# To: Docket ID EPA-HQ-OAR-2013-0495

Date: July 31, 2015

Title: Review of Electric Utility Integrated Resour ce Plans

Integrated Resource Plan Overview

Integrated resource plans (IRPs) are a tool that el ectric utilities use to plan operations and investm ents over long time horizons.

Since much of the infrastructure required in the el ectric utility industry can take several years to b uild and lasts for decades, it is

important to develop long-term plans. These plans t ypically cover 10 to 20 years and are mandated by s tate public utility

commissions (PUCs). To develop these plans, utiliti es model demand over a specified time period and ev aluate a suite of options

for meeting that demand (e.g., demand side manageme nt programs, investment in transmission infrastruct ure or new capacity).

Multiple scenarios are typically evaluated that loo k at variations in fuel prices, demand growth, carb on price and other factors

that could impact the system. Additionally, IRPs ac count for existing environmental regulations and th e potential for future

regulations and, in many cases, provide plans for c ompliance. These plans are generally updated every two or three years per

state law. States vary in the specificity of the c ontent they require. Usually an overview of supply , demand and transmission are

required, while some require a particular focus on certain areas such as demand-side initiatives. Som e states provide guidelines

for analysis.

EPA conducted a review of current IRPs to inform th e development of the new source performance standar d for emissions of

carbon dioxide for existing affected fossil fuel-fi red electric utility generating units. An overview of the results is provided below.

The EPA reviewed publicly available IRPs from a ran ge of companies (e.g., varying in size, location, c urrent fuel mix), and these

plans are generally consistent with both EIA and EP A modeling projections. These IRPs indicate that c ompanies are focused on

demand-side management programs to lower future ele ctricity demand and are mostly reliant on a mix of new natural gas-fired

generation and renewable energy to meet increased l oad demand and to replace retired generation capaci ty. Notwithstanding

the clear trend towards natural gas-fired generatio n and renewables, many of the IRPs highlight the va lue of fuel diversity and

include options to diversify new generation capacit y beyond natural gas and renewable energy. Several IRPs indicate that

companies are considering new nuclear generation, i ncluding either traditional nuclear power plants or small modular reactors,

