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SMART RATES FOR SMART UTILITIES

Creating a New Customer Paradigm

with Enhanced Pricing of Utility

Services

H. Edwin Overcast

®

®

H. Edwin Overcast | SMART RATES FOR SMART UTILITIES

BLACK & VEATCH | Table of Contents i

Table of Contents

Introduction................................................................................................................................1

TheChallengewithCurrentUtilityRateDesigns...........................................................2

UnderstandingCostDrivers............................................................................................................2

AUtility’sCostCausativeFactors.............................................................................................3

Understandingutilityservices.......................................................................................................4

Modernchallengestotraditionalrates.......................................................................................5

NetMeteringPolicies....................................................................................................................5

Demand‐SideManagement.........................................................................................................6

21stCenturyRateDesign.........................................................................................................7

UnbundledRateComponents.........................................................................................................7

DerivationoftheCustomerCharge.........................................................................................7

DerivationoftheProductionDemandCharge....................................................................8

DerivationoftheTransmissionDemandCharge...........................................................10

DerivationoftheDistributionDemandCharge..............................................................10

DerivationoftheEnergyCharge...........................................................................................11

IllustrativeRateStructures...........................................................................................................12

RoleofAdvancedTechnologies..................................................................................................15

OtherConsiderations......................................................................................................................15


BLACK & VEATCH | Introduction 1

Introduction TheU.S.electricutilityindustryisinthemidstofrapidtechnologicalchangeandatransformationof thecustomerserviceparadigm.Muchof thedebatesurroundingthechanging industrycenterson the implementation of more sustainable practices, such as energy efficiency and distributedenergy resources, and compliance with more stringent environmental regulations. Notably, thedebatescontinue to focuson technological andoperational solutions.However,developinga21stcenturyratedesign,orSmartRates,canhelpfacilitatesolutionstotoday’sindustrychallengesandprovidecustomerswithbetterpricesignalstoassesscompetitiveserviceofferings.

SmartRatesrecognizethatutilitiesprovideavarietyofservicestocustomersandthatthecostsoftheseservicesarenotalwayscausedbytheamountofenergythecustomerconsumes.Fromaratedesign perspective, Smart Rates fully unbundle1each component of utility costs and bill thosecomponentsontheappropriatecustomerbillingdeterminantsconsistentwiththeconceptofcostcausation.Theunbundlingofcostschangesvirtuallyallofthecurrentratetraditionsbecauseitnolongerrollsallutilitycostsintoasinglekilowatt‐hour(kWh)chargeorsinglekilowatt(kW)chargeas if those costs are caused only by the single measure of customer energy consumption. Costunbundling is critical for accommodating competition from on‐site generation and allowingcustomerstochoosewhichservicestheyneedfromtheutility.

This paper sets forth the theory and practice of 21st century rate designs through full rateunbundlingofutilityservicesandprovidesaframeworkfor“SmartRates”thatenablecustomerstopurchase – and pay an equitable and supportable price for – the services they want and need,regardlessof theirenergyconsumption levels.ThroughtheuseofSmartRates,autilitycansendcustomersaproperpricesignalassociatedwitheachserviceand improve theefficiencyofall itsservicestocustomers.

Manyaspectsoftheelectricutilityindustryhavechangeddramaticallysinceitsfounding,yetratestructureshavesignificantlylaggedtheseadvancements.Inordertobestrepresenttoday’selectricservicesandmeettheneedsoftoday’selectricconsumers,modernratedesignsareessential.SmartRatesenablecustomerstouseelectricityandelectricservicesmoreefficientlyandprovideutilitieswith revenue stability that enable the offering of more responsive services to accommodatecustomers’specificdemands.

1 Rate unbundling in this context is simply pricing each utility provided service separately so that customers pay only for the services they use, rather than paying a single charge that includes all services and assumes that all customers within a class have homogenous service requirements.


BLACK & VEATCH | The Challenge with Current Utility Rate Designs 2

The Challenge with Current Utility Rate Designs Currentutilityratedesignshavetheirfoundationinratesdevelopedinthe19thcentury.Themostcommonratesinusetodayarebasedonthewatt‐hourmeterandconsistofafixedcustomerchargeandsomeformofvolumetricchargeperkWh.Asapracticalmatter,thechoiceofratedesignsforvariouscustomerclasseshasdependedspecificallyonthecostofmeteringrelativetothetotalcostofservicetothecustomer.Forlargercustomers,mostutilitiesuseoneofthefollowingrateforms,bothdevelopedinthe19thcentury,oracombinationofthetwoforms:

HopkinsonDemandRate:Themostcommonmethodofpricingelectricityforcustomersservedwithdemandmeters,suchaslargeindustrialcustomers.TheHopkinsonDemandRateconsistsofan energy charge for total kWh consumption in addition to a demand charge based on thefacility’s maximum energy use during any short time period (quarter‐hour, half‐hour or one‐hour)inthemonth.

