricabytechnologyinthefourscenarios.............................47Figure2‑6ProjectionofgenerationinNorthAfricainthefourscenarios,bytechnology..................49Figure2‑7ShareofenergysourcesinelectricitygenerationinNorthAfricainthefourscenarios,bytechnology......................................................................................................................49Figure2‑8Newinstalledsolarphotovoltaiccapacitybycountryinthefourscenarios......................52Figure2‑9Newinstalledconcentratedsolarpowercapacitybycountryinthefourscenarios.........52Figure2‑10Newinstalledwindcapacitybycountryinthefourscenarios.................................................53Figure2‑11Modelassumptions(constraints)onexchangepricesbetweenNorthAfricancountriesandneighbouringregions..................................................................................................55Figure2‑12Totalelectricitytradeflowsin2040inthefourscenarios.........................................................55Figure2‑13GrossexportsandimportsofelectricityinNorthAfricancountriesinthefourscenarios,2018and2040.....................................................................................................................56Figure2‑14Morocco’simportsfromSpaininthePlannedscenario,2040..................................................58•5•NORTHAFRICAFigure2‑15Morocco’simportsfromAlgeriainthePlannedscenario,2040...............................................58Figure2‑16Tunisia’simportsfromAlgeriainthePlannedscenario,2040..................................................59Figure2‑17Tunisia’simportsfromLibyainthePlannedscenario,2040.....................................................59Figure2‑18Tunisia’simportsfromItalyinthePlannedscenario,2040.......................................................60Figure2‑19Egypt’simportsfromLibyainthePlannedscenario,2040.......................................................60Figure2‑20DailyprofilesofexportsintheTransitionscenario,2040..........................................................61Figure2‑21DailyprofilesofexchangesintheTransition+Batteriesscenario,2040..............................62Figure2‑22DailyprofilesofexchangesintheTransition+Batteries+H2scenario,2040.....................63Figure2‑23ElectricityexchangesinNorthAfricainthefourscenarios,2040(GWh).............................64Figure2‑24TotalinstalledbatterycapacityintheTransition+BatteriesandtheTransition+Batteries+H2scenarios........................................................................................................................66Figure2‑25Dailyuseprofileofbatteriesbyseasonandbycountry............................................................67Figure2‑26DailyuseofpumpedhydropowerinMoroccoinallscenarios.................................................68Figure2‑27Unitcostofhydrogengeneratedinscreenedwindandsolarphotovoltaicregions.........71Figure2‑28HydrogensupplycurveinNorthAfricaasdeterminedbythemodel,2030and2040....71Figure2‑29Evolutionofhydrogenproduction,electrolysercapacityandgenerationfromvariablerenewableenergyinNorthAfricaintheTransition+Batteries+H2scenario,2025-2040..........................................................................................................................72Figure2‑30SeasonalhydrogenproductionintheTransition+Batteries+H2scenario,bycountryandnormalised(relativetomaximumdailyproductionintheyear)...............73Figure2‑31DailyhydrogenproductionrateintheTransition+Batteries+H2scenario,bycountry..................................................................................................................................................74Figure2‑32DailyhydrogenproductionintheTransition+Batteries+H2scenarioforeachseason,bycountry...................................................................................................................................74Figure2‑33ResidualloaddurationcurveintheTransitionscenario,bycountry,2040..........................76Figure2‑34HourlycapacityfactorofconcentratedsolarpowerneededtomeetdemandintheTransitionscenario,2040..........................................................................................................77Figure2‑35Evolutionofsystemcostsinthefourscenarios............................................................................78Figure2‑36TotalcostsandtotalgenerationinNorthAfricainthefourscenarios,2020-2040...........79Figure2‑37EvolutionoftotalgenerationcostinNorthAfricainthefourscenarios(annualsystemcostdividedbyannualgeneration)....................................................................80Figure2‑38Averagegenerationcostinthefourscenarios,bycountry,2040.........................................80Figure2‑39EvolutionofcarbondioxideemissionsfromtheelectricitysectorinNorthAfricainthefourscenarios...............................................................................................................................82Figure2‑40Cumulativecarbondioxideemissionsandreductionsinthefourscenarios,2020-2040..................................................................................................................................................82Figure2-41Averagedifferencesbetweenthe1.5˚CScenarioandPlannedEnergyScenarioforAfrica,2021-2050.............................................................................................................................84•6•PLANNINGANDPROSPECTSFORRENEWABLEPOWERTABLESTable1‑1Power-sector-relatedtargetsinNorthAfricaasreflectedinrecentnationalplansandNDCs......................................................................................................................................20Table1‑2Hydrogenprojects,partnerships,co-operationagreementsandmemorandaofunderstandinginNorthAfrica...........................................................................................................28Table2‑1DefinitionandmodellingofpowersysteminputsinSPLAT-N.................................................32Table2‑2PlannedandcommittedrenewableenergyprojectsinNorthAfrica.....................................35Table2‑3Assumptionsbehindthefourmodelledscenarios........................................................................37Table2‑4Summaryofkeyresultsfromtheinvestigatedscenarios...........................................................40Table2‑5SummaryoftheanalysisofthestepsneededtogofromthePlannedtotheTransitionscenario..................................................................................................................................42Table2‑6Country-levelbreakdownofthepowergenerationmixby2040,byscenario....................50Table2‑7SensitivityofscenarioresultstopricesofexportsfromEgypttooutsideNorthAfrica..............................................................................................................................................57Table2‑8ShareofpowerexchangesintotalelectricitydemandinNorthAfrica...............................64Table2‑9ComparisonofhydrogenproductionintheTransition+Batteries+H2scenariowithnational,regionalandglobalhydrogendemandprojections,2030and2040.........72Table2‑10ComparisonofelectrolysercapacityintheTransition+Batteries+H2scenariowithnational,regionalandglobalhydrogenprojections,2030and2040............................73•7•NORTHAFRICABOXESBox2‑1Characterisationofdemandinthemodel.......................................................................................37Box2‑2Estimatingvariablerenewableenergygenerationprofiles........................................................43Box2-3Representationofstorageinthemodel..........................................................................................47Box2‑4AnexampleofIRENA’ssocio-economicanalysisofenergytransitionroadmaps..............83•8•PLANNINGANDPROSPECTSFORRENEWABLEPOWERABBREVIATIONSCAPEXcapitalexpenditureCCCconsolidatedcontractor’scompanyCCPPcombinedcyclepowerplantCFcapacityfactorCMPContinentalMasterPlanCO2carbondioxideCOMELECMaghrebElectricityCommitteeCSPconcentratedsolarpowerctcentEEHCEgyptianElectricityHoldingCompanyEHBEuropeanHydrogenBackboneEJexajouleENTSO-EEuropeanNetworkofTransmissionSystemOperatorsforElectricityEUEuropeanUnionGDPgrossdomesticproductGHGgreenhousegasGWgigawattGWhgigawatthourH2hydrogen(dihydrogen)HFOheavyfueloilIEAInternationalEnergyAgencyIPPindependentpowerproducerskWkilowattLNGliquefiednaturalgasMSRmodelsupplyregionMtmegatonneMWmegawattMWhmegawatthourNDCNationallyDeterminedContributionsO&MoperationandmaintenanceONEENationalOfficeofElectricityandWater(Morocco)OPEXoperationalexpenditurePJpetajoulePVphotovoltaicRErenewableenergyRORrun-of-riverSPLAT-NSystemPlanningTestModelforNorthAfricaTFECtotalfinalenergyconsumptionTWhterawatthourUNFCCCUnitedNationsFrameworkConventionforClimateChangeUNSDUnitedNationsStatisticsDivisionUSDUnitedStatesdollarVREvariablerenewableelectricityWACCweightedaveragecostofcapital•9•NORTHAFRICAThisreportispartofIRENA’sseriesonplanningandprospectsforrenewableenergy,whichfocusesonrenewableelectricitygenerationinAfricanpowerpools.ItscontextisthelackofaregionalmasterplanforpowersystemexpansioninNorthAfrica(Algeria,Egypt,Libya,Morocco,MauritaniaandTunisia)andIRENA’sinvolvementinthesearchforenergytransitionpathwaysfortheregion.ArecentexampleofthatinvolvementisIRENA’sparticipationasamodellingpartnerforthedevelopmentoftheAfricanContinentalPowerSystemsMasterPlan(CMP),aninitiativeledbytheAfricanUnionDevelopmentAgency’sNewPartnershipforAfrica’sDevelopment(AUDA-NEPAD)withthetechnicalandfinancialsupportoftheEuropeanUnion.ThisreportpresentsvariousscenariosforpowersystemexpansioninNorthAfricathrough2040,includingthepotentialitiesofhydrogenproductionandofinterconnectionswithinandoutsidetheregion(SouthernEuropethroughMoroccoandTunisia;andWesternAsiathroughEgypt).FeedbackfromnationalexpertswascollectedduringaworkshopinMarch2022,butthisreportdoesnotnecessarilyreflectcountries’officialpositions.Nordoesitintendtoprescribeapathforpowersectordevelopment.ThereportisbasedontheSystemPlanningTestModelforNorthAfrica(SPLAT-NorthAfrica),amodeldevelopedbyIRENAandbuiltonpubliclyavailabledata.SPLAT-NorthAfricacanbeusedinfuturecapacity-buildingeventsandbythecountriesoftheregiontoconducttheirownanalyses.ThereportshowcasespossibilitiesforNorthAfricancountriestodiversifytheirelectricitygenerationmixesandreducetheirrelianceonfossilfuelresourcesby2040.Theregionstandstobenefitfromfallingrenewableenergycostsanditsampleendowmentsofwindandsolarenergy.Bothcanhelptheregiondecreasesthecostofelectricitygenerationbyincreasingtheshareofrenewablesintheelectricitymix.Diversifyingthesourcesofelectricitygenerationwouldalsoallowtheregiontochoosebetweenusingitsfossilfuelresourceslocallyorexportingthem.TheflexibilitytomakesuchchoicesishighlyrelevantinacontextofhighfossilfuelpricesandthedesireofEuropetoincreaseimportsofnaturalgasfromNorthAfrica.PowergenerationinAlgeria,Egypt,LibyaandTunisiaisdominatedbynaturalgas,whilecoalistheprimarysourceinMoroccoandoilinMauritania.Thevulnerabilityoffossil-fuel-based,non-diversifiedpowergenerationistwofold.First,countriesthatrelyheavilyonimportedfossilfuels(Tunisia,MoroccoandMauritania)areexposedtoexternalpriceshocksinadditiontotheweightofimportsonforeigncurrencyreserves.Second,countrieswithfossilfuelreservestendtosubsidisethenationalfossilfuelindustrysoastoencouragecheapergenerationfromdomesticallyproducedfossilfuels,contortingcountries’fiscalposture.Fallingcapitalcostsforsolarphotovoltaicandwind–accompaniedbytheglobalpoliticalandsocialpressurestoachieveinternationalclimateobjectives–willmakeitincreasinglydifficulttosecuresocialacceptanceofthehighercostsoffossil-fuel-basedgeneration.Continuedinvestmentinthatfossil-fuel-basedgenerationinfrastructuremaywellleavecountrieswithpowerplantsthatwillbelittleused,bothbecauseoftheirhigherfuelcostsandinordertocomplywithtargetsforreductionofcarbondioxideemissions.ABOUTTHISREPORT•10•PLANNINGANDPROSPECTSFORRENEWABLEPOWERBasedonthemodellingstudiespresentedhere,thisreportfindsthatlarge-scaleroll-outofvariablerenewableelectricitygenerationfromsolarandwindpowerwouldbeacost-efficientwaytoavoidcontinuedrelianceonfossilfuels,whilecontinuingtomeettherisingdemandforelectricityinNorthAfrica.Althoughsolarandwindresourcesareweatherdependentandthusvariable,thereportshowshowtheeffectsofvariabilitycanbemitigatedusingmodernstoragesolutions(notablybatterystorage)andgreenhydrogenproductionforelectricityexporttotheEuropeanmarket.Theresultsshowthatsuchatransitionpathwouldlowertheunitcostsofpowergenerationfromthosethatwouldresultfromcountries’currentpolicies.Moreover,suchtransitionswouldhelpmostcountriesreducegreenhousegasemissions.Chapter1ofthereportpresentsaregionaloverviewoftheregion’senergyandelectricitysituation.Chapter2describesthemethodsandassumptionsusedtocompilefourscenariosfortheexpansionofgeneratingcapacityintheregionanddiscussestheaggregateresultsofthosescenarios.TheaccompanyingDataappendix(IRENA2022b),presentsthedatausedinthestudyandthecountryresultsobtainedbyprocessingthosedatausingthemodeldescribedinChapter2.•11•NORTHAFRICANorthAfricancountriesarehighlydependentonfossilfuelsforelectricitygeneration,renderingthemvulnerabletopricefluctuationsoffossilfuelcommoditiesonglobalmarketsandstrainingnationalbudgetsthroughsubsidisationoffossil-fuel-basedgeneration.DiversifyingawayfromacontinueddependenceonfossilfuelswillallowNorthAfricatosimultaneouslylowertheunitcostsofpowergenerationandallowtheregiontochoosebetweenusingitsfossilfuelresourceslocallyorexportingthem.Diversificationcanalsolowertherisksofdisruptionofenergysupplyincountrieslackinglocalfossilfuelresources.Alarge-scaleexpansionofsolarPV,concentratedsolarpowerandwindpowercapacity,substantiallybeyondcountries’currenttargets,couldfacilitatesuchatransition.Powergenerationcostscouldbefurtherreducedthroughutility-scaledeploymentofbatterypowerplants,whichwouldmakeitpossibletointegratesolarPVplantswiththegridandreducetheneedforadditionalinterconnectionsbetweenthecountriesoftheregion.Evenfurtherbenefitscouldbereapedfromtheproductionofgreenhydrogenforexporttoothermarkets,suchasEurope.Underanambitioushydrogenexportscenario,apronouncedexpansionofsolarandwindpowertechnologiestoallowforlarge-scalehydrogenproductioncouldresultinevenlowerunitcostsofelectricity,increasingearningsfromhydrogenexportsatcompetitiveprices.Suchascenariowouldrequireaquadruplingofpowersectorsizesandinvestmentsovercurrentplans,butitwouldcutelectricitygenerationcostsinhalf.Asidefromreducingcountries’dependenciesonextractiveresources,suchatransitionwouldhavetheadditionalbenefitofsubstantiallyloweringgreenhousegasemissionsfromthepowersectorcomparedwithpresentemissionsandthosethatwouldbeproducedundercurrentplans.Thethreetransitionscenariospresentedinthisreportwouldbringa75%reductioninemissionlevelsby2040comparedwith2020.KEYTAKEAWAYS•12•PLANNINGANDPROSPECTSFORRENEWABLEPOWER•13•NORTHAFRICA1.1CONTRIBUTIONOFTHISREPORTIRENA’sSPLAT-MESSAGE(SystemPlanningTestmodelbasedontheModelforEnergySupplyStrategyAlternativesandtheirGeneralEnvironmentalImpact)capacityexpansionmodellingframework,discussedinSection2.1,wasusedtodeveloptheSPLAT-NorthAfricamodel,coveringsixNorthAfricancountries(Algeria,Egypt,Libya,Mauritania,MoroccoandTunisia)tochartpossiblepathwaysforNorthAfrica’sfutureelectricitysupply.Inparticular,thenetbenefitsofstorage(batteriesandhydrogen,thelatterforexporttoEuropeanmarkets)inaninterconnectedelectricitysystemwereinvestigatedtoilluminatethepossibilitiesofreachingamuchlargershareofrenewableelectricityandacorrespondingdiversificationawayfromfossilfuelsby2040.Adetaileddescriptionofthemainassumptions–includingthegeographicandtemporalcharacterisationofrenewableresources(solarandwind),estimatesoffutureelectricitydemandinthecountriesoftheregion,internationalfuelprices,andestimatesofinvestmentcostsbytechnologytype–isprovidedinChapter2.TheaccompanyingDataappendix(IRENA,2022b)presentsthedatausedinthestudyandthecountryresultsobtainedbyprocessingthosedatausingthemodeldescribedinChapter2.ThisfirstchaptersummarisestheenergyandelectricitysectorcontextofNorthAfricancountries.Itpresentsaregionaloverviewaswellascountry-specificdatarelatedtoenergyandelectricitysupplyanddemand,withafocuson(1)recenttrendsintheenergyandelectricitysectors;(2)currentobjectivesforelectricitysupply;(3)thestatusofmodernrenewableenergytechnologies(inparticularsolarandwindpower);and(4)optionsfortheirintegrationintoNorthAfrica’selectricitysystems.1.2NORTHAFRICA’SENERGYSUPPLYISHIGHLYDEPENDENTONFOSSILFUELSWhilethecountriesinNorthAfricahaveincreasedtheuseofrenewablesourcesinelectricityproductionoverthepastdecade,mostoftheregion’sprimaryenergysupplystillcomesfromfossilfuels,namelynaturalgas,oilandcoal(inthecaseofMorocco).TheprimaryenergysupplystructureofthecountriesispresentedinFigure1‑1.Forthewholeregion,fossilfuelsaccountedfor95%(8.5exajoules[EJ])ofthetotalprimaryenergysupply(9EJ)in2019.Gasandoilrepresented49%(4.4EJ)and41%(3.7EJ)ofthetotal,respectively(UNSD,2022).LibyaandAlgeriaaretheleadingfossilfuelexportersintheregion,with80%and59%oftheiroilandgasproductionbeingexportedin2019,respectively(UNSD,2022).BothcountrieshavehistoricallybeenexportersofnaturalgastoEurope.Algeriaexportsnaturalgasasliquefiednaturalgas(LNG)andthroughthreepipelinestoEurope,thefirstreachingItalythroughTunisia(EnricoMatteipipeline),thesecondleadingtoSpainthroughMorocco(PedroDuranFarellpipeline)1andthethirdgoingdirectlyfromAlgeriatoSpain(Medgaz).AsforLibya,thecountryexportsnaturalgasthroughadirectpipelinetoItaly(Greenstreampipeline).1ExportsfromAlgeriatoSpainthroughthispipelineceasedin2022.1REGIONALOVERVIEWANDKEYDATA•14•PLANNINGANDPROSPECTSFORRENEWABLEPOWERInthepast,Egyptwasanoilandnaturalgasexporter,butdecliningresourcesandsurginglocaldemandhavemadeitanetimporter.EgyptwasexpectedtoagainbecomeanaturalgasexporterthankstorecentdiscoveriesintheEasternMediterraneanandthedevelopmentofnationalLNGprojects(Bloomberg,2021a,2021b).Thosenaturalgasreservesbegantobeextracted(Eni,2020),butlower-than-expectedproductionowingtotechnicalissues(Stevenson,2022)islimitingproductionfromthesefieldsandlimitingexportsfromEgypttothere-exportofgasimportedfromneighbouringcountries(Elgendy,2022).Mauritania,anetenergyimporter,couldalsobecomeanetexporterfollowingoffshorenaturalgasdiscoveries(S&PGlobalPlatts,2019).Tunisia,whichwasanetenergyexporteruntil2000,isnowanetimporter.ThecountryimportsnaturalgasfromAlgeriatomakeupfordecliningdomesticresources.MoroccowasimportingnaturalgasfromAlgeriauntilthecontractendedin2021.PlansforafloatingstorageregasificationunitterminalhavebeenannouncedtoimportLNG.ExceptforMauritania,alloftheregion’scountriespossessoil-refiningcapacities.Theuncertaintiesrelatedtooilandgasresourcesillustratedbyrecentexamplesoflower-than-expectedproductioninnewfieldsstrengthentheneedforotherenergysources.Fossil-fuel-basedelectricitygenerationrepresentsamajorpartofgenerationintheregion.Thefuelsusedinthesepowerplantshavedifferentoriginsaccordingtothecountry.AlgeriaandEgyptrelymainlyontheirdomesticnaturalgasforelectricitygeneration;Libyareliesondomesticnaturalgasandoilproducts;andTunisiareliespartlyondomesticnaturalgasandpartlyonimportsfromAlgeria.Presently,MauritaniaandMoroccorelytotallyonimportedfuels(coalandoilproductsforMoroccoandoilproductsforMauritania).Algeria2.5EJEgypt4.1EJLibya0.9EJMauritania0.1EJMorocco0.9EJTunisia0.5EJRenewablesGasOilCoalandothernon-renewables5%41%49%5%NorthAfrica9.0EJFigure1‑1TotalprimaryenergysupplystructureinNorthAfrica,2019Source:(UNSD,2022).Note:EJ=exajoule.