and a smaller number are considering new coal-fired generation capacity with and without CCS technolog y.Summary of IRPsUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionTennesseeValleyAuthority(TVA)2011(through2030)Federal•Peak: 1.3% annualgrowth (evaluated0-2%)•EnergyRequirement: 1%annual growth(evaluated 0-1.9%)EE and DSM/DR aresignificant in allcases (3,600 MW5,100 MW)EE•EE/DSM/DR: 3,600 - 5,100 MW by2020RE•Renewables: 1,500 – 2,500 MW by2020Nuclear•Nuclear: 1,150 – 5,900 MW in 2013to 2029Other•Energy Storage: 850 MW in 2020 to2024•Coal: 0 – 900 MW by 2025 to 2029•NG: 900 – 9,300 MW in 2012 to 2029New coal beginning in 2025with CCS if there isdramatic load growthSignificant existing coalcapacity idled (2,400 MW4,700 MW)Fuel diversity is 1of 4 metrics usedto evaluate allportfolio results.7 of 8 scenariosincludedcarbon price ofat least$17/ton up to$45/ton by2030.Prices notgiven.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionDominion2015-2029PlanningPeriodIOU•Peak: 1.4% annualgrowth•EnergyRequirement: 1.3%annual growth7% increase indemand reductionsfrom DSM programsbetween 2013 Planto 2014 Plan. 583MW total capacityreduction by 2029.3% decrease inenergy reductionsfor DSM programsbetween 2013 Planand 2014 Plan.3,063 GWhreduction in 2014Plan.RE•Renewables: 818 MW ( wind andsolar)Nuclear•1,453 MW by 2028Other•NG: 3,132 MW (total capacity of twoadditional CCs) and 914 MW (totalcapacity of two additional banks ofCTs) by 2029 (Base Plan)No new coal plannedthrough 2029.Does not believe new coalgenerating facility could bebuilt without CCS while stillcomplying with regulations.Considered coal and CCSoptions in analysis, but notpursuing at this time.“Fuel DiversityPlan” reducesreliance on naturalgas.Solar: 559 MW by2029Onshore Wind: 247MW by 2022Offshore Wind: 12MW demonstrationproject by 2018Nuclear: 1,453 MWby 2028Also selects 1,566MW of CC capacityand 457 MW of CTcapacityBase caseassumescarbon taxefficiencyrequirementenacted by2020. No pricesgiven Due touncertainties,examined ascenario withno marginalcost of carbonemissionsduring thestudy period.Predictlowerprices thanin the 2013Plan.2014 PlanBase case:Henry HubNaturalGas-- $6.02$/MMbtuDOM ZoneDeliveredNaturalGas--$6.01$/MMbtuUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionDuke EnergyIndiana2013(planthrough2032)IOU•Summer Peak:0.9% annualgrowth•Winter Peak: -0.2%annual growth•Net Energy forLoad: 0.6%•CAGR for Energyand Peak LoadDemands: 0.95%from 2013-2033Base Caseprojections:•EE program loadimpact of 641.1MW by 2032•DR programload impact of586.7 MW by2032EE•EE/DR: 1,227.8 MWRE•Renewables (nameplate)o600 MW added by 2027oAdditional 1,450 MW added inearly 2030s due to increasing priceof CO2.oSolar: 330 MW by 2026oBiomass: 14 MW by 2027oNuclear•280 MW in 2031Other•NGoCT: 800 MW by 2025oCC: 680 MW by 2030oWabash River 6 NG Conversion(318 MW) in 2016Capacity Sources in Reference Scenario:Coal – 59%Gas – 24%IGCC – 7%Renewable/EE/DR – 11%Edwardsport IGCC beganoperations in 2013.No new coal plannedthrough 2031.Sourcing low-sulfur coal ona short-term basis for lowcapacity factor coalstations.Coal retirements includedin Recommended Plan.Signed a 20-yearpower purchaseagreement withthe Benton CountyWind Farm,resulting in 100MW of windcapacity for 20years.Carbon TaxAssumptions—EnvironmentalFocus Scenario:$20/ton in2020,increasing to$75/ton by2033.Low RegulationScenario:$0/ton allyears.ReferenceScenario:$17/ton in2020,increasing to$50/ton by2033.ReferenceScenarioBaseAssumptionof $5-12/mmBtuUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionBlack HillsPower2011(planthrough2030)IOU•Peak: 1.0% annualgrowth•EnergyRequirement: 1.0%annual growthProjectedreductions indemand from EEand DSM for 3years.•Year 1: 737kW•Year 2:1,107kW•Year 3:1,450kWOther•NGoCT: 36 MWoCC: 55 MW in 2014•Coal: 100 MW in 2024•Market Purchases: 25 – 50 MWannuallyIncluded 100MW of coal(2,627 $/kW in 2010 $s) in2024 but noted theuncertainty due topotential carbon costs.Assumed CCS not viable inthe IRP 20 year horizon.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Carbon costsnot included inbase case.Sensitivityanalysis usedlinear rise from15.74 $/ton(2015) to 54.06$/ton (2030).Linear risefrom 4.45$/MMBtu(Jan 2011)to 11.60$/MMBtu(Dec 2030).Ameren MO2014(planthrough2034)IOUExpectenergyconsumption toincrease by 12% andpeak demand toincrease by 8% over20 year timeframe.Retail Sales: 0.59%annual increaseRetail Peak Demand:0.40% annual increaseDemand Side:Plans to spend $148million from 2016-2018 to achieve 426GWH of energysavings and 114 MWof peak demandsavings.REAdding 400 MW of wind power, 45 MWof solar, 20 MW of hydroelectric and 5MW of landfill gasOther•NGoCC: 600 MW by 2034oConversion of Units 1&2 atMeramec Energy Center to NG in2016Additional CC and Nuclear optionspresented in contingency plan.No new coal planned.Evaluated over 20 coal andnatural gas resourceoptions. Eliminating coalwithout CCS from anyfuture consideration.Planning to retire one-thirdof coal-fired generatingcapacity.•400 MW wind•45 MW solar•28 MWhydroelectric•5 MW landfillgas•600 MWefficient NGfired CC•Continue to relyon existingnuclear,preserveoptions for newnucleargenerationNeed to meetrequirements ofMissouri’s RES.Between$23/ton and$53/tonstarting in2025.Cost ofcompliancewith CPPexpected to behigher than$53/ton.Use rangeof 4 - 6$/MMBtuover 20yearplanninghorizon.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionDelmarvaPower &LightCompany2014(through2024)IOUTotal Peak Demand:•2015: 1,957 MW•2020: 2,127 MW•2024: 2,220 MWTotal DSM Savings:2015: 344 GWh2020: 591 GWh2024: 801 GWhREThe 2014 DE Solar Renewable EnergyCredits (SREC) Procurement Programsecured SRECs from 385 projects thatrepresent 5.5 MW of solar facilities.No new coal planned.In the first year,Delmarva isrequired to procure13% of its supplyrequirements fromrenewableresources,including at least1% from solar. By2024, thepercentageincreases to 24%for all qualifyingresources and atleast 3.25% fromsolar.DE subject to aRPS.No pricesgiven.No pricesgiven.City ofPasadenaWater andPowerDepartment2012(through2030)Muni•EnergyRequirement: 0.5%annual growthEE goals included inbaseline scenario:energy requirement14.8% lower in 2030with EE thanwithout EE.EE•DR: 5 MWRE•Renewables (nameplate)oWind: 3 MWoSolar: 19 MWoBiomass: 10 MWoLandfill Gas: 10 MWoGeothermal: 10 MWoFeed-in-Tariff: 10 MWOther•NGoCC: 67 MWNo new coal planned.Existing coal deliverycontract (largest source intheir portfolio) will bediscontinued (108 MW).More renewablescan help mitigaterisks associatedwith higherNG and CO2compliance costs.Diverse set ofrenewablespreferred.Portfolios wereevaluated based onthe differencebetween the highand low LCOEoutcomes across arange of marketdrivers includingfuel costs.Evaluated a33% and 40%RPS.CO2Pricescenariosincluded bothstate andfederalregulatoryscenarios. Pricerange of 15-50$/tonne.Referencecase: 15$/tonne in2013 rising to30 $/tonne in2030.Evaluated 4trends.Trendsincludeprices 4-12$/MMBtuReferencecase: 5$/MMBtuin 2013rising to 8$/MMBtuin 2030.