Life cycle emissions and cost of producing electricity from coal, natural gas, and wood pellets in Ontario, Canada

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Life cycle emissions and cost of producing electricity from coal, natural gas, and wood pellets in Ontario, Canada
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  See discussions, stats, and author profiles for this publication at: https://www.researchgate.net/publication/40448165 Life Cycle Emissions and Cost of ProducingElectricity from Coal, Natural Gas, and WoodPellets in Ontario, Canada  Article   in  Environmental Science and Technology · December 2009 DOI: 10.1021/es902555a · Source: PubMed CITATIONS 95 READS 1,009 7 authors , including:Jon MckechnieUniversity of Nottingham 26   PUBLICATIONS   486   CITATIONS   SEE PROFILE Warren E. MabeeQueen's University 76   PUBLICATIONS   3,193   CITATIONS   SEE PROFILE Akifumi OginoNational Agriculture and Food Research Org… 40   PUBLICATIONS   670   CITATIONS   SEE PROFILE Heather L. MacleanUniversity of Toronto 118   PUBLICATIONS   2,860   CITATIONS   SEE PROFILE All content following this page was uploaded by Heather L. Maclean on 19 March 2014. The user has requested enhancement of the downloaded file. All in-text references underlined in blue are added to the srcinal documentand are linked to publications on ResearchGate, letting you access and read them immediately.  Life Cycle Emissions and Cost of Producing Electricity from Coal,Natural Gas, and Wood Pellets inOntario, Canada  Y I M I N Z H A N G ,  † J O N M C K E C H N I E ,  † D E N I S C O R M I E R ,  ‡ R O B E R T L Y N G ,  §  W A R R E N M A B E E ,  |  A K I F U M I O G I N O ,  ⊥  A N DH E A T H E R L . M A C L E A N *  , † ,  3 Department of Civil Engineering and School of Public Policy and Governance, University of Toronto, 35 St. George Street Toronto, Ontario M5S 1A4, FPInnovations  - FERIC, 580 boul.St-Jean, Pointe-Claire, Quebec H9R 3J9, Ontario Power Generation, 700 University Avenue, Toronto, Ontario M5G 1X6 School of Policy Studies and Dept. of Geography, Queen’s University, 423-138 Union St. Kingston, Ontario K7L 3N6, and National Agriculture and Food Research Organization,2 Ikenodai, Tsukuba, Ibaraki 305-0901, Japan  Received August 21, 2009. Revised manuscript received November 19, 2009. Accepted November 20, 2009. The use of coal is responsible for  1  / 5  of global greenhousegas (GHG) emissions. Substitution of coal with biomass fuelsisoneofalimitedsetofnear-termoptionstosignificantlyreduce these emissions. We investigate, on a life cycle basis, 100%wood pellet firing and cofiring with coal in two coal generatingstations (GS) in Ontario, Canada. GHG and criteria air pollutantemissions are compared with current coal and hypotheticalnaturalgascombinedcycle(NGCC)facilities.100%pelletutilizationprovides the greatest GHG benefit on a kilowatt-hour basis,reducing emissions by 91% and 78% relative to coal and NGCCsystems, respectively. Compared to coal, using 100% pelletsreducesNO x  emissionsby40 - 47%andSO x  emissionsby76 - 81%.At $160/metric ton of pellets and $7/GJ natural gas, eithercofiringorNGCCprovidesthemostcost-effectiveGHGmitigation($70 and $47/metric ton of CO 2  equivalent, respectively). Thedifferencesincoalprice,electricitygenerationcost,andemissionsat the two GS are responsible for the different options beingpreferred.Asensitivityanalysisonfuelcostsrevealsconsiderableoverlap in results for all options. A lower pellet price ($100/metric ton) results in a mitigation cost of $34/metric ton of CO 2 equivalent for 10% cofiring at one of the GS. The studyresults suggest that biomass utilization in coal GS should beconsideredforitspotentialtocost-effectivelymitigateGHGsfromcoal-based electricity in the near term. Introduction “Oneofthemostsignificantchallengesinaddressingglobalclimatechangeisreducinggreenhousegas(GHG)emissionsresulting from the use of coal” ( 1 ), currently responsible for 1 / 5 ofglobalemissions.Giventheheavydependenceofmany countries on coal-fired electricity generation [coal provides50% of electricity in the US, 80% in China ( 1 ), and 40% onaverage worldwide ( 2  )], abatement of GHG emissions fromthis sector will be challenging but critical to meet targets. While carbon capture and storage (CCS) will be needed tomake large GHG reductions from coal generation, com-mercialprojectsarerequiredtodemonstratetheintegrationofthesetechnologiesatlargescaleandtobetterunderstandthetechnicalperformanceandfinancialcosts( 3  ).Inthenextdecadeorso,therearefewopportunitiestomakesignificantGHG emissions reductions from coal electricity generation.One near-term option that can reduce GHG emissionsand be utilized to meet renewable portfolio standards is thecombustion of sustainably produced biomass in coal gen-erating stations (GS). In contrast to many other renewablegeneration options, biomass firing does not have thedrawback of being intermittent and is applicable to areas without significant wind, solar, or hydropower resources.Biomass cofiring, where coal and biomass are fired simul-taneously, generally has a higher fuel cost than coal-only generationbutisafavorableoptionasitrequireslowcapitalexpenditure by using existing facilities and is applicable forvirtually all types of utility coal boilers. Biomass cofiring hasbeen shown to reduce SO x   and NO x   emissions and to resultin net GHG emissions reductions ( 4  ). The technology hasbeenutilizedcommerciallyinEurope,theUnitedStates,andother countries but not to our knowledge in Canada. Therearenomajortechnicalobstaclestocofiring,althoughitcouldpose logistical and operational challenges, primarily due todifferences in coal and biomass properties. There is far lessexperiencewith100%biomass-firedgeneration(oftentermed“repowering”) in prior coal GS, although it has beensuccessfully implemented in Europe (Electrobel, Belgium)and in the United States (Schiller Station, NH) and there areplansforadditionalGS(e.g.,FirstEnergy,SouthernCompany).Thereisnota“standardretrofit”forrepowering,witharangeof reported and planned modifications, from changes tohandling systems and coal boilers to full replacement witha biomass boiler (see Supporting Information).The Ontario government has committed to eliminating the use of coal for electricity production by December 31,2014. In 2007, the province obtained 18% of its electricity fromcoal(coalcapacityis6400MW,19%oftotalgenerationcapacity), resulting in  ∼ 28 million metric tons of CO 2 equivalent, or 15% of the province’s total GHG emissions( 5  - 7  ).Thegovernmenthasaplanforreducingemissionsby 2020, with the largest component of reductions (29%)expected from actions in the electricity sector ( 8  ). Ontario’selectricity generation capacity is expected to evolve by the year 2025 from the current mix to one that meets thegovernment’s supply mix directive (see Supporting Informa-tion). A doubling of renewable capacity and expansion of conservation are planned, although exact plans are notfinalized( 9  ).Whilethereareinitiativestoincreaserenewablegeneration (i.e., Ontario’s Green Energy Act 2009, whichincludesafeed-intariffprogram),expansionofhydrocapacity is constrained by limited remaining resource availability.OntarioPowerGeneration(OPG),whichoperatesfourcoal-fired GS, is investigating biomass firing in these stations asoneactiontowardaddressingsomeoftheaboveissues.Thisstudy examines the life cycle (LC) GHG emissions and costsof biomass options for these GS.In the United States and Canada (as well as othercountries),thepotentialforbiomassutilizationissubstantial * Corresponding author phone: (416) 946-5056; e-mail:hmaclean@ecf.utoronto.ca. † Department of Civil Engineering, University of Toronto. ‡ FPInnovations - FERIC. § Ontario Power Generation. | Queen’s University. ⊥ National Agriculture and Food Research Organization. 3 School of Public Policy and Governance, University of Toronto. Environ. Sci. Technol.  