•15•NORTHAFRICA1.3NORTHAFRICANCOUNTRIESSHOWDIVERGINGPATTERNSOFELECTRICITYINFINALENERGYDEMANDGenerally,popularaccesstoelectricityinNorthAfricaisveryhigh(99%).Mauritaniaisanexception,butitrecordedsubstantialprogressinthelastdecade,withaccessrisingto47%in2020from34%in2010(WorldBank,2019).Figure1‑2showstheincreaseinfinalenergyconsumptioninNorthAfricancountriesovertheperiod1990-2019.Egypthasachievedthehighestelectrificationofenduses,withelectricity’sshareinfinalenergyconsumptionaccountingfor21%in2019(563petajoules[PJ])(UNSD,2022).InMoroccoandTunisia,electricityrepresents18%and17%offinalenergyconsumption(120PJand63PJ,respectively),whileitaccountsfor13%inAlgeriaand14%inLibya(224PJand64PJ,respectively)in2019.Figure1‑3illustratestheelectrificationpathsoftheenergysectorinthecountriesoftheregion.Bycomparingtheevolutionofelectricityintensity(finalelectricitydemand/grossdomesticproduct[GDP])withtheevolutionofenergyintensityofotherfuels(finaldemandofotherfuels/GDP)fortheperiod1990-2019,thefigureillustratesthedivergentelectrificationpathwaysinNorthAfrica.Thedirectionofthearrowsrepresentstheevolutionofthecountry’spathovertime.Countriescanbeclassifiedintotwomaincategories.Ontheonehand,thoseforwhichtheslopeofthearrowisnegative,namelyEgypt,MoroccoandTunisia,arecharacterisedbyatendencytowardsgreateruseofelectricityperunitofGDPwhiletheuseofotherfuelsdrops.Electricityintensityinthosecountrieshasincreasedovertimecomparedtootherfuels.Bycontrast,thecountrieswheretheslopeofthearrowispositivearecharacterisedbyanincreasingintensityofbothelectricityandotherfuelsovertime.ThisisthecaseforAlgeriaandLibya,whicharebothoilandgasproducers,aswellasMauritania,whichhasbenefittedfromeconomicdevelopmentandanincreasingaccesstoelectricity.Source:(UNSD,2022).Note:PJ=petajoule.Percentagesindicate%shareofelectricityintotalfinalenergyconsumption.Figure1‑2TotalfinalenergyconsumptioninNorthAfrica,1990-2019ElectricityNaturalgasOilCoalBiofuelsandwaste4%6%7%6%10%10%16%18%13%13%14%14%11%12%15%17%8%9%11%13%13%14%20%21%050010001500200025003000199020002010201919902000201020191990200020102019199020002010201919902000201020191990200020102019MauritaniaTunisiaLibyaMoroccoAlgeriaEgyptTotalﬁnalenergyconsumption(PJ)•16•PLANNINGANDPROSPECTSFORRENEWABLEPOWERSource:(UNSD,2022;WorldBank,2021).Note:GDP=grossdomesticproduct;MJ=megajoule.1.4ELECTRICITYDEMANDINNORTHAFRICAISSTILLGROWINGSTRONGLY,REQUIRINGSUBSTANTIALPOWERSECTORINVESTMENTSTomeetgrowingdemand,electricityproductioninNorthAfricamorethandoubledfromapproximately140terawatthours[TWh]to367TWhbetween2000and2019(UNSD,2022).Installedpowergenerationcapacityintheregionin2020isestimatedatapproximately113gigawatts[GW](IRENA,2020a).Naturalgashasbeenthepredominantfuelforpowergenerationintheregion,accountingfor76%(278TWh)oftotalpowergeneration(bothsimpleandcombinedcyclegasplants).Regionally,theshareofoilinpowergenerationhassteadilydecreased.Thisisaresultoftheincreaseinnaturalgasgeneration,mainlyinAlgeriaandEgypt.Renewableenergyhasplayedamarginalroleingeneration,thoughitscontributionhasmoreorlessdoubledinthepastfiveyears.Hydropowerhashistoricallybeenthehighest-producingrenewableelectricitytechnologyinNorthAfrica;however,itisconcentratedinEgypt(ontheNileRiver)andMorocco(intheAtlasMountains).TheviabilityforfuturehydrogenerationinEgyptislowasmostofthepotentialhasalreadybeenexploited(Sterletal.,2021),whileMoroccocouldstillincreaseitscapacityto3100megawatts[MW](Azeroualetal.,2018)fromaround1300MWtoday.Overall,hydropower’sshareintotalpowergenerationhasgraduallydecreased,asnon-hydrorenewableshaveenteredthemarketinthepastdecade.Thesenon-hydrorenewables(windandsolar)nowmakeup3%oftotalpowergeneration,foratotalof10TWh.Figure1-4providesamoredetailedoverviewofthefuelsusedforelectricitygenerationinthecountries.Figure1‑3ElectrificationpathoftheenergysectorinNorthAfrica:electricityintensityandnon-electricityenergyintensityinNorthAfricancountries,1990-20190.002.004.006.008.0010.0012.000.000.501.001.502.002.503.00Electricityintensity(MJper2010dollarofGDP)MoroccoEgyptTunisiaAlgeriaLibyaMauritaniaOtherfuelsintensity(MJper2010dollarofGDP)•17•NORTHAFRICA02040608010012020152019201520192015201920152019201520192015201920152019NorthAfricaEgyptAlgeriaLibyaMoroccoTunisiaMauritaniaInstalledcapacity(GW)Non-renewableHydroWindSolarOthersourcesInstalledCapacityinNorthAfrica05010015020025030035040020152019201520192015201920152019201520192015201920152019NorthAfricaEgyptAlgeriaMoroccoLibyaTunisiaMauritaniaGeneration(TWh)ElectricityGenerationinNorthAfricaNon-renewableHydroWindSolarOthersourcesFigure1‑4InstalledcapacityandgenerationinNorthAfricain2015and2019Source:(IRENA,2020a).Note:GW=gigawatt;TWh=terawatthour.•18•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFollowingtheCOVID-19pandemicin2020,powersectorinvestmentsdecreasedinNorthAfricaasintherestoftheworld(IEA,2020b).Intheregion,investmentsinpowertransmissionwereparticularlyaffected,fallingby20%between2019and2020,whileinvestmentsinpowergenerationremainedroughlyconstantcomparedwith2019(Figure1‑5).ThechiefreasonforthedropininvestmentisthatthepowersectorinNorthAfricaishighlyreliantonpublicfunding,whichwasconstrainedbecauseofthedropinworldoilandgaspricesandtheincreasedcostoffinancing.CommittedpowerinvestmentsinNorthAfricafortheperiod2021-2025arepresentedinFigure1‑6.Thecountrieswiththehighestcommittedandplannedpowerinvestments(includingbothgenerationandtransmission)areEgypt(USD36billion),Algeria(USD23billion)andMorocco(USD12billion).InTunisiaandLibya,thecorrespondingfiguresareUSD3billionandUSD0.3billion,respectively(APICORP,2021).Renewableenergiesrepresentasignificantshareoftheseinvestments:62%forMorocco,39%forTunisia,36%forAlgeriaand15%forEgypt.Expressedasyearlyaverages,plannedpowerinvestmentsinNorthAfricaaveragearoundUSD15billionperyearduringtheperiod2021-2025,ofwhichaboutUSD5billionwouldbededicatedtorenewableenergy.Figure1‑5EvolutionofenergysectorinvestmentsinNorthAfrica,2015-2020Source:(IEA,2020b).Figure1‑6CommittedandplannedpowerinvestmentsinNorthAfrica,2021-2025Source:(APICORP,2021).Note:Plannedinvestmentsarepre-finalinvestmentdecisions,madebeforetheprojectowner/operatorcommencesexecutionoftheproject.Committedinvestmentsarethosemadeinprojectsthathaveenteredtheexecutionphase.024681012141618201520162017201820192020Investments(2019USDbillion)PowergenerationPowertransmissionShareofrenewablesintotalprojects15%36%62%39%0%10%20%30%40%50%60%70%0510152025303540EgyptAlgeriaMoroccoTunisiaLibyaInvestments(USDbillion)CommittedPlanned•19•NORTHAFRICAWithrespecttotheprojectedretirementofexistingpowerplantsandthecommittedprojects,Figure1‑7presentstheinstalledcapacityremaininginthesystemthatmustbeexpandedtomeetgrowthindemand.Theprojectionofpeakloadintheregionisshownunderthetwodifferentscenariosusedinthisstudy:PlannedandTransition.Theseareexplainedindepthinsection2.1.Presently,excessgenerationcapacityisavailableintheregion.Althoughtheexistingcapacitywillremainsufficientintheshortterm(2020-2025),inthemediumtolongterm(2025-2040)itisclearthatitwillnotbeenoughtomeetdemandundereitherscenario.Thus,newpowergenerationprojectswillhavetobeplanned,andfurtherinvestmentswillhavetobecommittedforNorthAfricatokeepmeetingitselectricitydemand.Theprincipalgoalofthisstudyistoinvestigatethebestwaystoclosethegapbetweenexistingandcommittedcapacityontheonehand,andtomeetprojecteddemand,ontheother.Toputitbluntly,willtheregioncontinuetorelyheavilyonfossilfuels,oraretherebetteralternatives?2Inparallel,theUNFCCChasdevelopedamechanismforitspartiestoformulateandcommunicatelong-termlow-emissiondevelopmentstrategies(LT-LEDS)tooperationalisethecarbon-neutralvisionstipulatedbytheParisAgreement.Todate,manycountrieshavesubmittedstrategiestotheUNFCCC(UNFCCC,2021a),andthe26thUnitedNationsClimateChangeconference(COP26),settotakeplaceinNovember2021inGlasgow,isexpectedtoleadtofurthersubmissions.However,noneoftheNorthAfricancountrieshavesubmittedanLT-LEDSsofar.Figure1‑7ExistingandcommittedcapacityinNorthAfricabytechnology,comparedwithprojectedpeakload,2020-2040Note:GW=gigawatt;HFO=heavyfueloil;PP=powerplant.1.5MOSTNORTHAFRICANCOUNTRIESHAVEAMBITIOUSRENEWABLEELECTRICITYTARGETSIn2016,Morocco,Algeria,Tunisia,Libya,EgyptandMauritaniasignedtheParisAgreementonClimateChangetogetherwith191othermemberstatesoftheUnitedNationsFrameworkConventiononClimateChange(UNFCCC).Withinthiscontext,theyarerequiredtosubmitNationallyDeterminedContributions(NDCs)everyfiveyears,describingthemitigationandadaptationactionsthattheypledgetotaketostayinlinewiththeobjectivesofthisagreement.2LibyahasyettoratifytheParisAgreement,buttheothercountriessubmittedtheirfirstNDCsbetween2016and2017;Morocco,TunisiaandMauritaniasubmittedupdatedNDCsin2021.HFOPPWindPPDieselPPPeakload(PlannedScenario)HydroPPPeakload(TransitionScenario)SolarPVPPCoalPPNaturalgasPPSolarthermalPP020406080100120140160202020212022202320242025202620272028202920302031203220332034203520362037203820392040InstalledcapacityinGW•20•PLANNINGANDPROSPECTSFORRENEWABLEPOWERNDCstendtobereflectiveofcountries’generalpolicytargetsconcerningenergyandclimate,forexample,throughenergysectordevelopmentplans,masterplans,strategiesorcomparabledocuments.AsummaryofNorthAfricancountries’policyobjectivesrelatedtotheelectricitymixisprovidedinTable1‑1,drawnfromNDCsandotherstrategicdocuments.Table1‑1Power-sector-relatedtargetsinNorthAfricaasreflectedinrecentnationalplansandNDCsCOUNTRYNATIONALPLANSANDCOMMITMENTSAlgeria•RatifiedtheParisAgreementon20October2016.•TheNationallyDeterminedContribution(NDC)aimstoreducegreenhousegas(GHG)emissionsby7%(unconditional)to22%(conditional)by2030,comparedwithabusiness-as-usualscenario.•TheRenewableEnergyandEnergyEfficiencyDevelopmentPlan2016-2030andtheNDCsetaconditionaltargetof27%ofelectricitygenerationfromrenewablesby2030.Egypt•RatifiedtheParisAgreementon29June2017.•TheNDCdefines“increaseduseofrenewableenergyasanalternativetonon-renewableenergysources”asoneofthefivepillarsofmitigationpolicies.However,itprovidesnoquantifiedrenewableenergytargets.•TheIntegratedSustainableEnergyStrategy2035callsforrenewablestomakeup42%oftheelectricitymixby2035.Libya•SignedbuthasnotratifiedtheParisAgreement.ThecountryhasnotsubmittedanNDC.Mauritania•RatifiedtheParisAgreementon27February2017.•TheNDC,updatedinOctober2021,setsatargetofreducinggreenhousegas(GHG)emissionsby11%(unconditional)to92%(conditional)by2030,comparedwithabusiness-as-usualscenario.•TherenewableenergytargetsinMauritania’sNDCareunconditionalandincludereaching13gigawatts(GW)ofrenewablecapacityby2030(includingthecapacitytoproducehydrogenforexport)andincreasingtheshareofrenewablesintheenergymixto50.34%by2030.Morocco•RatifiedtheParisAgreementon21September2016.•TheNDC,updatedinJune2021,aimstoreduceGHGemissionsby18.3%(unconditional)to27.2%(conditional)by2030,comparedwithabusiness-as-usualscenario.•TherenewableenergytargetsintheNDCincludereaching52%ofinstalledpowercapacityfromrenewableenergyby2030,ofwhich20%fromsolar,20%fromwindand12%fromhydropower.•TheNationalEnergyEfficiencyStrategyaimstoreduceenergyconsumptionby20%by2030comparedwithabusiness-as-usualscenario.Tunisia•RatifiedtheParisAgreementon10February2017.•TheNDC,updatedinOctober2021,aimstoreducecarbonintensityby27%(unconditional)to18%(conditional)by2030,comparedwith2010asthebaseyear.TheNDCincludesthetargetof30%renewableelectricityby2030(upfrom2.6%in2020).•TheNationalRenewableEnergyActionPlan2018targetsa3.8GWcapacityforrenewablesby2030.Source:(IEA,2020b;UNFCCC,2021b).Thecountries’policyambitionsrevealanoveralldesiretoreachahighershareofrenewablesinelectricitygeneration.AlloftheNDCsincluderenewableenergycapacityexpansiontargetsfor2030,bothunconditionalandconditional,aspresentedinTable1-1andFigure1-8.ThemostambitiousanddetailedNDCintheregionisMorocco’s,whichcallsforrenewablepowerplantstomakeup52%ofinstalledcapacityby2030.Thistarget,setinthecountry’sfirstNDC,remainsatthesamelevelintheupdatedversion;itisreiteratedinMorocco’s“StratégieBasCarboneàLongTerme–Maroc2050”(Long-TermLowEmissionDevelopmentStrategyorLT-LEDS).AlmosthalfofMorocco’srenewableenergytargetsareunconditional,whiletheremaininghalfisconditionedonexternalfinancialandpolicysupport.Ifallconditionsweremet,thecountrywouldtripletheinstalledcapacityofrenewablesduringthedecade.•21•NORTHAFRICAAmbitiousrenewableenergytargetswerealsosetinAlgeria’sandTunisia’sNDCs,whichaimtoreach27%and30%electricitygenerationfromrenewablesby2030,upfrom1%and4%atpresent.However,almostalltherenewableenergytargetsofthesetwocountriesareconditional,andtheiraimtomultiplythenationalrenewablepowergenerationcapacitybymorethantenwilldependonexternalconditions.AsforMauritania,whileitsfirstNDCdidnotcontainanyquantifiedrenewableenergyobjectives,theupdatedversionincludesambitiousunconditionaltargets,suchasreaching50.34%ofrenewablesinitsenergymixby2030.Incontrast,LibyahasnotyetsubmittedanNDC,andEgypthasnotprovidedanyquantifiedrenewableenergytargets.Figure1‑9showsthemostambitioustargetsfortheshareofrenewableresourcesinpowergenerationtowhichNorthAfricangovernmentshavecommittedthemselvesthroughNDCsorotherstrategydocuments.Mostcountriesareachievingfarbelowthetargetssetandtheycurrentlyrelyheavilyonfossilfuelsfortheirelectricityproduction.However,giventhesetargets,itistobeexpectedthatnon-hydrorenewableresourceswillincreaseinimportanceintheyearstocome.ThenextsectionlooksatrecenttrendsintheseresourcesintheNorthAfricancontext.Figure1‑8Renewableenergycapacityexpansionby2030accordingtoNDCsinNorthAfricaSource:(UNFCCC,2021b).Note:MW=megawatt;NDC=NationallyDeterminedContribution.3267686597237354396382521984453434102000400060008000100001200014000MoroccoAlgeriaEgyptTunisiaMauritaniaLibyaRenewableenergycapacity(MW)NDCconditionaltargetsNDCunconditionaltargetsExisting(2020)122•22•PLANNINGANDPROSPECTSFORRENEWABLEPOWER1.6SOLARANDWINDPOWERINNORTHAFRICAAREEXPANDINGANDGETTINGCHEAPERInthelastdecade,thegrowthratesofworldwideuseoffossilfuelshavesloweddown,partlyowingtotheincreaseduseofrenewableenergysourcessuchaswindandsolarasaconsequenceoftheirshrinkingcosts.Installedsolarcapacity,bothphotovoltaic(PV)andthermal,inNorthAfricahasincreasedstronglyinthepastfiveyears,reachingmorethan3000MWin2020.However,thatcapacitystillcorrespondstojust2.7%oftheregion’stotalinstalledelectricitygenerationcapacityofroughly116GW(IRENA,2020a)(Figure1‑10a).Regionaldifferencesarestark,withtheshareofsolarininstalledcapacityrangingfromlessthan0.1%(Libya)tomorethan15%(Mauritania)(seealsoTableA‑1intheDataappendix[IRENA,2022b]).EgyptandAlgeriahaveplayedacriticalroleininstallingsolarPVpowerplants;togethertheyrepresent84%ofthetotalsolarPVinstalledcapacityinNorthAfricain2020(Figure1-10b).Mostinstalledsolarpowercapacityisconnectedtothegrid;off-gridcapacityismostlyfoundonAlgeria’sisolatedsoutherngrids.Regardingconcentratedsolarpower(CSP),Moroccohadover90%oftheregion’scapacityin2020,mainlyfromthe510MWNoor-Ouarzazateplant–theworld’slargestCSPplant(Masen,2016).AlgeriaandEgypthaveinstalledsmallerCSPplants:in2011,theyinauguratedtheISCCHassiR’mel(SolarPACES,2011a)andtheISCCKuraymat(SolarPACES,2011b)powerplants,respectively,withcapacitiesof20MWeach.TheAlgeriangovernment,inits2015RenewableEnergyRoadmap(Ministèredel’ÉnergieetdesMines,Algérie,2015),setatargetofreaching2GWofCSPby2030.AsshowninFigure1‑11,theaveragetotalinstalledcostforsolarPVintheNorthAfricanregiondroppedfromUSD2000/kilowatt(kW)in2015toUSD1306/kWin2019(GlobalData,2020).Thesedatacover38projectsinNorthAfrica,ofwhich34areinEgypt,mainlyintheBenbanSolarParkarea.Onaglobalscale,Figure1‑9Shareofenergysourcesinelectricitygenerationin2019andmostambitioustargetsforrenewableenergy(includinghydropower)inNorthAfricaSource:(IRENA,2020a;MinistryofElectricityandRenewableEnergyofLibya,2013;MinistryofEnergyandMiningofAlgeria,2015;MinistryofEnvironmentandSustainableDevelopmentofTunisia,2015;Reuters,2021a).Note:Moroccohasatargetforinstalledrenewableenergycapacity,notfortheshareofrenewableenergyintheelectricitymix.RE=renewableenergy.28%19%9%4%1%0%0%10%20%30%40%50%60%70%80%90%100%MauritaniaMoroccoEgyptTunisiaAlgeriaLibyaNorthAfricaSolarHydroMostambitioustargetforREshareNon-renewableBioenergyWind7%0%1%4%9%19%28%50.34%42%30%27%10%•23•NORTHAFRICA0500100015002000250030003500201020112012201320142015201620172018201920200%10%20%30%40%50%60%70%80%90%100%PVCSPInstalledcapacity(MW)ConcentratedsolarpowerOn-gridsolarphotovoltaicO-gridsolarphotovoltaicAlgeriaEgyptMauritaniaMoroccoTunisiaLibyatheinstallationcostfellfromUSD1800/kWtoUSD995/kWduringthesameperiod(IRENA,2020b).RecenttariffsreportedinTunisiaforindependentpowerproducerprojectsbetween50MWand200MWaveragedUSD30/megawatthour(MWh)(TunisianMinistryofIndustry,EnergyandMines,2019).Thelowesttariffwasproposedforthe200MWsolarplantinTataouine;atTND71.783/MWh(approx.USD24/MWh),thiswasthelowestsolarbidrecordedinAfricaattheawarddate.SolarCSPplantsremainmorecostlythansolarPVplants,despitedecliningcosttrends;forcomparison,NOORIII,oneoftheCSPpowerplantsoftheNoor-Ouarzazatecomplex,hadatotalinstalledcostofUSD5367/kW(MAZARS,2016).Asimilarincreaseinwindenergy’sinstalledcapacitycanbediscernedfromdataoverthepastdecade.Thetotalinstalledwindcapacityintheregion,allofitonshore(seeFigure1‑12)wasslightlymorethan3000MWattheendof2020,representing2.7%ofNorthAfrica’stotalpowergenerationcapacity(IRENA,2020a).Again,regionaldifferencesarepronounced:fromzeroinLibyatonearly6%inMauritania.EgyptandMoroccoarethemainplayersinwindpower,witha45%and46%shareoftotalinstalledwindcapacityinallofNorthAfrica,respectively.Theaveragetotalinstalledcostofwindenergyprojectsintheregionhasalsofallensignificantly(seeFigure1-13),fromUSD1795/kWin2015toUSD1448/kWin2019(GlobalData,2020).ThedatacoversevenprojectsinstalledinNorthAfricabetween2015and2019,fourinEgyptandthreeinMorocco.Inthesameperiod,theinstallationcostdeclinedgloballyfromUSD1642/kWtoUSD1549/kW(IRENA,2020b).Insummary,althoughthecontributionofsolarandwindpowertoNorthAfrica’selectricitymixremainsrelativelysmall,thedatashowthatrenewableenergysourceshavegrowninimportance.Theireconomicandenvironmentalcompetitivenessalsomakesthem,intheshortandmediumterm,oneofthebestalternativestoreplaceelectricitygenerationbasedonfossilfuels.Figure1‑10InstalledcapacityofsolarPVandCSPinNorthAfrica,2010-2020,andshareinindividualcountries,2020Source:(IRENA,2020a).Note:CSP=concentratedsolarpower;MW=megawatt;PV=photovoltaic.a.SolarPVandCSPinstalledcapacityinNorthAfrica,2010-2020b.Countries’shareinsolarPVandCSPinstalledcapacityinNorthAfrica,2020•24•PLANNINGANDPROSPECTSFORRENEWABLEPOWER050010001500200025003000350020102011201220132014201520162017201820192020MW0%10%20%30%40%50%60%70%80%90%100%AlgeriaEgyptMauritaniaMoroccoTunisia2000258711932079130618011637141512089950500100015002000250030003500400020152016201720182019USD/kWNorthAfricaaverageRangeofprojectsinNorthAfricaWorldFigure1‑11EvolutionoftheaverageinstallationcostsforsolarPVprojectsinNorthAfricaSource:(GlobalData,2020;IRENA,2020b).Note:kW=kilowatt.Figure1‑12InstalledcapacityofonshorewindinNorthAfrica,2010-2020,andshareinindividualcountries,2020Source:(IRENA,2020a).Note:MW=megawatt.a.EvolutionofonshorewindinstalledcapacityinNorthAfrica,2010-2020b.Countries’shareofonshorewindinstalledcapacityinNorthAfricain2020•25•NORTHAFRICA1795213114941448164216351635162815490500100015002000250020152016201720182019USD/kWNorthAfricaaverageRangeofprojectsinNorthAfricaWorld1.7ENHANCEDFLEXIBILITYPROMOTESINTEGRATIONOFSOLARANDWINDINTONORTHAFRICANPOWERSYSTEMSRealisingthepotentialofvariablerenewablesources,mainlysolarPVandwindpower,togenerateelectricityforNorthAfricanpowersystemswilldependonflexibility–thatis,onmeasurestoenhancetheintegrationofvariablerenewableenergyintothegrid.Operationally,thesemeasurescanbegeneration-based(e.g.flexibledispatchfromthermalorhydropowerplants,aswellasincreasedinterconnections),storage-based(e.g.batterystorageorhydrogenproduction)ordemand-based(e.g.demandresponseandsectoralcoupling)(Sterl,2021).Thisreportfocusesmainlyonthepotentialbenefitofstoragetoenhancesystemflexibilityanditseffectsontheneedforsysteminterconnectivity.Anoverviewofthecurrentstateofinterconnectivity,batterystorageandhydrogenproductionfollows.1.7.1InterconnectionsThissectionsummarisestheexistingtopologyandpossibleexpansionofinterconnectionsthroughtransmissionupgrades.Foreachcountry,threetypesofinternalconnectionswereidentified:existingtransmissionlines(operational),plannedprojects(underconstructionorwithanestimatedstartdateintheperiod2025-2030)andcandidateprojects(includingexistingprojectsthat,innewgenerationscenarios,presentopportunitiesforexpansion).ThedataontransmissionlinesandplannedprojectsforthewholeregionwerecollectedfromtheComitéMaghrébindel’Electricité(COMELEC,asupranationalcommitteebetweenMorocco,Algeria,Tunisia,LibyaandMauritaniatocoordinateenergypolicyandliberalizationefforts,especiallyregardingthetransmissionnetworksofthememberstates)andtheEgyptianElectricityHoldingCompany.ThemapsinFigure1-14summarisetheexistingandplannedinterconnectioncapacitybetweenNorthAfricancountries,aswellasthoseconnectingNorthAfricancountrieswithotherregions.Figure1.13EvolutionofaverageinstallationcostsforonshorewindprojectsinNorthAfricaSource:(GlobalData,2020;IRENA,2020b).Note:kW=kilowatt.