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionPortlandGeneralElectric2013(through2033)IOUAnnual averagedemand growth rateof 1.3%.Peak demand grows1.0% in winter and1.3% in summerLoad growth averages1.56% per yearbetween 2014 and2033.Additional 23 MWof DispatchableStandby Generation(DSG) by 2017.158 MW worth ofdemand-sideactions by 2017.DR: additional 25MW by 2017.Reference Case—Total Cumulative EEby 2032 is 361 MWaat the meter.All Deployable EEcase—479 MWa by2032.OtherNo major new resource actions arewarranted in current IRP Action Planhorizon. Future IRP will identify actionsto be taken in intermediate term.New resources under construction willprovide approximately 462 MWa energycapability annually, as well as 784 MWof peaking capacity. These include PortWestward 2 flexible gas plant, Cartybase load gas plant, and Tucannon Riverwind farm.No new coal planned.Boardman Plant ends theuse of coal by 2020.Need to maintaincompliance withOregon RPSModel existingregulations inCA and Alberta,Canada.2013: $9.10per short ton2020: $14.55per short tonModel a CO2tax of$16/short tonin 2023,escalating at8%/yr on allWECC thermalplants.Referencecase reallevelizedprice in2013 $ is$4.76/MMBtuSanDiegoGas andElectric(SDG&E)2014(through2023)IOUMust use CECforecasts•2014 Peak Load:4850 MW•2024 Peak Load:5357 MW2015 EE: additional60 MW2015 DR: 90 MW2024 EE: additional567 MW2024 DR: 95 MWOtherD.14-03-004 directs SDG&E to procure aminimum of 500 MW and up to 800 MWof new resources by 2022.No coal considered.CA has “preferredloading order”•cost-effective EEand DR•renewableresources tomeet RPS•cost-effectiveCHP•other resourcesSubject toAB32 whichincludes acarbon tradingscheme. Noprices given.No pricesgiven.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionGeorgiaPower2013(through2032)IOU•EnergyRequirement: 1.2%annual growth(avg)DSM:2011 - achieved130.4 GWh energysavings2012 - achieved 215GWh of energysavingsPlanned DSMprogram 2014savings projections:•Demand:~64MW•Energy:~290GWhSources recommended after feasibilityreview (capacity mix redacted):•NGoCToCCoCC with CCS•Nuclear•Coal with CCSCurrently have 1,007MW of nuclearunder construction to be completed by2018.Onlyinclude coal with CCSin generation mix feasibilityreview.Working on IGCC with CCSdemonstration plant(Kemper County).Applied to decertify2,093MW of coal.Switching coal to NG atYates Units 6 -7 and GastonUnits 1-4.Switching coal to biomassat Mitchell Unit 3.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Base caseassumed nocarbon price.Sensitivities of10 $/tonne(beginning2017), and 20$/tonne(beginning2020).Escalationrates redacted.Pricesredacted.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionIdahoPower2013(through2032)IOU•Peak: 1.4%(55MW) annualgrowth (avg)•EnergyRequirement: 1.1%annual growth(avg)Planned DRCapacity:•150 MW by2016-2017(needed prior tocompletion oftransmissionline)•370 MW by2024-2032EE•DR: 370 MW by 2032Other•Transmission Line: 500 kV 300 milesto connect Boardman to Hemingwayby 2018No coal planned.Coal/CCS were not addedin any sensitivity analysis.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.3 Scenarios:•No cost•14.64 $/tonin 2018escalatingat 3%annually•35 $/ton in2018escalatingat 9%annuallyBoard ofDirectorsguidelinesreduce avg.CO2emissionsintensity from2010 through2013 to 10-15% below2005 level of1,194 lbs/MWhRPS in Oregonof 10% by2025; no RPS inIdaho.Use EIAAEO 2012forecasts(9-17$/MMBtuby 2032,nominal$s).Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionDuke EnergyCarolinas2014(through2029)IOU•EnergyRequirement: 1.5%annual growth(avg); 1.0% if EEprograms counted•Peak: 1.4% annualgrowth (avgNCUC requiresexamination of DSMto meet peak andDSM/EE marketpotential studies.EE can be used tomeet RPS.DEC Projected EEand DSM Energyand CapacitySavings:2015•664,000MWhenergy•1,173 MWcapacity2029•7,668,000MWhenergy•2,475 MWcapacityRE•RenewablesoBiomass/Hydro: 324 MW by2029oSolar: 1,670 MW by 2029oWind: 150 MW by 2029•Total of ~1,248 MW (nameplate)additional renewables by 2021, and~2,144 MW by 2029NuclearCommercial operation of the first unit atthe Lee Nuclear Station by 2024.Consider nuclear a viable option,especially regional nuclear (i.e., multipleowners).Other•NGoCT: consider 792 MW in 2028oCC: consider 866 MW in 2020o770 MW NG CC plant availableby 2017oConvert 170 MW Lee Steam Unit3 from coal to natural gas in2015No new coal constructionplanned. Noted EPA rulesfor new coal.Will soon be closing lastcoal facility withoutadvanced emissioncontrols.Considered SCPC and IPCCwith CCS but determinedno cost-effective CO2controls for fossil plants.Nuclear included inportfolio in orderto maintain fueldiversity.Need to complywith NC REPS.Developed aseparatecarbon neutralplan.Must makeCliffside Unit 6carbon neutralby 2018 for airpermit.Referencecase:•$17/ton in2020•$36/ton2029High case:•$20/ton in2020•$50/ton2029Gas hastraditionally beenused forpeakinggeneration,but hasbegun toplay a moreimportantrole due topricing andaddition ofsignificantCCgeneration.Sensitivityof +- 15%wasperformed:Short-termpricing:based onmarketobservations.Long-termpricing:based onCompany’sfundamental fuel priceprojections.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionProgressEnergyCarolinas,Inc.2012(through2027)IOU(Merged withDuke)•Retail Demand:1.2% annualgrowth; 1.6% ifDSM programs notcountedNCUC requiresexamination of DSMto meet peak andDSM/EE marketpotential studies.EE can be used tomeet RPS.EE•EE&DSM: 613 MWNuclear•Nuclear: 552 MW (regional partialownership agreements)Other•NGoCT: 1,051 MWoCC: 3,119 MWNo coal planned.Modeled NGCC costs(capital and O&M) lowerthan PC costs across allcapacity factors.