WrightHoursUseofDemand:ThisrateformisalsousedfordemandmeteredcustomersandbillsthosecustomersusingkWhchargesfordifferentlevelsofhoursuseofdemand.TheWrightHoursUseofDemandconsistsofacustomerchargeandkWhchargeblocksbasedonthenumberof hours that the customer’s maximum monthly demand is used. Hours use is calculated bydividingthemonthlykWhsbythemeasuredmaximumdemand.Thepriceofenergydeclinesasthehoursuseincreasesrecognizingboththecustomer’sincreasedloadfactorandtheincreasinguseofoff‐peakenergy.

Even today, not all electric service applications are metered and the rate design used for suchservicesarethesameflatrateserviceusedbytheindustrywhenitfirststarteddeliveringelectricpowertocustomersinthe1880s.

Unless the rate design reflects cost causation for the services provided, customers who elect to buy

particular service components will not pay for all the services they consume. This creates market

instabilities as the result of cross‐subsidies embedded in the utility’s rates. Such cross‐subsidies

cannot withstand today’s market pressures and will result in skewed prices and service levels for all

market participants.

UNDERSTANDING COST DRIVERS As noted, modern regulatory requirements for demand‐side management (DSM) and energyefficiency,aswellascustomerdemandsfordistributedgeneration(DG),donotalignwithcurrentutility rate structures.The reason for this is that current rate structures incorrectly assume thatenergy,ormeasuredkWhuse,causestheutilitytoincurnearlyallcostsexceptforthecoststhatarereflectedinamodestcustomercharge.Forlargercustomers,theuseofbothademandcomponentandanenergycomponentassumethatasinglemeasureofkWdemandcoupledwithaunitkWhcharge cause all of the fixed costs of utility service. In reality, utility services and the costsassociatedwitheacharecausedbyfixedandvariablecostdrivers.Boththefixedandvariablecostdriversdifferfordifferentcostcomponentsandfordifferentseasonalanddiurnalperiods.

Fixedcostsdonotchangewithenergyusebutcanvaryasa resultofothercostdrivers, suchascustomersordemand.Becausethesecostsarefixed,theydonotchangewithanyhourlypatternof



energyuse,eventhoughsometimeintervalisusedtomeasuredemand(e.g.,highest15,30or60minutes). Appendix A provides a brief description of the determination of demand for billingcapacity‐relatedcoststocustomers.Examplesofutilityfixedcostsinclude:

Theinvestmentinthefleetofplantsgeneratingelectricpower. The integrated transmission network investment that moves power from generators to thedistributionsystem.

Thedistributionsystemthatprovidespowertohomesandbusinesses.

Variablecosts,ontheotherhand,canvarybyseasonoftheyear,timeofuse,and/orenvironmentalconditions such as forced outages or partial unit deratings that change the marginal source ofenergyforaparticulartimeperiod.Examplesofvariablecostsinclude:

Fuelandfuelhandlingcosts. Purchasedpower. Volumetric charges from regional transmission organizations (RTOs) or independent systemoperators(ISOs).

Chemicalcosts. Energy‐relatedoperationsandmaintenancecosts. Otherenvironmentalcosts.

A Utility’s Cost Causative Factors

Whether fixed or variable, costs are generally caused by one or a combination of three generalfactors:

Customer: In general, if a cost varies as a result of customer count, then this is a customer‐caused cost and can include customer service expenses (e.g., billing and meter reading), andfacilitiesorassetslocatedonthecustomerpremise,suchasthemeterandserviceline,andevenportionsofthedistributionsystemthatservetoconnectcustomerstothegrid.

Energy:ThesearethecoststhatvarydirectlywiththenumberofkWhsproduced,withthecostoffuelbeingthelargestcomponent.

Demand:DemandrelatedcostsarethosecostscausedbythelargestloadinkWimposedon various parts of the utility’s transmission or distribution systems.NOTE:Thedemandfactorthatcausescostsdiffersfordifferenttypesofcostelements.Forexample,someformofcoincidentdemandisthecauseofbothutilityproductionandtransmissioncosts.Thispeakhourorothermeasureofdemanddrivestherequiredcapacityalongwitha levelofreservesanditisthismeasureofdemandthatshouldbethebasisforthechargestorecoverthatunbundledcost.