•26•PLANNINGANDPROSPECTSFORRENEWABLEPOWERAllNorthAfricancountriesareinterconnected,exceptMauritania.3However,theinterconnectionbetweenTunisiaandLibyahasbeenfacingtechnicalissuesandhasbeenusedmainlyattimeswhenLibya’seasternandwesterngridsweredisconnected.Moreover,astabilityproblemappearswhentryingtosynchronouslyconnectLibya-Egypt-Jordan-SyriawithTunisia-Algeria-MoroccoandtheEuropeanNetworkofTransmissionSystemOperators(ENTSO-E).Thedropinfrequency,owingtoinsufficientgenerationinthesoutheasternMediterranean,triggersprotectionsonthelines,whicharethenautomaticallydisconnected.Thelasttestoftheinterconnectiontookplacein2010.ThetestdemonstratedthattheTunisia-LibyainterconnectionwaspossibleonlywhenLibyaandEgyptweredisconnected.Despitethis,theinterconnectionsbetweenNorthAfricancountriesareintendedtoimprovethesystem’sreliability.WithinCOMELEC,Algeria,MoroccoandTunisiasharethereservemarginrequiredtostabilisethesystem.Yet,someoftheexistinginterconnectionlinesarenotcurrentlyoperatingatthedesignedcapacity.Amongthefactorscontributingtothissituationaredelaysinconnectingprojects,upgradestonationalpowersystemsandregulatoryframeworksthathavenotadvancedadequately.Theexistinginterconnectioncapacityforintra-regionalexchangesbetweenNorthAfricancountriesispresentlylimitedto1310MW,eventhoughthephysicalcapacityoftheinterconnectionlinesis4500MW.Anotheraspectconsideredinthisstudyisinterconnectionwithcountriesfromotherregions.NorthAfricaispresentlyinterconnectedtoEuropethroughlinesbetweenMoroccoandSpain,andwillbefurtherjoinedthroughplannedinterconnectionsbetweenTunisiaandItaly.Inaddition,EgyptisalreadyinterconnectedwithJordanandSudan(Med-TSO,2020)andwillsoonbeinterconnectedwithSaudiArabia(Farag,2022).Presentlynomarketmechanismgovernstheseinterconnections.TheNationalOfficeofElectricityandDrinkingWater(OfficeNationaldel’Electricitéetdel’EauPotable,ONEE),theMoroccanpowerutility,isanactorintheSpanishelectricitymarketandthuscanpurchaseandsellelectricitythroughtheinterconnectionbetweenMoroccoandSpain.Insomecases,contractsareestablishedbetweencountriesforimportsandexportsofelectricityatfixedprices(Redouaneetal.,2018).3MauritaniaisinterconnectedwithseveralWestAfricanPowerPool(WAPP)countries.Inthisstudy,wedonotmodeltheinteractionsbetweenMauritaniaandWAPPcountries.AseparatereportonWAPPappearedinthisseriesin2018(IRENA,2018a).Figure1‑14ExistingandplannedinterconnectioncapacityinNorthAfricaSource:FigureadaptedfromCEJA(Centred’ÉtudesJuridiquesAfricaines),www.ceja.ch/en/north-africa/.0SpainAlgeriaTunisiaLibyaItalyJordanCyprusKSASudanMoroccoEgypt400240028012004807501503000140029045020002000600ExistingUpgradeNew•27•NORTHAFRICA1.7.2BatterystorageBatterystorageisexpectedtobecomeacriticalenablerfortheintegrationoflargesharesofvariablerenewableelectricity,suchassolarPVandwind,intopowersystems(IRENA,2021a).Batteriescanenhancesystemflexibilitybystoringsurplusenergyforlaterrelease,forexample,whenthesunisnotshiningorthewindnotblowingstronglyenoughtogenerateelectricity,particularlyonday-nighttimescales(IRENA,2017).Batteriescanalsoprovideancillaryservices,suchasabsorbingsurpluspowerorcompensatingforshortfallsonascaleofmilliseconds(mimickingthebehaviouroflargerotatingmassesinthermalandhydropowerplants),thuscontributingtogridstability.Thiscapabilityisknownas“syntheticinertia”(IRENA,2019a).Similarly,batteriescanhelpmanagegridcongestion,thusallowingtransmissionsystemupgradestobedeferred,amongotheradvancedapplications.Currently,thedeploymentofbatterystorageisnotincludedinnationalenergyplansinNorthAfricancountries,andtherearenolarge-scalestationarybatterystorageprojectsintheregion.Thepaucityofeconomicallyviableprojectsintheregionistraceabletothehighpresentcostofbatteries(Killer,FarrokhsereshtandPaterakis,2020).However,thistechnologyisexpectedtoofferenormousglobalpotentialinthelongertermascostsfall(IRENA,2017).Withsubstantialgrowthinproductioncapacity,technologyimprovementsandfallingmanufacturingcosts,thepriceoflithium-ionbatteries,thetechnologythatcurrentlydominatesthemarket,hasfallenbyaround90%inthepastdecade(BNEF,2020).In2020,forthefirsttime,batterypackpricesoflessthanUSD100/kilowatthour(kWh)werereportedfortransportapplications,accordingtoBloombergNewEnergyFinance,whichforecaststhatthisfigurewillbecometheaveragemarketpriceby2023.Whilecostsforutility-scalestoragearehigherthanfortransportapplications,decreasingtrendsareexpectedthere,too(NREL,2021).Attheregionallevel,recentresearchfocusingontheintegrationofhighsharesofrenewableenergiesinNorthAfricaenergysystemshaveidentifiedsubstantialpotentialforthedeploymentofbatterystorageintheregiontocompensateforthevariabilityofrenewablesourcesofenergy(Aghahosseini,BogdanovandBreyer,2020;Killer,FarrokhsereshtandPaterakis,2020).1.7.3HydrogenOverthelastfewyears,NorthAfricancountrieshavesignedseveralagreementswithpartnercountriesandprivatecompaniestoexploregreenhydrogenproductionandlaunchpilotprojects.ThefinalobjectiveistoexporthydrogenproducedinNorthAfricatootherregionsforthepurposeofdecarbonisinghard-to-abatesectors,suchascertainindustrialsub-sectors.ProjectsthathavebeenannouncedorthatareunderdevelopmentarepresentedinTable1‑2.Manyoftheseprojectsareexportoriented.MoroccoandTunisiasignedco-operationagreementswithGermanyin2020(FederalMinistryforEconomicAffairsandEnergy,2020)toforgepartnershipsandalliancesingreenhydrogen.TheexistingnaturalgastransportinfrastructurebetweenNorthAfricaandEuropecouldbeusedfortheseexports(TimmerbergandKaltschmitt,2019).Anotheroptionisseabornetransportationofliquifiedhydrogenorammonia(IRENA,2022a).Inamovethatdemonstratestheviabilityofusingexistinginfrastructuretotransporthydrogen,SNAMandENIlaunchedapartnershipongaspipelinesbetweenAlgeriaandItalyinNovember2021(Jewkes,2021).SomecountriesinNorthAfricahaveincludedhydrogenintheirnationalenergystrategies.MoroccopublishedanationalstrategyongreenhydrogeninAugust2021,afterthecreationofanationalhydrogencommissionin2019(Ministèredel’Energie,desMinesetdel’EnvironnementduMaroc,2021a,2021b).Inthefoundingdocument,theMoroccanMinistryofEnergy,MinesandSustainableDevelopmentestimatesthatthecountrycouldcaptureupto4%oftheglobalgreenhydrogendemandby2030(Ministèredel’Energie,desMinesetdel’EnvironnementduMaroc,2021c).InJuly2021,Egyptalsoannouncedthepreparationof•28•PLANNINGANDPROSPECTSFORRENEWABLEPOWERanintegratedstrategyforhydrogenproduction;itsEnergyStrategy2030nowincludesgreenhydrogen(AhramOnline,2021).InMarch2022,theEgyptianMinistryofElectricityandRenewableEnergy,theMinistryofPetroleumandMineralResourcesandtheEuropeanBankforReconstructionandDevelopmentsignedamemorandumofunderstandingtoestablishaframeworkforassessingthepotentialoflow-carbonhydrogensupplychains;thepurposeoftheframeworkistoproduceguidelinesforthenationallow-carbonhydrogenstrategy(Zgheib,2022).Europe’sREPowerEUPlan(EuropeanCommission,2022a)estimatesarenewablehydrogendemandof20megatonnes(Mt)in2030,ofwhich10Mtwouldbeimported.Tofacilitatetheimports,theEuropeanCommissionwillsupportthedevelopmentofthreemajorhydrogenimportcorridorsviatheMediterranean,theNorthSeaandUkraine.TheEuropeanCommission’sEUExternalEnergyStrategy(EuropeanCommission,2022b),publishedinMay2022,announcedthattheCommissionisworkingonaMediterraneanGreenHydrogenPartnershipbetweentheEuropeanUnionandcountriesinthesouthernMediterranean.ThepartnershipwillstartwithanEU-EgyptHydrogenPartnershipandanEU-MoroccoGreenPartnership.Thetargettoimport10MtofhydrogenrepresentsaslightincreasefromwhatwaspreviouslyconsideredintheGlobalAmbitionScenariopublishedintheten-yearnetworkdevelopmentplanofENTSO-EandtheEuropeanNetworkofTransmissionSystemOperatorsforGas(ENTSOG),releasedinOctober2021,whichenvisionedimportsof9Mtin2030,2.5MtofwhichwouldbeimportedfromNorthAfrica(ENTSOGandENTSO-E,2021).Inthesamescenario,hydrogenimportsfromNorthAfricawereexpectedtoincreaseto7.8Mtby2040.Table1‑2Hydrogenprojects,partnerships,co-operationagreementsandmemorandaofunderstandinginNorthAfricaCOUNTRYPROJECT/AGREEMENTSDATEOFAGREEMENTCHARACTERISTICSANDTARGETSSOURCEMoroccoAgreementforthedevelopmentofanammoniaandgreenhydrogenproject(HEVOAmmoniacMaroc)betweentheMinistryofEnergyandMines,FusionFuelGreenandCCC(ConsolidatedContractorsGroupS.A.L.)July2020Greenammonia:3650tonnes(t)in2022;60000tin2025and2026.Hydrogen:616tin2022,3472tin2023,6940tin2024,10411tin2025and2026.Investment:EUR865million.(FusionFuelGreenPLC,2021)PartnershipagreementongreenhydrogenbetweentheMoroccanandGermangovernmentsJune2020100-megawatt(MW)renewableenergyplanttoproducegreenhydrogeninMorocco.(Afrik21,2020)AgreementbetweenMoroccoandPortugalforthedevelopmentofgreenhydrogenFebruary2021Nodetailsprovided(Masen,2021)TheMoroccanAgencyforSolarEnergy(Masen)planstodevelopahybridphotovoltaic/windpowerplanttosupplyagreenhydrogenplantNovember2020Electrolysiscapacity100MW2022:finalisationofthefeasibilitystudyandtenderingprocess.2024-2025:commerciallaunchofthesite.(Masen,2020)•29•NORTHAFRICACOUNTRYPROJECT/AGREEMENTSDATEOFAGREEMENTCHARACTERISTICSANDTARGETSSOURCEEgyptMemorandumofunderstanding(MoU)betweentheEgyptianMinistryofElectricityandRenewableEnergyandSiemensJanuary2021AssessmentofproductionofgreenhydrogeninEgyptandimplementationofapilotproject.(EgyptToday,2021)Co-operationagreementbetweenEgypt’sMinistriesofElectricity,PetroleumandtheNavyandDEME(Belgium)March2021StudiesonproducinggreenhydrogeninEgyptandexportingit.(DailyNewsEgypt,2021)AgreementbetweenEni,theEgyptianElectricityHoldingCompanyandtheEgyptianNaturalGasHoldingCompanyJuly2021StudytoassessthefeasibilityofprojectstoproducegreenandbluehydrogeninEgypt.(Eni,2021a)MoUbetweenSiemensandtheEgyptianElectricityHoldingCompany(EEHC)August2021Launchofagreenhydrogenpilotprojectwithanelectrolysiscapacityof100-200MW.(Siemens,2021)PartnershipbetweenScatec(Norway),theammoniacompanyFertiglobeandtheSovereignWealthFundofEgyptOctober2021Developmentofa100MWgreenhydrogenplantforammoniainEgypt.(S&PGlobalPlatts,2021)MoUbetweentheEgyptianMinistryofElectricityandRenewableEnergy,theMinistryofPetroleumandMineralResourcesandtheEuropeanBankforReconstructionandDevelopmenttoassesseslow-carbonhydrogeninEgyptMarch2022Assessmenttoproduceguidelinesforthenationallow-carbonhydrogenstrategy.(Zgheib,2022)TunisiaMoUbetweenTunisiaandGermanyDecember2020EstablishmentofaTunisian-Germanallianceongreenhydrogen.(TunisianMinistryofIndustry,EnergyandMines,2020)AlgeriaMoUbetweenthestate-ownedoilcompanySonatrachandEniMarch2020DevelopmentofapilotprojecttoproducegreenhydrogeninAlgeria.(Eni,2021b;Reuters,2021b)MauritaniaMoUbetweentheMauritanianMinistryofOilandtheAustraliancompanyCWPGlobalMay2021Developmentofa30-gigawatt(GW)power-to-XplantinMauritaniatoproduceandexportgreenhydrogen(“AMAN”project).Totalcost:USD40billion.(CWP,2021)MoUbetweentheMauritanianMinistryofPetroleum,MinesandEnergyandtheAfrica-basedenergygroup,ChariotSeptember2021Feasibilitystudyfor“ProjectNour”,a10GWgreenhydrogenplant.InApril2022,ChariotsignedaMoUwiththePortofRotterdamtoimportrenewablehydrogen.(ChariotTransitionalEnergy,2021,2022)•30•PLANNINGANDPROSPECTSFORRENEWABLEPOWER•31•NORTHAFRICAThemodelledresultspresentedinthischapterconfirmthatNorthAfrica’selectricitymixescouldbediversifiedawayfromfossilfueldependencywhiledecreasingtheunitcostsofelectricitygeneration.Thisresultcouldbeobtainedbyintegratingmuchhighersharesofrenewableelectricity,wellbeyond50%,thancurrenttargetsforesee.Suchahighshareofrenewablescouldbeabsorbedthroughbetterinterconnectionsbetweenthecountriesoftheregion,aswellaswithneighbouringregions,andthroughlarge-scaledeploymentofbatterystorageandhydrogenproduction.Thesuggestedrenewablepowerportfoliowouldincludesolarphotovoltaic(PV),concentratedsolarpower(CSP)andwindpower.Expandeduseofstoragetechnologiesmakesitpossibletoachievegreaterandmoreefficientlevelsofrenewableenergyinaninterconnectedelectricitysystemwhilealsoreducingtheunitcostofelectricitysupply.Exploitationoftheregion’shydrogenproductionpotentialcouldmeetasignificantshareofEurope’sprojectedhydrogendemandin2040,thushelpingtodecarboniseEurope’senergysector.2.1SPLAT-NMODELSCAPACITYEXPANSIONINNORTHAFRICAThissectionsummarisestheplanningmethodologyusedinthisstudyanditsapplicationtothedevelopmentofscenariosfortheexpansionofelectricitycapacityinNorthAfrica.ExpandingcapacityoptimallyrequiresidentifyingthebestwaytocombinenewconstructionofgenerationandtransmissionassetswithretirementsofoldassetssoastominimisethenetpresentvalueoftotalsystemcostsinNorthAfricaoveragivenplanninghorizonandunderagivensetofassumptions.Thisdeterminationisderivedfromthesolutionofaleast-costoptimisationmodel:IRENA’sSystemPlanningTestModelforNorthAfrica(SPLAT-N)4(IRENA,2018a).SPLAT-NwasdevelopedusingamodelgeneratorknownastheModelforEnergySupplyStrategyAlternativesandtheirGeneralEnvironmentalImpact(MESSAGE).MESSAGEisaflexible,dynamic,bottom-up,multi-yearenergysystemmodelthatapplieslinearandmixed-integeroptimisationtechniques.ItwasinitiallydevelopedbytheInternationalInstituteofAppliedSystemAnalysisbuthasbeenfurtherenhancedbytheInternationalAtomicEnergyAgency.TheMESSAGEplatformrequiresasinputasetofdemandprojections,adatabaseoftransmissioninfrastructure,economicandtechnicalparametersofpowersupplytechnologies,andinformationonexistingcapitalstockanditsremaininglifespan.Fromthestartingpointofexistingpowerinfrastructureintheregion,themodelcalculatesanevolutionoftechnicallyfeasibletechnologymixesthatachievealeast-costobjectiveovertheplanningperiod.Inotherwords,themodelgeneratesminimaltotaldiscountedsystemcosts,includinginvestment,operationandmaintenance,fuelandanyotheruser-definedcosts,whilemeetingvarioussystemrequirements(e.g.sufficientsupplytomatchdemandatagiventimeorsufficientresourcesandcapacitytoachievethedesiredproduction)anduser-definedconstraints(e.g.reservemargin,speedoftechnologydeployment,emissionlimits,policytargets).4https://www.irena.org/energytransition/Energy-System-Models-and-Data/System-Planning-Test-Model.2SCENARIOSFORNORTHAFRICA’SELECTRICITYSYSTEMS•32•PLANNINGANDPROSPECTSFORRENEWABLEPOWERThemodelinputsdescribedabovecanbevariedbytheusertoexplorevarioussystemevolutionscenariosunderspecificsetsofassumptions.Themodel’s“solution”includes,amongotherthings,requiredinvestmentinnewtechnologies,projectedelectricityproduction,fuelconsumptionandtradepatterns.Theeconomicandenvironmentalimplicationsassociatedwithparticularleast-costenergysystemscanbeeasilycalculatedwiththemodel.TheSPLAT-Nmodelcontainsmorethan450generatingplantsintheregionandsixcross-bordertransmissionlines;itcoversa20-yearhorizon(2020-2040).Itstemporalresolutionisdefinedbyfiveseasons,eachhavingtendistinctdailytimeslices,anditconsiderseachcountryasaseparatenode(usingthecopper-plateassumptionwithineachcountry,i.e.perfecttransmissionisassumedwithinacountry’sborders).2.1.1PowersysteminputsandmodellingThefirststepinoptimisingcapacityexpansioninNorthAfricaistobuildarobustdatabaseofpowergenerationassets.Intensivedatacollectionwascarriedoutforeachofthesixcountriesoftheregion.Thisprocessconsistedofreplicatingeachexistingpowersystem’soperation,comparingthemodeloutputswithrecordedhistoricalgenerationandadjustingcertainvariables(e.g.powergenerationandcapacityexpansion,powerexchange,operationalconstraintsandmaximumallowableyearlycapacityexpansion).Theresultwasareliablebasecaseforeachcountryoperatinginisolation(orwithinternationalelectricityexchangerestrictions).Finally,theindividualdatabasesweremergedintoasingleconsolidateddatabaseforthesixNorthAfricancountries.Devisingalong-termcapacityexpansionplanalsorequiresconfiguringthemostrelevantinputstothesystem.Themainelementsarethesupplyofelectricity(powerproducers)andthetransmissionnetwork.Theseinputstothemodelaredividedintothreecategories,asdefinedinTable2‑1.Annualelectricityconsumptionandpeakloadprojectionsforeachofthesixcountriesoverthe2020-2040planninghorizonareamongtheinputsrequiredbythemodel.Themodelwasconfiguredtooptimisesupplytomeetdemandonthelevelofthetransmissiongrid(i.e.beforedistributionlosses).Electricityinjectedbyauto-producers,suchasSonatrachinAlgeria,isconsideredaspartofthedemand,butoff-gridself-generation(e.g.thatisusedbyminesinMauritania)isnot.Detailsofthemodel’shandlingofdemandareprovidedinBox2-1.Table2‑1DefinitionandmodellingofpowersysteminputsinSPLAT-NCATEGORYDEFINITIONANDMODELLINGExistingpowersystemThiscategoryrepresentsthepowersystemsinplaceasof2020(thestartofthemodellinghorizon).CommittedgenerationandtransmissionThiscategoryincludesthegenerationandtransmissionelementscurrentlyunderconstruction,aswellasprojectswhoseimplementationhasbeenapproved.Thedeploymentoftheseelementsmaybeconsideredguaranteedinthemodelresults.Candidatesforgenerationandcross-bordertransmissionexpansionThesearetheelementsofthesystemthatmayormaynotberetainedinthelongtermandmaythusbepartoftheoptimisationprocess.Thecharacteristicsoftheseprojects(size,location,technology,etc.)mustbeconsistentwithexistinginfrastructure,pricetrendsandenergyresourcepotential.Themodelwillselectthemiftheyshowanetbenefittothemodelledpowersystem,whichimpliesthatbuilding,operatingandmaintainingthemshouldminimisethetotalcostofpowersystemexpansion.Candidatewindandsolarpowerplantsconsideredinthisstudyaresitespecific,withdifferentloadcurvesassociatedtoeachlocation.Fossil-fuel-basedpowerplantsaregenericcandidatesnotdependentonlocation.•33•NORTHAFRICACATEGORYDEFINITIONANDMODELLINGCandidatesforgenerationandcross-bordertransmissionexpansionFor“candidate”generationprojects,theinvestmentcost(alsocalledconstructionorcapitalcost)mustbedefinedinordertocomputeannualisedcapitalcosts.Investmentcostpaymentscanbedeterminedfromtheprojectstartdateorfromseveralyearsbefore(leadtime).Capitalcostsaredifferentdependingonthetechnology,sizeandlocation.Themodelwillbuildcandidatesifdoingsominimisesthetotalcost,namelythenetpresentvalueoftheinvestmentcost,thecostofoperationandmaintenance,andfuelcosts(seesection2.1.5).Expansionoftransmissioncapacityreferstoaddinglinestothesystem,changingtheexistingtransmissiontopologyandreinforcingexistingtransmissioncorridors(representedbynodes).Thismodelconsidersonlytransmissionlinesbetweencountries.Eachindividualcountryisrepresentedasasinglenode.Thus,thecostsofgridextensionwithineachcountryarenotfullycaptured.WhereasthePlannedscenarioconsidersonlyinstalledandcommittedlines,theexpansionofinterconnectioncapacityisallowedinthethreeTransitionscenarios.Whenthemodelconsidersiteconomicallybeneficialtoexportorimportpower,itwillexpandtransmissioncapacitytodevelopelectricitytrade.Inter-connectionsareconsideredbothwithinNorthAfricaandbetweenNorthAfricaandEurope(theexistinginterconnectionsbetweenSpainandMorocco,EgyptandJordan,andEgyptandSudan,andtheplannedinterconnectionbetweenTunisiaandItaly).HourlyexportpricesareconsideredtovaryaccordingtohistoricalpricesinItalyandSpainforinterconnectionsbetweenItalyandTunisiaandbetweenSpainandMorocco,andaccordingtohistoricalannualpricesforinterconnectionsbetweenJordanandEgypt.5ThethreeTransitionscenariosareintroducedinsection2.2.Note:SPLAT-N=SystemPlanningTestModelforNorthAfrica.2.1.2ModellingofsafetyandoperationalconstraintsAdditionalsafetyandoperationalconstraintsareincludedinthemodel,assummarisedbelow.Reservemarginrequirements(spinningandnon-spinning).Weconsiderareservemarginof10%ofavailablecapacityoverthepeakload.Technologiescontributingtothisreservemarginarefossilfuelpowerplants,biomass,hydropower,CSPwiththermalstorageandbatteries.Thereasonforallowingthelasttwotocontributetothereservemarginisthatthesetechnologiescanbeconsideredtobepartofthereservecapacity,providedthatstoragelevelsaretypicallyhighenoughtoprovidepeakpowerforlimitedperiodsoftime.(TheimplicationsofthisneedforthedesignofCSPplantsareexploredinsection2.10.)Variablerenewableenergy(VRE)technologies,ontheotherhand,arenotgivenacapacitycreditandaredeemednottocontributetothereservemargin.Dispatchlimits.ThemaximuminstantaneouspenetrationofsolarPVandwindpowerislimitedto70%ofdemandcountrybycountry.CSPisnotconsideredinthislimit.However,whenhydrogen(H2)isintroducedinthemodel(intheTransition+Batteries+H2scenario),5the70%limitisalsonotappliedtotheelectricityusedtoproducehydrogen,asitisproducedentirelyusingrenewableelectricity.Minimumgenerationconstraints/non-economicgroupdispatch.Aminimumgenerationlevelisconsideredforfossil‑fuel-basedpowerplants(5%forgasturbine,15%forcombinedcycles,20%forcoalpowerplants);aminimumdispatchof70%isconsideredfornuclearpowerplants.Table2‑1DefinitionandmodellingofpowersysteminputsinSPLAT-N(continued)•34•PLANNINGANDPROSPECTSFORRENEWABLEPOWER2.1.3ElectricitygenerationtechnologiesconsideredasoptionsduringthemodellingperiodThefollowinglistoftechnologiesareconsideredasoptionsforclosingthegapbetweeninstalledassets,ontheonehand,andprojectedelectricitydemandontheother.•Windpower.ThepotentialineachcountryisdescribedinBox2‑2andintheaccompanyingDataAppendix.•SolarPV.ThepotentialineachcountryisdescribedininBox2‑2andintheaccompanyingDataAppendix.•Solarthermal.CSPisconsideredasanoptionincombinationwiththree-hourstorageandwithafixed-generationprofile.Insection2.10,weexplorewhetherthisassumptionaboutstorageassociatedwithCSPisappropriate.