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Arnold SchwarzeneggerGovernor

RENEWABLE ENERGYCOST OF GENERATION UPDATE

PIER

INTERIM

PROJECTREP

ORT

Prepared For:

California Energy CommissionPublic Interest Energy Research Program

Prepared By:KEMA, Inc.

August 2009CEC-500-2009-084

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Prepared By:KEMA, Inc.Charles ODonnell, Pete Baumstark, Valerie Nibler, Karin Corfee, andKevin SullivanOakland, CA 94612Commission Contract No. 500-06-014Commission Work Authorization No: KEMA-06-020-P-R

Prepared For:

Public Interest Energy Research (PIER)

California Energy Commission

Cathy TurnerContract Manager

John Hingtgen, M.S.

Project Manager

Energy Generation Research Office

Kenneth Koyama

Office Manager

Energy Generation Research Office

Thom Kelly

Deputy Director

ENERGY RESEARCH & DEVELOPMENT DIVISION

Deputy Director

Melissa Jones

Executive Director

DISCLAIMER

This report was prepared as the result of work sponsored by the California Energy Commission. It does not necessarily represent the views of theEnergy Commission, its employees or the State of California. The Energy Commission, the State of California, its employees, contractors andsubcontractors make no warrant, express or implied, and assume no legal liability for the information in this report; nor does any party representthat the uses of this information will not infringe upon privately owned rights. This report has not been approved or disapproved by the CaliforniaEnergy Commission nor has the California Energy Commission passed upon the accuracy or adequacy of the information in this report.

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Preface

TheCaliforniaEnergyCommissionsPublicInterestEnergyResearch(PIER)Programsupports

publicinterestenergyresearchanddevelopmentthatwillhelpimprovethequalityoflifein

Californiabybringingenvironmentallysafe,affordable,andreliableenergyservicesand

productstothemarketplace.

ThePIERProgramconductspublicinterestresearch,development,anddemonstration(RD&D)

projectstobenefitCalifornia.

ThePIERProgramstrivestoconductthemostpromisingpublicinterestenergyresearchby

partneringwithRD&Dentities,includingindividuals,businesses,utilities,andpublicor

privateresearchinstitutions.

PIERfundingeffortsarefocusedonthefollowingRD&Dprogramareas:

BuildingsEndUseEnergyEfficiency

EnergyInnovationsSmallGrants

EnergyRelatedEnvironmentalResearch

EnergySystemsIntegration

EnvironmentallyPreferredAdvancedGeneration

Industrial/Agricultural/WaterEndUseEnergyEfficiency

RenewableEnergyTechnologies

Transportation

RenewableEnergyCostofGenerationUpdateistheinterimreportfortheRenewableEnergyCost

ofGenerationUpdateproject(ContractNumber50006014,workauthorizationnumber

KEMA06020PR)conductedbyKEMA,Inc.Theinformationfromthisprojectcontributesto

PIERsRenewableEnergyTechnologiesProgram.

FormoreinformationaboutthePIERProgram,pleasevisittheEnergyCommissionswebsiteat

www.energy.ca.gov/research/orcontacttheEnergyCommissionat9166544878.

Acknowledgement

GerryBraun,PIERtechnicalconsultant,isacknowledgedforhisinvaluabletechnicalguidanceandreviewofthisproject.

Pleaseusethefollowingcitationforthisreport:

ODonnell,Charles,PeteBaumstark,ValerieNibler,KarinCorfee,andKevinSullivan(KEMA).

2009.RenewableEnergyCostofGenerationUpdate,PIERInterimProjectReport.CaliforniaEnergy

Commission.CEC5002009084.

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Table of Contents

ExecutiveSummary........................................................................................................................... 11.0 Introduction.......................................................................................................................... 32.0 ProjectApproach................................................................................................................. 5

2.1. Task1: Technologies..................................................................................................... 52.2. Task2: CostDrivers...................................................................................................... 62.3. Task3: CurrentCosts.................................................................................................... 62.4. Task4: ExpectedCostTrajectories.............................................................................. 7

2.4.1. Method....................................................................................................................... 92.5. Task5:Price/CostReconciliation................................................................................. 102.6. Task6:CommunityandBuildingScaleRenewableEnergy Costs........................ 11

3.0 ProjectOutcomes................................................................................................................. 133.1. Technologies................................................................................................................... 13

3.1.1. TechnicalandAnalyticalCritiqueofReferenceDocuments.............................. 133.1.2. MethodforSelectingTechnologies........................................................................ 223.1.3. UtilityScaleTechnologies....................................................................................... 233.1.4. CommunityScaleTechnologies............................................................................. 243.1.5. BuildingScaleTechnologies.................................................................................... 24

3.2. Biomass............................................................................................................................ 243.2.1. TechnologyOverview.............................................................................................. 243.2.2. BiomassCombustionFluidizedBedBoiler........................................................ 273.2.3. BiomassCombustionStokerBoiler..................................................................... 353.2.4. BiomassCofiring....................................................................................................... 423.2.5. BiomassCoGasificationIGCC............................................................................... 47

3.3. Geothermal...................................................................................................................... 523.3.1. TechnologyOverview.............................................................................................. 523.3.2. GeothermalBinary................................................................................................. 593.3.3.

Geothermal

Flash

...................................................................................................

68

3.4. Hydropower.................................................................................................................... 72

3.4.1. TechnologyOverview.............................................................................................. 723.4.2. HydroDevelopedSitesWithoutPower............................................................. 753.4.3. HydroCapacityUpgradeforDevelopedSitesWithPower............................ 80

3.5. Solar.................................................................................................................................. 84

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3.5.1. TechnologyOverview.............................................................................................. 843.5.2. SolarParabolicTrough.......................................................................................... 863.5.3. SolarPhotovoltaic(SingleAxis).......................................................................... 96

3.6. Wind................................................................................................................................. 1023.6.1. TechnologyOverview.............................................................................................. 1023.6.2. OnshoreWindClass5........................................................................................... 1063.6.3. OnshoreWindClass3/4........................................................................................ 1173.6.4. OffshoreWindClass5........................................................................................... 117

3.7. Wave................................................................................................................................ 1233.7.1. TechnologyOverview.............................................................................................. 1233.7.2. OceanWave............................................................................................................... 125

3.8. IntegratedGasificationCombinedCycle................................................................... 1273.8.1. TechnologyOverview.............................................................................................. 1273.8.2. IGCCWithoutCarbonCapture(SingleorMultiple300MWTrains)...............1303.8.3. CarbonCaptureandSequestration........................................................................ 136

3.9. AdvancedNuclear......................................................................................................... 1383.9.1. TechnologyOverview.............................................................................................. 1383.9.2. WESTINGHOUSEAP1000................................................................................... 143

4.0 ConclusionsandRecommendations................................................................................. 1575.0 References............................................................................................................................. 1596.0 Glossary................................................................................................................................ 167AppendixA CostData

AppendixB ResponsestoWorkshopComments

List of Figures

Figure1.Utilityscalefluidizedbedgasifier........................................................................................ 25

Figure2.BiomassIGCCplantrepresentation...................................................................................... 26

Figure3.SchematicdiagramofbiomassIGCCprocess..................................................................... 26

Figure4.Utilityscalebiomassfluidizedbedgasifier......................................................................... 27

Figure5.Circulatingfluidizedbedschematicdiagram..................................................................... 28

Figure6.Bubblingfluidizedbedboiler................................................................................................ 30

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Figure7.Stokerboilerschematicdiagram........................................................................................... 35

Figure8.Flowschematicforastokerboilerconfiguration................................................................ 37

Figure9.Biomasscofiringschematicforapulverizedcoalboilersystem...................................... 42

Figure10.

Primary

biomass

cofiring

locations

.....................................................................................

44

Figure11.ProcessflowdiagramforbiomassgasificationandconditioningforIGCCapplication

............................................................................................................................................................ 49

Figure12.Binarypowerplant................................................................................................................ 58

Figure13.Flashpowerplant.................................................................................................................. 58

Figure14.Financialimpactofdelayonexplorationcosts................................................................. 62

Figure15.Specificcostofpowerplantequipmentvs.resourcetemperature................................. 61

Figure16.

Economies

of

scale

.................................................................................................................

63

Figure17.Impoundmenthydropower................................................................................................. 73

Figure18.Diversionhydropowerfacility............................................................................................ 74

Figure19.Runofriverhydropowerfacility........................................................................................ 75

Figure20.Hydropowercostsfordevelopedsiteswithoutpower.................................................... 78

Figure21.Hydropowercostsforincreasingcapacity......................................................................... 82

Figure22.Solarparabolictroughelectricgeneratingsystem............................................................ 84

Figure23.Simplifiedmoltensaltstorageprocessdiagram............................................................... 85

Figure24.NellisAirForceBasePVinstallation.................................................................................. 86

Figure25.Majorcostcategoriesforparabolictroughplant.............................................................. 91

Figure26Capitalcostcomparison........................................................................................................ 94

Figure27.LevelizedO&Mcostcomparison........................................................................................ 95

Figure28.Solarmoduleretail/priceindex,125wattsandhigher..................................................... 99

Figure29.Solarpowergenerationplantsince2006over20%cheaper.......................................... 100

Figure30.Typicalturnkeysystemprice............................................................................................. 101

Figure31.Amodern1.5MWwindturbineinstalledinawindpowerplant............................... 102

Figure32.Californiawindresourcemap........................................................................................... 103

Figure33.WindresourcemapofNorthernCalifornia..................................................................... 104

Figure34.WindresourcemapofSouthernCalifornia..................................................................... 105

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Figure35.CapacityfactortrendsofCaliforniautilitywindsites................................................... 106

Figure36.Installedwindprojectcostsovertime.............................................................................. 109

Figure37.MetalpricesJan.2002Sept.2007(LondonMetalExchange)..................................... 111

Figure38.

U.S.

dollar

vs.

euro,

Jan.

1999

through

April

2009

(European

Central

Bank)

.............