Understandingthenatureofdifferentutilitycosts,thetypesofcosts,andwhatcausescoststobeincurredenablesutilitiestousespecificpricingmechanismsthatalignwithcostfactors(Table1).



Table 1 ‐ Unbundled Costs by Type and Causal Factors

COSTFUNCTION COSTTYPE CAUSALFACTOR(S) PRICING

Generation Plant Fixed Demand kW Charge

Transmission Plant Fixed Demand kW Charge

Distribution Plant Fixed Demand, Customers kW Charge and Customer

Charge

General Plant Fixed Demand, Customers kW Charge and Customer

Charge

Generation O&M Fixed, Variable Demand, Energy kW Charge and kWh

Charge

Transmission O&M Fixed Demand kW Charge

Distribution O&M Fixed Demand, Customers kW Charge and Customer

Charge

Administrative & General

costs

Fixed Demand, Customers kW Charge and Customer

Charge

This table shows the appropriate type of charge to recover the categorized costs in order to match cost causation with pricing without a detailed specification of the particular charge.

UNDERSTANDING UTILITY SERVICES Unbundlingofratesrequiresanunderstandingofallservicesautilityprovides,andthecostdriversfor each service.Most stakeholders generallyunderstand that autilityprovides safe and reliableelectricservice to itscustomers.However,mostcharacterize thisserviceassimplyproviding theenergyproduct,whichisonereasonwhythekWh‐basedratestructurecontinuestoprevailtoday.Inreality,utilitiesprovidenumerousservices,including:

Generationservice Transmissionanddistributionservices Customerservice Avarietyofservicesthatprovidesafeandreliableoperationoftheelectricsystemaswellasthefacilitiesthatusetheelectricitybehindthemeter,suchasvoltageregulation,in‐rushcurrentforstartingelectricmotorsandotherancillaryservices.

Eachofthelistedmajorfunctionsoftheutilitycanprovidemultiplespecificservicesforavarietyofcustomers. Furthermore, each service also includes a quality of service component, generallydefined as firm or non‐firm. Firm quality means that the utility provides service continuouslywithout interruptionexcept those related tounavoidable systemoutages (e.g. outages causedbysevereweather).Non‐firmqualitymeansthatthecustomerhasagreedwiththeutilitytopermititsservice tobe interruptedat times theutilitychooses.Table2demonstrates themultipleservicesprovidedunderthegenerationfunctionalumbrella,andhowthoseserviceshavedifferentpatternsofcostbasedonthequalityofservice.



Table 2. Potential generation services

SERVICE QUALITY

Full Requirements Firm

Full Requirements Non‐Firm

Partial Requirements‐ Supplemental Firm/ Non‐Firm

Partial Requirements‐ Supplemental Baseload Firm/ Non‐Firm

Partial Requirements‐ Supplemental Peaking Firm/ Non‐Firm

Partial Requirements‐ Standby/Backup Firm/ Non‐Firm

Partial Requirements‐ Maintenance Service Firm/ Non‐Firm

Partial Requirements‐ Scheduled Maintenance Service Firm/ Non‐Firm

Partial Requirements‐ Unscheduled Maintenance Service Firm/ Non‐Firm

System Related Services‐ Black Start, Area Protection, Frequency,

Transmission Support

Firm

As Table 2 illustrates, there are many potential services (the list is not intended to becomprehensive)providedbythegenerationassets.Eachservicehasdifferentcostcharacteristicsaswellasqualitydifferences.Theresultisthatratesforunbundledgenerationmaydifferbasedonthetype of service required. A similar set of requirements relate to transmission and even to somedistributionservices,althoughtheclosertheserviceistothecustomerthelesscostsandqualityofservice provided vary. For example, if the provision of energy is non‐firm, that service does notchangethecostofthedistributionfacilitiesforservingthecustomerbecausetheutilitymuststillbeabletomeetthecustomer’smaximumrequirementswhenthereisnointerruptionofservice.

MODERN CHALLENGES TO TRADITIONAL RATES

Net Metering Policies

The fallacy of applying 19th century rate structures to the types of 21st century electric utilityservices requiredby customers ismade clearby theeconomiceffects ofDSMprograms, and thegrowingadoptionofDGassets(e.g.,rooftopsolar)amongcustomerswhoseektheeconomicbenefitnetmeteringpoliciesprovide.Whilethesecustomersareusinglessenergy,andsomemayevenbenet‐producers of energy, they are still using utility services. However, because current ratestructures assume that the level of kWh consumed by the customer causes the utility’s costs;discontinuitiesinbillingandcostrecoveryamongcustomersarecreated.AccordingtotheEdisonElectricInstitute(EEI):