2010,  44,  538–544 538  9 ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 44, NO. 1, 2010 10.1021/es902555a  ©  2010 American Chemical Society Published on Web 12/04/2009  due to abundant resources ( 10  ). The net benefits of using biomass will depend upon the activities throughout the LCof biomass production and combustion, particularly thebiomass properties, fossil energy inputs, fertilizer use (if employed) and related N 2 O emissions, and impacts associ-atedwithlandusechange.Asiswell-documentedforbiofuels( 11 ),GHGemissionsandotherperformancemetricscanvary significantly depending on the LC attributes. Additionally,the LC performance of the displaced energy system isimportant in determining net benefits of biomass. OPG isfocusing on pelletized biomass for use in the coal GS aspelletization dries and densifies input biomass, producing asolidfuelofevenproportionthatismoreeasilytransportedand handled and that has better properties for electricity generation than other forms of biomass. However, pelleti-zationgenerallyresultsinahigher-costfeedstockandrequiresenergy inputs that may negatively impact the net benefit of biomass use. Although life cycle assessments (LCA) of GHG emissionsassociated with electricity from biomass coal cofiring havebeen completed ( 12  - 15  ), only Damen and Faaij ( 15  ) exam-inedwoodpellets(hereafterreferredtoaspellets)andthese were produced from mill residues, unlike the present study, which examines dedicated wood harvest for pellet produc-tion. There have been studies on electricity generation frombiomass use in direct-fired biomass boilers and integratedgasification combined cycle systems ( 16, 17  ) but the studiesdid not include economic analyses. Robinson et al. ( 4  )estimated the cost-effectiveness (CE) of GHG reductionthroughcofiringnonpelletizedbiomassbutconsidereddirect,not LC, emissions. Qin et al. ( 18  ) employed a LC approachandcalculatedtheCEofGHGemissionsreductionsthroughcofiringnonpelletizedbiomassand100%biomassfiring(thelatterinahypotheticalstand-alonebiomassunit).InResultsand Discussion and Supporting Information, we compareour results with those of the literature. Weinvestigatetheuseofpelletsforcofiringwithcoaland100% biomass-fired generation in two of Ontario’s coal GS.To our knowledge, this is the first study to analyze 100%biomass usage in a coal GS and to examine dedicated woodharvest for pellet production. Life cycle GHG and selectedair pollutant emissions are quantified for biomass as well asreference coal and natural gas electricity generation. Theelectricity production costs as well as CE of GHG emissionsmitigation are also estimated, additional contributions toaddress gaps in the literature. While site-specific details of the Ontario case are important, insights from the analysiscan provide guidance for other jurisdictions. Methods Life cycle inventory (LCI) analysis models are developed toquantify the relative changes in selected GHG and airpollutant emissions, for the following Ontario “pathways”:(1)  Reference coal  : production of electricity from coal intwo existing coal-fired GS, Nanticoke [3948 MW (net)] and Atikokan [215 MW (net)].(2)  Reference natural gas  : production of electricity fromrepresentative (hypothetical) newly constructed natural gascombined cycle (NGCC) facility (400 MW).(3)  Pellet cofire  : production of electricity at cofire rates of both 10% and 20% (energy input basis) at Nanticoke and Atikokan.(4) 100%pellet-fired  :productionofelectricityfrompelletsasthesoleenergysourceinoneunitatNanticokeandinthesingle unit at Atikokan.Life cycle costing models are also developed to estimatethe electricity production cost for the above pathways. LCI Analysis.  All LC activities from resource extraction(e.g., roundwood, coal) and production (e.g., pellet produc-tion)throughuseofthefuelintheelectricityGSareincluded,aswellasalltransportationstages.“Cradle-to-gate”modulesfor the required energy and material inputs were developedor obtained from databases. Actual operating data for thecoalGSwereutilized.AstheLCIquantifiestherelativechangein the metrics when switching from coal-only to pelletcombustion or natural-gas-only options, grid electricity distribution and use are identical for all pathways andthereforenotincludedinthesystemboundary.Materialandenergy inputs needed for equipment manufacture, facility construction, and labor are not included in the study.Exclusion of these activities is common practice where it isexpected that these aspects have far smaller implicationsthan the operations of the