112

Figure39.2007Projectcapacityfactorsbycommercialoperationdate......................................... 112

Figure40.Onshorecapacityfactorbyinstalledyearandclass....................................................... 113

Figure41.AnnualandcumulativegrowthinU.S.windpowercapacity..................................... 114

Figure42.Averagecumulativewindandwholesalepowerpricesovertime.............................. 114

Figure43.Installedwindprojectcostsasafunctionofprojectsize:20062007projects.............115

Figure44.Europeanoffshorewindinstallations............................................................................... 118

Figure45.Europeanoffshorewindgrowthandprojections........................................................... 120

Figure46.Offshorecapacityfactorbyinstalledyear........................................................................ 122

Figure47.Pointabsorber...................................................................................................................... 124

Figure48.Oscillatingwatercolumn................................................................................................... 124

Figure49.Overtopping......................................................................................................................... 124

Figure50.Attenuator............................................................................................................................. 125

Figure51.TypicaloxygenblownIGCCprocess............................................................................... 128

Figure 52. Actual installation (Buggenum, The Netherlands) with typical technological

componentsindicated................................................................................................................... 129

Figure53.BureauofReclamationconstructioncosttrends............................................................. 134

Figure54.Actualvs.PredictedNuclearReactorCapitalCosts...................................................... 139

Figure55:PowerCapitalCostIndexNuclearandNonNuclearConstruction......................... 141

Figure56.Generationsofnuclearenergy........................................................................................... 149

List of Tables

Table1.RecentCalifornialegislationthatmayaffectcostofgeneration.......................................... 1

Table2.Costdriveranalysisworksheetexample................................................................................. 9

Table3.Comparisonbetween2009KEMAanalysisand2007IEPR................................................ 16

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Table4.Comparisonof2009analysiswiththeCPUCGHGmodeldata........................................ 18

Table5.Comparisonbetween2009analysiswiththeRETI1AData............................................... 20

Table6.CentralplanttechnologylistforCOGmodelingproject..................................................... 23

Table7.

Installed

CFB

boiler

capacity

by

country

...............................................................................

29

Table8.Recentcarbonsteelpricing...................................................................................................... 31

Table9.Recentcarbonsteelpricing...................................................................................................... 38

Table10.Biomassstokerinstalledcostranges2009dollarsperkWinstalled............................. 41

Table11.Coalfiredgenerationplantswithbiomasscofiring........................................................... 43

Table12.PotentialbinarygeothermalplantdevelopmentinCalifornia(mostlikelysources)....64

Table13.CaliforniaandNevadaexistingbinaryplantswithcapacityfactor................................ 65

Table14.FixedandvariableO&Mforbinarygeothermalpowerplants........................................ 66

Table15.PotentialflashgeothermalplantdevelopmentinCalifornia(mostlikelysources).......69

Table16.CaliforniaandNevadaexistingflashplantswithcapacityfactor................................... 70

Table17.FixedandvariableO&Mforflashgeothermalpowerplants........................................... 71

Table18.Parabolictroughcostcomparison......................................................................................... 89

Table19.Assessmentofparabolictroughandpowertowersolartechnology.............................. 91

Table20.Comparisonoftotalinvestmentcostestimates($/kWe):SunLabvs.S&L..................... 94

Table21.CSPplantcapitalcostbreakdowns,2005............................................................................. 95

Table22.AnnualCSPO&Mcostbreakdowns,2005.......................................................................... 96

Table23.Californiautilitywindplantinstallationssince2003....................................................... 108

Table24.Sizedistributionandnumberofturbinesovertime........................................................ 113

Table25.Oceanwaveenergycostdata.............................................................................................. 127

Table26.GasificationbasedpowerplantprojectsunderconsiderationintheU.S.beyond2010

.......................................................................................................................................................... 131

Table27.Expectednewnuclearpowerplantapplications.............................................................. 145

Table28.OperatorsofU.S.reactors.................................................................................................... 147

Table29.Nucleardecommissioningcosts.......................................................................................... 154

Table30.Nuclearplantconstructionspendingprofile(%oftotalinstantcostperyear)...........156

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Abstract

This2009reportupdatesthecostofgeneratingelectricityfortechnologiesifbuiltinCalifornia.

CaliforniaEnergyCommissionstaffprovidesfactorsthataffectcosts,includingcost

assumptions,for15renewabletechnologies,coalintegratedgasification,combinedcycle,and

nuclearpowergenerationalternativesforutilityscalegenerationtechnologies.Thesecostsare

usefulinevaluatingthefinancialfeasibilityofagenerationtechnologyandforcomparingthe

costsofbuildingandoperatingoneparticularenergytechnologywithanother.Theseestimates

updatethe2007costofgeneration,basedonempiricaldatacollectedfromoperatingfacilities,

researchfromprimarysources,actualcostsandsurveysofexpectedcostsfromexpertsinthe

field,andreferencedocuments.Thisreportdetailsarangeofinstantandinstalledcostswith

projectedcostsbasedontwoyearsofsignificantgrowthinrenewabletechnologies,changesin

materialcosts,andinflation.

Keywords:Renewableenergy,costofgeneration,biomass,geothermal,hydropower,solar,

parabolictrough,photovoltaic,PV,thermalsolar,windenergy,oceanwave,integrated

gasificationcombinedcycle,IGCC,nuclear

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1

Executive Summary

ThisstudyexaminesthecostsofrenewableelectricitygenerationinCaliforniatosupportthe

costofgenerationmodelingworkoftheElectricityAnalysisOffice. Inadditiontorenewable

electricitycostofgenerationassessment,nuclearandintegratedgasificationcombinedcycle

generation

are

also

examined.

The

California

Energy

Commission

is

tasked

with

developing

robustcostofgenerationestimates,backedbysolidresearchleveragingthefullassessmentof

previousresearchonthecostofgeneration,costdriversandtrends,andexpectedcost

trajectoriesforfuturecosts. AllofthesedataarethenusedbytheEnergyCommissionto

estimatethelevelizedcostofgenerationbytechnology.1

Inthelastseveralyears,Californiahasexperiencedtremendousactivityintherenewable

energymarket,largelydrivenbyseveralkeypiecesoflegislation. Thefollowingtableoutlines

somerecentlegislationthathasbeenadoptedthatislikelytohaveasignificantimpactonthe

costofgenerationforrenewablesaswellasconventionalgeneration.

Table 1. Recent California Legislation That May Affect Cost of Generation

Bill Author YearPassed

Summary

SB1 Murray

(Chapter

132)

2006 SB 1 establishes in statute the California Solar Initiative with a

goal of 3,000 megawatts of new solar produced electricity by

the end of 2016. The California Solar Initiative Program has a

$3.35 billion budget that will be administered by the California

Public Utilities Commission, Energy Commission, and publicly

owned utilities.

SB 107 Simitian

(Chapter

464)

2006 SB 107 accelerates Californias Renewables Portfolio

Standard targets by requiring Californias retail sellers of

electricity to increase renewable energy purchases by at least1 percent per year with a target of 20 percent renewable

energy by 2010. It also requires the publicly owned utilities to

file reports with the Energy Commission that outline their

specific Renewables Portfolio Standard goals and progress

towards the goals.

SB

1250

Perata

(Chapter

512)

2006 SB 1250, combined with SB 107, continues the authorization

of the Energy Commissions ongoing use of public goods

charge funds for the period of 2007-2012 for the continued

operation of the Energy Commissions Renewable Energy

Program.

AB2189

Blakeslee(Chapter

747)

2006 AB 2189 modifies the Renewables Portfolio Standardeligibility requirements for small hydroelectric generation

facilities regarding efficiency improvements that result in

increased capacity.

1Levelizedcostistheconstantannualcostthatisequivalentonapresentvaluebasistotheactualannual

costs,whicharethemselvesvariable.

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Bill Author YearPassed

Summary

AB 32 Nez 2006 Global Warming Solutions Act sets mandatory targets for

greenhouse gas emission reductions. Commits to reducing

greenhouse gas emissions to 2000 levels by 2010 (11 percent

below business as usual), to 1990 levels by 2020 (25 percentbelow business as usual), and 80 percent below 1990 levels

by 2050. Requires the California Air Resources Board and

the Energy Commission to determine baselines and create

systems to track greenhouse gas emissions.

Source: California Energy Commission

TheambitiousgoalsaRenewablesPortfolioStandardof20percentby2010and33percentby

2020,3,000megawatts(MW)ofphotovoltaicsinstalledwithinadecade,andan11percent

reductioningreenhousegasemissionsby2010areambitiousbutachievable.

TheEnergyCommissionsworkinthepreviousintegratedenergypolicyreportsconfirmthat

thetechnicalpotentialforrenewablesinCaliforniaandtheWesternElectricityCoordinatingCouncilregiondwarfsthesegoals. Inaddition,developersofrenewableenergypowerplants

andthesolarphotovoltaicindustryhaverespondedtoincreaseddemandforrenewableenergy

withenthusiasm. TheEnergyCommissionintendstobridgetheestablishedpolicybackdrop

andthesurgingrenewablemarkettoconverttechnicalpotentialintoreality.

KEMA,Inc.(KEMA)performedadetailedassessmentofthegenerationtechnologiesthatmight

beavailableinthenext20years. Foreachtechnology,KEMAassessedcostdriversandtrends

todevelopinputvariablesfortheEnergyCommissionslevelizedcostmodel. Toprovidethis

information,researchersperformedthefollowing:

Literaturereview

and

identification

of

renewable

energy

and

two

non

renewable

energy

technologieslikelytobedeployedinCaliforniaoverthenext20years,alongwith

identificationofthescaleatwhichtheyarelikelytobedeployed.

Costdriversandtrendanalysisforeachlikelycontributingtechnologyandanalysisof

factorsthatdeterminetherange(high,average,andlow)ofexpectedcosts.

Costmodelinputforutilityscaletechnologies,includingcurrentnominalcostsand

plausibleminimumandmaximumcostsforeachutilityscaletechnology,brokendown

intoinputvariablesthatareusedintheEnergyCommissionslevelizedcostanalysis.

Expectedpathsforfuturecostsforutilityscalegenerationtechnologies,plusa

discussionoffactorsthatdeterminethesecosts,asthebasisforcalculatinglevelized

energycosts.

Thefourtopicslistedaboveareaddressedforutilityscaletechnologiesintheinterimproject

report. Thefinalprojectreportwillalsoaddresscommunityandbuildingscaletechnologiesas

wellassummarizekeyfindingsandrecommendations.

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1.0 Introduction

RenewableenergydeploymentinCaliforniaisexpectedtoaccelerateintheneartermin

responsetolegislationidentifyingsupplyportfoliotargetsandclimatemitigationtargets.

Relatedpolicydevelopmentmustbebasedonthebestpossibleeconomicinformation,

especiallythecostofbulkrenewableenergyelectricitygeneration. Inaddition,twonon

renewableenergytechnologiesareexaminedinsupportofthecostofgenerationmodeling

workoftheElectricityAnalysisOfficeandascomparisonstotherenewableenergy

technologies. Thetwononrenewableenergytechnologiesincludedinthisreportarenuclear

andintegratedgasificationcombinedcycle(IGCC). Toprovidethisinformation,four

fundamentaltopicswereaddressed:

Literaturereviewandidentificationofrenewableenergyandtwononrenewableenergy

technologieslikelytobedeployedinCaliforniaoverthenext20years,alongwith

identificationoftheinfrastructurescalesatwhichtheyarelikelytobedeployed.