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Base case:•$26/ton in2017•$80/ton2031Low case:•$20/ton in2017•$45/ton2031High case:•$70/ton in2017•$170/ton2031Pricesredacted.IndianapolisPower &LightCompany2014(through2034 butalsoincludesscenariosthrough2024)IOU•Base Case with netDSM impacts:•0.3% CAGR peakload growth•3131 MW netinternal demandby 2034Indiana GeneralAssembly passedlegislationeliminatingpreviouslyestablished IURCtarget levels of EEDSM. Company willidentify costeffective DSMstrategy.EE•EE: 379,204 kW savings by 2017•DSM: 182,703 kW savings by 2017•Renewables: 300 MW wind and 100MW solar by 2024Other•NGoCC: 644-685 MW plant underconstructionBase Case expansion plan includes noadditional generation extending outuntil 2031.No coal planned.Planning to retire somecoal units by end ofPlanning Period.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Base Case :$0/tonAnalyzedEnvironmentalScenario withcarbon taxbeginning in2020, butassumptionsnot listed.Acknowledges thatnatural gasprices are akey driverinmodeling.Does notlist specificpriceassumptions.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionIndianaMichiganPowerCompany2013(through2033)IOU•EnergyRequirement: 0.2%annual growth(avg)•Summer Peak:0.3% annualgrowth (avg)•Winter Peak: 0.1%annual growth(avg)DR: 296 MWreduction in peakcapacityrequirementsEE: 2,586 GWhreduction in energyrequirements by2033Obligation to PJM of296 MWInterruptibleDemand Responseby 2033.New capacity needed to replace retiredcoal capacity.EE•DR: 296 MWRE•RenewablesoWind: 200 MW by end of 2014and 100 MW by 2026oSolar: 50 MW (nameplate) addedeach year beginning in 2020oSolar from customers: 10 MW(nameplate) in 2016, ~150 MW(nameplate) by 2033NuclearDo not view new nuclear as financiallypractical. Coal and nuclear baseloadoptions were not included in plan.No coal planned in anymodeled scenario—newcoal seen asenvironmentally andeconomically impracticalPlan to retire 982 MW ofcoal.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Expects that utilityscale solarresources willbecomeeconomicallyjustifiable by 2020.Project carbontax to takeeffect in 2022.$15-$20/metricton assumedover long-termanalysis period.Use EIA’s2013AnnualEnergyOutlookforecasts.IndianaMunicipalPowerAgency2013(through2033)Muni•EnergyRequirement: 1.0%annual growth•Peak: 1.0% annualgrowthHighEE target 10%reduction indemand and energyrequirements by2020. Earlyindicators suggestthis may not berealistic.Base EE plan targets2.5% cumulativesavings by 2020.New peaking and intermediate capacityneeded to replace retiring capacity.RE•RenewablesoSolar: 21 MW by 2020Other•NGoCT: 185 MW by 2016oCC: 200 MW by 2023No coal planned in anymodeled scenario.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Include amodel scenariowith CO2capand tradebeginning in2021.Include amodel scenariowith a modestcarbon taximplementedin 2030.Assumed max$25/metric tonin 2032.Use EIA2012referencecase, whichprojects NGpriceincrease on4.5% peryear.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionNorthernIndianaPublicServiceCompany2014(through2035)IOU•EnergyConsumption : lessthan 0.5% annualgrowth over next20 years•Peak: 3,208 MW in2014 to 3,574 MWby 2035Variety of DSMprograms available.2015 ProjectedSavings: 119,603MWhDSM: 126.5 averagepeak reduction overplanning horizonRE•Included renewables in one model,but added no value to portfolio andled to increased cost.Other•Long term need includes one CCGT in2023 and one CCGT in 2035, 660 MWeach.•Retiring 949 MW of coal by 2035.No coalplanned.Coal and CCS wereevaluated as resourceoptions.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.No price oncarbon prior to2020.Assumed$20/ton by2025 with SlowEconomicImprovement,and $20/ton by2020 inAggressiveEnvironmentalscenario.Assumed$4.54/MMBtu @ 5%in SlowEconomicImprovement scenario.Assumed$5.85/MMBtu @4.9%inAggressiveEnvironmentalScenario.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionVectrenCorporation: SouthernIndiana Gasand ElectricCompany(VectrenSouth)2014(through2034)IOU•EnergyRequirement: --0.2% CAGR overplanning period•Peak: -0.1% CAGRover planningperiodSavings target of 1%on eligible customersales for 2015-2019.Incremental energysavings of 0.5% peryear beginning in2020.DSM energyefficiency programsavailable to allcustomer classes.No additional generation needed.In high load growth scenarios additionaldemand was met with CCGT and solarPV.Will reevaluate economic viability ofsolar generation in future IRPsNo new generationplanned.No new generationplanned in nearfuture.Not making adecision aboutretirement date forFB Culley 2 at thistime.Models considerpotentialRenewablePortfolio Standard.Analysisconsiders pricefor carbonbeginning in2020.High scenarioassumed$15.5/ton, lowscenarioassumed$10.3/ton.Base Case(2014 $s):$4.65/MMBtu in2015.$7.35/MMBtu in 2034The naturalgas priceforecast isan averageof U.S.EnergyInformationAdministration(EIA)AnnualEnergyOutlook(AEO) 2014Referencecase, WoodMackenzielong termforecast,and Black &Veatch’snatural gasforecast.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionWabashValleyPowerAssociation,Inc.2013(through2032)Coop•EnergyRequirement: 0.7%annual growth (netof pass-throughs),or approximately53 GWh/yr•Peak: 0.4% annualgrowth (includingpass-throughs),reaching 1,926MW by 2032Do not serve anyretail customersdirectly. Customersserved by theAssociation’smembers.Have EE and DRcommittees thatrecommend EE andDR programs tomembers.Direct Load Controlprogram(“PowerShift”) goalis 55 MW ofcontrollable load by2020.•First forecasts a need for additionalcapacity in 2017. Analysis does notadd baseload or intermediateresources until 2027 when powerpurchase agreements expire.EE:•Specific capacity was not includedbut EE was referenced as a plannedsource.•DR: Additional 18 MW in 2014-2016•92 MW of planned additions by2032 in High Economic Growthscenario and Low Economic GrowthscenarioRE•Landfill: 4 MW gas power plannedfor purchase for 2014, as well as 3.2MW gas-fired internal combustionengines in 2014 and 2016.•Solar: 20 KW purchase planned for2014•Wind: Plans to purchase 10 MW in2015.