facilities ( 19  ).TwotimeframesrelevanttotheOntarioelectricitysector’snear-termtechnologiesandregulatoryinitiativesareselected.The cofiring pathways are relevant to the time frame 2010to2014,duringthecoalphase-out,whilethoseutilizing100%pelletsarerelevantpost-2014butcouldbeimplementedpriorto that time.The functional unit for the electricity analysis is 1 kWhofelectricityproduced.Theenvironmentalmetricsexaminedare selected GHGs (CO 2 , CH 4 , N 2 O), reported as CO 2 equivalents (CO 2 equiv) based on 100-year global warming potentials ( 20  ), and air pollutant (NO x   and SO x  ) emissions.The base assumption in this study is that emissions of CO 2 resulting from the combustion of biomass are entirely balancedbythecarbonincorporatedduringregrowthoftheforest during the time period considered. This assumptionis in line with the treatment of biobased sources in theliterature(forexample,refs 21 and 22  ),whichconsidersforestbiomass(referredtoasbiofiber)tobecarbon-neutralsolong as the forest is sustainably managed. Pellet Production.  The pellet production LC activitiesinclude biofiber harvesting, forest renewal, forest roadconstruction, biofiber transportation to a pellet facility,pelletization, and pellet delivery to Nanticoke and AtikokanGS(SupportingInformation,FigureS-1).AspelletproductionhasnotpreviouslyoccurredinOntarioatthescalepresentedhere, and siting studies are needed to determine locationsof harvest, transportation activities, and facility locations,best available data at the time of the study are utilized. A sensitivity analysis was completed on key parameters.Inthisstudy,biofiberforpelletproductionissuppliedby forest management units in the Great Lakes St. Lawrence(GLSL)forestregionofOntario(seeSupportingInformation).The total harvest volume available for pellets supplied fromsustainably managed Crown (public) GLSL forest is ∼ 1.475millionovendrymetrictons(ODT)/year.Allocatingthisforestbiofibertopelletproductionwouldnotreducecurrentharvestquantities for traditional products but instead would createa market for available merchantable logs no longer market-ablegiventhedeclineintheforestsector.Itisnotanticipatedthattherewillbeanytrade-offbetweentraditionalproductsand bioenergy outputs. The present study assumes noadditionalbiomasssupply;however,thereareotherresourcesintheprovinceandsurroundingregionsthatcouldbeutilized( 23  ).The pelletization process is described in Supporting Information (Figure S-2). Data on electricity and biofiberconsumption during pelletization were provided by a north-eastern U.S. pellet producer and reflect a state-of-the-artfacility (pellet capacity 12 ODT/h). The data obtained fromtheproducerwereutilized,withtwomodifications[todrying energy use (see Supporting Information) and the use of theOntario grid for grid-based electricity]. As data for pelletproduction are limited and generally proprietary, the pro-ducer’s data were verified by comparison with refs  24   and 25  . Pellets are shipped to Atikokan exclusively by rail, whilethose destined for Nanticoke are shipped by rail to a deep- VOL. 44, NO. 1, 2010 / ENVIRONMENTAL SCIENCE & TECHNOLOGY   9  539   waterportandthentransportedbyvessel.Characteristicsof thepelletsarebasedonspecificationsofthepelletproducerand ref   24   and would meet specifications stated by ref   26  .SeeSupportingInformation,TablesS-1andS-2,forLCIdata. Reference Coal and Natural Gas Pathways.  The LCIsystem boundary for coal-based electricity includes coalmining and processing, transportation, and combustion intheGS.ThesepathwaysreflectexistingconditionsattheGS.NanticokeGS,locatedonLakeErie,haseight490MW  e (net) wall-firednaturalcirculationpulverizedcoalboilersequipped with low-NO x   burners, two of which are equipped withselectivecatalyticreductionequipment.ThestationusesbothsubbituminoussouthernPowderRiverBasin(PRB)coal(84%by weight) and bituminous Central Appalachian U.S. low-sulfur (USLS) coal (16% by weight) ( 27  ). Atikokan GS, innorthwesternOntario,hasone215MW  e (net)boilerequipped with low-NO x   burner and uses Canadian lignite coal. Thecapacity factors and net coal to electricity conversionefficiencies are 55% and 35% for Nanticoke and 34% and33% for Atikokan ( 27  ). See Supporting Information, TablesS-3 and S-6.The natural gas reference pathway is based on a hypo-theticalNGCCelectricitygenerationfacility(53%conversionefficiency) ( 28  ) located in Ontario, which would receive gasfrom Alberta. The LCI activities are natural gas recovery,processing, transmission and storage, and use in the facility (SupportingInformation,TablesS-4andS-6).Retrofittingof the coal GS to natural gas boiler or NGCC systems are notconsideredeconomicallyviablealternatives(seeSupporting Information). Pellet Cofire Pathways.  