Costdriversandtrendanalysisforeachlikelycontributingtechnologyandquantitative

analysisoffactorsthatdeterminetherangeofexpectedcosts.

Costmodelinputforutilityscaletechnologies,includingcurrentnominalcostsand

plausibleminimumandmaximumcostsforeachutilityscaletechnology,brokendown

intocategoriesthatareusedinCaliforniaEnergyCommission(EnergyCommission)

levelizedcostanalysis.

Expectedpathsforfuturecostsforutilityscalegenerationtechnologies,plus

quantitativediscussionoffactorsthatdeterminethesecosts,asthebasisforcalculating

levelizedenergycosts.

Thefourtopicslistedaboveareaddressedforutilityscaletechnologiesintheinterimproject

report. Thefinalprojectreportwillalsoaddresscommunityandbuildingscaletechnologies

andthefollowingtwotopics:

Reconciliationofcurrentlyquotedforwardenergypricesandcurrentlyestimated

levelizedcosts,discussingtherelativeimpactofvariousfactorsotherthanovernight

constructioncostthatdeterminepricing. Reconciliationherereferstoexplainingthe

differencesbetweenpricesandcosts,identifyingthefactorsthataccountforthe

differences,andprovidingestimatesofthesizesofthesefactors.

Costsandcosttrajectoriesforcommunityandbuildingscalerenewableenergytechnologies,alongwithminimumandmaximumcostsandtrajectoriesforthesescales.

Theprojectwasundertakentoachievethefollowingobjectives:

Criticallyreview,adjustandaugmentthecontentofAppendixBofEnergyCommission

Report#CEC2002007011SF,December2007(ComparativeCostsofCaliforniaCentral

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StationElectricityGenerationTechnologies,KleinandRednam)inordertocreate

comparableinformationforthe2009IntegratedEnergyPolicyReport(IEPR).

UpdaterenewableenergyandnonrenewableenergyinputsforuseintheEnergy

CommissionsCostofGenerationModel,usedinpreparingthe2009IEPR.

Reconcile

price

and

cost

information

for

representative

utility

scale

power

purchases.

Estimatecostsandtrajectoriesforcommunityandbuildingscaletechnologies.

Thefollowingsectiondescribestheprojectapproachfollowedbyasectiononprojectoutcomes.

TheProjectOutcomessectionofthereportincludesanintroductiontothetechnologiesthat

wereselectedwiththesectionsfollowingorganizedbytechnology.

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2.0 Project Approach

Thissectiondiscussesthetaskstheresearchteamundertookandwhattheteamdidto

accomplishtheprojectobjectives.

2.1. Task 1: Technologies

Theresearchteamundertookthefollowingactivities:

Conductedatechnicalandanalyticalcritiqueofreferencedocuments,including:

ComparativeCostsofCaliforniaCentralStationElectricityGeneration

Technologies2publishedbytheCaliforniaEnergyCommissioninDecember

2007.

CostsandsupplycurvesgeneratedinsupportofCaliforniaPublicUtilities

Commission(CPUC)GreenhouseGas(GHG)ModelingProject.Finalresultsand

GHGCalculatorv2bfromE3.3

CostsestimatesfoundandusedintheRETIPhase1Aand1BreportsbyBlack&

VeatchinRenewableEnergyTransmissionInitiativePhase1A.4

RecommendedutilityscaleREtechnologiesforcostanalysiswithtechnicalandmarket

justification. UtilityscaleREtechnologiesaregenerallydefinedasthoseover20MW.

Identifiedtheprimaryexistingcommercialembodimentofeachutilityscaletechnology

inCalifornia.Thetermcommercialembodimentisintendedtodescribethemost

prevalentcommerciallyavailableapplicationofatechnology.Asanexample,inthecase

ofsolarthermalpower,theprimaryexistingapplicationisconcentratingparabolic

troughcollectors,

augmented

by

natural

gas

fired

boilers

and

supplying

heat

to

steam

Rankinepowerplantsinthe50MWto80MWsizerange.

Identifiedtheexpectedprimarycommercialembodimentin2018.

TheresearchteamwillrevisitTask1forthecommunityandbuildingscaletechnologiesinthe

secondphaseoftheprojectandincludefindingsinthefinalprojectreport.

2Klein,JoelandAnithaRednam.ComparativeCostsofCaliforniaCentralStationElectricityGeneration

Technologies.CaliforniaEnergyCommission,ElectricitySupplyAnalysisDivision,CEC2002007011,

December2007.http://www.energy.ca.gov/2007publications/CEC2002007011/CEC2002007011

SF.PDF.

3GHGCalculatorv2b,updatedon5/13/08.http://www.ethree.com/CPUC_GHG_Model.html.

4Black&Veatch.RenewableEnergyTransmissionInitiativePhase1A(DraftReport).Black&Veatch,RETI

StakeholderSteeringCommittee,ProjectNumber149148.0010,March2008.

http://www.energy.ca.gov/2008publications/RETI10002008001/RETI10002008001D.PDF.

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Pleasealsonotethatthisstudyprovidesestimatesforcostofgenerationtechnologiesbutdoes

notprovidelevelizedlifecyclecostestimatesforthevariousenergytechnologies.5

2.2. Task 2: Cost Drivers

ForeachoftheutilityscaletechnologiesidentifiedinTask1,theresearchteamidentified:

MarketandindustrychangessinceAugust2007thathavemateriallyaffectedcosts.

Currenttrendsthatwillmateriallyaffectfuturecosts.

PrimarygeneralandCaliforniaspecificcostdrivers(e.g.,plantscale,globalindustry

manufacturingscale,resourcequality,plantlocation,capacityfactorincaseofstorage

coupledplants,overnightcost).

2.3. Task 3: Current Costs

ForeachoftheutilityscaletechnologiesidentifiedinTask1,theresearchteamidentified:

Nominal2009costsintheformatrequiredfortheEnergyCommissionslevelizedCost

ofGenerationmodel.

Plausibleminimum,average,andmaximumcostswithtechnicaljustification. Tothe

extentpossible,plausiblemaximumisdefinedasacostmorethanonecompetitive

playerwouldbewillingtopay,andplausibleminimumisdefinedasistheleastcost

recordedabsenthiddensubsidies. Insomecases,uniquesitecharacteristicswerealso

considered.

Theprocessforcompilingdataoftheplausibleminimum,average,andmaximumcostcases

wasdiscussedbetweentheresearchteamandEnergyCommissionstaff. Establishingranges

betweenminimum,average,andmaximumcostscircumscribestherangeofmarketcoststhatwouldreasonablybeencounteredintheactualdevelopment,construction,andoperation

withineachtechnology.

Foreachtechnology,sizerangeswereidentifiedfortotalplantcapacitytodetermineminimum,

average,andmaximumplantcapacitiesinmegawatts(MW). Plantcapacityfactorsandforced

outagerateswerealsodefinedusingminimum,average,andmaximumvalues,reflectingthe

rangesidentifiedthroughresearchedvalues. NorthAmericanEnergyReliabilityCorporation

(NERC)/GeneratingAvailabilityDataSystem(GADS)fleetreliabilitydatawereusedfor

technologieswheredatawasavailable,andinthecaseofwind,solar,andbiomasstechnologies,

otherresearchsourceswereidentified. Plantheatratesandfuelusagedataweresimilarly

modeledforlow/average/highcases,basedonactualoperatingplantcharacteristics;datawas

compiledforeachfossiltechnologyfuelusagereflectinginservicevaluesforgeneratingplants.

5Levelizedlifecyclecostestimatesincludethetotalcostofaprojectfromconstructiontoretirementand

decommissioning.Theresearchteamscostestimatesfornuclearenergydonotincludenuclearplant

decommissioningandwastedisposalcosts.

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Fuelcostestimateswerederivedwithrangesforeachfueltypebasedonpublishedstudiesand

datafromcoal,naturalgas,uranium,andbiomass.

Overnightandinstalledcapitalcostvaluesforminimum,average,andmaximumcostswere

definedthroughtwoapproaches. Forovernightcosts,capitalcostrangesweredeveloped

throughdocumented

plant

cost

histories

and

adjusted

for

capacity

scaling

effects,

noting

that

theovernightcostperkilowattdependsonthetotalcapacityoftheplant. Furtheradjustments

toovernightcostweremadetoreflectthecostdriveranalysis,showinglearningeffectsof

cumulativegeneration. Theseexperiencecurveeffectswerereflectedontheyeartoyear

overnightcostswithinthegenerationtechnologydataset.

Forinstalledcapitalcostvalues,thelow/average/highcasesweredevelopedprimarilythrough

theuseofdifferingconstructiontimedurationswheresuchdatacouldbeverifiedbythe

researchteam. Thisdatareflectstheuncertaintyinconcepttocompletiontimeforeach

technologyandresultsincostimpactduetoadditionalinterestcostsandallowanceforfunds

usedduringconstructioncharges(AFUDC).

Theuseandapplicationofrenewableenergyandothertaxincentiveswerealsoconsideredand

modeledwiththeinputdatasettodeveloplow/average/highcostdatavalues. Thesetax

incentiveswereappliedforeachtechnology,basedontheircurrentvalidityandspecific

applicationforeachtechnology.

Thedatasetcontainscellsforlow/average/highvaluesforeachinputtothecostofgeneration

model,andeachspecificinputismodeledwithitsownlow/average/highcostrange. Onemay

notdrawtheconclusionthatthesecostsarespecifictoaparticularsizeprojectforexample,

thelowplantcapacityautomaticallygeneratesthehighestoperatingcost. Instead,thedatasets

werecompiledsothateachtechnologydimension(e.g.,capacity,forcedoutagerate,heatrate,

overnightcost)

has

its

own

low/average/high

range

and

is

not

associated

with

arelative

capacityorsizeproject.Inthatway,thedataismodeledsuchthattherangeofinputsdefining

low/average/highcostsreflectboundariesforeachtechnology;andtheminimumcost

representsthelowestplausiblerangeofcost,andthemaximumcostrepresentsthehighest

plausiblerangeofcostforeachtechnology.