•Naturalgas.Openandcombinedcyclesareconsideredascandidates.IntheTransitionscenarios,nofossilfuelgenerationcanbeinstalledafter2025.Duringtheperiod2020-2025,9.1gigawatts(GW)havebeencommittedorareunderconstructionintheregion.•Nuclearpower.TheDhabaanuclearpowerprojectinEgyptisconsideredcommitted;constructionbeginsin2025.•Biomass.Biomasspowerplantsareconsideredascandidatesaccordingtothenationalplans(e.g.the960megawatts(MW)potentialpresentedinMorocco’snationalbiomassroadmap).•Hydropower.Nonewhydropowerprojectsareconsideredinthecountriesoftheregionasthepotentialisalmostentirelyexhausted.2.1.4CapacityexpansionplanningTable2‑2summarisestargetedandcommittedrenewableenergyprojects,aswellasthemostrecentofficialplanningdocumentsinNorthAfricancountries.Targetedcapacityincludesthetargetssetbygovernmentsintheirlatestnationalplanningdocuments.Thesetargetcapacitiescorrespondtotheadditionalcapacityneeded,asestimatedintherespectiveplanningdocuments,toreachnationalrenewableenergytargets.Themodeldoesnotconsiderthesetargetedcapacitiesasfixed(i.e.asacertainpartofthefuturepowersystem)inordertoallowforoptimisation.Committedprojectsarethosethatareconsideredtohaveahighprobabilityofbeingbuiltintheshortormediumterm,andwhosemaincharacteristics(capacity,energy,location,investmentcost)areknown,asexplainedinsection2.1.5.Thecommittedpowerplantsareincludedinthemodelascertainpartsofthefuturepowersystem–thatis,themodelconsidersthattheywillbebuiltandoperatedinallscenarios.Duringthemodellingperiod(2020-2040)thecommittedfossilfuelpowerplantsintheregionrepresent9.1GW(naturalgascombinedcycleandopencycleplants)tobeinstalledandenterintoservicebytheendof2021,primarilyinAlgeria.IntheDataappendix(IRENA,2022b),Section1.1containscountry-leveldetailoncurrentinstalledcapacity(TableA‑1,TableA‑2andTableA‑3);Section1.5containsthecapacityexpansionresultsformodellingyears2025,2030,2035and2040(TableA‑21throughTableA‑25).•35•NORTHAFRICATable2‑2PlannedandcommittedrenewableenergyprojectsinNorthAfricaRECENTPLANNINGDOCUMENTPROJECTS(PLANNEDANDCOMMITTED)AlgeriaNationalRenewableEnergyDevelopmentStrategy2015-2030(METRE,2015)Planned:•RenewableEnergyStrategy:22GWfromsolarandwindby2030,including13.5GWsolarPV,5GWwind,2GWCSPCommitted:•2021tender:1000MWsolarPVby2023(RadioAlgérienne,2021)•100MWsolarPVby2022(Afrik21,2019;Sonelgaz,2019)•DiffelSolarPV(Commissionderégulationdel’ElectricitéetduGazd’Algérie,2019)andHybridisationofOCGTEgypt2035IntegratedSustainableEnergyStrategy(MinistryofElectricityandRenewableEnergy,2016)EgyptianSolarPlan(MinistryofElectricityandRenewableEnergy,2012)Planned•EnergyStrategy:42%renewablesintheinstalledcapacitymixby2035(22%PV,14%wind,3%CSP,2%hydropower)•SolarPlan:add3.5GWofrenewablespowerplantsby2027,comprisedof2.8GWCSPand700MWPVCommitted:•SolarPVprojectintheKomOmbo:200MW;windpowerprojectintheRasGhareb:500MWby2022-2023(AMEAPower,2019)•SolarPVpowerstationinKomOmbo:50MW(ArabFundforEconomic&SocialDevelopment,2017)•HurghadaPVPowerPlantProject:20MW(ZAWYA,2019)•ZaafaranaWindPowerPlant:50MW(EQInternational,2021)MoroccoNationalEnergyStrategy(Masen,2015)InvestmentPlan2019-2023(ONEE,2019)Planned:•EnergyStrategy:52%oftheinstalledpowercapacityfromrenewablesin2030.Add10GWofrenewableenergycapacitiesbetween2018and2030(4.5GWsolar,4.2MWwind,1.3GWhydropower)•InvestmentPlan:1.6GWwindpower,2GWsolar,anewpumpedhydroprojectof350MW(Abdelmoumenproject),220MWnewhydrogenerationintheperiod2020-2030TunisiaTunisianSolarPlan(MinistryofIndustry,EnergyandMinesofTunisia,2015)Planned:•SolarPlan:Add3815MWrenewablepowerby2030,including1510MWsolarPV,1755MWofwindand450MWCSPCommitted(MinistryofIndustry,EnergyandMinesofTunisia,2015):•1084MWsolarPVand200MWwindby2021-2024Note:ThetabledoesnotincludeMauritaniaasthecountrydoesnothaveanofficialpubliclyavailablemasterplan.CSP=concentratedsolarpower;GW=gigawatt;MW=megawatt;OCGT=opencyclegasturbine;PV=photovoltaic.2.1.5Evolutionofcapitalexpenditure,operatingexpenditureandfuelcostsforpowergenerationThecapitalexpenditureofbuildingnewgeneratingplantsisanessentialparameterforexpandingtheeconomiccapacityofthesystem.Foreachtechnology,thesamecapitalcostswereconsideredforallregionsinNorthAfrica.Theestimatedevolutionofthesecapitalcoststo2040canbefoundinsection1.4(TableA‑14andTableA‑16)intheaccompanyingDataappendix(IRENA,2022b).A10%discountratewasassumedforallcosts.Forcommittedprojects,announcedprojectcostsareused.Forothergenericfossil-fuel-basedgenerationoptions(openandcombinedcyclegasturbines,coalpowerplants),theinvestmentcostscitedininternationallyrecognisedsources(TimilsinaandDeluqueCuriel,2020)andlistedinsection1.4(TableA‑14)oftheaccompanyingDataappendix(IRENA,2022b),areusedinallcountries;theyearlyfixedoperatingexpenditureisassumedtobe3%ofthecapitalexpenditure.Thesecostsaretakentobeconstantthroughoutthestudyperiodasthetechnologiesinquestionareassumedtohavereachedmaturity.Fornon-conventionalgenerationtechnologies,namelysolarPV,windandCSP,thereisasignificanttrendtowardslowercapitalcosts.Ingeneral,thesetechnologiesshowarelativelysteepdeclineintheearlyyearsofthestudy,followedbyalesspronounceddeclineatsomelaterpoint.Thisaspectmainlyrepresentsthegradual•36•PLANNINGANDPROSPECTSFORRENEWABLEPOWERmaturationofthesetechnologiesoverthestudyhorizon.Between2020and2040,IRENA’scostinganalysisprojectswindinvestmentcoststofallfromUSD1458/kilowatt(kW)toUSD842/kW;forsolarPVtheyareexpectedtofallfromUSD950/kWtoUSD280/kW.Inthesameperiod,CSP(withthree-hourstorage)capitalcostsareprojectedtodeclinefromUSD4058/kWtoUSD2562/kW.Overall,solarPVisexpectedtobethepowergenerationtechnologywiththelowestcapitalcostsby2024.Theoperationandmaintenancecostsofwind,solarPVandsolarthermalpowerplantsarepresentedinTableA‑16oftheaccompanyingDataappendix(IRENA,2022b).ElectricityproductioninNorthAfricaisbasedchieflyonnaturalgasandheavyfueloilinEgypt,Libya,AlgeriaandTunisia,andoncoalinMorocco(IEA,2020c;seealsosection1.2).Fuelpriceprojectionswerebasedonpriceprojectionsfrominternationallyrecognisedbenchmarks(TimilsinaandDeluqueCuriel,2020),andnodifferentiationwasmadebetweencountry-levelfuelpricesandthosebetweenproducersandimporters.Therationaleforthisisthatsubsidiesarethemainreasonforinter-countrydifferencesinfuelprices;thisapproachthusavoidedskewingresultsonthebasisofsuchsubsidies.Inotherwords,usingglobalfuelpricesallowsustotakeintoaccounttherealcostofelectricitygenerationandtherealpotentialforexportingthosefuelsfromoilandgasproducingcountries.Asshowninsection1.4inTableA‑14intheaccompanyingDataappendix(IRENA,2022b),anincreaseinfossilfuelpricesisexpectedintheshortterm,through2025.Afterthatdate,astabilisationisprojectedasdemandforthesefuelsisexpectedtodecreaseowingtohigherpenetrationofrenewables.2.2FOURSCENARIOSFORNORTHAFRICA’SPOWERSECTORWEREMODELLEDUsingtheSPLAT-Nmodeldescribedpreviously,fourscenariosweredevelopedforNorthAfrica’spowersectors.ThesearedescribedbelowandinTable2‑3.ThePlannedscenariorepresentstheachievementofplannedpolicygoalsthrough2040,withcountriesreaching(butnotsurpassing)theirrenewabletargetsinpowergeneration.Electricitydemandisdeemedtofollowhistoricaltrendsandwithelectricity’sroleinmeetingfinaldemandatcurrentlevels.Forpowerexchangesbetweencountriesintheregionandoutsideit,onlytheexistingandcommittedinterconnectionsareused.ItisalsoassumedthatNorthAfricancountrieswillreachtheirnationaltargetsfortheshareofrenewablesinelectricitygeneration.Oncethesetargetsaremet,thesameshareismaintainedfortheremainderofthemodellingperiod.TheTransitionscenarioconsidersthatelectrificationexpandsinNorthAfricaandthatpowerinterconnectionsaredevelopedtoenablehigherexchangesofelectricitybetweencountries.Higherpowerdemandisassumedfortheregiongiventhehigherpenetrationofelectricityinfinalenergyconsumption.(Box2‑1providesdetailsaboutthemodel’scharacterisationofdemand.)ExpansionofinterconnectioncapacitiesispermittedtocomplementtheexistingandcommittedlineswithintheregionandwithcountriesoutsideNorthAfrica.Noinvestmentinfossil-fuel-basedpowerplantsismadeafter2025.AnoverviewofthedifferencesbetweenthePlannedandTransitionscenarios(surpassingnationalrenewableenergytargets,disallowingnewfossilfuelinvestments,higherelectrificationratesandincreasedinterconnections)isgiveninsection2.3.TheTransition+BatteriesscenariointroducesthepossibilityofbatterystoragetoprovideflexibilitytobetterintegrateVRE,whilemaintainingthesameparametersastheTransitionscenario.Themodelallowsforthedeploymentofbatterystoragetechnologytobalancesupplyanddemandonsub-dailytimescales.TheTransition+Batteries+H2scenarioassumesthat,inadditiontobatterystorage,hydrogenproductionispossibleinNorthAfricausingelectrolyserspoweredonlybyrenewableelectricity.ThemodelallowsfortheconstructionofelectrolysingfacilitiestoproducegreenhydrogeninallNorthAfricancountrieswhere•37•NORTHAFRICAhydrogenprojectshavebeenannounced(seeTable1‑2).Hydrogenproductionisconsideredforexportonly,namelytotheEuropeanmarket,resultinginrevenuesfortheproducingcountries.Toensuretheproductionofgreenhydrogen,carbondioxide(CO2)emissionsarecappedattheleveloftheTransitionscenario.Themodelwilldeterminethequantityofhydrogenthatcanbeproducedatacostthatislessthanorequaltothedefinedhydrogenexportcost.Table2‑3AssumptionsbehindthefourmodelledscenariosPLANNEDTRANSITIONTRANSITION+BATTERIESTRANSITION+BATTERIES+H2HistoricdemandgrowthandelectrificationlevelsCurrentinterconnectioncapacityCountries’renewableenergytargetsaremetbutnotsurpassedHigherdemandgrowthwithhigherelectrificationofendusesPossibilitytoincreaseinterconnectioncapacityNofossil-fuel-basedgenerationinvestmentafter2025RenewableenergytargetscanbesurpassedHigherdemandgrowthwithhigherelectrificationofendusesPossibilityofincreasinginterconnectioncapacityNofossil-fuel-basedgenerationinvestmentafter2025RenewableenergytargetscanbesurpassedHigherdemandgrowthwithhigherelectrificationofendusesPossibilityofincreasinginterconnectioncapacityNofossil-fuel-basedgenerationinvestmentafter2025RenewableenergytargetscanbesurpassedBatterystorageBatterystorageHydrogenproductionNote:H2=hydrogen.Twoelectricitydemandscenarioswereconsideredinthisreport:PlanneddemandandTransitiondemand.Thesearedescribedbelow.Planneddemandscenario.Thedemandprojectionsandunderlyingassumptionswerederivedfromhistoricaltrendsandassumenodrasticelectrificationofend-usesectors.Thehistoricalgrowthoffinalelectricitydemandshowsdifferenttrendsinthecountriesoftheregion.TherateofgrowthoffinalelectricitydemandisincreasinglyuncoupledfromtheGDPgrowthrateowingtoenergyefficiencymeasures.Inthisscenario,weassumeacontinuationofthistrendwithanaveragegrowthrateof2.8%peryear(decreasingfrom5.9%intheperiod2005-2010and4.0%in2010-2015butincreasingfrom0.3%in2015-2019).•InEgypt,thegrowthrateoffinaldemandhascontinuouslydecreasedoverthepasttwodecadesowingtobetterenergyefficiency(lowerelectricityintensity,expressedaskilowatthours/unitofGDP).•Algeriashowsasustainedgrowthrateoverthepasttwodecades,whichisprojectedtocontinueatthesamelevelduring2019-2040(averageyearlygrowthrateof5.6%).•InLibya,inthisscenario,agrowthrateof2.6%isassumedfortheperiod2019-2040.Thetrendinthedecadesince2010cannotbetakenasareferencebecauseofthemajordecreaseoffinalelectricitydemandduring2010-2015andonlymodestgrowthduring2015-2019.Finalelectricitydemandwasstagnantpriorto2010andverymoderatein2005-2010.•InMauritania,effortstoreachelectricityaccessforallwillkeeptherateofgrowthinfinalelectricitydemandatahighlevelduringtheperiod2019-2040.Averageyearlygrowthof7.3%isassumedinthemodel.•InMorocco,annualgrowthinfinalelectricitydemandhasbeendecliningfortwodecadesowingtobetterenergyefficiency.Thisscenarioassumesthistrendwillcontinue,withanaverageannualrateofincreaseindemandof2.2%(comparedto4.8%during2010-2015and2.8%during2015-2019).•InTunisia,asimilarpatterncanbeseen,withadecreaseintheannualrateofgrowthinfinaldemandfrom6%in2005-2010to2.6%in2010-2015and3%in2015-2019.Inthisscenario,weanticipateanaverageyearlygrowthrateof2.3%duringtheperiod2019-2040.Box2‑1Characterisationofdemandinthemodel•38•PLANNINGANDPROSPECTSFORRENEWABLEPOWERTotalfinalelectricitydemandintheregionisprojectedtoroughlydoublefromaround288TWhin2019toapproximately590TWhin2040(TableA‑4oftheaccompanyingDataappendix[IRENA,2022b]).Theaverageannualratesofgrowthinelectricitydemandandpeakdemandareestimatedat3.5%(TableA‑5andTableA‑6);andtheshareofelectricityintotalfinalenergyconsumption(TFEC)isassumedtobe20%by2040(TableA‑7).By2040,Egyptisexpectedtohavethelargestfinaldemandforelectricity(277TWh)intheregion,followedbyAlgeria(197TWh)andMorocco(53TWh).Itisnoteworthythattwooftheareasofhighestconsumption(EgyptandMorocco)showGDPgrowthratesbelowtheNorthAfricaaverage.Inreality,dailydemandprofileschangeovertheyearsowingtochangingconsumptionhabitsandsectoralpatternsofelectricityuse.Forexample,themountinguseofairconditioningalteredtheloadcurveofmostNorthAfricancountriesbyshiftingthepeakloadfromthewinterseasontosummer.Historicaldatashowthatthisshiftoccurredatdifferentmomentsinthedifferentcountries.Thefirstoccurrencesofpeakloadduringthesummerwere2007inMorocco,2008inLibyaand2009inAlgeria.Climatechangemaypushpeakloadsinsummerevenhigher.Inthemodel,theshapeofthenormalisedprofileisassumedtobeinvariableto2040owingtothelackofdetaileddataonelectricityusepatternsinthecomingdecades.Theprofileisthusexogenousanddoesnotaccountforthedynamicsofnewtechnologicalinnovationssuchasdemand-sideresponsestrategies.Transitiondemand.Thedemandprojectioninthisscenarioassumesacontinuousincreaseintheshareofelectricityinfinalenergyconsumptionrepresentingagrowingelectrificationofenduses.Theassumedelectrificationtrend(highershareofelectricityinTFEC)isbasedonpastgrowthinenergyintensity(TFEC/GDP)andspecificelectricityintensity(finalelectricityconsumption/GDP)(seeFigure1‑3).Inallcountries,theshareofelectricityinTFECisassumedtoreachhigherlevelsthaninthePlannedscenario.TheaverageyearlydemandandpeakdemandgrowthrateforNorthAfricaisestimatedat4.4%(seeTablesA-4,A-5andA-6oftheDataappendix[IRENA,2022b]);theshareofelectricityinTFECreaches27%by2040.TotalelectricitydemandforNorthAfricaisprojectedtoincreasefrom288TWhin2019toaround708TWhin2040,representinga20%increaseinelectricitydemandoverthePlanneddemand.By2040,Egyptisexpectedtohavethelargestelectricitydemand(352TWh)intheregion,followedbyAlgeria(205TWh)andMorocco(64TWh).ForMauritania,thedemandprojectionisthesameinthePlannedandTransitionscenarios;thisisbecausedemandgrowthinMauritaniaisdrivenprincipallybyincreasingaccesstoelectricity,whichisreflectedinthePlannedscenario.ProjectionstoassessfutureloadprofilesweremadefollowingthemethodologyofToktarovaetal.(2019),sincerealloadcurvedatawerenotpubliclyavailableforallofthesixcountriesasofthewritingofthisstudy.Themethodusedgeneratesaloadcurvereflectingseasonalvariationandvariousfactors(suchastemperatureandairconditioninguse).Electricitydemandisprojectedathourlyresolutionwithinasingleframeworkforallcountriesbydecomposinghistoricaldataintoasetofsinefunctionstoanalysethecyclicalpatternofthedata.Themethodprovidesimportantinformationforelectricitynetworkplanningandisflexibleenoughtobeappliedtovarioussocio-economicscenariosbasedonalternativeassumptionsaboutlong-andshort-termtrendsandprojections.Thegeneratedloadcurvesareusedforthewholemodellingperiodandscaledbytheelectricitydispatchedeachyear.Loadprofilesareaggregatedbytimeslice.TheSystemPlanningTestModelforNorthAfrica(SPLAT-N)wassetupusingfiveseasonsandtendailytimeslices.Season1beginson1Januaryandendson20March;Season2beginson21Marchandendson16June;Season3beginson17Juneandendson7September;Season4beginson8Septemberandendson8November;Season5beginson9Novemberandendson31December.Thetendailytimeslicesconsistofasix-hournightsliceandninetwo-hourslicesfortheremainderoftheday,resultingin50timeslicesoverthecourseoftheyear.Box2‑1Characterisationofdemandinthemodel(continued)•39•NORTHAFRICAFigure2‑1showsforeachcountrythemodel’snormalisedloadcurvesonanaveragedayineachofthefiveseasons.Themaincharacteristicoftheregion’sloadcurvesisanannualpeakinSeason3duetotheuseofairconditioning.Theextentofthepeakdiffersfromcountrytocountryowingtothedisparityinthepenetrationofairconditioning.Thepeakinthesummerloadcurveisnearlythesameinthedaytimeandintheevening,whichwouldlikelyaffecthowsolarisused:directlyduringthedaytimepeakandviastorageintheevening.Unlikethesummerandspringloadcurves,whicharerelativelysimilarformostcountries,thewinterandautumncurvesdiffer,displayingaslightduckcurvewithdifferentmagnitudes.Unlikethespringandsummerloadcurves,theeveningloadsinautumnandwintershowahigherpeakowingtodemandforlightingandhouseholdappliances.Figure2‑1NormalisedloadcurvesonanaveragedayineachseasoninNorthAfrica(appliedforallyearsofthemodellingperiod)Note:UTC=CoordinatedUniversalTime.Keyresultsforthefourscenariosrelatedtothedevelopmentofrenewableenergysources,CO2emissions,investments,costs,batterystorageandhydrogendevelopmentaresummarisedinTable2‑4.Thesectionsthatfollowdiscusseachoftheseresultsinmoredetail.00.10.20.30.40.50.60.70.80.91135791113151719212313579111315171921231357911131517192123135791113151719212313579111315171921231January-20March21March-16June17June-7September8September-8November9November-31DecemberNormalisedload(load/peakload)Seasonsofthemodelandtime(UTC)AlgeriaEgyptLibyaMauritaniaMoroccoTunisiaBox2‑1Characterisationofdemandinthemodel(continued)•40•PLANNINGANDPROSPECTSFORRENEWABLEPOWERTable2‑4SummaryofkeyresultsfromtheinvestigatedscenariosPARAMETERPLANNEDTRANSITIONTRANSITION+BATTERIES(costsrelatedtobatteries)TRANSITION+BATTERIES+H2Installedcapacityin2040(GW)180286270597–ofwhichREcapacity(GW)76235220546–ofwhichVREcapacity(GW)72229214541Totalgenerationin2040(TWh)6478228121878–ofwhichREgeneration(TWh)2367137011770–ofwhichVREgeneration(TWh)2237016891753REshareingenerationin2040(%)36878694VREshareingenerationin2040(%)35858593CO2emissionsfromelectricitygenerationin2040(MtCO2/year)146353433Cumulativeinvestmentingenerationcapacity,2020-2040(USDbillions)152379343+(13)573+(19)Totalsystemcost,2020-2040(USDbillions)863898881+(5)1063+(4)Revenuefromhydrogenproduction,2020-2040(USDbillions)---358NewPVcapacity,2020-2040(GW)342329149NewCSPcapacity,2020-2040(GW)0.4746155Newwindcapacity,2020-2040(GW)34129121333Batteriesin2040(capacityinGW/storagevolumeinGWh)--13.0/7819.2/115.2Hydrogenproductionin2040(MtH2/year)---24Electrolysercapacity(GWe)---156Investmentinelectrolysers,2020-2040(USDbillion)---77.4Netunitcostofpowergenerationin2040(UScents/kWh)8.77.57.14.7VREcurtailmentin2040(%)relativetogenerationpotentialofVRE325165Note:CO2=carbondioxide;CSP=concentratedsolarpower;GW=gigawatt;GWe=gigawattelectrical;GWh=gigawatthour;H2=hydrogen;kWh=kilowatthour;MtCO2=megatonnesofcarbondioxide;MtH2=megatonnesofhydrogen;PV=photovoltaic;RE=renewableenergy;TWh=terawatthour;VRE=variablerenewableenergy.•41•NORTHAFRICA2.3THETHREETRANSITIONSCENARIOSDIFFERINTHEIRASSUMPTIONSThebasicassumptionsofthemodelchangeinthreewayswhenmovingfromthePlannedtotheTransitionscenarios.Theseconcern(1)nationalrenewableenergytargets,whicharemetexactlyinthePlannedscenariobutcanbesurpassedintheTransitionscenarios;(2)electricitydemand,whichishigherundertheTransitionscenarios,becauseend-useelectrificationisassumedtobemoreextensive;and(3)cross-borderinterconnections,thecapacityofwhichcanbestrengthenedundertheTransitionscenarios.AbriefinvestigationofthesestepsusingtheSPLAT-NmodelforsensitivityanalysisrevealswhichofthesestepshasthestrongestimpactontheobservedchangesinthepowermixbetweenthePlannedandtheTransitionscenarios(seeTable2‑5).TheinvestigationinvolvesthreetestscenariosthatprogressivelyclosethegapbetweenthePlannedandtheTransitionscenarios:•TestA:SameasPlanned,butallowingcountries’renewableenergytargetstobeexceeded•TestB:SameasTestA,butdisallowingfossilfuelinvestmentsafter2025•TestC:SameasTestB,butwithincreasedelectrificationleadingtoahigherelectricitydemandTheTransitionscenario(Table2‑4)thusbecomesequaltoTestC,plusthepossibilityforadditionalinterconnectionsbetweencountries.TheresultsofthesetestscenariosascomparedtothePlannedandTransitionscenariosareshowninTable2‑5.ItisclearthatthelargestchangebetweenthePlannedandTransitionscenariosisexhibitedbyTestA:ifcountries’renewableenergytargetsareallowedtobesurpassed,themodelfindssolutionsatsubstantiallylowercostbydeployingmorerenewables(doublingtheinstalledcapacityofrenewableenergyby2040,i.e.from37%to72%inthepowermix),mostlysolarPVandwindpower.Thisindicatesthatincreasedambitionincountries’renewableenergydeploymenttargetstodaycouldpavethewayformorecost-effectivesystemsinthefuture.Theconstraintofprohibitingnewfossilfuelinvestmentsafter2025(TestB)resultsinasmallerjumpinrenewableenergycapacity(22%),andthecompositionoftherenewableenergyportfoliochanges.ThemodelnowprefersdeployingCSPwiththermalstorageinsteadofsolarPV,asCSP’shighercapacitycredit(thefractionoftheinstalledcapacitywhichcouldbereliedupontobeavailableatanygiventime)makesCSPplantsabetterinvestmentthansolarPV,giventhehaltafter2025onnewthermalpowerplantsthatcouldhaveprovidedfirmcapacity.Theeffectofhigherdemandduetoelectrification(TestC)isthatnearlyallthenewdemandismetbynewVREplants,withtheshareofrenewablesinthepowermixremainingessentiallyunchanged.Lastly,theeffectofallowingadditionalinterconnectioncapacitybetweenneighbouringcountriesisseentohavemarginaleffectsonoverallinstalledrenewableenergycapacity,butitreducesoverallsystemcostsandtheunitcostsofelectricity.Thisisbecauseinterconnectionsallowbetterexploitationofthespatio-temporalsynergiesbetweendemandandcountries’VREprofiles(seeBox2‑2).ThedifferentassumptionsrelatedtothemodellingofinterconnectionsbetweentheNorthAfricancountriesandbetweenthesecountriesandotherregionsareshowninTableA‑17oftheaccompanyingDataappendix(IRENA,2022b).InthePlannedscenario,noexpansionoftheexistinginterconnectioncapacityisconsidered.InthethreeTransitionscenariostheexpansionofinterconnectioncapacitywithinNorthAfricaispossibleandsubjecttooptimisation.