Emissions associated with elec-tricitygenerationfromcofiringareestimatedonthebasisof upstream coal and pellet production and transportationemissions, the amount of each fuel required to produce 1kWh of electricity, and the emissions from electricity genera-tion. Cofiring at Nanticoke displaces USLS coal initially andthen PRB coal after all USLS is displaced ( 27  ), while cofiring at Atikokan displaces lignite. To implement cofiring at theGS,thefueldeliveryandhandlingsystemsmustbemodifiedby installing additional conveyors, hoppers, and coveredstoragetohandleandstorethepellets.Pelletsareintroducedto the boilers through dedicated silos. Based on tests at theGS, the estimated heat rate degradation due to cofiring is0.5%forevery10%inputofpellets( 27  ),resultinginminimaldecreaseinconversionefficiency.ForNanticokeandAtikokanat20%cofire,efficienciesare34.7%and32.7%,respectively.The issue of efficiency loss is of less concern with pelletsbecause of their low moisture content (5% in this study).Pellet combustion-related CO 2  emissions are treated aszero as per our base assumption. Pellet cofiring is expectedto reduce GS SO x   emissions relative to coal-fired generationbecausebiomasstypicallycontainslesssulfur.SO x  emissionsreductions are often greater than would be expected fromfuel substitution alone because sulfur in coal can react withalkali in biomass to form sulfates ( 29  ). Reductions in SO x  emissions are estimated on the basis of sulfur contents of the pellets and coals (reductions beyond those associated with fuel substitution are not considered). The effects of cofiring on NO x   emissions are more difficult to quantify dueto the complex mechanisms of NO x   formation during combustion. Emissions of NO x   can increase, decrease, orremainthesamedependingonfueltype,firingandoperating conditions, and the change in combustion conditions. Weassume cofiring does not yield reductions in NO x   emissionsin either of the GS, as tests at Nanticoke reported that NO x  emissionswerevirtuallyunchangedfromcoal-onlyoperation. 100% Pellet-Fired Pathways.  According to OPG, modi-fications expected at both GS to accommodate 100% pelletfiringincludethosetodustandfiresuppressionequipment,fuel storage (covered) and handling equipment, pulverizers(replacementormodificationofclassifiers),andprimaryairsystems. Detailed engineering studies will determine if additional modifications are necessary (e.g., to air heatersystems and burners). It is assumed that the units wouldoperate year-round on pellets. Atikokan’s capacity whenoperating with pellets is expected to be close to that whenoperatingwithcoal( 27  ).TheheatratedegradationatAtikokanis estimated to be 5% for 100% pellet operation comparedtocoal-only,resultinginanefficiencyof31.4%.Duetoseveraltechnical issues, the capacity of Nanticoke’s unit whenoperatingwithpelletsisanticipatedtobe50%ofitscapacity  when operating with coal. The issues include (1) limitedfurnace size (as the units were originally designed forbituminous coal with a higher energy density than pellets)and (2) the use of ball-race mills (used to pulverize the fuel); whenusedwithpellets,thickbedsofwooddustaregeneratedthat result in high pressure differentials that limit theircapacity( 27  ).TheNanticokeunit’scapacitywhenoperating  withpelletsisestimatedat250MW  e .Thereductionincapacity could be lessened with additional retrofitting. Heat ratedegradation is estimated to be about 10% ( 27  ) resulting inan efficiency of 31.8% (Supporting Information, Table S-6).No measurements have been made of CH 4  and N 2 