2.4. Task 4: Expected Cost Trajectories

Theresearchteamdevelopedaspreadsheetmodelusingcostdriverinformationtoestimate

futurecosttrajectories(costsexpectedineachyearfrom20092029)oftherecommendedutility

scaletechnologiesidentifiedinTask1.

Thespreadsheetmodeltodevelopexpectedcosttrajectoriesforeachtechnologywasdeveloped

usingtheconceptoflearningeffectsandtheexperiencecurve. Experiencecurvesareusedin

developingtechnologypolicybecausetheyshowthemarketeffectsofincreasedcumulative

production. Asthemarketadoptsanewenergytechnology,manufacturersgaineconomiesof

scaleduetoincreasedproduction,andtheylearnhowtoimprovethetechnology. Bothofthese

factorsovertimecanlowerunitcostsofproduction.

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Theprimarydefinitionofexperiencecurveeffectsiscapturedinwhatistermedtheprogress

ratioforatechnology. Simplyput,theprogressratioistheexpectedpercentagedecreasein

unitcost,basedonadoublingofcumulativeoutputofthattechnology. Asanexample,a

technologythathasaprogressratioof0.90wouldindicatethatadoublingofinstalledunitsfor

thattechnologychoicewouldresultina10%unitcostreduction.6

Energytechnologiesgenerallyhavetechnologyprogressratiosintherangefrom0.70to1.00,

withthelowernumberindicatingarapidlearningrateandloweringofunitcostsovertime

(newtechnologydeployment)andprogressratiosclosetounityreflectingextremelymature

technologieswithonlysmall,incrementallearningeffects.

Theresearchteamnotedthatitispossiblefortechnologiestoexhibitchangesinprogressratios

overtime,duetoseveralfactors:

DisruptiveTechnologyAdvancesbreakthroughdevelopmentsinatechnologythat

significantlyaffectunitcostand/orpaceoflearningforamanufacturer.

Price

Subsidies

Artificial

price

subsidies

can

alter

the

balance

between

experience

and

learning,andmitigatelearningeffects,sincethepricesignalisnotatruecompetitive

marketsignal.

ChangesinMacroeconomicFundamentalsTheycanaffectsupply/demandbalance

andadoptionratesoftechnologies,enhancingorinhibitinglearningeffectsofadditional

production.

Thesechangesovertimedemonstratethatonevalueforprogressratioandexperienceeffectsis

generallynotsuitableformodelingtheexperiencecurveovertime,especiallyforthose

technologieswithhighlearningeffects. Theresearchteamthusmodeledarangeoflearning

effects,withdocumentedprogressratiosforeachtechnologymodifiedthroughtheuseofkey

costdriversthatwereidentifiedforeachtechnologychoice.

Inthemodelingoftheselearningeffects,thetechnologyprogressratioandexperienceeffects,

whichtypicallyrangefrom0.70to1.00,weremodifiedthroughtheuseofcostdriverratesof

changeratios. Thesecostdriverratiosbeginatunity(1.00)asabasecase,whichreflectsthe

normal,expectedexperiencecurve,andtheratioscanbeweightedasgreaterthanunity,which

implyalesserlearningeffect,orlessthanunity,whichimplyagreater,acceleratedlearning

effectthanthenormalexperiencecurve.

Costdriversweresubjectivelyevaluatedbasedontwofactors: importanceweighting(how

importantthedriveristothetechnologycostimprovement)andlow/highrangestoreflectthe

subjectivevariationinlearningeffect. Foreachtechnologyandtheresearchedtechnology

6InternationalEnergyAgency.ExperienceCurvesforEnergyTechnologyPolicy.OrganizationofEconomic

CooperationandDevelopment(OECD),2000.

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progressratio,eachcostdriverwasmodeledatunityfortheaveragecaseandthenmodifiedfor

thelow/highcasesbasedontheresearchteamtechnicalfindingsandjudgment.

Amodifiedprogressratio,calculatedastheproductoftheexpectedtechnologyexperience

curve(shownasTechnologyProgressRatiointheexamplebelow)andtheweightedaverage

costdriver

effect,

combines

the

effects

of

the

baseline

technology

experience

curve

and

identifiedcostdriversthatmighteitheraccelerateordeceleratethecostimprovements

associatedwithanincreaseinthecumulativeinstalledbaseforeachtechnology. Thismodified

progressratioisusedforfinalcostmodelingforeachtechnology.

Theweightedaveragecasesforlow/average/highcostdrivereffectsusingthemodified

progressratiowerethenmodeledusingthestandardexperiencecurveequationandyearover

yearpricechangesidentified. Thesepricechangeswereusedtodeveloptheforecasted

overnightcostsforeachtechnology.

2.4.1. Method

Theexperiencecurveeffectsandcostdriversweredevelopedforeachtechnologybycombining

theexpectedvariabilityinidentifiedcostdriverswiththepublisheddatareflectingtheexpected

learningcurveeffectsforeachrenewableenergytechnology,aspublishedbytheU.S.

DepartmentofEnergy(DOE)andotherindustrysources. Theresearchteammodifiedthe

experiencecurveeffectsbytheweightedimpacteachcostdrivercouldhaveonthetechnology

anditscosttrajectory.

AmodelwasdevelopedtocalculatetheseimpactsandisshownbelowinTable2:

Table 2. Cost Driver Analysis Worksheet Example

Cost Driver Analysis

Technology: Onshore Wind 7

Technology Progress Ratio: 0.900

Rate of Change

Cost Driver Percentage Low Average High

1 Turbine Costs 75.0% 0.95 1.00 1.10

2 Reliability 10.0% 0.97 1.00 1.04

3 Permitting/Site Selection 5.0% 0.98 1.00 1.02

4 Land Acquisition 5.0% 0.99 1.00 1.01

5 Transmission Costs 5.0% 0.97 1.00 1.10

Total and Averages: 100.0% 0.96 1.00 1.09

Modified Progress Ratio: 0.86 0.90 0.98

Source: KEMA

Forexample,theabovesheetshowsthecalculationsmadefortheonshorewindrenewable

technology. Thetechnologyprogressratioforonshorewindisidentifiedas0.90asabaseline

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fromindustrypublisheddata.7 Thisbaselinevalueforexperiencecurveeffectsisthen

subjectivelyadjustedbyeachcostdriverratio,andthenaweightedaverageistakenthattakes

thesubjectiveeffectsofthesecostdriversintoaccount.

Thecalculatedweightedaverageisthenshownasthemodifiedprogressratio,ortheexpected

rangein

learning

curve

effects

with

additional

cumulative

capacity

over

time.

In

the

case

above,theexpectedrangeinmodifiedprogressratioisfromalowvalueof0.86toahighvalue

of0.98,whichimpliesthatwithadoublingofoverallinstalledcapacity,theexpecteddecrease

incostswouldbebetween2%and14%,withanaverageexpecteddecreaseof10%.

Thenextstepincomputingexperiencecurveeffectsandoverallcosttrajectoriesisdeveloping

reliableestimatesforcumulativeinstalledcapacityforeachtechnology. Thiswasdonethrough

twoprimaryresearchsources:theEnergyInformationAdministrations(EIA)AnnualEnergy

Outlookfor20098andEuropeanWindEnergyAssociations(EWEA)PurePowerreport,9

whichprovidesglobaldataforoffshorewindtechnologyadoption. Cumulativeinstalled

capacityforecastswerecompiledforeachtechnologyusingthisreferencesourcedata.

Theoverallcosttrajectorydevelopedinayearoveryearfashionwascomputedusingthe

standardexperiencecurveformula:

1_

__

Y

Y

GenerationCumulative

GenerationCumulativeRatioCost ^ln

2

_Pr_ RatioogressModified

Thiscostratiowasdevelopedinthecostdriverdataworksheetsforeachtechnologyandthen

usedtoadjusttheforecastedyearlycostsforeachtechnology.

2.5. Task 5: Price/Cost Reconciliation

Inalaterphaseoftheproject,theresearchteamwill:

AnalyzepubliclyavailablepricinginformationforrepresentativeutilityscaleREpower

purchasesinCalifornia.

Reconcilerepresentativepricesandestimatedlevelizedlifecyclecosts,includingthe

relativeimpactoffactorsotherthancostthatdeterminepricing,e.g.,stateandfederal

incentivesandtaxpolicies,financingassumptions,andthecostofcredit.

TheprojectoutcomesfromtheresearchteamsanalysisforTask5willbepresentedinthefinal

projectreport.

7U.S.DOE.EnergyInformationAdministration.LearningCurveEffectsforNewTechnologies.

8U.S.DepartmentofEnergy.EnergyInformationAdministration. AnnualEnergyOutlook2009

(AEO2009).DOE/EIA0383(2009),March2009.

9Zervos,Arthourous,ChristianKjaer,.PurePower:WindEnergyScenariosupto2030.EuropeanWind

EnergyAssociation,March2008.

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2.6. Task 6: Community and Building Scale Renewable EnergyCosts

Inalaterphaseoftheproject,theresearchteamwill:

IdentifysourcesofrelevantU.S.costinformationforrenewableenergyheatingand

coolingtechnologies.

Estimatenominalcostsandexpectedcosttrajectoriesforrecommendedcommunity and

buildingscaleREtechnologies.

Presentplausibleminimumandmaximumcostsandcosttrajectoriesforsame,with

explanationoffactorsthatvaryandcausecoststovary.

TheprojectoutcomesfromtheresearchteamsanalysisforTask6willbepresentedinthefinal

projectreport.

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3.0 Project Outcomes

Thissectionpresentstheresearchresults. ThetechnologiesselectedinTask1arepresentedin

Section3.1alongwithadescriptionofthemethodforselectingthetechnologies. Notethatthe

communityandbuildingscaletechnologieswillbeincludedinthefinalprojectreport. The

sectionsfollowing3.1areorganizedbytechnologyandincludeoutcomesfromTasks2,3,and4.

3.1. Technologies

Theresearchteamconductedatechnicalandanalyticalcritiqueofreferencedocumentsinorder

torecommendtechnologiesforcostanalysis. Theinterimprojectreportincludestheresearch

teamsrecommendationsforutilityscaletechnologies(i.e.,>20MW). Thefinalprojectreport

willincluderecommendedcommunityscaleREtechnologies(i.e.,120MW)andbuilding

scaleREtechnologies(i.e.,

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Transmissioncosts

Integrationcosts

Environmentalbenefitsandotherexternalities

Generationcostsarealwaysconsideredsincetheygenerallyformthebasisofcostestimation.

Treatmentoftransmissioncosts,integrationcosts,andenvironmentalbenefitsisnotconsistent

andtreatmentofexternalitiesisevenlesscommon.