Whilenetmeteringpoliciesvarybystate,customerswithrooftopsolarorotherdistributedgenerationsystemsusuallyare creditedat the full retail electricity rate forany electricity they sell to electriccompaniesviathegrid.Thefullretailelectricityrateincludes,notonlythecostofpowerbutalsoallofthefixedcosts…thatmakestheelectricgridsafe,reliable,andabletoaccommodatesolarpanelsorother distributed generation systems. Through the credit, net‐metered customers effectively areavoidingpayingthesecostsforthegrid.2

Net metering is the practice of allowing on‐site generation to reduce the kWh portion of theresidential customer’s bill (netting generation against load) on a unit kWh generated basis.Recognizing that under a utility’s traditional rate design the kWh charge for these customersrecovers most of the fixed costs and the variable costs of energy on an average basis, thecompensationforthecustomer’slevelofself‐generationessentiallyassumesthatallofthecostsnotrecoveredundernetmeteringcanbesavedbytheutility.Thatissimplynotthecase.

Consider,forexample,theutilitythatpeaksaftersunsetineverymonthoftheyear.SolarPVmakeszerocontributiontoreducingthefixedcostsforthatutility.Importantly,theonlycostsavingsaretheavoidedenergycosts ‐ and thatwouldnotevenbevaluedat theutility’shighestenergycosthours.Inthiscase,netmeteringforcesallnon‐solarPVcustomerstobearthecostsofproduction,transmissionanddistributioncapacitycoststhatarecausedbythesolarPVcustomer.Whilethisisanextremecasetoillustratethisdeficiencyinnetmetering,therearemanyutilitieswherethepeakloadsoccurwhensolarPVisnotgeneratingitsmaximumoutput.Thismeansthattheavoidedcostsoftheutilitywillnotbeaslargeasthecreditprovidedundernetmetering,andthatacrosssubsidywillbecreatedwhichallowssolarPVcustomerstoavoidpayingforthefixedcoststheycausetheutilitytoincur.

Demand‐Side Management Issues

With respect toDSM, issues similar to thoseundernetmeteringarisewhenDSMprogramssaveenergy,butnotcapacity.Asimpleexampleillustratesthispoint:

A recreational facility owner invests in skylights to save energy during the day. The skylightsalesmancalculatedhisexpectedsavingsbydividingthetotalutilitybillbythemonthlykWhandprovidingaunitkWhsavings.However,thefacilitywasbilledonacommercialratethatincludedademandcharge.Needlesstosay,thesavingsdidnotmaterializebecausethefacility’speakdemandoccurred at night due to its heavy lighting load. The skylights creatednodemand savings ‐ onlydaytime energy savings. Based on the actual savings, the skylights were not economic and theownermadeapoordecisiontoinvesthislimitedcapitalonaninefficientsolutiontoreduceenergy‐relatedcosts.

By unbundling rates, the utility recovers all of its costs from each customer regardless of the amount

of energy (kWh) used by the customer, or when the energy was used. Such a pricing structure will

create rates that fairly portray the value of the service in the market and will eliminate the inherent

2 “Straight Talk About Net Metering.” Edison Electric Institute (http://www.eei.org/issuesandpolicy/generation/NetMetering/Documents/Straight%20Talk%20About%20Net%20Metering.pdf). September 2013.


BLACK & VEATCH | 21st Century Rate Design 7

intra‐class cost subsidies in current utility rates, creating benefits for all segments of the energy

industry.

21st Century Rate Design A21stcenturyratedesignfullyunbundleseachcomponentofcostandbillsthosecomponentstocustomersbasedontheappropriatebillingdeterminants(customer,kW,kWh)consistentwithcostcausation.Theunbundlingofcostsandthe implementationofmodernratedesignsappropriatelychange virtually all of the current rate traditions perpetuated over the years. Different ratecomponentsarebilledseparatelyandeachcustomerwillonlypay for theservices theyuse.Thissectionfocusesonthecomponentsofanunbundledratedesign.

Unbundledratesconsistofthebasiccustomer,demandandenergycharges.Underfullunbundling,thesebasicratecomponentsaretranslatedinto:

Customercharge Productiondemandcharge Transmissiondemandcharge Distributiondemandcharge

● Distributionsubstationservice● Distributionprimaryservice● Secondarydistributiondemand

Energycharge● Energyserviceattransmissionvoltage● Energyserviceatsubstationdelivery● Energyserviceatprimarydeliverywithandwithouttransformation● Energyserviceatsecondaryvoltage.