•Other•NGoEvaluated cost of CT and CC, butnot included in short term plan.No coal planned.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Potentialfuturelegislation isfactored intoanalysisbeginning in2023. Priceassumptionsbased on ACESlong-termforecast.HighPrice:$10/MMBtuLow Price:$1/MMBtuUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionGreat RiverEnergy2014(through2029)Coop•EnergyRequirement: 1.3%annual growth•Peak: 1.0% annualgrowthEE is a focus ofthe“preferred plan” butno specificcapacities are given.EE contributes to1.5% of total retailenergy savings ineach year ofplanning period.Addition of renewables needed in 2026to meet the MN Renewable EnergyStandard. No other capacity needed.REoWind: 600MW nameplate by 2029oHydro: 200 MW by 2020oExploring possibility of solarNo coal planned.No non-renewable capacityis needed in the planningperiod.Plan to depreciate twolargest coal fired stationsby 2028.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.Up to 2019(EnvironmentalCost): $0.43-$4.46/ton forpowergeneratedwithin MN. $0for outsideMN.After 2019(RegulatoryCost):$9-$34/tonregardless oflocation.Prices wereprojectedby blendingbrokerquotes withWoodMackenziepriceforecast.Prices notgiven.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionAEP East2011IOU•Energy Sales:0.24% CAGR•Peak Load Growth:0.71% CAGR•1,213 MWincrementalpeak demandreduction by2014•Passive demandresponse (DR):868 MW by2020•Active DR: 600MW by 2020No new baseload capacity requiredwithin planning period.Assumes 540 MW Dresden CC facilitycomes on line in 2013.Also includes assumed performance ofDonald C. Cook Nuclear Plant ExtendedPower Update (EPU) within 2014-2018time period.Purchase power agreements forrenewable energy—mostly wind.Natural gas-fired peaking andintermediate capacity added shortlyafter 2020 to meet future loadobligations.No new coal planned.Plan includes developmentand phase-in of CCS at theAPCo Mountaineer Plantand at a unit of the OPCoGarvin Station by 2020. CCSdevelopment driven in partby future CO2emissionlegislation/regulation.Plan also considers thepotential retirement ofaround 6,000 MW of coal,due in part to future EPAregulation (HAP and CCRrulemaking).Prospect of futureGHG and CO2emissionlegislation/regulation has promptedaround 2,000 MWof renewableresource additionsby end of 2014.Assumes 1,100MW nameplatecapacity ofrenewables, mostlywind. Consistentwith staterequirements inregion, includingOhio SubstituteS.B. 221.150 MW dedicatedbiomass generationby 2018CO2pricingassumptionsdevelopedafter U.S.House passageof theWaxmanMarkey bill.Analysisassumeslegislation willbe effective by2014.No naturalgas priceslistedUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionPacifiCorp2013-2022IOU•Peak: 1.2% annualgrowth•1.1% annualenergy loadgrowth•1,593 MW ofDSM EEInstalledCapacity•193 MW of DSMload control•System capacity deficit of 2,308 MWby 2022RE•Wind: 650 MW between 2024-2025•Solar: 303 MW utility +distributedOther•362 MW peaking gas installedcapacity by 2032•2,813 MW CCTT by 2032No coal planned.Retiring 502 MW of coal in2015.Variations of RPSsincluded inscenarios.Variousscenariosanalyzed, bothcarbon tax andcap-and-trade.Tax: $13.52-$74.99/shortton overplanningperiodCap-and-trade:$47/47-$132.25/shortton overplanningperiodPacifiCorprelies upona numberofexpertthird-partyproprietarydata andforecastingservices toestablish arange ofgas pricescenarios.Prices notgiven.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionColoradoSpringsUtilities2012-2031Muni•Energyrequirements:1.9% increase by2031•System peak: 2.1%increase by 2031Analyzed variousDSM scenariosHigh: 10% energyreduction by 2020Medium: 6% energyreduction by 2020Low: 4% energyreduction by 2020DSM could decreaseload requirement by82 MW by 2030.•35 MW deficit by 2030Scenario 1—Energy Vision 2020RE•Wind: 100 MW in 2013•Biogas: 0.6 MW in 2013•Biomass: 20 MW in 2024•Hydro: 13.2 MW by 2026•Geothermal: 10 MW in 2023•Solar: 40 MW by 2031Scenario 2—Current BusinessRE•Wind: 50 MW in 2013•Biogas: 0.6 MW in 2013•Hydro: 10.2 by 2029•Geothermal: 10 MW in 2018Other•LM 6000 Gas CT: 39 MW in 2030•Nixon Plant Upgrade: 15 MW in2018No coalplanned.Advanced pulverized coalwith and without CCSincluded in evaluation.CORES requiresthat energy fromqualifyingrenewable energyresources must beat least six percentfor the years 2015through 2019 and10 percent for year2020 andthereafter. Mustcome fromqualifyingrenewable energyresources, whichinclude solar, wind,geothermal,biomass, existinghydroelectricgeneration with anameplate ratingof 30 megawatts orless, and newhydroelectricgeneration with anameplate ratingof 10 megawatts orless.Low PricePoint: $3/tonMedium andHigh Points:Based onEuropeanUnion carbonmarkets. Rangefrom $25-$50/ton$4.29/mmBtu in 2012$10.49/mmBtu in 2031High andlowscenariosused plusand minus40% of thisrange.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionArizonaPublicServiceCompany(APS)2014-2029IOU—subsidiary ofPinnacle West•Peak Load Growth:3% annual increaseover planningperiodEE: 1,447 MWDR: 275 MWDistributed Energy:261 MW (722 MWNameplate capacity)About 6,600 MW of additional resourcesneeded by 2029RETotal: 425 MWOtherNG Total: 4,205 MWNo coal growth plannedHighly flexiblenatural gasresources will befavored overtraditionalbaseload sourcesdue to low prices,increased cost ofenvironmentalregulation, andincreased selfdispatching solargeneration.Assumedcarbonallowancesbeginning in2021, based ontrading price ofCO2allowancesin CA inSeptember2013. After2021, pricesescalate at rateof inflation.High Scenario:$15/ton in2019,increasing 7.5%annuallyPriceassumptions derivedfromanalysis offorwardmarketprice curveat end of3rdquarter2013.Slightlymore than$7/mmBTUdeliveredby 2029TucsonElectricPower (TEP)2014-2028IOU•Peak Demand:1.0%-1.5% annualincreaseEE: reduce peakdemand by 312 MWby 2028DR: reduce peakdemand by 50 MWby 2028RE•Total: 529 MW utility-scalenameplate capacity by 2028 (solar,wind, and biogas)•Solar: 78 MW rooftop solar by 2015Other•CC: 413 MW in 2015•Other NG: 820 MW from 2019-2026(550 MW CC and 270 MW peakingresources)•Transmission upgrades andimproved storage technologies: 50MW battery storage by 2028Plan to reduce coalcapacity by 492 MW overnext five yearsLooking tominimize waterusage and negativeenvironmentalimpacts whilemeeting Arizona’sRES.RES requires 4.5%of 2014 loadrequirement and15% of 2025 loadrequirement is metwith renewableresources.