Thethreestudiesarebrieflydescribedbelowfollowedbycomparisontablesofkeyinput

assumptions.

2007 Cost of Generation Report

TheEnergyCommissionsCostofGenerationReport(COG)provideslevelizedcostestimates

forvariouscentralstationgenerationtechnologiesinCalifornia. Thelevelizedcostestimates

weredevelopedusingtheEnergyCommissionsCostofGenerationModelwhichwasinitially

developedtosupportthe2003Integrated

Energy

Policy

Report(IEPR). The2007Costof

GenerationReportusedanewlyrefinedCostofGenerationModeltoestimatethelevelized

costsofenergyforthreeclassesofdevelopers:investorownedutilities,publiclyownedutilities,

andmerchantplants. Thereportsummarizesthelevelizedcostestimatesinaclearandconcise

mannerforeightconventionaltechnologiesandtwentyrenewabletechnologiesforthethree

classesofdevelopers. Italsodocumentskeyinputassumptionsandcomparesthe2007input

assumptionstothoseusedinthe2003IEPRforecastandEIAestimates. Ageneraldescription

oftheEnergyCommissionsModelandmethodisprovidedaswellasuserinstructionsand

explanationofthescreeningandsensitivityanalysiscomponentsoftheModel.

CPUC 2008 GHG Modeling Project

ThecostandsupplycurvesgeneratedbytheCaliforniaPublicUtilitiesCommission(CPUC)

GHGModelingProjectin2008provideabenchmarkforwhichtocomparethekeyassumptions

andlevelizedcostestimatesprovidedinthisstudy. TheanalysisusedaGHGcalculator

developedbyE3andreviewedthroughthestakeholderprocessundertheCPUCGHGdocket

R.0604009.

TheCPUCisscheduledtocompletethefirstphaseoftheimplementationanalysisinearly2009.

Theintentistoconductarenewablepenetrationbarrieranalysisandtodevelopplausible

resourceportfoliosforCaliforniaIndependentSystemOperator(CaliforniaISO)toanalyze

further.13 Inaddition,theanalysiswillestimatenetcostandrateimpacts,lookingatcostand

rateimpacts

of

the

33%

Renewables

Portfolio

Standard

(RPS)

portfolio

relative

to

a20%

RPS

referencecasebaseline. ThoughtheresultsoftheCPUC2009analysisarenotyetavailable,

KEMAassessedthestudybasedonpubliclyavailablepresentations.14 AccordingtoaCPUC

13Thestudydoesnotrecommendoptimalrenewableresourceportfolios.

14CPUC,Aspen,E3,andPlexos. 33%ImplementationAnalysisWorkingGroupMeeting.CPUC,2008.

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presentation,RETIprovidedusefulinputsforthe2008CPUCGHGModelingProjectandthe

pendingCPUC33%ImplementationAnalysis.

TheE3calculatorconsidersfactorssuchasintegrationcostsandrenewableimpactonwholesale

prices. Thestudyperformedasensitivityanalysisthatdeterminedfourkeydriversofresultsin

theelectricity

sector:

Loadgrowthassumptions.

Fuelprices.

EEachievements.

Carbondioxide(CO2)marketcosts.

InclusionofCO2marketcostshasbecomeincreasinglyimportantforplanningpurposesin

California. AccordingtoE3,CO2costsaretreatedasanexogenousinputtothemodel. The

analystusingtheGHGcalculatorinputsaCO2price,aswellasanyassumptionsaboutoffset

prices,andwhetherCO2permitsareauctionedorallocated,amongotherCO2marketdesign

questions.CO2costsarethencalculatedandallocatedtoloadservingentitiesdifferentlybased

ontheselectedscenario. CO2costsaretrackedonlyforretailprovidersandCO2coststo

existinggeneratorsarenottracked.

RETI 1A 2008 and IB 2009 Studies

AccordingtotheRETIReport,RETIsgoalistoidentifytransmissionfacilitieslikelytobe

requiredtomeeta33%RPSrequirementbytheyear2020. TheRETIIB2009studydeveloped

informationforrankingpotentialrenewableresourcesgroupedbygeographicproximity,

developmenttimeframe,sharedtransmissionconstraints,andeconomicbenefits. Italso

estimatedthe

value

of

energy

by

considering

time

of

day

and

capacity

value

of

resource

(contributiontosystemreliability). Itthenconductedahighlevelscreeninganalysisranking

therenewablezonesbycosteffectiveness,environmentalconcerns,developmentandschedule

uncertainty,andotherfactors. Therenewablesresourcesrankingbygroupingisintendedto

assistintransmissionplanning.

TheRETIanalysishasnotyetincludedintegratedcostsinitsmethod. However,itappearsthat

thereisaplantoincludethesecostsmaybeincludedinfutureRETIanalysesshouldthe

informationbedevelopedinanappropriatemannerthatitwarrantsinclusioninthecost

estimates. Forinstance,furtherinformationonintegrationcostsareneededtosupport

estimatesonthecosttointegrateintermittentwindandsolarresources.

TransmissioncostscalculatedbyBlack&VeatchandusedinthePhase1economicranking

assumesimultaneousdeliveryofthefullnameplategeneratingcapacityofeverycompetitive

renewableenergyzone(CREZ).Thisconservativeapproachisappropriateforahighlevel

screeninganalysisyetwithoutdoubtoverstatestheamountandcostofthetransmission

facilitiesnecessarytomeetcurrentstateGHGandrenewableenergygoals.

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ThemethodemployedbytheRETIteamincludesscenarioanalysistoanalyzetheeffectsof

differentpolicyscenarios,resourceportfoliosandtechnologyoptionsandcosts. Thismethod

allowedtheRETIanalysistoassesstheimpactsofuncertaintyontherankingprocess. TheRETI

analysisalsoappearstoincludecarboncostsbasedonaGHGadder.

Comparison of 2009 Analysis With the 2007 IEPR Data

Thefollowingtableprovidesacomparisonofthekeyassumptionspresentedinthe2007IEPR

andKEMAs2009analysis.

Table 3. Comparison between 2009 KEMA analysis and 2007 IEPR

Technology Gross

Capacity

(MW)

Capacity

Factor (%)

Instant Cost

($/KW)

Fixed O&M

($/kW-Yr)

Variable O&M

($/MWh)

2009

KEMA

2007

IEPR

2009

KEMA

2007

IEPR

2009

KEMA

2007

IEPR

2009

KEMA

2007

IEPR

2009

KEMA

2007

IEPR

Biomass Combustion -

Fluidized Bed Boiler28 25 85% 85% $3,200 $3,156 $99.50 $150.26 $4.47 $3.11


Stoker Boiler38 25 85% 85% $2,600 $2,899 $160.00 $134.72 $6.98 $3.11

Biomass Cofiring 20 N/A 90% N/A $500 N/A $15.00 N/A $1.27 N/A

Biomass - IGCC 30 21.25 75% 85% $2,950 $3,121 $150.00 155.44 $4.00 3.11

Geothermal - Binary 15 50 90% 95% $4,046 $3,093 $47.44 $72.54 $4.55 $4.66

Geothermal - Flash 30 50 94% 93% $3,676 $2,866 $58.38 $82.90 $5.06 $4.58

Hydro Small Scale or

Developed Sites15 10 30% 52% $1,730 $4,125 $17.57 $13.47 $3.48 $3.11

Hydro Capacity

Upgrade80 N/A 30% N/A $771 N/A $12.59 N/A $2.39 N/A

Solar - Parabolic Trough 250 63.5 27% 27% $3,687 $4,021 $68.00 $62.18 $0.00 $0.00

Solar - Parabolic Trough

with Storage250 N/A 65% N/A $5,406 N/A $68.00 N/A $10.30 N/A

Solar - Photovoltaic

(Single Axis)25 1 27% 22% $4,550 $9,611 $68.00 $24.87 $0.00 $0.00

Onshore Wind - Class 5 100 N/A 42% N/A $1,990 N/A $13.70 N/A $5.50 N/A

Onshore Wind

Class 3/450 50 37% 34% $1,990 $1,959 $13.70 $31.09 $5.50 $0.00

Offshore Wind - Class 5

(2018 start date)100 N/A 45% N/A $5,588 N/A $27.40 N/A $11.00 N/A

Ocean Wave (2018 start

date)40 0.75 26% 15% $2,587 $7,203 $36.00 $31.09 $12.00 $25.91

Coal - IGCC 300 575 80% 60% $2,250 $2,198 $41.70 $36.27 $6.67 $3.11

Nuclear: Westinghouse-

AP1000960 1000 86% 85% $4,000 $2,950 $147.70 $140.00 $5.27 $5.00

Source: KEMA and 2007 Integrated Energy Policy Report

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NotestoTable:IfN/Aislisted,nodatawasavailable. Thehydrodevelopedsitescategoryisanalogoustothe

hydrosmallscalecategoryusedinthe2007IEPR. Grosscapacityreferstothegrosselectricalgenerationoutput,

Capacityfactorreferstothefullloadequivalentoperationalpercentageforaunit,andinstantcostreferstothe

costtobuildaunitimmediately(withoutconstructioninterestorescalationeffects). Theinstantcostfornuclear

energydoesnotincludedecommissioningornuclearwastedisposalcosts.

Keyobservationsinclude:

Thehydroelectricfordevelopedsiteswithoutpowerdiscrepancyininstantcostsis

primarilyduetoestimatedlicensingandmitigationcosts. KEMAexaminedtheIdaho

NationalLaboratory(INL)databaseofpotentialsitesandfoundthattheaverage

mitigationcostsweresubstantiallylessthanwhatwasestimatedin2007.

Thecapacityfactorforthehydrowasdeterminedthroughananalysisofexisting

hydroelectricplantsinCalifornia. Throughthisanalysis,theaveragecapacityfactorwas

foundtobemuchlowerthanthe2007IEPRestimate.

Solarphotovoltaic(PV)singleaxisinstantcostshavedecreasedsubstantiallysincethe

2007IEPR. Thesedecreasingcosttrendsareconsistentwithseveralresearchand

financialsourcesaswellassignificanteconomiesofscaleassociatedwiththechange

froma1megawatt(MW)unittoa25MWinstallation. Section3.5.3providesfurther

documentationofKEMAsassumptionsandsourcedocuments.

Oceanwaveisanewtechnologyresourcecategoryatthecentralscaleprojectlevelthat

isscheduledtobecomeaviableresourceinthe2018timeframe. Theinstantcostsarenot

directlycomparablebetweena40MWsystemandthe0.75MWpilotprojectthatwas

includedinthe2007IEPRanalysis.