Oemissionsfor100%pelletfiringattheGS,andthereforedatafrom ref   28   are used to estimate these emissions. Test datafor 100% pellet firing at Atikokan are utilized for estimating SO x   and NO x   emissions for both GS, as no tests have beencompleted at Nanticoke. During testing, SO 2  emissionsremained below the detectable level of the analyzer for allfiring conditions. We estimate SO x   emissions on the basis of sulfur content of the pellets. A range of NO x   emissions ratesis provided by the test data. Data are extrapolated forNanticoke GS by assuming the same percentage change inemissions (from operation on coal) would occur as at Atikokan. These results are compared with the limited dataavailable in the literature (Supporting Information, TableS-5). Life Cycle Cost Analysis and Cost-Effectiveness of GHGEmissionsAbatement. Lifecyclecostmodelsaredevelopedtoestimatethecostofelectricitygeneratedfromcoal,pellet,andNGCCsystems(seeSupportingInformation,TableS-6).Capital (including financing), fixed operating and mainte-nance (O/M), nonfuel variable O/M, and fuel costs areconsidered. The cost of electricity production from coal atthe GS is based on actual operating data, with the capitalcosts treated as sunk costs. The NGCC system costs areestimated from those of a 400 MW advanced NGCC system( 30  ) and estimates in ref  31 . Due to the uncertainty of futurenatural gas prices, low, average, and high prices based on2004 - 2008 prices are examined (see Supporting Informa-tion).BiomasscofiringhasnotbeenimplementedbyOPGandtherefore costs are estimated from literature and reviewedbyOPG.Thecapitalcostisestimatedtobe$225/kWbiomasscapacity, the midpoint of the range in ref   4  . A delivered costforpellets,$160/metricton,isbasedonrefs 32  and 33  ,studiesthat estimate the pellet production cost from roundwood inthe GLSL forest for utilization in OPG’s GS.There is little data publicly available from which toestimate the cost of converting the GS to 100% biomass, asfewconversionshavebeencompletedanddetaileddatahavenot been published. Capital cost estimates in the gray literature for completed retrofits are ∼ $125/kW (Electrobel,Belgium) and ∼ $1500/kW (Schiller Station, NH) of biomasscapacity (calculated from refs  34, 35)  . The cost differencereflects the level of retrofit and facility configuration (seeSupporting Information). A retrofit to be completed by FirstEnergy (R.E. Burger GS, OH) ( 36  ) and expected to cost ∼ $640/kW of biomass capacity (assuming no capacity loss,as is claimed by FirstEnergy) matches most closely those 540  9  ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 44, NO. 1, 2010  planned by OPG. On the basis of the above and discussions withindustryexperts,weassumethe$640/kWcostforOPG’sGS.Duetotheuncertaintyinthecost,weperformasensitivity analysis (see Supporting Information).The CE of LC GHG (CO 2  equivalents) and air pollutantemissions mitigation (dollars per metric ton) relative to thereference (coal) pathways through the switch to the pelletsandNGCCarecalculated(seeSupportingInformation).Dueto the significant impact of variability/uncertainty in pelletand natural gas prices, ranges of these values are examined. Results PelletProduction. ThemassofpelletsthatcouldbeproducedannuallyfromtheGLSLbiofibersupply(unusedcomponentofannualallowablecut)isestimatedtobe1.25millionODT(1.475 million ODT less biomass used for drying). Imple-menting 10% cofiring year-round in both GS would require76% of the pellet supply, while 20% cofiring would requiremorepelletsthancouldbeproducedbytheGLSLforestaloneunder the sustainable management plans, assuming noimpactonthewoodsupplyoftraditionalindustries.Utilizing 100% pellets in Atikokan and one unit at Nanticoke wouldrequire 83% of the pellets. These calculations assumeelectricity output from the two GS remains at 2007 levels(Nanticoke 18 210 GWh; Atikokan 652 GWh).The production of the pellets and their transportation toeither GS results in 0.133 metric ton of CO 2 equiv/ODT(Supporting Information, Table S-7). A comparison of ourresultswiththoseofanotherstudyisreportedinSupporting Information. The forest harvest and pelletization processesare each