$17.23/metricton beginningin 2023.Increasing 6%annually.Wood-Mackenzieforecast.$4.47/MMBtu in2014.$7.36/MMBtu in2028.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionUNSElectric, Inc.2014-2028UniSource—IOU•2014 ReferenceCase projects peakdemand stayingrelatively flat forplanning periodEE: reduce peakdemand by 59 MWby 2028DR: reduce peakdemand by 14 MWby 2028RE•Total: 119 MW utility-scalenameplate capacity by 2028 (Solarand wind)•Solar: 56 MW distributed generationby 2028Other•CC: 138 MW in 2015•CT: 111 MW by 2019•408 MW nameplate capacity in NGresources by 2028•Transmission upgrades andimproved storage technologies: 1.85MW battery storage by 2028No additional coal planned.RES requires 4.5%of 2014 loadrequirement and15% of 2025 loadrequirement is metwith renewableresources.$17.23/metricton beginningin 2023.Increasing 6%annually.Wood-Mackenzieforecast.$4.47/MMBtu in2014.$7.36/MMBtu in2028.ArizonaElectricPowerCooperativeCoop•Total annual peakdemand forecastof 62.5 MWthrough 2028 forDuncan ValleyElectricCooperative, Inc.(DVEC) andGraham CountyElectricCooperative, Inc.(GCEC)•No demand growth expected 2014-2021. No indication of new resourcecapacity in planning horizon.Assume energyportfolio thatcomplies withArizona RES andenergy efficiencystandardsUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionPugetSoundEnergy2013-2033IOU•Additional 12 MWof peak hourcapacity by 2017.Grows to 100 MWby 2020.Demand-Sideresources: 1,007MW cumulativenameplate capacityby 2033Retiring up to 2,000 MW by 2020,creating a need for new resources.RE•Wind: 600 MW by 2033Other•Peakers (CT in MW): 2,212 by 2033•Transmission renewals: 1,567 MWby 2033•Gas storage: 150 MDth/dayEvaluated economicviability of Colstripgenerating station underdifferent regulationscenarios. Planning tocontinue operation ofColstrip for this planningcycle.Need to complywith Washingtonstate law (RCW19.285) and RPSPSE has acquiredenough eligiblerenewableresources and RECsto meet therequirements ofthe law through2022.To account foruncertainty,analysisincludes rangefrom $0 to$179/ton.Gas priceforecastsare acombination offorwardmarks inthe nearterm andWoodMackenzieforecastsfor thelongerterm.Seattle CityLight2014-2034Muni•Demand growth:0.5% annual 20-year avg.ConservationPotentialAssessment: 118.4MW by 2023 and250.6 MW by 2033Other•Hydro efficiencies expected toincrease generating capability by~40 MW by 2017No coal planned.Modeled potentialclimate changeimpacts, especiallythe effect of glacialmelt onhydropower. Takeninto account inplanning.Includes forecastedelectric vehicledemand.Do not includeprices.Assuming stateregulationbegins beforefederalregulation.$6.50/MMBtu by2031Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionMontana-DakotaUtilities2013-2032IOU•Summer Peakdemand: 1.6%average annualgrowth rate (priorto DR programs)through 2032, but2.4% increaseannually through2018•EnergyRequirements:2.0% annualincrease throughplanning period,but 3.2% annualincrease through2018DR: 10 MW programby 2015Will continue topromote theinterruptible ratesto reach 23 MWtotal.Committed to:•88 MW Simple cycle CT atHeskett by 2015•Air Quality Control System at BigStone plant by 2015Potential Resource Options:RE•Wind: 50 to 100 MWOther•36.6 MW internal combustionengines by 2015•CC: 200 MW in 2020Coal-fired generation wasanalyzed as a resourceoption.No coal planned.Consideredeconomic, societal,and customerissuesMentionscommitment toreducing airemissionsMentions ongoingCCS researchModeledcarbon tax of$30 and $50per tonBase case:$3.51/MBTU in 2013and$4.33/MBTU in 2017.3% annualescalationthereafter.High case is$3 moreand lowcase is $1less.Xcel EnergyUpperMidwest2016-2030IOU•Peak demand:0.4% annualincrease•Forecasted load:10,251 MW by2030DR: additional 76MW through 2030DSM goal: 1.5% ofretail salesNo new capacity needs for the first fiveyears of the plan. By 2030, 2,862 MWdeficit.RE•Wind: 1,800 MW•Solar (utility-scale): 1,887 MW•Small-scale solar: 500 MW by 2030Other•NG Peaking Resources: 1,750MWContinuing to run ShercoUnits 1 and 2 throughoutthe planning periodNo additional coal plannedUntil 2020, focus isto meet the SolarEnergy Standardand accomplish a30% carbonreduction.Exposure to fuelprice volatility wasfactored intogeneration mixchoices but noquantitativemeasurementsgiven.$21.50/ton in2019,increasing withinflation.Also analyzedsocietal valueof CO2as anexternality.Prices notincludedUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionSouthwestern ElectricPowerCompany2016-2035IOU•Internal energyrequirements:0.2% annualdecrease through2035•Summer peakdemand: 0.2%annual decreasethrough 2035•Winter peakdemand: 0.1%annual decreasethrough 2035•Demand decreaseis due to expiringcontracts—if theseare omitted,demand isexpected toincrease by 0.7%(internal energy),0.7% (summerpeak demand),and 1.1% (winterpeak demand),annuallyReduce energyrequirements by1,121 GWh (5% ofprojected energyneeds) by 2035Reduce capacityrequirements by410 MW by 2035RE•Wind: 1,700 MW•Solar (utility scale): 800 MW•Solar (distributed): 50 MWOther•Retires 722 MW of older gas-steamunits beginning in 2016 through2030.•Adds 207 MW of natural gas peakingresources over the 20-year planningperiodMaintains solid-fuel units atWelsh Units 1 & 3, FlintCreek and Pirkey, inaddition to its share ofenergy and capacity fromthe non-SWEPCO operatedDolet Hills unitRetires Welsh Unit 2 (coalfired plant) in 2016Reduced relianceon solid fuel-based(from 46% to 31%)and gas-steam(from 25% to 13%)capacity as part ofits portfolioof resources.Combined cyclenatural gasincreases from 12%to 13% of capacitymix.Increased relianceon demand-side(from 1% to 6%)and renewableresource capacity(from 6.9% to37%), therebyenhancing resourcesupply technologyand resourcesupply fueldiversity.Generation fromcoal decreases(81% to 49%),while renewablesincrease (7.7% to38.6%).Base pricingscenario of$15/tCO2beginning in2022,increasing to$17/mt in 20302 lowerprobabilityscenarios:$15/mt in 2020rising to$25/mt in2030, applyingonly to coal,not gas$25/mt in2020, rising to$40/mt in2030, applyingto all fossilgenerationBase:$5.5/mmbtu in 