The2007IEPRanalysisdidnotcoverClass5windspecifically. Rather,theyincluded

onebroadwindcategorythatalignscloselywithClass3and4. Thedataalignsquite

nicelybetweenthetwostudies. Costsperunitofcapacityandenergyareexpectedto

declineasmachinesizeandoutputperunitincreases.

Offshorewindisanewcategoryinthe2009analysisandisscheduledtocomeonlineinthe

2018timeframe. Offshorewindinstantcostsareestimatedtobeapproximatelytwicethatof

onshorewind.

ThecoalIGCCcapacityfactorissubstantiallyhigherintheKEMA2009analysis. Thischangeis

basedonactualplantdataandwarrantedbecauseastechnologiesmaturecapacityfactorstend

toincrease.

Theinstantcostofnuclearishigherinthe2009analysisversusthe2007IEPRestimate. The

KEMAdataisbasedontheWestinghouseAP1000system,and,asdiscussedinSection3.8of

thisreport,thenucleardataiswellsubstantiatedbyseveralresearchandfinancialsources. In

addition,theinformationisconsistentwithdataavailablefrommajoroperatorssuchasFlorida

PowerandLight,GeorgiaPower,andSouthCarolinaElectricandGasCompany.

The2009IEPRcostofgenerationreportwilladdtothepreviousanalysesofrenewable

resourcesinthefollowingmanner:

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Thecostestimateswillbepresentedasarange(high,mid,low)ofestimatestoreflectthe

uncertaintyandotherfactorsthataffectprojectcosts.

Installedcostshavebeenaddedthatincludethecarryingcostofcapitalduringthe

averageconstructionperiods.

Include

explicitly

cost

trajectories

affected

by

specific

influences

into

the

future.

Clearlyincludingfinancingandotherconstructionrelatedcostsbeyondengineering

estimates.

Providingexplicitreferencedocumentationforrenewabletechnologies.

Assessingofcostsforcommunityorbuildingscaletechnologies.

Comparison of 2009 Analysis With the CPUC GHG Modeling Project

KEMAs2009analysisiscomparedtothedatathatwaspresentedintheCPUCGHGmodeling

projectinthefollowingtable.

Table 4. Comparison of 2009 analysis with the CPUC GHG model data

TechnologyGross Capacity

(MW)*

CapacityFactor (%)

Instant Cost($/KW)

Fixed O&M($/kW-Yr)

Variable O&M($/MWh)

2009KEMA

CPUCE3 Data2008$

2009KEMA

CPUCE3

Data2008$

2009KEMA

CPUCE3

Data2008$

2009KEMA

CPUCE3 Data2008$

2009KEMA

CPUCE3

Data2008$

Biomass1

1 85% $3,737 $107.50 $0.01

BiomassCombustion -Fluidized Bed Boiler

28 85% $3,200 $ 99.50 $ 4.47

BiomassCombustion - StokerBoiler

38 85% $2,600 $160.00 $ 6.98

Biomass Cofiring 20 90% $500 $ 15.00 $ 1.27

Biomass - IGCC 30 75% $2,950 $150.00 $ 4.00

Geothermal2

1 90% $3,011 $154.92 $ -

Geothermal - Binary 15 90% $4,046 $47.44 $ 4.55

Geothermal - Flash 30 94% $3,676 $58.38 $ 5.06

Hydro - Small Scaleor Developed Sites

15 1 30% 50% $1,730 $2,402 $17.57 $13.40 $ 3.48 $3.30

Hydro CapacityUpgrade

80 N/A 30% N/A $771 N/A $12.59 N/A $2.39 N/A

Solar - ParabolicTrough

250 1 27% 40% $3,687 $2,696 $68.00 $49.63 $ - $ -

Solar - ParabolicTrough with Storage

250 N/A 65% N/A $5,406 N/A $68.00 N/A $10.30 N/A

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TechnologyGross Capacity

(MW)*

CapacityFactor (%)

Instant Cost($/KW)

Fixed O&M($/kW-Yr)

Variable O&M($/MWh)

Solar - Photovoltaic(Single Axis)

25 27% $4,550 $68.00 $ -

Wind3 1 37% $1,931 $ 28.51

Onshore Wind -Class 5

100 42% $1,990 $13.70 $ 5.50

Onshore Wind -Class 3/4

50 37% $1,990 $13.70 $ 5.50

Offshore Wind -Class 5 (2018 startdate)

100 N/A 45% N/A $5,588 N/A $27.40 N/A $11.00 N/A

Ocean Wave (2018start date)

40 N/A 26% N/A $2,587 N/A $36.00 N/A $12.00 N/A

Coal - IGCC 300 1 80% 85% $2,250 $2,388 $41.70 $ 36.36 $ 6.67 $2.75

Nuclear:Westinghouse -AP1000

960 1 86% 85% $4,000 $3,333 $147.70 $ 63.88 $ 5.27 $0.47

Notes: Source for CPUC E3 data is GHG Calculator v2b (May 2008).15

1) Biomass is listed as generic category in the CPUC GHG Model

2) Geothermal is listed as generic category in the CPUC GHG Model

3) Wind is listed as a generic category (no Class is listed)

* Capacity MW was listed as 1 MW in all cases

Source: KEMA and CPUC

Keyobservationsinclude:

CostcharacterizationsandheatratesintheGHGmodelcomeprimarilyfromtheEIA

2007AnnualEnergyOutlookReport.16

Directcomparisonofdataisdifficultduetolackofdataonunitsizeassumptions.

TheCPUCdatadoesnotincludesolarsingleaxisPVsystems,despiterecent

announcementsinCaliforniaforlargerscalecentralizedPVsystemapplications.

TheCPUCsolarthermalinstantcostestimatesaresubstantiallylowerthanthe2007

IEPR,a2006NationalRenewableEnergyLaboratory(NREL)studyandKEMAs2009

estimate

for

reasons

that

are

not

easy

to

identify.

KEMAs

cost

data

is

based

on

a

2006

NREL/Black&Veatchstudyandindependentresearchoncapitalcostsofprojectsin

SpainandtheUnitedStates. Costestimatesanddiscussionofmajormarketdriversare

includedinSection3.5.2.

15http://www.ethree.com/CPUC_GHG_Model.html. E3GHGCalculatorv2b,May2008.

16U.S.DOE.EnergyInformationAdministration.AssumptionstotheAnnualEnergyOutlook.2007.

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KEMAsClass3and4winddataalignscloselywiththeCPUCdata. E3benchmarked

windcoststoarecentAmericanWindEnergyAssociation(AWEA)study.

AllcostsintheGHGmodelwereinflatedby25%peryearfortwoyearstoreflectthe

recentrapidinflationinconstructioncosts. Giventherecentdownturnintheeconomy,

thisassumptionmaynolongerbeappropriate.

TheCPUCGHGmodelincludessitespecifictransmissioninterconnectiondistancesfor

geothermal,solarthermal,windandhydro. Conversely,KEMAs2009assessment

includestransmissioncostsandvoltageconversionfromthegenerationplanttothe

localfirstpointofinterconnectiontothetransmissionordistributionnetwork.

TheCPUCdataincludeswindandsmallhydroincludefirmingresourcecostsbasedon

costofCTsneededtoreach90%availabilityonpeak. KEMAsassessmentdoesnot

includefirmingresourcecosts.

Comparison of 2009 Analysis With the RETI Project (Phase 1A and 1B)

The2009analysisiscomparedtothedatathatwaspresentedinRETI1Areportinthefollowing

table.

Table 5. Comparison between 2009 Analysis with the RETI 1A Data

Technology Gross

Capacity

(MW)

Capacity

Factor (%)

Instant Cost

($/KW)

Fixed O&M

($/kW-Yr)

Variable O&M

($/MWh)

2009 RETI

1A

2009 RETI

1A

2009 RETI

1A

2009 RETI

1A

2009 RET

1A

Solid Biomass1

35 80% $4,000 $83 $11.0


Fluidized Bed Boiler*28 85% $3,200 $99.50 $4.47


Stoker Boiler*38 85% $2,600 $160.00 $6.98

Biomass Cofiring 20 35 90% 85% $500 $400 $15.00 $10 $1.27 $0.00

Biomass - IGCC 30 N/A 75% N/A $2,950 N/A $150.00 N/A $4.00 N/A

Geothermal2

30 80% $4,000 $0 $27.5

Geothermal Binary 15 90% $4,046 $47.44 $4.55

Geothermal - Flash 30 94% $3,676 $58.38 $5.06

Hydro - Developed Sites

or New as listed in RETI15

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Technology Gross

Capacity

(MW)

Capacity

Factor (%)

Instant Cost

($/KW)

Fixed O&M

($/kW-Yr)

Variable O&M

($/MWh)

Solar - Parabolic Trough

with Storage250 N/A 65% N/A $5,406 N/A $68.00 N/A $10.30 N/A

Solar - Photovoltaic

(Single Axis)25 20 27% 28% $4,550 $7,000 $68.00 $35 $0.00 $0.00

Wind3

100 32% $2,150 $50 $0.00

Onshore Wind - Class 5** 100 42% $1,990 $13.70 $5.50

Onshore Wind - Class 3/4 50 37% $1,990 $13.70 $5.50

Offshore Wind - Class 5 100 200 45% 40% $5,588 $5,500 $27.40 $88.00 $11.00 $0

Ocean Wave 40 100 26% 35% $2,587 $4,000 $36.00 $210 $12.00 $11.0

Coal IGCC 300 N/A 80% N/A $2,250 N/A $41.70 N/A $6.67 N/A

Nuclear: Westinghouse -

AP1000960 N/A 86% N/A $4,000 N/A $147.70 N/A $5.27 N/A

Notes:

1) RETI 1A Solid Biomass.

2) Only one category of geothermal is listed in the RETI 1A Report.

3) Only one category of onshore wind is listed in the RETI 1A Report.

If ranges were presented in RETI 1A data, midpoints are listed in the table

Source: KEMA, Black & Veatch RETI 1A Report, 2008

Keyobservationsincludethefollowing:

Forthemostpart,theKEMAanalysisisfairlyconsistentwiththeRETIdata.

InformationonunderlyingassumptionsinRETIreportonthetwohydrocategoriesis

limited. Therefore,itisdifficulttoassesswhycostestimatesvarybetweenKEMA2009

dataandtheRETIIAdata.

TheRETIIAinstantcostdataforsolarparabolictroughappearstoalignnicelywith

KEMAsdata.