Obviously,noteveryutilitywillrequireallofthesedistinctchargesbasedontheirexistingservicearrangements and the customers’ available service options. Further, there may well besubcomponents of various costs associatedwith services such as back‐up, standby,maintenanceand supplemental power as each relate to generation, transmission, distribution and energyservices. In some markets, unbundled services, such as meter reading and billing, may not beprovidedbytheutility.Inthatcase,thecustomerchargecomponentneedstoreflecttheexclusionofthecostsoftheseservices.

A customer’s ratesmay alsodiffer basedon geographic segments of theutility’s systembecausecostsmaydiffer at different loadnodes (this consideration is particularly important for systemswithwidegeographicreachthatincludedifferentloadnodesand/orclimaticconsiderations.)

UNBUNDLED RATE COMPONENTS

Derivation of the Customer Charge

Thederivationofa fullyunbundledratedesignbeginswith thecustomercost component.Whilecustomer costs will always be a subject of debate among a utility’s stakeholders, the logic



supportingthisconcept isquitesimple: Ifacostvariesbasedoncustomercount, thenthecost iscustomer‐related.Thisincludesautility’scustomerservicefunctionsanditsassetslocatedonthecustomerpremise.

Anotherelementofcustomercostsarethoseportionsoftheutility’sminimumdistributionsystemrequiredtoserveeventhesmallestcustomer.Minimumdistributionsystemrequirementsincludetransformers,secondaryconductors,polesand/orundergroundfacilities.

Toderive its fixedcustomercharge, autilityusesadetailedcostof servicestudy thatunbundlescostsintovariouscomponents.Theseunbundledcostsformthebasisforsettingtheratesforeachcomponentofservice.Forexample,ifthecostofservicestudycalculatesthecustomercomponenttobe $300per year, that amountwouldbe thebasis for a $25permonth customer charge.Theannual cost derived from the utility’s cost of service studywould include the annualized cost tosupport the investment in a meter, service line, transformers, secondary conductors and poles,Operation&Maintenance(O&M)expensesrelatedtothecustomer’splant,generalplant,andanyother assets required to provide the service, and customer service expenses (e.g., billing, meterreading,customeraccountsandcollections).

Derivation of the Production Demand Charge

Notallelectricutilitieswillhaveproductiondemandcharges.Thisdiscussionfocusesontheneedfor such charges for a vertically integrated utility. In that case, the production demand chargeincludes the fixed costs of generation and the transmission lines and related facilities thatinterconnecttheutility’sgenerationtoitsbulktransmissionsystem.Ideally,thesecostswouldbecollected through twoseparatedemandcharges.This is thepreferred rate structurebecause thetypicalelectricutilityexperiencesdistinctdifferencesbetweenthemarginalcostsofproductionforservingpeak loadscompared to thecosts forserving loadsoccurringother thanduring thepeakperiod(i.e.,baseloadproduction).Atthesametime,withtheexpectedincreaseinthepenetrationofdistributedenergyresources(DER)onutilitysystems,thisratestructurewillproperlyvaluethebenefitsofDERtothecustomerbasedonthetimeswhensuchself‐generationactuallyisoperating.

In general terms, the first demand charge (known as the Production Peak Demand Charge)recognizes the capacity costs associatedwith theutility’s peakdemandperiod,while the seconddemandcharge recognizes thehigher capacity costsofbase loadunits thatprovide substantiallylowerenergycosts.Thesecostsarerecoveredbasedonthemaximumdemandinthepeakdemandperiodsubjecttoaonehundredpercentratchet.

Thecarryingcostof theutility’s least‐costproductionresource(nominallyagasturbine)andtheassociatedtransmissioncostswouldbecollectedasademandchargebasedonademandmeasureduring the highest load hours,where load is defined as:Thesumofcustomerload,forcedoutageload,scheduledoutageloadandgeneratorderatings.

Thisdemandchargereflectstheunbundledcostsofrequiredcapacitywithalevelofreserves.Theresultisthatcertainchargesmaybeincurredbythecustomerbasedonspecifictimeperiodsthatmay differ from on‐peak hours for energy, in general, and may differ for generation andtransmission.Forexample,ifthereserverequirementsarecalculatedbyanRTOorISObasedonaspecific setof criticalhours, those criticalhoursmaybe appropriate fordetermining thebillableproductiondemandassociatedwithpeakingfacilities.Ifthesehoursareveryshortperiods,suchas



themaximumdemandhour in the summermonths of June, July andAugust, it is not feasible toknowinadvancewhenthosepeakhoursmayoccurandthepeakhoursusedtomeasurethehourswhenthedemandchargeisappliedmaychangefromyear‐to‐yearandmonth‐to‐month.