2015,rising to$8.5/mmbtu in 2030Highestscenario:$5.9/mmbtu in 2016,rising to$9.8 in2030Lowestscenario:$5.1/mmbtu in 2015,rising to$7.5/mmbtu in 2030All prices innominaldollarsUtility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionDuke EnergyOhio2013-2023IOU•Net energy: 1.7%annual increasefrom 2013 (~21.5million MWh) to2023 (~25.5 millionMWh) before EE,0.4% increase afterEE•Summary peakdemand: 1.7%annual increasefrom 2013 (~4,250MW) to 2023(~4,500 MW)before EE, .5%increase after•Winter peakdemand: 1.6%annual increasefrom 2013 (~3,500MW) to 2023(~3,750 MW)before EE, 0.8%afterCumulative savingsof 3.5 million MWhthrough 2023.Reduced summerpeak demandthroughConservationProgram LoadImpacts (595 MW)and DSM impacts(138 MW) in 2023(733 MW total).Few specifics on the fuel/plant types tomeet new demand. Duke does employ acompetitive bidding process to securecompetitive retail supply in advance.EEPlans to meet Energy Efficiencyobligations under existing law throughconservation and demand-sidemanagement programs.Acceleratedretirement ofcertain coal-firedgeneration is possible.Future coal and IGCC Unitsmust employ CCS to meetNSPS. New gas will nothave to use CCS.Current renewableenergy strategy isthrough short-termREC purchases,though Dukerealizes efforts maybe required inorder to ensurecompliance withthe 12.5%renewablerequirement underOhio’s AlternativeEnergy PortfolioStandard (whichalso has a carveout for solar).Does notinclude carbonpricingAnnualgrowth ratefrom 2013to 2023 of2.9%annually, innominalterms.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionPG&E2015-2024IOU•Firm peak-hourAugust demandincreasesfrom21,186 MW in2015 to 21,724MW in 2024(CPUC-mandatedscenario)•Firm peak-hourAugust demanddecreasesfrom20,153 MW in2015 to 18,091MW in 2024 (PG&Ealternativescenario)•Energy demandincrease of 85,494GWh in 2015 to77,968 GWh in2024 (CPUCmandatedscenario)•Energy demandincreaseof 85,494GWh in 2015 to66,855 GWh in2024 (PG&Ealternativescenario)DR Program of 287MW in 2024 of baseinterruptible power,82 MW of ACCycling residentialpower, and 1 MW ofAC Cycling nonresidential powerCPUC ScenarioREPortion of contracted renewable energyincreases from 2,728 MW (17,791 GWh)in 2015 to 3,544 MW (14,656 GWh) in2024 (other portion of RE was redactedin this version).Generic renewable energy increasesfrom 0 MW (0 GWh) in 2015, increasingto 1,304 MW (8,691 GWh) in 2024.OtherEnergy storage resources increase from0 MW (0 GWh) in 2015 to 403 MW (124GWh) in 2024.PG&E ScenarioREPortion of contracted renewable energyincreases from 2,728 MW (17,791 GWh)in 2015 to 3,183 MW (14,656 GWh) in2024 (other portion of RE was redactedin this version).Generic renewable energy increasesfrom 0 MW (0 GWh) in 2015, increasingto 114 MW (1,532 GWh) in 2024.OtherEnergy storage resources increase from0 MW (0 GWh) in 2015 to 403 MW (124GWh) in 2024.Fossil resource capacityprojected to remainconstant through 2024(although projectedgeneration informationwas redacted in thereport).California loadingorder preferences:Cost-effective EEand DR arepreferred to meetCalifornia’sgrowing energyneeds, followed bycost-effectiverenewable and DGresources, andfinally clean andefficient fossilfueled generation.Information oncompliancewith AB32 isredacted in thereport. Thereport does saythat “PG&E willonly useapproved GHGproducts thathedge GHGprice risk thatwould besubject to GHGlimits.”Projectionsof naturalgasconsumption andpossiblyprices havebeenredacted inthis versionof theprocurement plan.Utility YearUtilityOwnershipTypeFuture Demand Energy Efficiency New Resources to Meet Demand Future Coal and CCS Fuel DiversityChoicesCarbon PriceAssumptionsNatural GasPriceProjectionNorthwestPower andConservation Council2010-2030RegionalAdvisoryCouncil•Electricity load:1.4% annualgrowth (~335 MWper year)•Summer peak:1.7% annualgrowth•Winter peak: 1%annual growthStringent enoughenergy efficiencyand conservationcould meet 85% ofload growth forduration of planningperiod.Energy efficiency isNWPCC’s firstpriority resource.Council target is1,200 average MWby 2014, and 5,900average MW by2030.EECouncil target is 1,200 average MW by2014, and 5,900 average MW by 2030.RE•Resources developed inresponse to state RPS mandateswill account for 1,450 MW ofenergy on average (4,500 MWinstalled capacity)Options modeled include:•4,800 MW of wind by 2030•424 MW geothermal by 2030•830 MW biomass by 2030Other•Mention that additional naturalgas generation will likely benecessary•Considered 4,400 MW nuclearby 2030No new coal planned.Some new coal optionsconsidered in analysis.The Council suggests thatutilities and states supportCCS development.By 2030, the sharesof loads that mustbe met fromrenewabletechnologies are:15% in MT, 25% inOR, and 15% (by2020) in WA.Planningscenariosmodeled from$0 to $100 perton, with $47per ton by2030High casewellheadprice: $9 by2025 and$10 by2030Low case:$4 to $5per millionBtuUtilityDocument TitleWeb Link to IRPTennessee Valley Authority (TVA)Integrated Resource Plan 2015 Draft Reporthttp://www.tva.com/environment/reports/irp/pdf/TVA-Draft-Integrated-Resource-Plan.pdfDominionDominion North Carolina Power's and DominionVirginia Power's Report of Its Integrated ResourcePlan,August 2014https://www.dom.com/library/domcom/pdfs/corporate/integrated-resource-planning/nc-irp-2014.pdfDuke Energy IndianaThe Duke Energy Indiana 2013 Integrated ResourcePlan, November 2013http://www.in.gov/iurc/files/2013_Duke_Energy_Indiana_-_IRP_Report_Volume_I.pdfhttp://www.in.gov/iurc/files/2013_Duke_Energy_Indiana_-_IRP_Volume_II.pdfBlack Hills Power2011-2030 Integrated Resource Plan For Black HillsPower, 2011http://psc.state.wy.us/pscdocs/dwnload/BHP%20EFP%20IRP%20&CLFP%20IRP/BHP%202011-2030%20IRP.pdfAmeren MOIntegrated Resource Plan Update, October 2014https://www.ameren.com/missouri/environment/renewables/ameren-missouri-irpDelmarva Power & LightCompanyDelmarva Power & Light Company 2014 IntegratedResource Plan, December 2014https://www.delmarva.com/uploadedFiles/wwwdelmarvacom/DE%20IRP%20PUBLIC%20VERSION%20%20120114.pdfCity of Pasadena Water andPower DepartmentIntegrated Resource Plan Update, February 2012http://ww2.cityofpasadena.net/waterandpower/irp/2012IRPUpdate.pdfPortland General Electric2013Integrated Resource Plan