responsible for the largest fractions (30% each) of the GHG emissions associated with pellet production andtransportation. Of the parameters studied, the pellet pro-duction emissions were found to be most sensitive to theGHGemissionsintensityofforestoperations,butthesedataare generally of high quality and based on actual fuel use,etc., in GLSL operations (see Supporting Information). Life Cycle Inventory Results for Electricity Generation. LifecycleGHGemissions(thoseassociatedwiththeGSitself and“upstream”activities)areshowninFigure1.ThelowestGHGemissionsonakilowatt-hourbasisresultfromthe100%pellet pathways. Reductions at Nanticoke and Atikokan are91% and 92%, respectively, compared to the reference coalpathways. The 100% pellet pathway (in both GS) produces78% less GHG emissions compared to the NGCC. Displace-ment of coal or natural gas with a biobased resource suchas pellets results in a large reduction in emissions based onthe assumption that the CO 2  resulting from the combustionof the biobased resource is exactly balanced by carbonincorporated during regrowth of the forest during the timeperiod considered. The small amount of GS emissions (16 g of CO 2 equiv/kWh) in the 100% pellet pathways results fromemissions of non-CO 2  GHGs. While these results are en-couraging, to maintain the current GS capacity factors,biomassresourcesotherthanthoseoftheGLSLforestwouldbe required, and in the case of Nanticoke, a more extensiveretrofit (e.g., replacement of the coal boiler with a biomassboiler) could be an option. Other sources of electricity orconservationinitiativeswouldberequiredtobalancesupply and demand. The implications of these initiatives woulddepend on the LC emissions intensity of the feedstock/conversion system options utilized.Compared to the reference coal pathways, the 10% and20% cofiring rates at both GS result in GHG emissionsreductions of 9% and 18%, respectively (values for a 10%cofiring rate in the literature range from 6.3% to 9.9%; seeSupporting Information). While cofiring results in loweremissions than coal-only operation, emissions from theNGCCarelower.Thisismainlybecausecofiringinvolvesthecombustion of a large amount of coal, which has a highercarbon content than natural gas (25 vs 14 kg of C/GJ). Inspite of the emissions benefits of the NGCC, natural gas isa fossil fuel that is limited in supply and subject to pricevolatility, which are factors of concern if moderate to largeportionsofelectricityweretobegeneratedfromthisresource.The upstream emissions associated with production of the fuels are of similar magnitude on a kilowatt-hour basis. With the exception of the 100% pellet pathways, the vastmajority of LC emissions occur at the GS (resulting from thecombustion of the fuel in the facility).The GS (facility) emissions of NO x   and SO x   represent themajority of LC emissions for the coal, NGCC, and cofiring pathways (Supporting Information, Figures S-4 and S-5).Compared to coal, both NO x   and SO x   emissions are reducedby using 100% pellets; reductions are 40 - 47% and 76 - 81%,respectively. The NGCC pathway also substantially reducesemissions compared to the coal reference. The cofiring pathways reduce SO x   emissions but result in approximately the same NO x   emissions compared to the coal reference. Cost of Electricity Production.  The coal pathways havethe lowest cost due to their low fuel costs and sunk capitalcosts (see Figure 2). Atikokan has higher fixed O/M coststhan Nanticoke, resulting in a higher electricity cost ($42.6vs$29.2/MWh).Co-firingat10%increasestheelectricitycost FIGURE 1. Life cycle GHG emissions associated with electricity production through reference, cofiring, and 100% pellet-firedpathways. Sources of emissions are indicated. Upstream (U/S) and GS fossil emissions for coal and cofiring refer to production andcombustion of coal, respectively; for NGCC, fossil emissions refer to production and combustion of natural gas. CO 2  emissionsresulting from biofiber combustion are not included in the figure due to base assumptions. VOL. 44, NO. 1, 2010 / ENVIRONMENTAL SCIENCE & TECHNOLOGY   9  541
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