ItisimportanttonotethatderivingtheProductionPeakDemandChargebasedonashortdemandperiod runs the risk of shifting load out of that period. In addition, this also creates risk forincreasingloadafterthepeakdemandperiod,causingthepeaktooccurindifferenthoursbecauseshiftingloadoutofashortperiodmayreducenaturaldiversity.Itiscriticalthattheshiftingpeakconceptbefullyassessedbecausethereisapossibilitythatthelossofnaturaldiversityinloadsmaycause other capacity‐related costs to increase ‐ such as for the utility’s distribution andtransmissionfacilities.

ByestablishingalongerfixedperiodforderivingtheProductionPeakDemandCharge,theshiftingdemandpeakcreatesnoissueforcreatinganewproductiondemandpeakoutsideofthedemandhours.Thisisdonebytakingadvantageofthenaturaldiversitythatoccursbetweenloads.

Itisalsocriticaltounderstandthattheneedforcapacityisbasedonmorethanjustthecustomerloadontheutility’ssystem.Simply,thetotalmaximumloadonthesystemisthesumofcustomerloads, scheduled outage loads, unscheduled outage loads and unit derating loads. The latter twocomponents change for every time interval just like customer loads. In some cases, the seasonalderating is known in advance based on the generation technology or a condition such as lowerwaterflowsthatoccurnaturally.

Otherfactorsmayalsoderatethecapacityofaunitwithoutforcingtheunitoutofservice(e.g.,tubeleaks).Sincethesetypesofoccurrencesreduceavailablecapacity,theymustbetreatedasloadforpurposesofdeterminingthepeakhoursthatmatter forcostcausationpurposes. Ithasbeensaidthatifloadfactoronthegenerationsystemincreasesbeyondacertainpoint,itwillbenecessarytobuildreservesjusttoschedulemaintenanceactivities.Thus, it is importanttounderstandthefulldemandongeneration resources forpurposesof establishing thedemandperiod forproduction.Shiftingloadtooff‐peakperiodsdoesnotalwaysresultinthefullexpectedsavingsandcouldwithsometechnologiescreateanewpeakperiodintheformeroff‐peakhours.

Theseconddemandcharge (knownas theProductionBaseLoadDemandCharge) isdesigned torecoverthatportionoftheutility’srevenuerequirementassociatedwithproductionnotrecoveredthrough the Production Peak Demand Charge. The value of this charge may be zero in somecircumstances.Wherethereareadditionalcosts,theProductionBaseLoadDemandChargewillbebased on the highest monthly demand outside the peak demand period, without any ratchetprovision. Thus, customerswhobenefit from lowercostenergywill contribute to theadditionalcapacitycoststhatproducethosesavings.

In the alternative,where utilities operate in restructuredmarkets, the Production PeakDemandChargeofRTOorISOparticipantscouldbebasedonthecapacityresponsibilitydeterminedbytheoperational control entity. This charge would be subject to a 100 percent ratchet on an annualbasis. The remainder of the capacity costs not covered by the Production Peak Demand Chargewouldberecoveredinaseconddemandchargeapplicabletothehighestmonthlyloadoccurringinthemonth,withoutaratchet.



Derivation of the Transmission Demand Charge

Fortransmission,theanalysisofpeakloadsneednotbethesameasforgeneration.Onintegratedutilitysystems,native loadmaybeonlyonecomponentof thepeak load.Understandinghowthesystemis loadedonanhourlybasis isanecessaryelementforthedeterminationof transmissionsystempeakperiods.Itispossiblethatthedemandallocationforthegenerationfunctionwilldifferfromtheallocationthatisappropriateforthetransmissionfunction.Thisisparticularlytruewheretransmissionforothersacrosstheutilitysystemresults inhigher loadingat timesotherthanthenativeloadsystempeak.

Transmissionsystemloadingonintegratedutilitysystemsisnotsolelyafunctionofcustomerloadon the systembecause of congestionmanagement and centralizeddispatch. For example, if loadflowsacrosstheindividualutilitysystembecauseoflowercostgeneration,atransmissionsystemmay be fully loaded many more hours than retail customers’ own load alone would indicate.Determination of the expected loading may also change because of events unrelated to thetransmission facility owner, such as unit forced outages, changes in relative fuel costs,must‐rungeneration andother factors that alter griddispatch.The result of these factors is to change theallocationandcostresponsibility for transmission inawaythat impactstheappropriatedemandperioddetermination.Todothis,itisimportanttounderstandthecomponentsofthetransmissionsystemandthecostdriversforeach:

Generation laterals: costs driven by connecting generation to the system and should beincludedinthegeneration/productiondemandcosts.