Updatehttps://www.portlandgeneral.com/our_company/energy_strategy/resource_planning/irp.aspxSan Diego Gas and Electric(SDG&E)San Diego Gas and Electric Company Draft 2014 Long-Term Procurement Plan, 2014https://www.sdge.com/sites/default/files/regulatory/PUBLIC-SDGE-Bundled-Plan.pdfGeorgia PowerGeorgia Power Company’s 2013 Integrated ResourcePlanand Application for Decertification of Plant BranchUnits 3 and 4, Plant McManus Units 1 and 2, Plant KraftUnits 1-4, Plant Yates Units 1-5, Plant Boulevard Units 2and 3, and Plant Bowen Unit 6, 2013http://www.psc.state.ga.us/factsv2/Document.aspx?documentNumber=145981Idaho Power2013 Integrated Resource Plan, June 2013https://www.idahopower.com/AboutUs/PlanningForFuture/irp/2013/default.cfmDuke Energy CarolinasDuke Energy Carolinas’ 2014 Integrated Resource Plan,September 2014http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=c3c5cbb5-51f2-423a-9dfc-a43ec559d307Progress Energy Carolinas, Inc.Progress Energy Carolinas, Inc.’s IntegratedResourcePlan, November 2012http://www.energy.sc.gov/files/view/ProgressEnergyResource%20Plan2012.pdfIndianapolis Power & LightCompanyIndianapolis Power & LightCompany2014 Integrated Resource Planhttp://www.in.gov/iurc/files/IPL_2014_IRP_Report.pdfIndiana Michigan PowerCompanyIndiana Michigan Power Company Integrated ResourcePlanning Report, November 2013http://www.in.gov/iurc/files/2013_Indiana_Michigan_Power_Co_-_IRP_Report.pdfIndiana Municipal Power AgencyIndiana Municipal Power Agency2013IntegratedResource Plan, November 2013http://www.in.gov/iurc/files/2013_Indiana_Municipal_Power_Agency_(IMPA)_-_IRP_Report.pdfNorthern IndianaPublic ServiceCompanyNIPSCO 2014Integrated Resource Plan, November2014http://www.in.gov/iurc/files/NIPSCO_2014_IRP.pdfVectren Corporation: SouthernIndiana Gas and ElectricCompany (Vectren South)Vectren 2014Integrated Resource Plan, November2014http://www.in.gov/iurc/files/SIGECO-Vectren_2014_IRP_Report.pdfWabash Valley PowerAssociation, Inc.WabashValley Power Association, Inc. 2013IntegratedResource Plan, November 2013http://www.in.gov/iurc/files/2013_Wabash_Valley_Power_Association_-_IRP_Report.pdfGreat RiverEnergyGreat River EnergyResource Plan2015-2029, October 2014http://www.greatriverenergy.com/makingelectricity/resourceplan/2014_irp.pdfPacifiCorp2013 Integrated Resource Plan Volumes 1 and 2http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/PacifiCorp-2013IRP_Vol1-Main_4-30-13.pdfhttp://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2013IRP/PacifiCorp-2013IRP_Vol2-Appendices_4-30-13.pdfgeneral website:http://www.pacificorp.com/es/irp.htmlColorado Springs Utilities2012 Electric Integrated Resource Planhttps://www.csu.org/CSUDocuments/eirp.pdfArizona Public Service Company(APS)APS 2014 Integrated Resource Planhttp://www.azenergyfuture.com/getmedia/c9c2a022-dae4-4d1b-a433-ec96b2498e02/2014_IntegratedResourcePlan.pdf/?ext=.pdfTucson Electric Power (TEP)Tucson Electric Power 2014 Integrated Resource Planhttps://www.tep.com/doc/planning/2014-TEP-IRP.pdfUNS Electric, Inc.UniSourceElectric2014 Integrated ResourcePlanhttps://www.tep.com/doc/planning/2014-UES-IRP.pdfArizona Electric PowerCooperativeArizona Electric Power Cooperative, Inc. IntegratedResource Plan Presentation to the Arizona CorporationCommission 2014General website, need to keep looking for IRP:http://www.azgt.coop/electricity-generation-and-transmission/generation/arizona-electric-power-cooperative/Unable to find IRP, but presentation on IRP is available here:http://www.azcc.gov/Divisions/Utilities/Electric/IRP2012/2014/AEPCO%20IRP%20Presentation%2009.11.14.pptxPuget Sound Energy (2013)2013 Integrated Resource Plan, chapters andappendiceshttp://pse.com/aboutpse/EnergySupply/Documents/IRP_2013_Chapters.pdfhttp://pse.com/aboutpse/EnergySupply/Documents/IRP_2013_Appendices.pdfSeattle City Light (2014)Seattle City Light Integrated Resource Plan 2014Update and Progress Reporthttp://www.seattle.gov/light/news/issues/irp/docs/SeattleCityLight2014_IRPUpdateandProgressReport.pdfMontana-Dakota Utilities (2013)Montana-Dakota Utilities Co.2013 Integrated Resource Plan, Volumes I-IVhttp://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-i.pdf?sfvrsn=0http://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-ii.pdf?sfvrsn=0http://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-iii.pdf?sfvrsn=0http://www.montana-dakota.com/docs/default-source/2013-irp/2013-mdu-irp-report---volume-iv.pdf?sfvrsn=0Xcel Energy Upper Midwest(2016)Upper Midwest Resource Plan 2016-2030http://www.xcelenergy.com/staticfiles/xe/Regulatory/Regulatory%20PDFs/03-Preferred-Plan.pdfAEP East2010 AEP-East Integrated Resource Planhttp://www.psc.ky.gov/PSCSCF/2011%20cases/2011-00401/Kentucky%20Power%20Responses%20to%20042312%20Order/Sierra%20Club/012712/Sierra%201-3%20%20AEP%20East%202010%20IRP.pdfSouthwesternElectric Power Company(SWEPCO)Draft Integrated Resource Plan (2015)https://www.swepco.com/global/utilities/lib/docs/info/projects/SWEPCOIntegratedResourcePlan/2015_DRAFT_SWEPCO_LA_IRP_Filed_Feb_6.pdfDukeEnergy OhioDuke Energy Ohio 2013 Resource Planhttps://www.duke-energy.com/pdfs/2013-Ohio-IRP-FINAL.pdfPG&EPG&E Proposed 2014 BundledProcurement PlanProceedinghttps://pgera.azurewebsites.net/Regulation/ValidateDocAccess?docID=313992Northwest Power andConservation CouncilSixth Northwest Conservation and Electric Power Planhttps://www.nwcouncil.org/media/6284/SixthPowerPlan.pdf

# Abbreviations

AEO – Annual Energy Outlook

AEP – American Electric Power

CAGR – Compound Annual Growth Rate

CC – Combined cycle

CCS – Carbon capture and sequestration

CHP – Combined heat and power

CT – Combustion turbine

DR – Demand response

DSM – Demand side management

EE – Energy efficiency

EIA – Energy Information Administration

EPA – Environmental Protection Agency

IGCC – Integrated gasification combined cycle

IRP – Integrated resource plan

IURC – Indiana Utility Regulatory Commission

kV – Kilovolts

kW – Kilowatt

kWh – Kilowatt hours

LCOE – Levelized cost of energy

MMBtu – Million British thermal units

MW – Megawatts

MWa – Average megawatts, or the average number of m egawatt-hours over a given year

MWh – Megawatt hours

NCUC – North Carolina Utility Commission

NG – Natural gas

RPS – Renewable portfolio standards