TheinstantcostforsolarPVsingleaxissystemsissignificantlylowerintheKEMA

studythantheRETIanalysis. TheKEMAdataisstronglysupportedbyrecentdeclining

pricetrendsasdiscussedinSection3.5.3.

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Summary

MoreandmorestudiesthatassesscostofachievingRPSgoalsaretakingmacroeconomicand

externalitybenefitsintoaccount. Forinstance,somestudiesarenowassessingmacroeconomic

benefitsofrenewablegenerationincludingbenefitsassociatedwithgrowthintheclean

technologyindustryandemployment. Externalitiesshouldalsopotentiallybeexaminedeither

onaqualitativeorquantitativebasis. Forinstance,thebenefitassociatedwithrenewablesinhelpingtoserveasahedgeagainstthepriceoffossilfuelcouldpotentiallybequantified.

Futurestudiesshouldconsiderincluding:

CO2abatementcosts.

Qualitativeorquantitativeassessmentofotherkeyissuesthatmayinfluencecostsof

generationincluding:

Environmentalsensitivity.

Landuseconstraints.

Permittingrisk.

Transmissionconstraintsandequityissuesrelatedtowhobearsthecostofnew

transmission.

Systemintegrationcosts.

Systemdiversity.

Taxcreditavailabilityandstructure.

Financingavailability.

Macroeconomicbenefits(jobscreation,security,fueldiversity,etc.).

Natural

gas

price

and

wholesale

price

effects

associated

with

increased

penetrationofrenewables.

Otherriskfactors.

3.1.2. Method for Selecting Technologies

Theresearchteamusedthefollowingscreeningcriteriatoselectthemajorityoftechnologiesfor

costanalysis:

Isthetechnologycommerciallyavailableandinuseonanylevelotherthana

demonstrationphase?

ArethereanumberofprojectsinuseintheUnitedStatesorabroadthatusethis

technology?

IsthisaviabletechnologyforuseinCaliforniaorinneighboringstates? Ifso,whatis

theproductionpotential?

ArethereanyregulatoryissuesorotherrestrictionsforuseinCalifornia?

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Isthereanyactualcostdataavailablefortheexistinginstallationsthatcanbeusedinthe

study?

Costanalysisforthetechnologiesthatpassedthesescreeningtechnologieswasconductedto

providedatastartingin2009(i.e.,currentstartdata). Inseveralcases,technologiesthatarenot

currentlycommerciallyavailablewereselectedforcostanalysis. Thesetechnologieswere

includedbecausethereissubstantialdemonstrationprojectactivityorsufficientinterestinthese

technologiestoexpectthatthesetechnologiescouldbecommerciallyavailableanddominantin

10yearstime. Sincenocostdatafromcommercialinstallationsisreadilyavailableforthese

technologies,theauthorsexpectgreateruncertaintyaroundthecosts. Theauthorshave

identifiedthesetechnologiesinthetablebelowwithadatastartdateof2018. Theutilityscale

technologiesfallingintothiscategoryareBiomassCoGasificationIGCC,OffshoreWind(Class

5),andOceanWave.

3.1.3. Utility-Scale Technologies

Theutility

scale

technologies

recommended

for

cost

analysis

are

shown

in

Table

6below.

Table 6. Central plant technology list for COG modeling project

Technology List Gross Capacity

(MW)

Data Start Date

Biomass

Biomass Combustion - Fluidized Bed Boiler 28 Current

Biomass Combustion - Stoker Boiler 38 Current

Biomass Cofiring 20 Current

Biomass Co-Gasification IGCC 30 2018

Geothermal

Geothermal - Binary 15 CurrentGeothermal - Flash 30 Current

Hydropower

Hydro - Small Scale (developed sites without power) 15 Current

Hydro - Capacity upgrade for developed sites with

power

80 Current

Solar

Solar - Parabolic Trough 250 Current

Solar - Photovoltaic (Single Axis) 25 Current

Wind

Onshore Wind - Class 5 100 Current

Onshore Wind - Class 3/4 50 Current

Offshore Wind - Class 5 100 2018

Wave

Ocean Wave 40 2018

Integrated Gasification Combined-Cycle

IGCC without carbon capture 300 Current

Nuclear

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Technology List Gross Capacity

(MW)

Data Start Date

Westinghouse - AP1000 960 Current

Source: KEMA

3.1.4. Community-Scale Technologies

Communityscaletechnologieswillbediscussedinthefinalprojectreport.

3.1.5. Building-Scale Technologies

Buildingscaletechnologieswillbediscussedinthefinalprojectreport.

3.2. Biomass

3.2.1. Technology Overview

Theuseofbiomasstechnologyhasbeenapartoftheenergylandscapeforcenturiesandhas

becomeatechnologyofincreasingimportanceinthecurrentenergymix,bothinCalifornia,the

UnitedStates,andtherestoftheworld.

Biomass,ortheuseofplantbasedhemicellulosematerial,agriculturalvegetation,or

agriculturalwastesasfuel,hasthreeprimarytechnologypathways:

Pyrolysistransformationofbiomassfeedstockmaterialsintofuel(oftenliquidbiofuel)

byapplyingheatinthepresenceofacatalyst.

Combustiontransformationofbiomassfeedstockmaterialsintoenergythroughthe

directburningofthosefeedstocksusingavarietyofburner/boilertechnologiesalsoused

toburnmaterialssuchascoal,oilandnaturalgas.

Gasificationtransformationofbiomassfeedstockmaterialsintosyntheticgasthrough

thepartialoxidationanddecompositionofthosefeedstocksinareactorvesseland

oxidationprocess.

Ofthesetechnologypathways,thetwoprimaryembodimentsofelectricityproduction

technologyarefoundinthedirectcombustionandgasificationapproachestobiomass

combustionintoelectricityandenergy. Activeresearchintopyrolysisforbiofuelproductionis

activeandongoingbutisnotyetatcommercialscale.

Combustiontechnologiesarewidespread,andincludethefollowinggeneralapproaches:

StokerBoilerCombustionusessimilartechnologyforcoalfiredstokerboilersto

combustbiomassmaterials,eitherusingatravelinggrateoravibratingbed. Whilea

verymature,centuryoldtechnology,stokerboilerdesignshaveseentechnology

improvementsrecentlytoimprovebiomasscombustion,particularlyemissions

reductionsandincreasedcombustionefficiencies.

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BiomassCofiringusesbiomassfuelburnedwithcoalproductsincurrenttechnology

pulverizedcoalboilersusedinutilityscaleelectricityproduction. Biomasscofiringisa

maturetechnologyinEuropeandisincreasinglybeingadoptedintheUnitedStates,

sinceitcansignificantlyenhancetheuseofbiomass,reducenetcarbonemissionsin

powergeneration,andhasshowngoodreliabilityinservice.

FluidizedBed(FB)Combustionusesaspecialformofcombustionwherethebiomass

fuelissuspendedinamixofsilicaandlimestonethroughtheapplicationofairthrough

thesilica/limestonebed. Fluidizedbedcombustionboilersareclassifiedeitheras

bubblingbed(FB)orcirculatingfluidizedbed(CFB)units.

Figure 1. Utility-scale fluidized bed gasifier

Source: Energy Products of Idaho

Gasificationtechnologies,whilerelativelyrecentintheirevolution,aregrowinginscopeand

scaleastheyareincreasinglybeingdevelopedandusedthroughouttheworld. Several

differentformsofgasificationtechnologiesexisttoday:

BiomassIntegratedGasificationCombinedCycle(IGCC)similartothecoalbased

IGCCprocess,exceptthebiomassfuelisgasifiedinareactorvesselpriortoits

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introductionandcombustioninagasturbinegeneratorset. Gasturbinesdevelopedfor

coalbasedIGCCarewellsuitedforbiomassIGCCbecausebothgasifiedfuelsareof

sufficientBTUheatingvaluecontent. BiomassIGCCplantsarenowbeingintroducedas

technologydemonstrationunits.

Figure 2. Biomass IGCC plant representation

Source: KEMA

Figure 3. Schematic diagram of biomass IGCC process

Source: U.S. Department of Energy

(www.fossil.energy.gov/programs/powersystems/gasification/howgasificationworks.html)

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BiomassfluidizedbedgasificationusingaFBorCFBgasificationreactortoconvert

biomassfeedstocksintosyntheticfuelgas,whichisthenburnedinaconventionalcoal

ornaturalgasfiredutilityboiler. Thistechnologyisnotbeingadoptedforthecostof

generationstudybecausethecurrentcommercialembodimentisdirectfluidizedbed

combustionofbiomassforelectricalpowergeneration.

Figure 4. Utility-scale biomass fluidized bed gasifier

Source : Foster Wheeler

3.2.2. Biomass Combustion Fluidized Bed Boiler

Technical and Market Justification

Forbiomassfuels,fluidizedbedcombustionisrapidlyemergingasasystemofchoiceformany

powergenerationapplications. Theinherentfuelversatilityoffluidizedbedsystemsprovidesa

plantoperatortheabilitytoburnmanydifferentbiomassresourcetypes,includingthose

feedstockswithsignificantmoisturevariations. Themajorreasonforthisisthatthefluidized

bedcarryingmedium(typicallyamixofsilicasandand/oralumina)providesathermalflywheel

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effectthatmaintainsconstantheatoutputandfluegasqualityevenwhenburningfuelsof

varyingmoisturecontent.17

Fluidizedbedboilersarecharacterizedaseitherbubblingbed(FB)orcirculatingfluidizedbed

(CFB),andthisisbasedonhowthebedmaterialisusedwithintheboiler. Inabubblingbed

(FB)unit,

the

bed

material

stays

within

afixed

zone

in

the

boiler,

while

in

acirculating

fluidized

bed(CFB)unit,thematerialissuspendedaboveanairzoneandiscirculatedthroughareturn

loopbacktothecombustionzonebymeansofamassorcyclonicseparator.

Figure 5. Circulating fluidized bed schematic diagram

Source: Babcock & Wilcox Image (www.babcock.com/products/boilers/images/cfb.gif)

Forboth

FB

and

CFB

units,

due

to

the

high

quality

combustion

and

near

complete

carbon

burnout(99100%)ofbiomassfuelsources,ashiscarriedoverintothefluegasstream,requiring

theadditionofpostcombustionashremovalequipmentsuchascyclonesandbaghouses. The

17Overend,R.P.BiomassConversionTechnologies.Golden,CO:NationalRenewableEnergyLaboratory,

2002.

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postcombustioncontrolsallowparticulateremovaltoNewSourcePerformanceStandards

(NSPS)forPM10.