Load laterals: Costsdrivenby the loadson the lateral andmaydiffer from the systemor thetransmission peak. Costs for load laterals are recovered through the distribution facilitiesdemandcharge.

Bulktransmissionsystem:Costsdrivenbyloadingofthebulksystemandarerecoveredbasedontheloadcharacteristicsofthesystem.Optionsinclude:● Maximum load occurs in eachmonth of the year: The demand charge is based on the peakperioddemandwithineverymonthandisthebasisforthetransmissiondemandcharge.

● Maximumloadoccursinsummer:Ifsystemisloadedonlyduringfoursummermonths,thenthecostswouldbebasedondemand thatoccursduring thepeakdemandtimeperiod,eventhoughthechargesarebilledoverall12months.Inessence,thenon‐seasonaldemandwouldbeequaltotheaverageofthefourcriticalpeakdemandperiods.

Derivation of the Distribution Demand Charge

Distributiondemandcostsaredrivenbythecustomerpeak loadwhenever itoccurs.Thesecostsare not identifiable on a time‐of‐use basis and the individual customer’s maximum demand orcontractdemand(themaximumobligationoftheutilitytoprovidethelocaldistributionservice)istheappropriatedemandmeasuretousetorecoversuchcosts.Anydistributioncostsnotrecoveredinthecustomercostcategoryandtheportionoftransmissioncostsforloadlateralsarerecoveredin thedistributiondemandcharge.Thedistributiondemandchargewould includea100percentdemandratchetbasedoneitherthecustomer’scontractoractualdemand.

As a general rule, the distribution system components peak at times thatmay not be coincidentwiththegenerationortransmissionpeakload.Inplanninganddesigningthedistributionsystem,



animportantdesignelementisnaturalloaddiversitythatoccursbasedontheelectricityuseofthepremise(businessesandresidenceshavedifferingtimepatternsofload).

Certainactivities,suchasstoragemayalterthenaturaldiversityofloads.Forexample,controllingelectric water heaters by shutting them off for extended peak periods results in much highercoincidentpeakdemandsondelivery facilitiesbecause thenatural loaddiversity isdisruptedbythe added control. The result is both higher distribution costs and higher peak demands forcustomers subject to control.Basedonexperiencewith time‐of‐use rates, there ispotential for asimilarimpactonthedistributionpeaksandthecostofdeliveryservice.

The recovery of distribution‐related costs based on maximum demand whenever it occurs is

fundamental to cost‐based rates.

The three components of the distribution demand charge are recognized in the cost allocationprocessandrelatetosubstationcosts,primary facilitiesandsecondaryfacilitiesnotrecovered inthe customer charge. Conceptually, in a modern electric system all secondary costs should becustomer‐related. The allocation process recognizes that diversity increases as the load ismeasuredfurtherfromthecustomer’sindividualload.Totheextentthatloadsarehomogeneous,asingledistributiondemandchargewouldbeadequate.Ifthereislittlehomogeneity,thenthecostsmayneedtobebrokenoutseparatelybutbilledunderthesame100percentratchetprovision.

Thecustomerandratcheteddemandchargeswouldbebasedonanannualcostpayablein12equalamounts. These annual charges would be premise‐based so that a new customer occupying thepremisewouldhavehisbillsinitiallybasedonthepremise’smeasuresofdemand.Inaddition,ifacustomer has service turned off at the premise and subsequently turns service back on, thecustomerwouldberesponsibleforthepaymentoffixedchargesfortheperiodwhereservicewasnottakenaspartofthecostofestablishingservice.Non‐ratcheteddemandchargeswouldbebasedontheactualmonthlyuseofdemand.

Derivation of the Energy Charge

Thefinalcomponentoftheunbundledratedesignistheenergycharge.Theenergychargerecoversallofthevariablecostsassociatedwiththeproductionorpurchaseofpower.Further,theenergychargeisnotpartoftheutility’sbaserate.Rather, it isreflectedina full trackingfuelclausethatrecovers not only fuel and purchased power, but also variable production costs, environmentalcosts (e.g., scrubber chemicals), variable charges from the RTO or ISO, and any other costs thatchangewiththeconsumptionofenergy.

The energy charge is subject to regular adjustments, like a fuel clause, and includes a deferralaccount that matches these costs dollar for dollar. The energy charges under this charge aredifferentiatedbased on cost causationby season, by timeof use, by voltage level of service and,whereapplicable,bycriticalperiodsaboveandbeyondthetimeofuseperiods.Theadjustmentstothis charge are always seasonal‐basedadjustments in the sense thatoverorunder recoveries ofcostinaseasonaresubsequentlyrecoveredinthatseason.