•42•PLANNINGANDPROSPECTSFORRENEWABLEPOWERTheaverageyearlypricesofexchangingelectricitywithcountriesoutsidetheregionarebasedon2019actualprices,drawnfromtheannualreportoftheJordanianNationalElectricPowerCompany,marketdataforSicily(Italy),andmarketdataforSpain(seeFigure2‑11).ThepricesoftheJordan-EgyptinterconnectionareusedfortheSudan-Egyptinterconnectionbecausespecificpricedataforthelatterlinkarelacking.Table2‑5SummaryoftheanalysisofthestepsneededtogofromthePlannedtotheTransitionscenarioPLANNEDTESTA(sameasPlanned,exceptthatrenewableenergytargetsmaybeexceeded)TESTB(TestA+nofossilfuelinvestmentsafter2025)TESTC(TestB+higherdemand)TRANSITION(TestC+moreinterconnections)Installedcapacityin2040(GW)180236233289286–ofwhichREcapacity(GW)76150183238235–ofwhichVREcapacity(GW)72144177232229Totalgenerationin2040(TWh)647676685822822–ofwhichREgeneration(TWh)236501573708713–ofwhichVREgeneration(TWh)223484558694701REshareingenerationin2040(%)3674848687VREshareingenerationin2040(%)3472818585CO2emissionsfromelectricitygenerationin2040(MtCO2/year)14661353835Cumulativeinvestmentingenerationcapacity,2020-2040(USDbillion)152227298382379Totalsystemcost,2020-2040(USD,billions)863799794905898NewPVcapacity,2020-2040(GW)3433172323NewCSPcapacity,2020-2040(GW)0.417527474Newwindcapacity,2020-2040(GW)3492104131129Netunitcostofpowergenerationin2040(UScents/kWh)8.77.37.67.77.5Note:CO2=carbondioxide;CSP=concentratedsolarpower;GW=gigawatt;kWh=kilowatthour;MtCO2=megatonnesofcarbondioxide;PV=photovoltaic;RE=renewableenergy;TWh=terawatthour;VRE=variablerenewableenergy.•43•NORTHAFRICARenewableenergy’spotentialinNorthAfricaisspreadwidely,withexcellentsolarresourcesinallcountriesandgoodwindresources,especiallyalongMorocco’swesterncoastandinEgypt.Theregion’shydropowerpotentialhasalreadybeenmostlyexploited,andbiomassresourcesarelimited.Fallingcostshavealreadymadevariablerenewableenergy(VRE)sourcesviablealternativestofossilfuels.Yettheirvariability(dailyandseasonal,inthecaseofwindandsolar)stilllimitstheiruse.Thesolutionistoexploitthespatialandtemporalcomplementaritypresentintheregion.Forexample,tappingtheregion’swidespreadsolarpowerpotentialwillrequiremeasurestomitigateday-nightvariability.Fortunately,varioussitesinEgyptshowamarkedpotentialforwindpowergenerationduringthenight,whensolarpowerisnotavailable.Furthermore,thankstothewiderangeoflongitudesintheregion,thedailytemporalcomplementaritybetweenthesolarprofilesofcountriessuchasEgypt,AlgeriaandMauritaniaisalsopronounced(Figure2‑2).Anotherpotentialcomplementaritybetweencountries’renewableresourcesisobservedattheseasonallevel.Figure2‑3showshowthewindprofilesofEgyptandMoroccocouldcomplementeachotherduringtheyear.Thecomplementarityoftheregion’sgeographicalandclimaticcircumstancespresentsanexcellentopportunitytointegrateelectricitymarkets,yieldingsignificanteconomic,environmentalandenergysecuritybenefits.Tomeasuretheextentofthatopportunity,weidentified“modelsupplyregions”(MSRs)usingamethodologydevelopedinIRENAandLBNL(2015).Theexerciseinvolvedscreeninghigh-potentiallocationsascandidatesitesforwindandsolarpowerplantdevelopmentanddeployment.EachMSRischaracterisedbydifferentresourceavailabilityandinfrastructurecosts(linkedtotheexpansionofroadsandtransmissioninfrastructure).Themodelselectsthedistributionofnewinstalledcapacitythatofferstheleast-costsolutioninlightofthecostparametersandthefitbetweenVREloadcurvesandthedemandloadcurve.Foreachcountry,theMSRsselectedforwindandsolarpowerplantdeploymenthadtosatisfythefollowingcriterion:thatafullexploitationoftheirpotentialwouldsuffice,onaverage,tocoverfutureelectricitydemand.Foreachcountry,50MSRswereselectedforwindand50forsolarphotovoltaic(PV).MSRcoordinates,maximumcapacityandcapacityfactoraresummarisedintheaccompanyingDataappendix(IRENA,2022b)inTableA‑8(wind)andTableA‑11(solarPV).Country-levelillustrationsareprovidedinsection1.7oftheDataappendix.Toreducemodelruntime,insteadofusingeachMSRasaseparatetechnologyintheSystemPlanningTestModelforNorthAfrica(SPLAT-N),MSRswereclusteredintotendistinctclustersbycountrybasedonk-meansclustering,thusgroupingtogetherMSRswithhighlysimilartemporalprofiles.TheallocationofMSRsacrosseachcountry’stenclustersisprovidedinTableA‑8andTableA‑11.ThedeploymentofVREcapacityacrossthedifferentclustersforeachscenarioisshowninTableA‑9andTableA‑12(IRENA,2022b).ThesetablesdemonstratetheaddedvalueofconsideringdistinctclustersofMSRsforeachcountryinsteadofrepresentingVREasasingle,generictechnology:themodeldeployscapacityinclearlydifferentsetsofclustersacrossthefourscenarios,dependingonwhichspecificcombinationofresourceprofilesresultsinacost-optimaloverallsystem.TheclusteringmethodyieldedasetofdistinctVRE-generationprofiles(withdistinctpossibilitiestocontributetoabalancedelectricitymixanddistinctsynergieswithotherVREplantsandwithdemand)tobeconsideredfortheoptimisationexercise.TheMSRs’capacityfactorprofilesfortheSPLAT-Nmodelwerederivedbyaveragingacrosstimeslicesforeachofthefivemodelledseasons,therebysmoothingoutintra-seasonalandintra-dayvariability,especiallyforwind.Tovalidatetheresults,additionalsimulationsatfullhourlyresolutionwereperformedbasedontheproposedcost-optimalcapacityexpansionscenarios.ThatexercisecorroboratedthepertinenceoftheSPLAT-Nmodelresults(seesection2.9).Figure2‑4showsthetotalsolarandwindpotentialforeachcountryacrossallscreenedMSRsandtherangeoftheircapacityfactors.ThecapacityfactorscalculatedforsolarPVinclude4%outagelossesand4%inverterandalternatingcurrentlossesforsolarPV.Forwind,outagelossesaccountfor2%andarrayandcollectionlossesare15%(IRENAandLBNL,2015).Theidentifiedtotaldeploymentpotential(inmegawatts)andtherangesofcapacityfactors(post-losses)acrossMSRsbycountryarefoundinTableA‑10andTableA‑13(IRENA,2022b).Box2‑2Estimatingvariablerenewableenergygenerationprofiles•44•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFigure2‑2ExamplesofdiurnalprofilesofsolarphotovoltaicpowergenerationforsitesinMauritania(UTC),Algeria(UTC+1)andEgypt(UTC+2)Note:UTC=coordinateduniversaltime.Figure2‑3MonthlyaveragewindprofileofdifferentlocationsinEgyptandMorocco00.10.20.30.40.50.60.70.80.9112345678910111213141516171819202122232425262728293031323334353637383940414243444546NormalisedelectricityoutputHours(UTC)Mauritania(UTC)Egypt(UTC+2)Algeria(UTC+1)0.00.10.20.30.40.50.6JanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecemberNormalisedelectricityoutputIsmaïla,Egypt(30,3672;32,1565)Essaouria,Morocco(31,5118;-9,7621)Box2‑2Estimatingvariablerenewableenergygenerationprofiles(continued)•45•NORTHAFRICAFigure2‑4IdentifiedsolarphotovoltaicandwindmodelsupplyregionsfromresourcescreeninginNorthAfricawith8%and17%accountedlosses,respectivelyNote:Acountry-tailoredtechnicalanalysisforplanningprojectdevelopmentcanbeconductedusingzoninganalysisdevelopedundertheIRENAGlobalAtlasforRenewableEnergy.MW=megawatt;PV=photovoltaic.Disclaimer:Thismapisprovidedforillustrationpurposesonly.BoundariesandnamesshownonthismapdonotimplytheexpressionofanyopiniononthepartofIRENAconcerningthestatusofanyregion,country,territory,cityorareaorofitsauthorities,orconcerningthedelimitationoffrontiersorboundaries.2.4IFINVESTMENTINFOSSILFUELPROJECTSISDISCONTINUED,LEAST-COSTCAPACITYEXPANSIONISDOMINATEDBYSOLARANDWINDPOWERTheresultsofourcapacityexpansionmodellingforthePlanned,Transition,Transition+BatteriesandTransition+Batteries+H2scenariosareillustratedinFigure2‑5.Amorecomprehensivetablecanbefoundinsection1.5oftheDataappendix(IRENA,2022b).InthePlannedscenario,whichmeetscountries’currentrenewableelectricitytargets,agradualincreaseinnaturalgas–firedgeneration,inabsoluteterms,issuggested.Whiletheshareofnaturalgasintotalinstalledcapacitydecreases(from63%in2025to52%in2040)ascountriesmeettheirrenewableelectricitytargets,itstillremainstheprimarycontributortoelectricitygenerationcapacityin2040(95GW)inNorthAfrica.ComparedwiththePlannedscenario,theTransitionscenarioconstrainsinvestmentinfossil-fuel-basedgenerationfrom2025onward.Theresultofthisconstraintisahighershareofintermittentwindgenerationenteringthesystem(atanannualgrowthrateof10%).Additionally,largesharesofCSParealsodeployedBox2‑2Estimatingvariablerenewableenergygenerationprofiles(continued)•46•PLANNINGANDPROSPECTSFORRENEWABLEPOWERtobalancethesystemwithoutnaturalgasgeneration(a35%increaseeachyearbetween2025and2040).Withoututility-scalebatterystorage,however,solarPVdeploymentproceedsmoreslowlythaninthePlannedscenario,giventhelackofflexibilitytobalanceitsdiurnalvariability(aflexibilityprovidedbynaturalgasinthePlannedscenario).Attheendofthemodellinghorizon,renewablesrepresent82%ofthetotalinstalledcapacityinNorthAfricainthisscenario,whileVRErepresents80%ofthetotal.Naturalgasinstalledcapacityfallsby49%between2025and2040.Theintroductionofbatteries(seeBox2‑3)intheTransition+BatteriesscenarioallowsahigherpenetrationofsolarPVthatpartlyreplacesCSP,asbatteriesarehighlysuitedtoreducetheday-nightvariabilityofsolarPVoutput.In2040,31GWofsolarPVareinstalledinNorthAfrica,26%abovethe24GWdeployedintheTransitionscenariowithoutbatteries.WindpowercapacitydoesnotchangeasmuchassolarPV,aswindpowergenerationbenefitslessfrombatterystoragethansolarPVbecauseitsvariabilitiesaretypicallyexhibitedontimescalesotherthanday-night.Overall,theTransition+Batteriesscenarioischaracterisedbyalowertotalinstalledcapacityin2040(270GWcomparedwith286GWintheTransitionscenario)sincebatteriespermitamoreoptimaluseoftheinstalledtechnologieswithlowercurtailment(thecurtailmentratefallsto16%from25%intheTransitionscenario).VREcomestorepresent79%ofthetotalinstalledcapacityin2040.TheTransition+Batteries+H2scenariocontainsthesameassumptionsastheTransition+Batteriesscenariobutallowsforthedevelopmentofelectrolysercapacitytoproducegreenhydrogenfromrenewableelectricity.Thisnewfeatureleadstoasurgeofthetotalinstalledcapacityoverthemodellinghorizon,reaching597GWin2040,twiceasmuchasintheTransition+Batteriesscenario(270GW).Thisisaconsequenceofthesignificantgrowthofrenewablepowercapacityinstalledby2040expresslytoproducehydrogen.Theadditionalcapacityis212GWforwindand120GWforsolarPVovertheTransition+Batteriesscenario.Ontheotherhand,theinstalledcapacityofCSPisreducedinthisscenariocomparedwiththeTransition+Batteriesscenario(by6GW)becausehydrogenproductionprovidestheflexibilityneededtointegratemorewindandsolarPVintotheenergymix.Intotal,VRErepresents91%oftotalinstalledcapacityin2040intheTransition+Batteries+H2scenario.InallthreeTransitionscenarios,biomassisusedtoitsmaximumpotentialinMoroccoasdefinedintheMoroccoNationalPlan(960MW)(Ministèredel’Energie,desMinesetdel’EnvironnementduMaroc,2021d).Theestimatedpotentialforothercountriesisverysmall.Theoptiontoinvestinadditionalcross-bordertransmissioncapacityintheTransitionscenariosallowsforamoreoptimaldeploymentofsolarandwindpowerplants,favouringtheirpreferentialbuildoutinlocationswiththehighestcapacityfactorsandthegreatestsynergieswithintheregion,notjustwithinindividualcountries.Thegeneratedelectricityisthenmoreeasilydistributedthroughgreaterinterconnectioncapacity,makingitpossibletomeetthesamerenewableobjectiveswithlessinstalledcapacity.•47•NORTHAFRICA01002003004005006007002025203020352040202520302035204020252030203520402025203020352040PlannedTransitionTransition+BatteriesTransition+Batteries+H2Installedcapacity(GW)CoalLargeHydroDamSolarPV-UtilityHFOLargeHydroRORWindDieselSmallHydroBiomassNaturalGasGeothermalNuclearSolarThermalPresently,pumpedhydroistheonlystorageoptionusedintheregion.One350-MWpumpedhydropowerplantisinserviceinMorocco;asecond415-MWplantisunderconstruction.Bothplantsareconsideredinthemodel.Duetoalackofdata,nofuturepossibilitiesforadditionalpumpedhydropowerplantswereconsidered.However,furtherpossibilitiesfor(closed-loop)pumpedhydropowerarelikelytoexist,particularlyinMorocco’sAtlasMountains.ThreeotherstorageoptionsareconsideredinthetechnologiesmodelledforNorthAfrica:solarthermalstorage,batteriesandhydrogenproductionforexport.Solarthermalisassignedafixedgenerationprofileinthemodel.Itgenerateswhilesolarradiationisavailableduringthedayandcontinuestogenerateaftersunsettosupplyelectricityduringtheeveningpeak.Inthismodel,weassumeathree-hourstoragecapacityforconcentratedsolarpowerplants.Batteriesareconsideredanoptioninallcountriesstartingfrom2025.Weassumesix-hourstoragebatteries.TheNationalRenewableEnergyLaboratory’smid-scenariocostprojectionsandtechnicalparametersareused,assuminga15-yearlifetimeandan85%efficiencyofthecharging/dischargingcycle(NREL,2021).Batteriesareconsideredtooperateforday-nightbalancing–thatis,themodeldoesnotallowthemtooperateforseasonalstorage.AssumedcapitalexpenditureandoperationalexpendituretrajectoriesofbatterystoragearegiveninTableA‑18intheDataappendix(IRENA,2022b).Inthemodel,allhydrogenproductionisassumedtobefromrenewableelectricity.Thatassumptionisoperationalisedbyimposingaconstraintthathydrogenmustbeproducedwithoutanyincreaseincarbondioxideemissionsoverscenariosinwhichhydrogendoesnotfigure.Hydrogenproductionisconsideredanoptionfrom2025inthecountrieswhereprojectsorpartnershipshavebeenannounced(i.e.Algeria,Egypt,Mauritania,MoroccoandTunisia).Plantsareconsideredbythreevintageyears(2025,2030and2035),withinvestmentcostsdecreasingandefficiencyincreasingovertime.ElectrolysercostassumptionsarepresentedinTableA‑19.Allhydrogenproducedisassumedtobeallocatedforexportatapricethatisassumedexogenously(seeTableA‑20inIRENA,2022b).Figure2‑5CapacityexpansioninNorthAfricabytechnologyinthefourscenariosNote:GW=gigawatt;H2=hydrogen;HFO=heavyfueloil;PV=photovoltaic;ROR=run-of-river.Box2-3Representationofstorageinthemodel•48•PLANNINGANDPROSPECTSFORRENEWABLEPOWERThemodeloptimisesthequantityofhydrogentobeproduced,usingexportpricesastheoptimisationmechanism.ExportpricesaregiveninTableA‑20(IRENA,2022b)andarebasedonIRENA’sprojections(IRENA,2020b).Inaddition,weestimatethehydrogenquantitythatcouldbeproducedatdifferentexportprices.Themodelalsooptimisesthedispatchofelectricitytomeeteitherelectricitydemandortoproducehydrogenforexportaccordingtotheopportunitycostofthelatter.Inthisstudy,hydrogenmustbeproducedatacostlessthanorequaltoUSD2/kilogramme(kg),asthisisconsideredtobethecostatwhichhydrogencanbecomeaviablealternativetoconventionalfuels(Edwardes-Evans,2020).Thiscostdoesnotincludetransportbypipeline,estimatedatEUR0.11-0.21/kg(EHB,2021).PipelinetransportispossiblebetweenNorthAfricaandEurope,wherehydrogendemandisprojectedtoreacharound10megatonnes(Mt)in2030,40Mtin2040and70Mtin2050(EHB,2021).Thesetransportcostsarenotconsideredinthisstudy.TheresultsintermsofelectricitygenerationarepresentedinFigure2‑6andFigure2‑7.MoredetaileddatacanbefoundinTable2‑3(country-levelbreakdown)aswellassection1.5oftheDataappendix(IRENA,2022b).InthePlannedscenario,theshareofrenewableenergyremainsatroughlythesameleveloverthemodellingperiod(from33%in2025to37%in2040,correspondingto135terawatthours(TWh)and236TWh,respectively).TheproportionofVREincreasesfrom30%to34%oftotalgenerationoverthe20-yearplanninghorizon,risingfrom120TWhto223TWh.Thesmallincreaseintheshareofrenewablesisduetoincreaseddemandandthemodelconstraintofkeepingtherenewablestargetatthesamelevelinthepost-2030period.Incontrast,theshareofrenewablesintotalgenerationincreasessharplyintheTransitionscenario,from41%in2025to87%in2040.Inthisscenario,inwhichfossilfuelinvestmentsaredisallowedafter2025,thermalgenerationdecreasesbothinabsolutetermsandinproportiontototalgeneration,withanetreductionof68%between2025and2040(fallingfrom218TWhin2025to69TWhin2040).Thisreductionisoffsetbyrenewablegeneration(chieflywind),whichgrowsfrom30%to58%oftotalgeneration(134TWhto479TWh).WhenaddingbatterystoragetotheTransitionscenario,electricitygenerationfromsolarPVbecomesmorerelevantandreplacessomegenerationfromwindandCSP,whilegenerationfromotherenergysourcesremainssimilar.In2040,solarPVgenerationisindeed35%higherintheTransition+Batteriesscenario(47TWh),whereitrepresents6%oftotalpowergeneration,thanintheTransitionscenario(35TWh),whereitaccountsforonly4%ofthetotal.EnablinghydrogenproductioninNorthAfricaleadstoasurgeinrenewablegeneration,whichreaches1773TWhin2040(comparedwitharound700TWhinboththeTransitionandTransition+Batteriesscenarios).Thisadditionalgeneration(morethan1000TWh)isusedtoproducerenewablehydrogenforexport(sinceelectricitydemandinNorthAfricadoesnotchangeacrossthethreeTransitionscenarios).Inthisscenario,theshareofrenewablesintotalgenerationreaches94%attheendofthemodellinghorizon,thehighestlevelofallscenarios.Thegreaterpowerdemandcreatedbytheproductionofhydrogenforexportallowsformoreintegrationofrenewableenergy,withhydrogenservingasasystemflexibilityoption.Solarthermalalsohelpstodealwithapartofthevariability.Box2-3Representationofstorageinthemodel(continued)•49•NORTHAFRICA0500100015002000Transition+Batteries+H2Generation(TWh)2025203020352040202520302035204020252030203520402025203020352040PlannedTransitionTransition+BatteriesNuclearSolarPV-UtilityCoalLargeHydroDamWindHFOLargeHydroRORBiomassDieselGeothermalNaturalGasSolarThermalFigure2‑6ProjectionofgenerationinNorthAfricainthefourscenarios,bytechnologyNote:H2=hydrogen;PV=photovoltaic;ROR=run-of-river;TWh=terawatthour.Figure2‑7ShareofenergysourcesinelectricitygenerationinNorthAfricainthefourscenarios,bytechnologyNote:H2=hydrogen;HFO=heavyfueloil;PV=photovoltaic;ROR=run-of-river.0%10%20%30%40%50%60%70%80%90%100%Transition+Batteries+H22025203020352040202520302035204020252030203520402025203020352040PlannedTransitionTransition+BatteriesNuclearSolarPV-UtilityCoalLargeHydroDamWindHFOLargeHydroRORBiomassDieselGeothermalNaturalGasSolarThermal•50•PLANNINGANDPROSPECTSFORRENEWABLEPOWERTable2‑6Country-levelbreakdownofthepowergenerationmixby2040,byscenarioGENERATIONMIXIN2040(%)COALHFODIESELNATURALGASNUCLEARHYDRORESERVOIRHYDRORORGEOTHERMALSOLARPVCSPWINDBIOMASSPlannedscenarioAlgeria0%0%0%74%0%0%0%0%15%0%11%0%Egypt0%0%0%45%11%3%1%0%8%0%32%0%Libya0%4%1%86%0%0%0%0%4%0%6%0%Mauritania0%0%0%53%0%0%0%0%11%0%35%0%Morocco20%0%0%15%0%4%0%0%13%4%44%0%Tunisia0%0%0%72%0%0%0%0%14%0%15%0%TransitionscenarioAlgeria0%0%0%9%0%0%0%0%2%29%59%0%Egypt0%0%0%10%8%2%0%0%5%18%58%0%Libya0%1%1%1%0%0%0%0%6%34%56%0%Mauritania0%0%0%4%0%0%0%0%1%31%64%0%Morocco9%0%0%0%0%3%0%0%6%22%51%9%Tunisia0%0%0%10%0%0%0%0%6%23%61%0%Transition+BatteriesscenarioAlgeria0%0%0%9%0%0%0%0%4%25%62%0%Egypt0%0%0%10%9%2%0%0%6%14%58%0%Libya0%1%1%2%0%0%0%0%9%28%59%0%Mauritania0%0%0%4%0%0%0%0%7%31%57%0%Morocco8%0%0%0%0%2%0%0%6%20%56%8%Tunisia0%0%0%10%0%0%0%0%6%22%62%0%Transition+Batteries+H2scenarioAlgeria0%0%0%5%0%0%0%0%17%10%67%0%Egypt0%0%0%7%6%1%0%0%10%9%67%0%Libya0%1%1%1%0%0%0%0%9%28%60%0%Mauritania0%0%0%0%0%0%0%0%20%1%78%0%Morocco1%0%0%0%0%0%0%0%13%4%80%2%Tunisia0%0%0%1%0%0%0%0%18%3%77%0%Note:CSP=concentratedsolarpower;H2=hydrogen;HFO=heavyfueloil;PV=photovoltaic;ROR=run-of-river.