Fluidizedbedboilertechnologyhaslongbeenincommercialuse,withmuchmorewidespread

adoptioninEuropethanintheUnitedStates,duetoseveralreasons.18 First,fuelresourcesin

Europecan

vary

widely

in

quality

and

processing,

and

the

ability

of

fluidized

bed

boilers

to

handlewidelyvaryingfuelsisofadvantage. Second,fluidizedbedboilersexhibitsuperior

emissionsperformance,especiallynitrogenoxide(NOx)emissions,duetotheinherentlylow

firingtemperatureoftheboiler. Third,forcoalbasedfuels,theabilitytodirectlyinject

limestoneasasorbentprovidesexcellentsulfurandsulfurdioxide(SOx)reductionswithoutthe

needforexpensivepostcombustionscrubbingequipmentandsystems.

Marketadoptionoffluidizedbedboilertechnologyforbiomasshaslongbeenacommercial

reality,withbothbubblingbedandCFBunitsbeingusedforbiomasscogenerationthroughout

theUnitedStates,particularlyintheforestproductsandpaperindustry. AdoptionofCFB

technologyforutilityscalecoalandbiomasspowergenerationhasreachedworldwidegeneral

industryadoption,

as

shown

below:

Table 7. Installed CFB boiler capacity by country19

Country Installed Capacity (MW)

China 10,000

Czech Republic 1,400

Germany 1,800

Poland 3,310

India 1,200

United States 8,800

Source: Tavoulareas, Stratos. Advanced Power Generation Technologies An Overview

TechnologySelectionCriteria

Fluidizedbedcombustiontechnologyforgeneratingelectricpowerusingbiomassfuelwas

selectedforthecostofgenerationstudybytheresearchteambecauseofthefollowingfactors:

CommercialscaleBothbubblingbedandcirculatingfluidizedbedtechnologieshave

beendevelopedtoutilityscale,andcurrentcommercializedunitsfitwellwithinthe

overallsupplycurveconstraintsforbiomassthatcanlimitoverallgeneratingunitsize

potential.

18U.S.EnvironmentalProtectionAgency.CombinedHeatandPowerPartnership. BiomassCombined

HeatandPowerCatalogofTechnologies,September2007.

19Tavoulareas,Stratos.AdvancedPowerGenerationTechnologiesAnOverview.U.S.Agencyfor

InternationalDevelopment.ECOAsiaCleanDevelopmentProgram,August2008.

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FuelflexibilityBiomasscombustioninfluidizedbedboilershasbeenwelldocumented

foravarietyofbiomassfuelfeedstocks. Theinherentstabilityinfluidizedbedboilers

whileburningfuelsofvaryingqualityisakeyadvantagewhenevaluatingchanging

biomassfuelsourcesoverthelifeofthegeneratingplant.

ReliabilityFluidizedbedcombustionisreliableandprovenoverdecadesofservice.

Whilerelativelynewintechnologywhencomparedtostoker ortraditionalfired

boilers,thereisrapidandgrowingadoptionoffluidizedbedboilertechnologyformid

sizedunits.

EmissionsperformanceFluidizedbedcombustionperformswellinreducingNOx

emissionsbecauseofthelowcombustiontemperaturesusedintheprocess. Inaddition,

thenearcompleteconversionofavailablecarbonresultsinlowercarbonmonoxide(CO)

emissions. Particulateemissionsaremanagedthroughpostcombustioncontrols,as

withtraditionalfiredunitsburningsolidfuels.

Figure 6. Bubbling fluidized bed boiler

Source: Energy Products of Idaho

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Primary Commercial Embodiment

Today,theprimarycommercialembodimentofcirculatingfluidizedbedboilertechnologyisin

EuropeandChinaandgainingmomentumintheUnitedStates Forover20years,the

developmentofcirculatingandbubblingfluidizedbedtechnologyhasprogressedinEuropeto

thepointwherecirculatingfluidizedbedboilersareastandard,utilityscaletechnologytoday.

IntheUnitedStates,severalcompanieshaveprogressedwithstandardizeddesignsofcirculatingfluidizedbedboilerscombustingavarietyoffuels,frombiomasstocoaland

petroleumcoke.

InCalifornia,currentcommercialembodimentislimited,mainlybecauseofthelimitedability

topermitsolidfuelcombustionfacilities. However,thereiscurrentinterestinthecogeneration

andforestproductsindustrialbasetoexaminefluidizedbedcombustiontechnologyfor

repoweringexistingsolidfuelcombustionfacilitiestobiomassfuelconversion.20

Theresearchteambelievesthatfluidizedbedtechnologywillbecomecommerciallyembodied

inCaliforniatoenablethestatetoachieveitsbiomassenergygoalsby2018. Theinherentlyfuel

flexiblenatureoffluidizedbedcombustion,theintegrationofprimarypollutioncontrolsintothecombustionprocess,andthesmallfootprintareenablersofthistechnologyinCalifornia,as

beingdemonstratednowinEuropeandChina.

Cost Drivers

MarketandIndustryChanges

MarketandindustrychangessinceAugust2007havenotsignificantlyaffectedcostsfor

circulatingfluidizedbedboilertechnology. Materialcostincreaseshaveabatedduetothe

currenteconomicrecession,especiallyincarbonsteelandstainlesssteelcosts,whicharethe

primarycostcomponentsofcirculatingfluidizedbedboilermanufacturing.

CarbonsteelcostshavechangedsignificantlysinceAugust2007,butthenetchangeisnot

significant. Theattachedtablehighlightstherapidriseandthenfallofcarbonsteelpricing:21

Table 8. Recent carbon steel pricing

Year Average Carbon Steel Price ($/Ton)

2007 $717

2008 $1,004

2009 (April 2009 average annual price) $736

Source: Purchasing Magazine

20KEMASources:PersonalCommunicationwithEPI,FosterWheeler,March2009.

21PurchasingStaff.Steelplatepriceshaveplunged50%frommid2008peak.PurchasingMagazine.

April2009.www.purchasing.com/article/CA6654110.html?industryid=48389.

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CurrentTrends

Currenttrendsthatwillmateriallyaffectfuturecostsare:

GlobaleconomicdownturnThebreadthanddepthofthecurrentrecessionhascaused

asignificantreductioninthenumberofnewboilerordersforbothpowergeneration

andindustrialmanufacturingcapacity. Thelengthofthecurrentrecessionandthepaceofrecoverywilldeterminetheescalationrateinrawmaterials,theuseofboiler

manufacturingcapacity,andthusfuturecosts.

SteelpriceabatementCurrentameliorationofworldwidesteelprices,bothforcarbon

andstainlesssteel,willhaveapricemoderatingeffectonstokerboilerpricesbothnow

andinthenearfuture. Longtermsteelcommoditypricesarecurrentlydifficultto

predict.

IndustrialproductionandeconomicgrowthinChinaByNovember2008,Chinalost

over30millionmanufacturingjobsinGuangzhouProvinceduetotheglobalrecession,

significantlycurtailingChineseeconomicgrossdomesticproduct(GDP)growth.

Enoughoftheglobaloutputforsteelandotherrawmaterials,usedincirculating

fluidizedbedboilerproduction,werebeingusedinChinathatsignificantescalationof

pricesresulted. ThepaceoftheeconomicrecoveryandstimulusinChinawill

determinerawmaterialpriceescalationandthuswillimpactcirculatingfluidizedbed

boilercosts.

EconomicstimulusBecausestimuluspackagesaredesignedtosupportenergy

technologies,suchascombinedheatandpower,cogeneration,andbiomass,stimulus

supportintheUnitedStatescouldhaveanescalatingeffectonbothmaterialsand

demandforcirculatingfluidizedbedboilers.

CostDrivers

Costdriversforbiomasscirculatingfluidizedbedboilertechnologiesareasfollows:

BiomassfueltypeanduniformityThetypeanduniformityofdeliveredbiomassfuel

supplyisaprimarycostdriverforanybiomasstechnology. Becauseofthevaried

natureofbiomassfuelfeedstocks,theirdeliveredmoisturecontentandheatingvalue

variations,andfuelprocessingissues,thehandlingandprocessingcostsofbiomass

fuelscanvarygreatly. Asaresult,thetypeandnatureofbiomassfuelscombustedcan

haveamaterialimpactonthecapitalcostoftheboilerislanddesign,aswellasthe

overallfuelhandlingandoperationscost.

Supplycurveforbiomassfuel,fueltransportandhandlingcostsTheavailabilityof

adequateandsufficientbiomassfuelresourceswithina100mileradiusoftheplant

locationisacriticaldriverforoperatingcost. Mostbiomassfuelistransportedbytruck

transporttoaplantsite,whichlimitstheeffectiveeconomicradiusfromtheplant

locationtoaggregatefuelsupplyatcommerciallyreasonableprices. Thevariednature

ofbiomassfuelfeedstocksalsonecessitatesspecialhandlingequipmentandlarger

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numbersofdedicatedstaffthanforcoalfiredcombustionpowerplantsofequivalent

size.

BoilerislandcostCapitalcostoftheboilerislandisacriticalcostdriverthatcanentail

approximately4060%oftheoverallplantcost,dependingonthetypeofbiomass

combustedandtheneedforpostcombustionpollutioncontrols.22 Thedesignbasisfor

thetypeoffuelstobecombustedisanimportantcostdriver. Inaddition,theescalation

trendsforrawmaterialsusedinmanufactureoftheboilerisland,primarilysteelcost,

arefactorsthatcaninfluencedeliveredboilerislandcost.

LongtermfuelsupplycontractavailabilityMostcurrentbiomassfuelsupplycontracts

areofshorttermdurationandforfuelofsometimesvaryingquality. Akeycostdriver

topromotingbiomasscirculatingbedcombustioninCaliforniaistheabilitytodevelop

andachieveperformanceonlongterm(e.g.,fiveyearsdurationandlonger)fuelsupply

contractsforavailablefuelsources.

PlantscaleCurrentCFBtechnologyhasbeenproventoutilityscaleapplicationsofup

to

300

MW,

with

the

primary

commercial

embodiment

in

sizes

from

30

100

MW.

Developmentof800MWclasssupercriticalCFBcyclesisnowbeingstudiedfor

applicationsinChina,andtheoutcomeofthatresearcheffortwouldmateriallyaffectthe

capitalcostprofileandscaleofCFBtechnologyapplicationsforbiomass.23

EmissionscontrolcostsCostsespeciallyofpostcombustionemissionscontrol

technologies,suchasSCR/SNCRtechnologiesforNOxcontrol,andadditiona