•51•NORTHAFRICA2.5BATTERYSTORAGEANDHYDROGENPRODUCTIONARECONDUCIVETOGREATERINTEGRATIONOFSOLARPV,BUTTHEYLOWERTHENEEDFORCSPNewsolarcapacity(solarPVandCSP)installedinNorthAfricabetween2020and2040increasesunderallscenarios(Figure2‑8andFigure2‑9).Inallcases,AlgeriaandEgypt,whichhavethelargestpowersystemsintheregion,arethecountriesthatinstallthemostnewsolarPVandCSPcapacity.IntheTransition+Batteries+H2scenario,however,Mauritania,TunisiaandMoroccoalsodeploysubstantialsolarPVcapacitytoproducegreenhydrogen.Inthiscase,totalsolarPVinstalledcapacityreaches151GWin2040inNorthAfrica.Asmentionedintheprevioussection,theintroductionofbatterystorageenablesgreaterdevelopmentofsolarPV(Figure2‑8),comparedwiththeTransitionscenario.In2040,31GWofsolarPVcapacityisinstalledinNorthAfricaintheTransition+Batteriesscenario,comparedwith36GWand24GWinthePlannedandTransitionscenarios,respectively,neitherofwhichincludetheoptionofbatterystorage.TheslightlyhighertotalinstalledcapacityofsolarPVinthePlannedscenariocomparedwiththeTransitionscenarioisduetothepresenceofCSPintheTransitionscenarios,withCSP’sstoragecapabilityprovidingapartoftheneededreservemargin.IntheTransitionscenario,solarPVcapacitystagnatesafter2030,leavingroomforCSP.TheTransition+Batteries+H2scenarioisbyfartheonethatimpliesthegreatestdevelopmentofsolarPV,with151GWinstalledby2040.ThismeansthathydrogenproductionallowsabetterintegrationofsolarPV,sincepowernotusedtomeetdemandisconvertedintohydrogen.WithregardtonewCSPinstalledcapacity,only1GWisexpectedtobedevelopedunderthePlannedscenarioinNorthAfricaby2040(Figure2‑9).IncontrasttothePlannedscenario,theabsenceofnewfossilfuelpowerplantsafter2025intheTransitionscenarioproducesaneedformoredispatchablepowergeneration,whichcanbeprovidedbyCSPwiththermalstorage,sincethistechnologycanprovideelectricityduringtheeveningpeakload.Theresultistheinstallationof75GWofCSPcapacityby2040,wellabovethe24GWsolarPVcapacity.Whenbatterystorageisenabled,CSPcapacitiesarestillinstalledbutataslowerpace,resultingin62GWand55GWofCSPcapacityintheTransition+BatteriesandTransition+Batteries+H2scenarios,respectively.Inthethreetransitionscenarios,AlgeriaandEgyptrepresentmorethan80%oftheregion’sCSPinstalledcapacityin2040.InthePlannedscenario,firmcapacityisprovidedbyfossilfuelpowerplants.IntheTransitionscenario,itisprovidedbyCSP,andthereforeCSPtakestheplaceofsomePV.Whenbatteriesareconsideredasanoption,theycontributetofirmcapacityby“firmingup”solarPV,thusobviatingsomeoftheneedfordispatchableCSPcapacity.•52•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFigure2‑8NewinstalledsolarphotovoltaiccapacitybycountryinthefourscenariosNote:GW=gigawatt;H2=hydrogen.Figure2‑9NewinstalledconcentratedsolarpowercapacitybycountryinthefourscenariosNote:GW=gigawatt;H2=hydrogen.0510152025303540455020202025203020352040Installedcapacity(GW)PlannedAlgeriaEgyptLibyaMauritaniaMoroccoTunisia0510152025303540455020202025203020352040Installedcapacity(GW)Transition0510152025303540455020202025203020352040Installedcapacity(GW)Transition+Batteries02040608010012014016018020202025203020352040Installedcapacity(GW)Transition+Batteries+H2AlgeriaEgyptLibyaMauritaniaMoroccoTunisia01020304050607080Planned20202025203020352040Installedcapacity(GW)01020304050607080Transition20202025203020352040Installedcapacity(GW)01020304050607080Transition+Batteries20202025203020352040Installedcapacity(GW)01020304050607080Transition+Batteries+H220202025203020352040Installedcapacity(GW)•53•NORTHAFRICA2.6WINDPOWERISANATTRACTIVEINVESTMENTINALLNORTHAFRICANCOUNTRIES,ESPECIALLYINCOMBINATIONWITHHYDROGENPRODUCTIONThenewwindcapacityinstalledbyeachNorthAfricancountrybetween2020and2040ispresentedinFigure2‑10.Detailednumberscanbefoundinsection3.7.ThePlannedscenarioleadstothelowestdevelopmentofwindcapacity.By2040,underthatscenario,atotalofjust35GWwindcapacityisinstalledintheregion,morethanhalfofitinEgypt(21GW).WindcapacityissignificantlyincreasedintheTransitionscenario,reaching130GWwindby2040.AsinthePlannedscenario,halfofthiscapacityisinstalledinEgypt(65GW).Inthisscenario,curtailmentofwindenergyisobservedatdifferenttimesoftheyear.Theeffectivecapacityfactorofwindpowerplantsintheregionin2040–thatis,theenergyproducedandsentouttothegrid–fallsfrom50.5%inthePlannedscenarioto42%intheTransitionscenario.TheTransition+BatteriesscenarioischaracterisedbyaslightlylowerinstalledwindcapacitythanintheTransitionscenario(121GW,or9GWlessthantheTransitionscenario).ThisisexplainedbythehigherdevelopmentofsolarPVinstalledcapacityaswellastheintroductionofbatteries,whichreducecurtailmentbystoringelectricity.Theeffectivecapacityfactorofwindpowerplantsintheregionin2040risesinthisscenariocomparedwiththeTransitionscenario(wherebatteriesarenotavailable)from42%to45.5%.Asmentionedpreviously,theintroductionofhydrogenproductionforexportleadstoaboominrenewableenergycapacity,includingwindenergy.By2040,334GWofwindcapacityisinstalledintheregion,almostthreetimesmorethanintheTransition+Batteriesscenario.ThecountryleadingthisdeploymentisstillFigure2‑10NewinstalledwindcapacitybycountryinthefourscenariosNote:GW=gigawatt;H2=hydrogen.AlgeriaEgyptLibyaMauritaniaMoroccoTunisia020406080100120140Planned20202025203020352040Installedcapacity(GW)020406080100120140Transition20202025203020352040Installedcapacity(GW)020406080100120140Transition+Batteries20202025203020352040Installedcapacity(GW)050100150200250300350400Transition+Batteries+H220202025203020352040Installedcapacity(GW)•54•PLANNINGANDPROSPECTSFORRENEWABLEPOWEREgypt,withawindcapacityof100GWin2040,butitsshareintotalwindcapacityislowerthanintheotherscenarios,becauseMorocco,AlgeriaandTunisiaalsoboosttheirwindcapacitytoproducerenewablehydrogen(reaching77GW,69GWand58GW,respectively).Inthisscenario,lesswindiscurtailedthantheTransition+Batteriesscenario;theeffectivecapacityfactorofwindreaches46%,comparedwith45.5%intheTransition+Batteriesscenario.ThepaceatwhichwindcapacityisdeployedinNorthAfricadiffersacrossthescenarios.WhileadditionstowindcapacitystagnateinthePlannedscenarioafter2030,oncenationaltargetsarereached,theTransition+Batteries+H2scenariomaintainsasteadypace,withadditionalcapacityexpandinguntiltheendofthemodellingperiod.Theaverageannualgrowthrateofwindcapacityduringtheperiod2030-2040isclosetozerointhePlannedscenario,5.5%intheTransitionscenario,4.3%intheTransition+Batteriesscenarioand14.1%intheTransition+Batteries+H2scenario.2.7BATTERYSTORAGEANDHYDROGENPRODUCTIONLOWERTHENEEDFORADDITIONALCROSS-BORDERINTERCONNECTIVITYUnderallscenarios,thepowerexchangesofNorthAfricancountries(withintheregionaswellaswithcountriesoutsidetheregion)aresignificantlygreaterin2040thanin2018,whentwo-thirdsofthe5.5TWhofgrossexchangestookplacethroughtheMorocco-Spaininterconnection.AsshowninTable2‑8,the2040volumeofpowertradebetweenthecountriesoftheregionandoutsidetheregionswellsfrom23.6TWhinthePlannedscenario(ofwhich7.1TWhiswithintheregion)to69.5TWhintheTransitionscenario(ofwhich32.3TWhwithintheregion),55.5TWhintheTransition+Batteriesscenario(ofwhich25.5TWhwithintheregion)and42.6TWhintheTransition+Batteries+H2Scenarioin2040(ofwhich21.3TWhwithintheregion).Theexchangepriceassumptionswithintheregionandwiththeneighbouringregions,showninFigure2‑11,arebasedonthehistoricalhourlypricesinSpainandItalyaspublished(GME,2021;OMIE,2021).HourlypricesarenotavailableoninterconnectionsbetweenEgyptandJordan,orbetweenEgypt/SudanandEgypt/SaudiArabia.Forthoseinterconnectionsweassignaconstantpricefortheyearbasedonthe2019priceontheEgypt-Jordaninterconnection(NEPCO,2019).ThevolumeofelectricitytradedbyNorthAfricancountriesin2040islowestinthePlannedscenario,withatotalof23.7TWhexchanged,mostofittradedwithcountriesoutsideNorthAfrica(SpainandItaly).Thisstillcorrespondstoafivefoldincreaseintradebetween2018and2040.Thepresentconstraintonexchangebetweenthecountriesoftheregionisthelackoftrademechanismsandthesettingsputontheselines,eventhoughthephysicalcapacitiesoftheinterconnectionlinesaresufficienttoallowmoreexchange.InterconnectionsplayasignificantlyhigherroleintheTransitionscenario.ThetotaltradeflowisthreetimesthatinthePlannedscenario(69.5TWh),andhalfofthisbeingintra-regionalpowertrade.Clearly,itiscost-effectiveforcountriestoexploitthespatio-temporalcomplementaritiesofVREbyexpandingcross-bordertransmissioncapacityratherthanallowingeachcountrytorelyingsolelyontheVREresourceswithinitsownborders.Thesecomplementaritiesplayoutatmultiplescales(acrosstheday-nightcycle,acrossseasons,andacrosstimezones);detailsareprovidedinsection3.3.WhenintroducingbatteriestothisTransitionscenario,theneedforpowerexchangesisreduced(to55.5TWh),asbatteriesprovideanalternativeflexibilitymeasure.Iftheregionbeginstoproducehydrogen,thetotaltradedvolumedecreasesfurther(to42.6TWh).TheopportunityofusingelectricitytoproducehydrogenandexportitatanassumedpriceofUSD2/kilogrammeofhydrogen(kgH2)(seeBox2‑3)becomesmorecost-effectiveinthisscenariothanexportingelectricity.ThetotaltradeflowsofelectricitybetweencountriesunderthefourscenariosarerepresentedinFigure2‑12.Figure2‑13showsthegrossexportsandimportsforeachcountryintheresultsofthefourscenarios.•55•NORTHAFRICA0204060801001201401601802001Januaryto20March21Marchto16June17Juneto07September08Septemberto07November08Novemberto31DecemberElectricityprice(USD/MWh)ElectricitypricesinItalyElectricitypricesinSpainElectricitypricesinJordan/SaudiArabiaandSudan13579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Figure2‑11Modelassumptions(constraints)onexchangepricesbetweenNorthAfricancountriesandneighbouringregionsFigure2‑12Totalelectricitytradeflowsin2040inthefourscenariosNote:MWh=megawatthour;NAPP=NorthAfricanPowerPool.Note:TWh=terawatthour.01020304050607080HistoricalPlannedTransitionTransition+batteriesTransition+batteries+H220182040projectionsGeneration(TWh)WithcountriesoutsideNorthAfricaBetweenNorthAfricancountries•56•PLANNINGANDPROSPECTSFORRENEWABLEPOWERExportImport-30-25-20-15-10-505101520MoroccoAlgeriaTunisiaLibyaEgyptTWhPlannedTransitionTransition+BatteriesTransition+Batteries+H2PlannedTransitionTransition+BatteriesTransition+Batteries+H2PlannedTransitionTransition+BatteriesTransition+Batteries+H2PlannedTransitionTransition+BatteriesTransition+Batteries+H2PlannedTransitionTransition+BatteriesTransition+Batteries+H220182018201820182018204020402040204020403.4414.296.610.25-4.22-0.09-0.22-11.65-7.748.200.17-0.76-0.750.1-0.810.122.214.335.695.77-0.34-0.42-27.68-15.74-11.23Toassesstheimpactofexportpricesontheresults,werunasensitivitytestconsideringvariouspricesofexportsfromEgypttoJordan,SaudiArabiaandSudan.Table2‑7showstheresults.LowerexportpricesdonotleadtoadecreaseinexportsintheTransitionscenarioowingtotheavailabilityofelectricitygenerationthatwouldotherwisebecurtailed.Whenbatteriesareconsideredasanoption(theTransition+Batteriesscenario),lowerexportpricesleadtomorebatteriesbeinginstalledinEgyptandlesselectricitybeingexportedoutsidetheregion;atthesametime,slightlymoreelectricityisexportedwithintheregion(toLibya).Whenhydrogenisadded(theTransition+Batteries+H2scenario),lowerpricesofexportsoutsidetheregionleadtoafurtherreductionofexportsandslightlymorebatteriesbeinginstalled.Figure2‑13GrossexportsandimportsofelectricityinNorthAfricancountriesinthefourscenarios,2018and2040Note:H2=hydrogen;GWh=gigawatthour.•57•NORTHAFRICATable2‑7SensitivityofscenarioresultstopricesofexportsfromEgypttooutsideNorthAfricaPRICEOFEXPORTSFROMEGYPTTOCOUNTRIESOUTSIDETHEREGIONINUSD/MWH7567.56037.515ExportsfromEgypttooutsidetheregionin2040(GWh)Plannedscenario00000Transitionscenario2373923672231282263421527Transition+Batteriesscenario1483212544909721691099Transition+Batteries+H2scenario81565355510600BatterystoragecapacityinEgyptby2040(MW)Plannedscenario00000Transitionscenario00000Transition+Batteriesscenario6681733984281063410471Transition+Batteries+H2scenario769678678040971410122ExportsfromEgypttoLibyain2040(GWh)Plannedscenario415415415415415Transitionscenario65986796860084818795Transition+Batteriesscenario45395057585168618286Transition+Batteries+H2scenario39723991387340123945Note:GWh=gigawatthour;MW=megawatt;MWh=megawatthour.Lookingatthedailyandseasonalprofilesofexportsandimportsbetweenthecountriesprovidesabetterunderstandingoftheobservedtradeflows.IntheresultsofthePlannedscenario,MoroccoimportsatanearlyconstantcapacityfromSpainandAlgeria(Figure2‑14andFigure2‑15).AlgeriaimportsfromTunisiaduringallseasonsandallhoursoftheday,exceptduringtheeveningpeakloadinTunisia,whenTunisiaisimportingfromAlgeria(Figure2‑16).TunisiaexportstoLibyaaswell,especiallyduringthesummerseason(Figure2‑17).Furthermore,theflowontheinterconnectionlinebetweenTunisiaandItalyisusedmoreintenselyfromItalytoTunisiathanintheotherdirection.ThisisduetothelowelectricitypricesduringtheoffloadperiodsinItaly(duringthenight)andlowpricesduringItaly’ssolarpoweravailability(Figure2‑18).Inthisscenario,theelectricityexchangebetweenLibyaandEgyptturnsouttobecharacterisedbyaflowfromthelattertotheformerinsummerandequilibriuminotherseasons(Figure2‑19).Finally,inthisscenario,thereisnoelectricitytradebetweenEgyptandJordan/Sudanbecauseofthepriceassumptionsconsidered.Theflowpatternsin2040aredifferentintheTransitionscenario,whereahigherlevelofrenewableenergyisdeployed.ExportsfromSpaintoMoroccoremainimportant,balancedbyexportsfromMoroccotoSpainduringperiodsofexcesssolarpowergeneration.Additionally,MoroccosimultaneouslyimportselectricityfromAlgeriathatisaddedtoexportstoSpain(Moroccobecomingthetransitcountry).ThisisshowninFigure2‑20,whichillustratestheaveragedailyprofileofexportsfromAlgeriatoMoroccoandfromMoroccotoSpain.Asimilarpatternisseeninallinterconnectedcountriesoftheregion,withinterconnectionbalancingthesurplusofgenerationofsolarenergy.Thisleadstobalancedexchangesofelectricityinbothdirectionsonmostinterconnectionlines(bidirectional,ratherthanunidirectional,tradepatterns).ThepatternsofflowsintheTransition+BatteriesscenarioaresimilartothoseseenintheTransitionscenario.•58•PLANNINGANDPROSPECTSFORRENEWABLEPOWER-4000-3000-2000-100001000200030004000Morocco’simportsfromAlgeriaMorocco’sexportstoAlgeria13579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Morocco’simportsfromSpainMorocco’sexportstoSpain-1500-1000-50005001000150013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Alltradeflowsin2040arepresentedinthediagramsinFigure2‑23.Thegeneralpresenceofbidirectionalitymaymitigatethedangerofcountriesbecomingoverlydependentontheirneighbours’electricitygeneration.Further,theintroductionofutility-scalestorageandofhydrogenproductiontechnologyreducestheoverallrecoursetoexchanges(Table2‑8),furtherreducingpotentialworriesabouthighdependencyonelectricityimports.Figure2‑14Morocco’simportsfromSpaininthePlannedscenario,2040Figure2‑15Morocco’simportsfromAlgeriainthePlannedscenario,2040Note:MW=megawatt.Note:MW=megawatt.•59•NORTHAFRICAFigure2‑16Tunisia’simportsfromAlgeriainthePlannedscenario,2040Figure2‑17Tunisia’simportsfromLibyainthePlannedscenario,2040Note:MW=megawatt.Note:MW=megawatt.Tunisia’simportsfromAlgeriaTunisia’sexportstoAlgeria-1500-1000-50005001000150013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Tunisia’simportsfromLibyaTunisia’sexportstoLibya-1500-1000-50005001000150013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)•60•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFigure2‑18Tunisia’simportsfromItalyinthePlannedscenario,2040Figure2‑19Egypt’simportsfromLibyainthePlannedscenario,2040Note:MW=megawatt.Note:MW=megawatt.Tunisia’simportsfromItalyTunisia’sexportstoItaly-1500-1000-50005001000150013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Egypt’simportsfromLibyaEgypt’sexportstoLibya-1500-1000-50005001000150013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)•61•NORTHAFRICAFigure2‑20DailyprofilesofexportsintheTransitionscenario,2040Note:MW=megawatt.Morocco’simportsfromSpainMorocco’sexportstoSpain-2000-1500-1000-50005001.0001500200013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Morocco’simportsfromSpain-TransitionScenarioMorocco’simportsfromAlgeriaMorocco’sexportstoAlgeria-4000-3000-2000-10000100020003000400013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Morocco’simportsfromAlgeria-TransitionScenarioTunisia’simportsfromItalyTunisia’sexportstoItaly-1000-800-600-400-2000200400600800100013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Tunisia’simportsfromItaly-TransitionScenario•62•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFigure2‑21DailyprofilesofexchangesintheTransition+Batteriesscenario,2040Note:MW=megawatt.Morocco’simportsfromSpainMorocco’sexportstoSpain-2000-1500-1000-500050010001500200013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Morocco’simportsfromSpain-Transition+BatteriesScenarioMorocco’simportsfromAlgeriaMorocco’sexportstoAlgeria-4000-3000-2000-10000100020003000400013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Morocco’simportsfromAlgeria-Transition+BatteriesScenarioTunisia’simportsfromItalyTunisia’sexportstoItaly-1000-800-600-400-2000200400600800100013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Tunisia’simportsfromItaly-Transition+BatteriesScenario•63•NORTHAFRICAFigure2‑22DailyprofilesofexchangesintheTransition+Batteries+H2scenario,2040Note:H2=hydrogen;MW=megawatt.Morocco’simportsfromSpainMorocco’sexportstoSpain-2000-1500-1000-500050010001500200013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Morocco’simportsfromSpain-Transition+Batteries+H2ScenarioMorocco’simportsfromAlgeriaMorocco’sexportstoAlgeria-2000-1500-1000-500050010001500200013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Morocco’simportsfromAlgeria-Transition+Batteries+H2ScenarioTunisia’simportsfromItalyTunisia’sexportstoItaly-2000-1500-1000-500050010001500200013579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)Electricityimports(MW)Tunisia’simportsfromItaly-Transition+Batteries+H2Scenario•64•PLANNINGANDPROSPECTSFORRENEWABLEPOWERTable2‑8ShareofpowerexchangesintotalelectricitydemandinNorthAfricaYEARSCENARIOTOTALSENT-OUTELECTRICITY(TWH)POWEREXCHANGES(TWH)SHAREOFPOWEREXCHANGESINTOTALPOWERDEMAND2018Historical36361.5%2040Plannedscenario662243.6%Transitionscenario795698.7%Transition+Batteriesscenario795567.0%Transition+Batteries+H2scenario795435.4%Note:H2=hydrogen;NA=NorthAfrica;TWh=terawatthour.Figure2‑23ElectricityexchangesinNorthAfricainthefourscenarios,2040(GWh)122640235332820412350179841503496649000000367859171105622066413437267030596598266179139520320619910018542SpainAlgeriaTunisiaLibyaItalyJordanKSASpainItalyJordanAlgeriaTunisiaLibyaSudanKSASudanPlannedscenario2040–ExchangesinGWhTransitionscenario2040–ExchangesinGWhTransition+Batteriesscenario2040–ExchangesinGWhMoroccoEgyptMoroccoEgypt122640235332820412350179841503496649000000367859171105622066413437267030596598266179139520320619910018542SpainAlgeriaTunisiaLibyaItalyJordanKSASpainItalyJordanAlgeriaTunisiaLibyaSudanKSASpainItalyJordanSudanPlannedscenario2040–ExchangesinGWhTransitionscenario2040–ExchangesinGWhTransition+Batteriesscenario2040–ExchangesinGWhMoroccoEgyptMoroccoEgypt•65•NORTHAFRICA2.8THENEEDFORBATTERYSTORAGEINCREASESWITHTHESHAREOFVARIABLERENEWABLESINTHEENERGYMIXBatterystorageisconsideredanoptionforallcountriesstartingfrom2025intheTransition+BatteriesandTransition+Batteries+H2scenarios(seeBox2‑3).Inthefirst,thedeploymentofbatteriesbeginsin2027.Inthesecond,theirdeploymentstartsin2032.Theimpactofhydrogenproductiononbatterydeploymentdependsoneachcountry’sVREgenerationprofile,demandprofileandtheshareofsolar/windinstalled.ThetopcountriesforbatterystorageintheTransition+BatteriesscenarioareEgyptandAlgeria.In2040theyhave6.7GWand4.6GWofinstalledbatterystorage,respectively.IntheTransition+Batteries+H2scenario,installedcapacitydoublesinAlgeriawhereasitstaysatthesamelevelinothercountries.IntheTransition+Batteries+H2scenario,theinstalledcapacityreaches7.7GWinEgyptand10.1GWinAlgeria(Figure2‑24).Figure2‑23ElectricityexchangesinNorthAfricainthefourscenarios,2040(GWh)(continued)Note:GWh=gigawatthour;H2=hydrogen;KSA=KingdomofSaudiArabia.19028766810729831165134070317358145392112188520784171939117722088111715615520671252956267778374034413972903333415520994640006522SudanSpainAlgeriaTunisiaLibyaItalyJordanSudanKSASpainAlgeriaTunisiaLibyaItalyJordanSudanKSATransition+Batteriesscenario2040–ExchangesinGWhTransition+Batteries+H2scenario2040–ExchangesinGWhMoroccoEgyptMoroccoEgypt28766810729831165134070317358145392112188520784171939117722088111715615520671252956267778374034413972903333415520994640006522SudanSpainAlgeriaTunisiaLibyaItalyJordanSudanKSASpainAlgeriaTunisiaLibyaItalyJordanSudanKSATransition+Batteriesscenario2040–ExchangesinGWhTransition+Batteries+H2scenario2040–ExchangesinGWhMoroccoEgyptMoroccoEgypt•66•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFigure2‑25showsthedailybatteryuseprofileoftheregion’scountriesbyseason.Inallcountrieswherethistechnologyisselectedbythemodel,batteriesaregenerallychargedwhensolarpowerisabundantlyavailableanddischargedduringtheeveningpeakandatnight.InAlgeria,EgyptandLibya,thebatteryuseprofiledoesnotchangewhenhydrogenproductionisadded.InTunisia,theintroductionofhydrogenremovestheneedforbatteries,andnoneareinstalledintheTransition+Batteries+H2scenario.ThelowercapacityneededinTunisiamaybeexplainedbytheinterconnectionwithlargerpowersystems(AlgeriaandItaly).LikeTunisiaintheTransition+Batteries+H2scenarioandunliketheothercountries,MoroccoinstallsnobatteriesintheTransition+Batteriesscenario.ThiscanbeexplainedbyitslowcurtailmentrateintheTransitionscenario–10%ofavailablerenewableenergyiscurtailedin2040comparedwiththeregionalaverageof25%.IntheTransition+Batteriesscenario,morewindcapacityisinstalledinMoroccobutnoadditionalsolarPVovertheTransitionscenario.Curtailmentreaches13.6%in2040intheTransition+Batteriesscenario.Figure2‑26showsthedailyuseprofileofpumpedhydroinMorocco(whichcorrespondstotheAfourerandAbdelmoumenpowerplants).TheavailabilityofthisoptioninMoroccohelpsexplainthecountry’slowcurtailment.NotableistheloweruseofpumpedhydrointheTransition+Batteriesscenario(althoughnobatteriesareinstalledinMorocco)ascomparedtotheprecedingscenarios.ThiscanbeexplainedbythebatteriesinstalledinneighbouringAlgeriatostoresolarenergyproducedthere,whichresultsinlowerexportsfromAlgeriatoMoroccoinSeason1andSeason2.IntheTransitionscenario,thisenergywasstoredbypumpedhydroinMoroccoanddispatchedintheevening.Figure2‑24TotalinstalledbatterycapacityintheTransition+BatteriesandtheTransition+Batteries+H2scenariosNote:H2=hydrogen;MW=megawatt.050001000015000200002500020252030203520402025203020352040Transition+BatteriesTransition+Batteries+H2Capacity(MW)LibyaEgyptTunisiaAlgeriaMoroccoMauritania•67•NORTHAFRICAFigure2‑25DailyuseprofileofbatteriesbyseasonandbycountryMauritania159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)DischargingChargingDailyuseproﬁle(MW)-15000-10000-5000050001000015000Transition+Batteries-15000-10000-5000050001000015000Transition+H2+Batteries159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)DischargingChargingDailyuseproﬁle(MW)-20000-15000-10000-500005000100001500020000Transition+Batteries-20000-15000-10000-500005000100001500020000Transition+H2+Batteries159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)DischargingChargingDailyuseproﬁle(MW)-2500-1500-50050015002500Transition+Batteries-2500-1500-50050015002500Transition+H2+BatteriesAlgeriaEgyptLibya159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)DischargingChargingDailyuseproﬁle(MW)-500-300-100100300500Transition+Batteries-500-300-100100300500Transition+H2+Batteries•68•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFigure2‑25Dailyuseprofileofbatteriesbyseasonandbycountry(continued)MoroccoNote:H2=hydrogen;MW=megawatt.Figure2‑26DailyuseofpumpedhydropowerinMoroccoinallscenariosDailyuseproﬁle(MW)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)DischargingCharging-5000-3000-1000100030005000Transition+Batteries-5000-3000-1000100030005000Transition+H2+BatteriesTunisiaNote:H2=hydrogen;MW=megawatt.159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)DischargingChargingDailyuseproﬁle(MW)-1000-50005001000Transition+Batteries-1000-50005001000Transition+H2+Batteries159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)GeneratingPumpingDailyuseproﬁle(MW)-1500-1000-500050010001500Pumpedhydro-Plannedscenario-1500-1000-500050010001500Pumpedhydro-Transition159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)159131721159131721159131721159131721159131721Season1(01/01-20/03)Season2(21/03-16/06)Season3(17/06-07/09)Season4(08/09-08/11)Season5(09/11-31/12)GeneratingPumpingDailyuseproﬁle(MW)-1500-1000-500050010001500Pumpedhydro-Transition+Batteries-1500-1000-500050010001500Pumpedhydro-Transition+H2+Batteries•69•NORTHAFRICA2.9GREENHYDROGENPRODUCTION,COMBINEDWITHVARIABLERENEWABLESANDSTORAGE,COULDBECOMEANINTEGRALPARTOFANINTERCONNECTEDELECTRICITYSYSTEMHydrogenproductioninNorthAfricaisconsideredonlyintheTransition+Batteries+H2scenario.Producedfromrenewableelectricity,so-calledgreenhydrogenisassumedtobeforexportonly.TheEuropeanHydrogenBackbone(vanRossumetal.,2022)estimatesthecostoftransportinghydrogenthroughrepurposedoffshorepipelinesatEUR0.14-0.15/kgH2/1000kilometre(km)andthroughnewoffshorepipelinesatEUR0.32-0.60/kgH2/1000km.TransportinghydrogenthroughrepurposedonshorepipelineswouldcostEUR0.09-0.12/kgH2/1000km,whilesendingitthroughnewonshorepipelineswouldcostEUR0.19-0.35/kgH2/1000km.InthecaseofexistingpipelinesbetweenNorthAfricaandEurope,theoffshoresectionofthepipelinesislessthan250kmfortheTransmed,MedgazandMaghreb-Europepipelines.Inthecaseofrepurposedpipelines,thesetransportationcostsrepresentbetween3%and10%oftheexportpricesusedinthisstudy.Thecostofhydrogenproductionfromrenewableelectricitysourceshastwocomponents:thecostsassociatedwiththeelectrolyser(investment,operationandmaintenance;seeTableA‑19oftheaccompanyingDataappendix[IRENA,2022b])andtheelectricitysuppliedtoit(IRENA,2020c).Thethreetypesofelectrolysers–thefirstcomingintoservicein2025;thesecondin2030;andthethirdin2035–areexpectedtodropincostandriseinefficiencyovertime.Alloftheforegoingcostsareusedtocalculatetheunitcostofthehydrogenproduced,withtheassumptionthatthehydrogenplantandtheelectricitygenerationplantarecompletelycoupled–thatis,thatthehydrogenplantisusingalltheelectricitygeneratedbytheplantandnoothersourcesofelectricity.Figure2‑27showsthatacostoflessthanUSD3/kgH2isachievablein2035inAlgeria,EgyptandMorocco,andevenfrom2030inEgypt.Theuseofgridelectricitygeneratedbyrenewablesources(windandsolar)atvariouslocationslowerscostsasitbenefitsfromthecomplementarityofthesourcesandenableselectrolyserstoproducehydrogenatahighercapacityfactor,asshowninthefollowingsection.AspresentedinTableA‑20intheDataappendix(IRENA,2022b),theexogenouslyassumedhydrogenexportpriceinthemodelfallsfromUSD3.5/kgH2in2025toUSD2/kgH2in2040.Thesetrendsarechieflydrivenbythedecliningcapitalandoperatingcostsofrenewableresources(seeTableA‑16).IntheTransition+Batteries+H2scenario,theSPLAT-NmodeloptimisesthepowersystemtoexploitthepossibilityofexportinghydrogenattheexogenouslysetpriceshowninTableA‑20.ThatpossibilitydependsonelectrolysersbeingbuiltatthecostsshowninTable3‑19.Themodelidentifiestheoptimalamountsofelectricitytobesuppliedtoendusersandtobeusedtoproducehydrogenfromtheavailablemixofprojectsandresources.ToinvestigatetheestablishmentofahydrogensupplycurvefromNorthAfrica,weoptimisethemodelusingdifferenthydrogenexportprices(USD1/kgH2,USD2/kgH2,USD3/kgH2andUSD4/kgH2).Exploitingthesynergybetweentheenergysources(windandsolar)producesbetterelectrolysercapacityfactorsandthuslowercostsatanearlierpoint.ThehydrogensupplycurveresultingfromthemodellingisshowninFigure2‑28.In2040,23.6megatonnes(Mt)ofhydrogencouldbeproducedinNorthAfricaatthecostofUSD2/kgH2orless.In2030,1.9Mtcouldbeproducedatthesamecost.Theregion’shydrogenproductionandelectrolysercapacityintheTransition+Batteries+H2scenarioarepresentedinFigure2‑29.Hydrogenproduction,whichisassumedtobeviableinfivecountries(Algeria,Egypt,Mauritania,MoroccoandTunisia),beginsinMauritaniaandTunisiain2025,followedbythethreeothercountriesin2030.Thetotalproductionintheregionremainsbelow0.5MtH2/yearbetween2025and2029,beforeacceleratingbetween2030and2034ata41%averageyearlygrowthrate(from1.8MtH2in2030to7.2MtH2in2034).Growthissustaineduntiltheendofthemodellingperiod.Theaverageyearlygrowthratebetween2035and2040is16%,withproductiongrowingfrom11.3MtH2in2035to23.6MtH2in2040thankstotheavailabilityofcheaperandmoreefficientelectrolysers.In2040,hydrogenproductioninthe•70•PLANNINGANDPROSPECTSFORRENEWABLEPOWERregionisledbyMorocco(6.3MtH2/year),followedbyAlgeria,Egypt,MauritaniaandTunisia(4.6,4.6,3.0and5.2MtH2/year,respectively).NorthAfrica’selectrolysercapacityexpandsfrom13.6GWin2030to82.2GWin2035beforereaching156GWin2040.Figure2‑29alsoshowstheevolutionoftheadditionalsolarPVandwindcapacityrequiredforhydrogenproduction.In2040,327GWofadditionalvariablerenewablecapacityisneededtoproducehydrogen,ofwhich213GWarewindpoweredand114GWsolarPVpowered.Theseresultsareworthcomparingwithotherhydrogenprojectionsinglobal,regionalandnationalreportsthathavebeenpublishedoverthepastfewyears.Table2‑9andTable2‑10presentacomparisonofhydrogendemandprojectionsandelectrolysercapacityestimates,respectively.MoredetailscanbefoundintheDataappendix(IRENA,2022b).AsshowninTable2‑9,othersourcesprojectglobalhydrogendemandintherangeof80-200MtH2in2030,and95-400MtH2in2040.NorthAfricanproductioninourTransition+Batteries+H2scenariowouldthusrepresent1-2%oftheworldwidedemandprojectedinthosescenariosin2030,and6-25%in2040.OtherhydrogendemandprojectionshavealsobeendevelopedattheEuropeanlevel.TheEuropeanUnionhaspredictedhydrogendemandof20Mtin2030ofwhich10Mtwouldbeimportedfromneighbouringcountries(EuropeanCommission,2022a).AccordingtotheEuropeanHydrogenBackbonestudy(EHB,2021),Europewouldneed10Mtofhydrogenin2030and40Mtin2040tomeetitsdemand,meaningthatNorthAfrica’sproductionintheTransition+Batteries+H2scenariowouldrepresent18%(1.8MtH2)and59%(23.6MtH2)ofEuropeandemandin2030and2040,respectively.However,theshareofhydrogensuppliedbyNorthAfricain2030couldbesignificantlylargeratahydrogenpriceofUSD3/kgH2.Inthatcase,NorthAfricacouldsupply4.0MtH2ofhydrogenin2030,equivalentto40%ofEHB’sprojecteddemand.Consideringdemandatthenationallevel,Germanyestimatesinitshydrogenstrategythatitshydrogendemandwillbe2.7-3.3MtH2by2030,15%ofwhichwillbesuppliedbyelectrolysersinstalledinGermany(0.42MtH2)andtherestimported(2.5MtH2)(FederalMinistryforEconomicAffairsandEnergy,2020).Withaproductionof1.8MtH2ofrenewablehydrogenin2030,NorthAfricacouldthuscoveraround72%oftheGermanimports.AtahydrogenpriceofUSD3/kgH2,theNorthAfricanhydrogenproductionpotentialwouldreach4.0MtH2in2030,thuscoveringallGermanimports.Withregardstohydrogenproductioncapacity,acomparisonwiththetargetsannouncedbyseveralEuropeancountriesthathavepublishedhydrogenstrategiesshowsthattheNorthAfricanelectrolysercapacityin2030resultingfromthemodelling(13.6GW)wouldbealittlelessthanthreetimesthattargetedbyGermany,ItalyortheUnitedKingdom(5GW),anddoublethe6.5GWcapacityplannedbyFrance.AninventoryofthevarioushydrogencapacitytargetssetbyEuropeancountriescanbefoundinFigureA‑1insection1.6oftheaccompanyingDataappendix(IRENA,2022b).Moreover,theNorthAfricanelectrolysercapacityin2030wouldrepresent34%ofthe40GWthatcouldbebuiltintheEasternandSouthernneighboursoftheEuropeanUnion(suchasUkraineandNorthAfrica)tocoverEUhydrogendemand,accordingtothe2x40GWGreenHydrogenInitiativesupportedbytheEuropeanCommission(EuropeanCommission,2020;HydrogenEurope,2020).Atagloballevel,recentstudieshaveestimatedtheelectrolysercapacitythatcouldbeachievedworldwide,aselectionofwhichcanbefoundinFigureA‑3oftheDataappendix(IRENA,2022b).Overall,theprojectedelectrolysercapacityinNorthAfricain2030intheTransition+Batteries+H2scenariowouldaccountfor5%ofthe270GWcapacityprojectedinIRENA’sTransformingEnergyScenario(IRENA,2020d).AtabularoverviewofthescenarioresultsintermsofhydrogenproductionandelectrolysercapacityisprovidedinTable2‑9andTable2‑10,respectively.Oneofthechallengesofintroducinghydrogenintoenergysystemsistheseasonalnatureofproductionanddemand,whichmaycreateaneedforhydrogenstorage.Theseasonalvariationsinhydrogendemandcouldresultfromtheapplicationsusingit(forexample,transportationorheating).Presently,atafewsites,hydrogenisstoredundergroundinsaltcaverns.However,undergroundhydrogenstoragemaybeincompatiblewith•71•NORTHAFRICA0123456789202520302035202520302035202520302035202520302035AlgeriaEgyptMoroccoTunisiaUSD/kgH2Unitcostofhydrogengeneratedinscreenedwindregions0123456789202520302035202520302035202520302035202520302035AlgeriaEgyptMoroccoTunisiaUSD/kgH2UnitcostofhydrogengeneratedinscreenedsolarPVregionscertainapplications,whichmayrequirefastercycles(IEA,2021a).Figure2‑30showstheseasonalityofhydrogenproductioninthecountriesconsideredinthisstudy,normalisedtotheirmaximumproduction.Algeria’smaximumdailyhydrogenproductionoccursinNovember-December;Egypt’sinSeptember-October;Mauritania’s,Tunisia’sandMorocco’sinMarch-June.Thesedifferencespromisesomecomplementarity,whichcanhelptostabilisehydrogensupplyfromtheregion.Althoughtheseasonalvariationinhydrogendemandisnotprojectedinthisstudy,thecomplementaritybetweenthecountriesmayreducethehydrogenstoragecapacityneededtoensureareliablehydrogensupplytoendusers.TheannualcapacityfactorofelectrolysersinNorthAfricais80%in2040accordingtothemodel.Figure2‑31showsthedailyproductionrateofhydrogeninthecountriesoftheregion.Theratevariesfrom58kilotonnesofhydrogen(ktH2)/dayinSeptember-Octoberto74ktH2/dayinMarch-June.ThelatterpeakreflectsthecombinedpotentialofsolarPVandwindpowerpeakingatthattimeyear,coupledwithmoderatedemand.Figure2‑32showsthehourlyhydrogenproductioncurveforeachseasoninthedifferentcountries.Itischaracterisedbyhigherproductionduringtheperiodsofgreatestsolarpoweravailability.Figure2‑27UnitcostofhydrogengeneratedinscreenedwindandsolarphotovoltaicregionsFigure2‑28HydrogensupplycurveinNorthAfricaasdeterminedbythemodel,2030and2040Note:kgH2=kilogrammeofhydrogen;PV=photovoltaic.Note:kg=kilogramme;Mt=megatonne.0510152025303540<1USD/kg1-2USD/kg2-3USD/kg3-4USD/kgHydrogen(Mt)20400510152025303540<1USD/kg1-2USD/kg2-3USD/kg3-4USD/kgHydrogen(Mt)2030AlgeriaEgyptMauritaniaMoroccoTunisia•72•PLANNINGANDPROSPECTSFORRENEWABLEPOWERSolarWindSolarWind0501001502002503003502025203020352040Capacity(GW)AdditionalsolarandwindcapacityintheTransition+Batteries+H2scenariocomparedwiththeTransition+Batteriesscenario0200400600800100012002025203020352040Generation(TWh)AdditionalsolarandwindgenerationintheTransition+Batteries+H2scenariocomparedwiththeTransition+BatteriesscenarioTable2‑9ComparisonofhydrogenproductionintheTransition+Batteries+H2scenariowithnational,regionalandglobalhydrogendemandprojections,2030and2040COUNTRY/REGIONSOURCEDEMANDPROJECTIONS(MtH2/YEAR)20302040GermanyNationalHydrogenStrategy(FederalMinistryforEconomicAffairsandEnergy,2020)2.7-3.3n/aEurope(EHB,2021;HydrogenEurope,2020)10-17.540(EuropeanCommission,2022a)20Globe(AcilAllen,2018;BP,2020;COAGEnergyCouncil,2019;GlobalAlliancePowerfuels,2020;HydrogenCouncil,2017;IEA,2020c,2021b;Shell,2021;WEC,2016)80-21294-391NorthAfricaTransition+Batteries+H2scenario1.823.6Note:MtH2=megatonneofhydrogen.Figure2‑29Evolutionofhydrogenproduction,electrolysercapacityandgenerationfromvariablerenewableenergyinNorthAfricaintheTransition+Batteries+H2scenario,2025-2040Note:GW=gigawatt;GWe=gigawattselectric;H2=hydrogen;Mt=megatonne;TWh=terawatthour.AlgeriaEgyptMauritaniaMoroccoTunisiao5101520252025202620272028202920302031203220332034203520362037203820392040Hydrogen(Mt)HydrogenproductionintheTransition+Batteries+H2scenario(Mt)0204060801001201401601802025203020352040Capacity(GWe)ElectrolysercapacityinNorthAfrica•73•NORTHAFRICA0.00.20.40.60.81.01January-20March21March-16June17March-07September8September-8November9November-31DecemberMauritaniaEgyptAlgeriaTunisiaMoroccoSeasonalcurveofdailyhydrogenproduction(normalisedtoannualmaximum)Table2‑10ComparisonofelectrolysercapacityintheTransition+Batteries+H2scenariowithnational,regionalandglobalhydrogenprojections,2030and2040COUNTRY/REGIONSOURCEELECTROLYSERCAPACITY(GWe)20302040GermanyNationalHydrogenStrategy(FederalMinistryforEconomicAffairsandEnergy,2020)510Europe(EHB,2021;EuropeanCommission,2020;FCH,2019)15-40n/aGlobe(HydrogenCouncil,2021;IEA,2021b;IRENA,2020d)270-850n/aNorthAfricaTransition+Batteries+H2scenario13.6156Note:GWe=gigawattselectric;H2=hydrogen.Figure2‑30SeasonalhydrogenproductionintheTransition+Batteries+H2scenario,bycountryandnormalised(relativetomaximumdailyproductionintheyear)Note:H2=hydrogen;kt=kilotonne.•74•PLANNINGANDPROSPECTSFORRENEWABLEPOWER0.01.02.03.04.05.00.51.52.53.54.5Hydrogen(kt/hour)MoroccoEgyptTunisiaAlgeriaMauritania13579111315171921231357911131517192123135791113151719212313579111315171921231357911131517192123Season1Season2Season3Season4Season5010203040506070801January-20March21March-16June17June-07September8September-8November9November-31DecemberHydrogen(kt/day)MauritaniaEgyptAlgeriaTunisiaMoroccoFigure2‑31DailyhydrogenproductionrateintheTransition+Batteries+H2scenario,bycountryFigure2‑32DailyhydrogenproductionintheTransition+Batteries+H2scenarioforeachseason,bycountryNote:H2=hydrogen;kt=kilotonne.Note:H2=hydrogen;kt=kilotonne.•75•NORTHAFRICA2.10CSPSTORAGEWILLBEIMPORTANTTOENSURESYSTEMADEQUACYThissectiondescribesapost-modelanalysisoftheoptimisationresultsofthescenarios.TheSPLAT-Nmodelworkswithseasonaltimeslicesbutdoesnotrunathourlyresolution.Foraproperassessmentofsystemadequacy,simulationsofthecapacitymixessuggestedbySPLAT-Nareneededathourlyresolutiontoverifytherobustnessofthemodelresultsfromanoperationalpointofview.Accordingtothemodellingassumptions,weconsiderareservemarginof10%overtheannualpeakloadprovidedbyfossil-fuel-basedtechnologiesinadditiontoCSP(withthermalenergystorage)andbatteries.IntheTransitionscenarios,thisreservemarginisprovidedbyCSPandbatteries.Inthissection,weexplorewhetherenoughenergycanbestoredusingthesetwotechnologiestosupplydemandwhenVREisnotavailable.Althoughgridstabilityliesoutsidethescopeofthisstudy,weexploreheretheadequacyissuesthesystemmayfacewithrespecttoavailablecapacityandintra-seasonalvariabilityofwindandsolarresources.Theseissuesdonotaffecttheenergygeneratedannuallybyeachtechnology.Asdescribedinsection3.2.1,anaverageprofileofelectricitydemandandVREsupplyiscreatedforeachseason,bytimeslice.Averagingbytimeslotresultsinanunderestimationofthepeakload,whichmayresultinunderestimationofthefirmcapacityneededtoensurethatthesystemcanmeettherequiredloadatalltimes(Ponceletetal.,2016).Inaddition,asCSPandbatteriesareassumedtocontributetothereservemarginatfullinstalledcapacity,wemustbesurethatenoughenergycanbestoredinthesetechnologieswhenneeded.Here,thehourlywindandsolarprofilesforthemodelsupplyregions(MSRs)ineachcountry(seeBox2‑2)areusedincombinationwithhourlydemandtocalculatetheresidualdemandthatmustbesuppliedusingfossilfuels,importsorelectricitystoragesystems,giventhecapacityexpansionsuggestedbytheSPLATmodelresults.TheresidualdemandisequaltothedemandminusthesumofsolarPVgenerationandwindgeneration.Residualdemandcanbenegative,asinFigure2‑33,whenrenewablegenerationexceedsdemand.Inthatcase,theoptionsaretoexport,toproducehydrogen(iftheoptionisavailable),tostoretheelectricityinbatteriesortocurtailtheexcesselectricity.Thus,themaximumpositiveresidualdemandmustbecomparedwiththesumofthefirmcapacityofnon-VREpowerplants(solarthermal,hydro,imports,batteriesandfossilfuels),andtheminimumresidualload(ormaximumexcessVREproductionbeyonddemand)mustbecomparedwiththecapacityofthepower-consumingtechnologiesotherthanfinaldemand(exports,batteriesandhydrogenproductionplants).IfthemaximumexcessVREproductionisgreaterthanthecapacityofthesetechnologies,thisproductionshouldbecurtailed.Inourmodel,mostoftheresidualloadissuppliedusingCSP.Thankstothestoragecapacityassociatedwiththistechnology,electricitysupplycanfollowtheloadprofile.Thestoragemustbecarefullydesigned,however,toadjusttotheneedsofthesystem.Indeed,ifthehourlydispatchshowsaneedforenergyfromCSPstorageoveranextendedperiodonemustensurethattheavailablestoragecanholdenoughenergy.Figure2‑34showstheperiodsintheyearwhenCSPgenerationisneeded(withoutconsideringthepossibilityofimportingfromneighbouringcountries).ThemostcriticaltimesareeveningsandnightsinJune,July,AugustandSeptember,whicharecharacterisedbyhighsolarpoweravailabilityandhighdemand.StorageassociatedwithCSPshouldthereforebedesignedwiththesetimesinmind.LongstorageisespeciallynecessaryintheTransitionscenario.IntheTransition+Batteriesscenario,thebatteriesimprovetheadequacyofthesystem,sinceelectricityfromthevariousgenerationtechnologiescanbestoredinthem.IntheTransition+Batteries+H2scenario,thetotalinstalledcapacityismuchhigherthanthecapacityneededtosupplylocaldemand;forthatreason,adequacyisensuredbyreducinghydrogenproductionwhenelectricityisneededtomeetlocaldemand.Likebatterystorage,hydrogenproductioncanreduceVREcurtailment–from25%ofpotentialVREgenerationin2040intheTransitionscenarioto16%intheTransition+Batteriesscenarioand5%intheTransition+Batteries+H2scenario.Becauseelectrolyserscanrampupanddownonatimescaleofminutesandevenseconds(IRENA,2019b),hydrogenproductioncanalsocontributetotheflexibilityofthesystem.•76•PLANNINGANDPROSPECTSFORRENEWABLEPOWERFigure2‑33ResidualloaddurationcurveintheTransitionscenario,bycountry,2040Note:CSP=concentratedsolarpower;MW=megawatt.-30000-20000-1000001000020000300004000050000Load/capacity(MW)Algeria-40000-20000020000400006000080000Egypt-4000-200002000400060008000100001200014000Load/capacity(MW)Libya-800-600-400-200020040060080010001200Mauritania-6000-4000-200002000400060008000100001200014000Load/capacity(MW)Morocco-6000-4000-2000020004000600080001000012000TunisiaMax1stdecile2nddecile3rddecile4thdecile5thdecile6thdecile7thdecile8thdecile9thdecileMinMax1stdecile2nddecile3rddecile4thdecile5thdecile6thdecile7thdecile8thdecile9thdecileMinMax1stdecile2nddecile3rddecile4thdecile5thdecile6thdecile7thdecile8thdecile9thdecileMinMax1stdecile2nddecile3rddecile4thdecile5thdecile6thdecile7thdecile8thdecile9thdecileMinMax1stdecile2nddecile3rddecile4thdecile5thdecile6thdecile7thdecile8thdecile9thdecileMinMax1stdecile2nddecile3rddecile4thdecile5thdecile6thdecile7thdecile8thdecile9thdecileMinImportcapacityCSPFossilfuelcapacityResidualloadExportcapacity•77•NORTHAFRICA2.11DEPLOYMENTOFVREWITHSTORAGESOLUTIONSCANTEMPERSYSTEMCOSTSIFFOSSILFUELINVESTMENTSAREHALTEDThetotalcostoftheelectricalsystem,andthereforeofeachscenario,isdeterminedbyvariouscomponents:investmentcosts,fixedandvariableoperationandmaintenancecosts,andfuelcosts.Theinvestmentcostsrefertotheannualisedcapitalcosts.Theannuitiesarecalculatedaccordingtotheusefullifeoftheprojectsandtheweightedaveragecostofcapitalofgenerationandtransmission.ThedifferenceingenerationtechnologiesbetweenthefourscenariosandthelowerdemandinthePlannedscenarioexplainthechangesinthecoststructureoftheelectricitysysteminNorthAfrica.Figure2‑35showstheevolutionofthesecostsinthefourscenarios.Ontheonehand,thereisanotablereductioninthefuelcostcomponentbetweenthePlannedscenarioandthethreeTransitionscenarios,explainedbythelowershareofelectricityderivedfromfossilfuelthermalpowerplantsinthelatter.ThefuelcostsapproachzeroastheshareofrenewablecapacityincreasesinthethreeTransitionscenarios.Ontheotherhand,theinvestmentcostcomponentishigherinthethreeTransitionscenarioscomparedwiththePlannedscenario,aresultofsignificantgrowthinrenewablecapacityandtotalgeneration.Figure2‑34HourlycapacityfactorofconcentratedsolarpowerneededtomeetdemandintheTransitionscenario,2040AlgeriaJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember0h24hEgyptJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember0h24hLibyaJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember0h24hMauritaniaJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember0h24hMoroccoJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember0h24hTunesiaJanuaryFebruaryMarchAprilMayJuneJulyAugustSeptemberOctoberNovemberDecember0h24hHourswithcurtailmentPositiveresidualloadHourswhenmorethan25%ofCSPcapacityneedstobeavailabletocovertheentireresidualloadHourswhenmorethan50%ofCSPcapacityneedstobeavailabletocovertheentireresidualloadHourswhenmorethan75%ofCSPcapacityneedstobeavailabletocovertheentireresidualloadNote:CSP=concentratedsolarpower.•78•PLANNINGANDPROSPECTSFORRENEWABLEPOWER202020222024202620282030203220342036203820400102030405060708090100202020222024202620282030203220342036203820402020202220242026202820302032203420362038204020202022202420262028203020322034203620382040PlannedscenarioTransitionscenarioTransition+BatteriesscenarioTransition+Batteries+H2scenarioSystemcosts(USDbillion)AnnualisedinvestmentcostsFixedO&McostsFuelcostsBatteriesWhenhydrogenproductionisintroduced,investmentcostsbecomesignificantlyhigherthaninthetwoTransitionscenariosthatdonotincludehydrogen(Figure2‑35).Thisisduetotheinstallationofnewsolarandwindenergycapacitytosupplyadditionalelectricitytopowerelectrolysers(Figure2‑36).However,theoperatingcostsarerelativelysimilaracrossallthreeTransitionscenarios.In2040,investmentcostsrepresentmorethan75%ofthesystemcostsintheTransition+Batteries+H2scenario.TheadditionalcostsintheTransition+Batteries+H2scenarioarecompensatedbyhydrogenexportrevenues.Intheend,theaverageannualinvestmentneededinthePlannedscenarioovertheperiod2020-2040isUSD7.3billion,avalueonthesameorderofmagnitudeastheUSD8.5billioninannualinvestmentsinrenewableenergycommittedandplannedfor2021-2025intheregion(seesection1.8).TheaverageannualinvestmentsneededintheTransitionandTransition+BatteriesscenariosareUSD18billionandUSD16.3billion,respectively.ThehighestaverageannualinvestmentcostsarereachedintheTransition+Batteries+H2scenario,whichrequiresanaverageofUSD27.3billionannuallyowingtothehighercapacityneededtoproducehydrogen.AsshowninFigure2‑36,thescenariowiththehighesttotalcostsistheTransition+Batteries+H2,withatotalofUSD1067billioncostsovertheperiod2020-2040,comparedwithUSD885billionintheTransition+Batteriesscenario.Butproducinghydrogencanbecost-effectiveforNorthAfricancountriessincetheproductioncostsarecompensatedbytherevenuegeneratedfromexports(USD358billioninrevenue).Thesystemcostsdonotincludeadditionalequipmentneededtoensuregridstabilityandexpansionoftransmissioncapacityineachcountry.AlthoughtheadequacyofgenerationtomeetloadatallhourswouldbeguaranteedintheTransition+Batteries+H2scenariobytheavailabilityofenoughdispatchablegenerationtohandletheintra-seasonalvariabilityofintermittentenergysources(seeprevioussection),gridstabilitymayrequireadditionalfeaturestoprovidefrequencyandvoltagecontrol.Figure2‑35EvolutionofsystemcostsinthefourscenariosNote:H2=hydrogen;O&M=operationandmaintenance.•79•NORTHAFRICA2.12HOLDINGDOWNTHELEVELISEDCOSTOFELECTRICITYTheplanningmodelusedinthestudyrepresentsasimplifiedelectricitygridofsixcountriesinNorthAfrica,whereeachcountryrepresentsanode.Thetechnologiesassociatedwitheachnodeandtheircorrespondinginvestmentcost,operatingcostsandfuelcostsdeterminethetotalcostofgeneratingelectricity.Theaverageannualcostfortheregioniscalculatedinthisstudyastheload-weightedaveragecostatalltransmissionsystemnodes.Figure2‑37showstheevolutionoftheunitgenerationcostinNorthAfricaovertheperiod2020-2040inthefourscenarios.UnderthePlannedscenario,generationcostincreasesslightlybetween2020and2025andremainsconstantafterwardatclosetoUSD0.09/kilowatthour(kWh).Thisisdirectlylinkedtothepriceoffossilfuels,whichrepresentahighshareofthepowergenerationinthisscenario,whichareassumedtoriseupto2025beforestabilising(TableA‑15oftheDataappendix[IRENA,2022b]).Incontrast,averageannualcostsfallafter2025inthethreeotherscenarios,thankstotheincreasingpenetrationofVRE.Eventhoughthestrongerdeploymentofrenewablestranslatesintohigherinvestments,theheavyreductionoffuelcostsinducedbythesescenariosreducestheoverallcostofgeneration.ThePlannedscenariohasasignificantlyhigherthermalgenerationcomponentduetotheconstraintimposedtolimitrenewablestocurrentnationaltargetsandnotexceedthem,whichimpliesthatmoreexpensive(andlessefficient)thermalplantsareusedmoreoften,resultinginahigherregionalaveragecost.TheTransition,Transition+BatteriesandTransition+Batteries+H2scenarioshaveproportionallylowerthermalgeneration,andtheregionalaveragecostinthesecasesislower,withthelowestbeinginthelastscenario.Inthesethreescenarios,thermalenergyisprogressivelyreplacedbysolarandwindrenewableenergyoverthestudyhorizon.TheunitcostsofgenerationbycountryarepresentedinFigure2‑38fortheyear2040.Forallcountries,thelowestcostsattheendofthemodellinghorizonarefoundintheTransition+Batteries+H2scenario.MauritaniashowsthelowestgenerationcostsinNorthAfrica,withnetcostsoflessthanUSD0.03/kWh;MoroccoandTunisiabothachieveacostbelowUSD0.04/kWhby2040.Figure2‑36TotalcostsandtotalgenerationinNorthAfricainthefourscenarios,2020-2040Note:H2=hydrogen;TWh=terawatthour.8638988851067020040060080010001200PlannedscenarioTransitionscenarioTransition+BatteriesscenarioTransition+Batteries+H2scenarioTotalcosts(USDbillion)Totalcosts1015612099120181803902000400060008000100001200014000160001800020000PlannedscenarioTransitionscenarioTransition+BatteriesscenarioTransition+Batteries+H2scenarioTotalgeneration(TWh)Totalgeneration•80•PLANNINGANDPROSPECTSFORRENEWABLEPOWERPlannedscenarioTransitionscenarioTransition+BatteriesscenarioTransition+Batteries+H2scenario024681012AlgeriaEgyptLibyaMauritaniaMoroccoTunisiaNorthAfricaAveragegenerationcost(USDcents/kWh)Figure2‑37EvolutionoftotalgenerationcostinNorthAfricainthefourscenarios(annualsystemcostdividedbyannualgeneration)Figure2‑38Averagegenerationcostinthefourscenarios,bycountry,2040Note:H2=hydrogen;kWh=kilowatthour.Note:H2=hydrogen;kWh=kilowatthour.0246810202020212022202320242025202620272028202920302031203220332034203520362037203820392040Generationcost(USDcents/kWh)PlannedscenarioTransition+Batteries+H2scenarioTransition+BatteriesscenarioTransitionscenario•81•NORTHAFRICA2.13THEPROPOSEDTRANSITIONTOWARDSVREWOULDSUBSTANTIALLYLOWERCO2EMISSIONSFROMPOWERGENERATIONThegenerationofelectricityfromoil,naturalgasandcoalemitsCO2.TheevolutionofthoseemissionsinthefourscenariosinNorthAfricaarepresentedinFigure2‑39.InthePlannedscenario,CO2emissionsdropbyabout25%intheperiod2020-2030,reflectingtheimpactofcurrenttargetsforrenewablecapacitydeployment.However,theybegintoriseagainin2030andcontinuetorisethroughtheendofthemodellingperiod.MostoftheeffectisexplainedbygrowingemissionsinAlgeriaowingtogrowingdemandwithoutacommensuratelygreatershareofrenewableenergyintheelectricitymix.(ThePlannedscenariousedasabaselineinthisstudyassumesthatcountries’currentrenewabletargetsareachievedbutnotexceeded.)Theadditionofnewrenewablepowerplantscanoffsetthegrowthinemissionsanddecoupleitfromdemandgrowth.InthethreeTransitionscenarios,powerdemandishigherthaninthePlannedscenario,butfossil-fuel-basedpowergenerationis75%lowerby2040,asrenewablegenerationtakesitsplace,bothinabsolutevalueandasashareoftotalgeneration.ThetransitionscenariosarethuscharacterisedbyadeclineinCO2emissionsoverthemodellingperiod.Whereasthepowersectorwasresponsibleforemitting154megatonnesofcarbondioxideequivalent(MtCO2eq)in2020,thoseemissionsarereducedto64MtCO2eqin2030andtolessthan35MtCO2eqin2040–a78%dropoverthe2020-2040period.IntermsofcumulativeCO2emissionsreleasedbythepowersectoroverthe20-yearmodellingperiod,thescenariosshowcasepossibilitiestoreducecumulativeemissionsdespitethesubstantialincreaseinelectricitydemandinNorthAfrica.Between2020and2040,thecumulativeCO2emissionscausedbytheelectricitysectoraresignificantlylowerintheTransition,Transition+BatteriesandTransition+Batteries+H2scenarios(1763MtCO2eq,1746MtCO2eqand1703MtCO2eq,respectively)thaninthePlannedscenario(2698MtCO2eq)(Figure2‑40).Theequivalentannualaveragesare128MtCO2/yearinthePlannedscenario,84MtCO2/yearintheTransitionscenario,83MtCO2/yearintheTransition+Batteriesscenarioand81MtCO2/yearintheTransition+batteries+H2scenario.Inotherwords,theTransitionandTransition+Batteriesscenariosbringabouta35%reductionincumulativeCO2emissionsovertheperiod2020-2040comparedwiththePlannedscenario;theTransition+Batteries+H2scenarioyieldsa37%reduction.•82•PLANNINGANDPROSPECTSFORRENEWABLEPOWER0500100015002000250030002697PlannedCumulativeCO2emissions(Mt)1763Transition-35%1746Transition+Batteries-35%1704Transition+Batteries+H2-37%020406080100120140160180202020212022202320242025202620272028202920302031203220332034203520362037203820392040CO2emissions(Mt)020406080100120140160180020406080100120140160180020406080100120140160180202020212022202320242025202620272028202920302031203220332034203520362037203820392040CO2emissions(Mt)CO2emissions(Mt)CO2emissions(Mt)PlannedscenarioTransitionscenario202020212022202320242025202620272028202920302031203220332034203520362037203820392040202020212022202320242025202620272028202920302031203220332034203520362037203820392040Transition+BatteriesscenarioTransition+Batteries+H2scenarioEgyptLibyaMoroccoTunisiaMauritaniaAlgeriaFigure2‑39EvolutionofcarbondioxideemissionsfromtheelectricitysectorinNorthAfricainthefourscenariosNote:CO2=carbondioxide;H2=hydrogen;Mt=megatonne.Figure2‑40Cumulativecarbondioxideemissionsandreductionsinthefourscenarios,2020-2040Note:CO2=carbondioxide;H2=hydrogen;Mt=megatonne.•83•NORTHAFRICA2.14ADDITIONALSTUDIESCOULDSHEDMORELIGHTONTHENORTHAFRICANPOWERSYSTEMDemandandloadcurves.InsomeNorthAfricancountries,peakloadgrowthismuchhigherthangrowthinannualelectricityusage.Becausethisstudyuseddemandloadcurvesavailableinthepublicdomainforallcountries,theloadcurvehadthesameshapeforallthemodelledyears.Forthesakeofaccuracy,futureworkwithNorthAfricancountriesshouldprojectevolvingloadcurves.Moreefficientairconditioningmayreducethegrowthofpeakload.Atthesametime,highertemperaturesresultingfromclimatechangemayincreasetheneedforairconditioning.Inaddition,increasingelectrificationofenduses(e.g.introductionofelectricvehicles)mayresultindifferenthourlyelectricitydemandloadcurves.Fortunately,SPLATisabletointegratedifferentloadcurvesfordifferentyears.Domestichydrogendemand.Inthisstudy,weassumethatallhydrogenproducedinNorthAfricawillbeexported.Usinghydrogenlocallycouldhelpdecarbonisetheregion’seconomies,butdemandforthatpurposecannotyetbedeterminedendogenouslywithinSPLAT.Severalcountriesarepresentlypreparingtheirhydrogenstrategyandmayincluderelevantprojections.Flexibilityandgridreliability.Althoughinthisstudywecheckedtheadequacyofsupplyanddemand,furthermodellingfocusingspecificallyonthegridmayoffermoreinsightonthegridinvestmentsneededasrenewablescometomakeupaveryhighshareofthepowersystem.Toassesstheflexibilityofcapacityexpansionplans,IRENAdevelopedtheFlexToolmodel(IRENA,2018b).StudiesusingFlexToolhelptoidentifytheleast-costmixofsolutionstoshortagesofflexibility.FlexToolisadetailedbutuser-friendlytooldesignedtoanalysenotonlythetraditionalconceptofflexibility(forexample,flexiblethermalandhydropowergenerationwithhighrampingcapabilityandverylowstart-uptime),butalsootherinnovativetechnologiesthatenrichtheconceptofflexibility,suchasflexibledemand,energystorageandsectorcoupling.Economicimpactofhighersharesofrenewables.IRENAapproachesthesocio-economicanalysisoftheenergytransitionusingamacro-econometricmodel(E3ME)thatlinkstheenergysystemwiththeworld’seconomieswithinasinglequantitativeframework.E3MEmeasurestheimpactsoftransitionscenariosandtheiraccompanyingclimatepolicybasketsbyevaluatingtheireffectsonGDP,employmentandwelfare.(Carbonpricingandinternationalco-operationaretwokeyelementsthathavebeenconsideredintheclimatepolicybaskets.)Theultimategoalistoinformenergysystemplanningandpolicymakingtoensureajustandinclusiveenergytransitionattheglobal,regionalandnationallevels.Box2‑4containsanexampleofsocio-economicanalysisoftheenergytransitioncarriedoutbyIRENAincollaborationwiththeAfricanDevelopmentBank.IRENA’slatestmodellingresults,obtainedincollaborationwithAfricanDevelopmentBank(IRENAandAfDB,2022),revealhowtheenergytransitionbenefitsAfrica’seconomiesandpeople–beyondemissionsreductions–through2050.Twoscenarioshavebeenanalysed:(1)anambitiousenergytransitionscenario(calledthe1.5˚CScenario)thataimstoreachtheglobalgoaloflimitingtheriseintheglobalaveragetemperaturetonomorethan1.5°Cby2050;and(2)thePlannedEnergyScenariobasedonthestatusquo.The1.5˚CScenarionotonlyassumesthattheprovisionsoftheParisAgreementarebeingmet,butalsothatthetransitionisaccompaniedbyaproactivesetofpoliciesdesignedtomaximisethesocio-economicbenefitsoftransformingenergysystems.Box2‑4AnexampleofIRENA’ssocio-economicanalysisofenergytransitionroadmaps•84•PLANNINGANDPROSPECTSFORRENEWABLEPOWERResultsfromAfricashowthat,despitethedifficultshiftawayfromcarbon-intensiveenergysources,theenergytransition–whenaccompaniedbyappropriatepolicies–holdshugepromise.The1.5˚CScenariopredicts6.4%higherGDP,3.5%morejobsanda25.4%higherwelfareindexacrossthecontinentthanwhatcouldberealisedundercurrentplans(Figure2-41).Intherenewableenergysector,theenergytransitioncouldboostemploymentsubstantiallyinAfrica,fromaround0.35millionin2020to4.3millionby2030andmorethan8millionby2050underthe1.5˚CScenario,a20-foldincreaseby2050fromtoday’svalues.IRENA’sanalysisalsoshowsAfricaprosperingfromadiversifiedeconomy,industrialdevelopmentandinnovation,energyaccess,andprofoundbenefitsfortheenvironment,allofwhicharecriticaltomoreequitablesocio-economicdevelopmentacrossthecontinent.Figure2-41Averagedifferencesbetweenthe1.5˚CScenarioandPlannedEnergyScenarioforAfrica,2021-2050Note:1.5-S=1.5˚Cscenario;GDP=grossdomesticproduct.Globalimpactsoftheenergytransitionwillbeunevenlydistributedacrossregionsandcountries,dependingonlocalsocio-economicstructures,thedegreeofrelianceonfossilfuelsandthedepthoftherenewablessupplychain,amongotherfactors.Thus,IRENAhasdeepenedandbroadeneditssocio-economicimpactanalysiswithinAfrica’sfiveregions.InthecaseofNorthAfrica,betterresultsonGDP,economy-wideemploymentandwelfareareobtainedoverthe2021-2050periodwithamoreprogressivepolicybasket.Beyondtheirimpactonthesocio-economicfootprintofenergytransitionmodelssuchasthe1.5˚CScenario,thegreatestvalueofusingprogressivepolicybasketstoaddresstheequityandjusticedimensionsofthetransitionisthattheyincreasethechangesthatambitiousmitigationplanswillberealisedbytriggeringtherequiredcollaborativeeffort.Box2‑4AnexampleofIRENA’ssocio-economicanalysisofenergytransitionroadmaps(continued)Moreeconomy-widejobsHigherwelfareindexMoreGDP+6.4%+3.5%+25.4%1.5-S1.5-S1.5-S•85•NORTHAFRICA2.15PATHWAYSTOLOWER-COSTELECTRICITYGENERATIONINNORTHAFRICATheSPLAT-Nmodel,developedbyIRENAforthisstudy,suggeststhatitistechnicallyandeconomicallypossibleforNorthAfricancountriestoreducetheirrelianceonfossilfuelsbyraisingtheshareofrenewablesinpowergenerationfarbeyondcountries’currenttargets.Ambitiousincreasescouldbefacilitatedbyutility-scalebatterystorageandhydrogenproductionoveraninterconnectedNorthAfricangrid.Theseoptionswouldreducetheunitcostofelectricityinthelongtermcomparedwithcontinuedrelianceonfossil-fuel-poweredgenerationofelectricity.AsshownbytheTransitionscenario,lowerpowergenerationcostsarepossibleeveniffossilfuelplantinvestmentsarefullyhaltedafter2025,thankstothewidespreadpotentialforsolarandwindpowerinNorthAfrica,includingsolarthermalwithawell-designedstoragecapacity.Reinforcedcross-borderinterconnectionsmakeitpossibletoharnessthesubstantialspatio-temporalcomplementaritiesofsolarandwindpoweracrosstheregion,enablinggreateruseofthesevariableresources.InterconnectionsarevitalwhenasurplusofgenerationisavailableinNorthAfricaforexporttoEuropeandwhenpeakloadsshiftwithinthecountriesoftheregion.AsshownbytheTransition+Batteriesscenario,battery-basedstoragecanplayanimportantroleincost-effectivelysupportinggridintegrationofVRE.TheTransition+Batteries+Hydrogenscenariodemonstratesthathydrogenproductionintheregionopensyetanotheropportunitytointegraterenewablesintotheregion’selectricitysystem,therebyloweringtheunitcostofgenerationandearningrevenuefromtheexportationofhydrogenthroughexistinginfrastructure(naturalgaspipelines)ornewinfrastructure.ThethreeTransitionscenarioswouldyielda75%reductioninemissionsby2030over2020levels.Theywouldreducecumulativeemissionsfor2020-2040bymorethan30%overthePlannedscenario.Thisreductionisachievablethankstothemassiveintroductionofrenewables–supportedbybatterystorageandhydrogenproductiondestinedforexport–andbyceasinginvestmentsinnewfossilfuelgenerationin2025.IntheTransition+Batteries+H2scenario,theregion’sfossilfuelconsumptionforelectricitygenerationin2040fallsfrom2537PJ/yearto565PJ/year.Theimmenseopportunityofloweringelectricitygenerationcostsintheregion,harnessingitssolarandwindresourcestoexporthydrogen,andreducingemissionscouldbecomearealitythroughcooperationamongNorthAfricancountriestoexploitavailablesynergiesinelectricitygenerationandexportinfrastructure.Thetransitionrequireslargeinvestments,investmentsbestmadebythepublicandprivatesectorsworkinginconcertandwiththeexplicitintenttoincludelocalindustriesintheeffort.TheSPLAT-Nmodelwasdevelopedandpopulatedlargelywithpubliclyavailableinformation.Becausethismaywellskeworlimittheanalysispresentedhere,IRENAwelcomesfurthervalidationfromnationalandregionalexpertsinNorthAfricatoenhancetherobustnessofthemodellingandanalysis.Variousassumptionsrelatingtofuelcosts,infrastructureandpolicydevelopments,amongothermatters,maybechallengedorvieweddifferentlybystakeholdersintheregion.Thisisasitshouldbe.IRENAwillmaketheSPLAT-Nmodelfreelyavailabletoexpertsfromitsmembercountriestoenablethemtoexplorevariousassumptions,tovalidatetheassumptionsofthemodel,todevelopandcomparetheirownscenarios,andtoanalyseingreaterdepththebenefitsandchallengesofanacceleratedroll-outofrenewablepowergenerationtechnologies.•86•PLANNINGANDPROSPECTSFORRENEWABLEPOWERREFERENCESAcilAllen(2018),OpportunitiesforAustraliafromHydrogenExports,AcilAllenConsultingfortheAustralianRenewableEnergyAgency(ARENA),Australia,https://arena.gov.au/assets/2018/08/opportunities-for-australia-from-hydrogen-exports.pdfAfrik21(2020),“Morocco:PartnershipwithGermanyforgreenhydrogen”,www.afrik21.africa/en/morocco-partnership-with-germany-for-green-hydrogen/Afrik21(2019),“Algeria:Condorselectedtobuild50-megawattsolarpowerplant”,www.afrik21.africa/en/algeria-condor-selected-to-build-50-megawatt-solar-power-plant/(accessed2August2021).Aghahosseini,A.,D.Bogdanov,andC.Breyer(2020),“Tow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