Energychargesmaynot require the inclusionof allof thecost componentsdescribedabove.Forexample,someutilitiesmaynothavedistinctseasons.Othersmayhavediurnalcostdifferencesthat



aresosmallthatthereisnoreasontoseparatelybillforthosedifferences.Someutilitieswithlittlediurnaldifferencemayinsteadhavecriticalpeakperiodswhen,forafewhourspermonthorforafewhoursperseason,theymayexperiencecosts far inexcessoftypicalaverageormarginalcostlevels.Forexample,theaveragecostmightbeapproximate$35perMWhfor97percentofthetime,butcouldeasilyexceed$100perMWhintheremaininghours. Inthiscase,theabilitytoprovideproperpricesignalstocustomerswouldbeimportantaswouldrateprovisionsdesignedtomatchcostsandrevenuesunderthecriticalpeakperiod.

ILLUSTRATIVE RATE STRUCTURES Usingtheconceptoffullyunbundledratesmeansthatautility’straditionalrateclassdefinitionsarenolongerasimportant.Cost‐basedratesenabletheuseofalesshomogeneousclassofcustomers,(e.g.,thereisnoneedtohaveoneormoreresidentialclassesofservice).Therewillnolongerbeaneed for separate rate classes for certain end‐uses, such as churches or schools, to reflect theirdifferentloadcharacteristicscomparedtothoseofothergeneralservicecustomers.Theabilitytorecovercostsbasedonindividualloadcharacteristicsthenallowsforratesbasedonotherrelevantconditions of service that have specific cost implications, such as voltage level of service ortransformerorsubstationownership.

Thinking about the factors that impact cost must begin with the customer component of costsincludingmeterandserviceinvestment.Thisclassificationshouldalsorecognizethatvoltagelevelofserviceisofparticularimportance.Inthatcontext,itispossibletodefineaSmallGeneralServiceSecondaryVoltageClass.Thisclasswouldconsistofallcustomerswhohaveessentially thesametypes of meter installations and service lines (e.g., residential, residential space heating, smallcommercial,smallcommercialallelectric,etc.).Differencesinothercharacteristicsofutilityservice,suchasdemandcoincidencefactorsandindividualmaximumdemands,wouldnotmattersincethecoststhatarecausedbythesedemandmeasuresarealreadyunbundled.Theimportantpointistoderiveeachcomponentoftheratestructuretoreflecttheactualcostofservice.

Other classes would include General Service Primary Voltage, General Service Primary VoltageTransformer Ownership, Large General Service Substation, Large General Service Transmission,Non‐Firm Service Rates and Back‐Up and Standby Service Rates. These rates would reflect thedifferentcostsassociatedwitheachserviceand,asappropriate,seasonal, timeofuseandcriticalpeakpricing‐typeconsiderationsbasedonservicelevelrequirementsandassociatedcosts.

Customers who require unique service arrangements would have those costs recovered in aseparatemonthlyfixedchargefordirectly‐assignedfacilities.Forexample,anindustrialcustomermay take service at the substation, but require one or more dedicated lines to connect thesubstationtoitsfacility.Inthatinstance,thededicatedlineswouldbeadirectly‐assignedcostandrecoveredunderaseparatechargeunrelatedtothecustomer’sactualload.

To illustrate these concepts, the following tables outline the rate forms for General ServiceSecondaryVoltageClassandGeneralServicePrimaryVoltageClasscustomers.

RatesfortheGeneralServiceSecondaryVoltageClassassumethefollowingoperatingconditions:



All customers have the same meter costs and the average cost of secondary service linesconsistent with the applicable line extension policy (customer’s requiring a greater level ofserviceinvestmentmakeanappropriatecontributionfortheexcessinvestment).

Customer costs include a minimum system component for local distribution facilities at thesecondarylevel.

Allprimaryrelatedcostsareincludedinthedistributiondemandcharge.

Theutilityisstronglysummer‐peakingforthe4months,JunethroughSeptember.

Partial requirements customers take service under this rate and the applicable back‐up andstandbyservicerate.

Customers who require unique service arrangements either make a contribution in aid ofconstructionforexcessfacilitiesortheypayaseparatefixedcharge.

Table 3 ‐ Rate structure for General Service Secondary Voltage Class customers (i.e., residential)

RATESTRUCTURE(Billedamount)

TYPEOFCHARGE DESCRIPTIONOFCHARGE

Customer Charge $300.00/year or $25.00/month

Fixed Charges that support the customer service functions of a utility (e.g., billing, meter reading, distribution connection)

Distribution Demand Charge $3.00/kilowatt of billed demand

Fixed Charges resulting from the demand‐related portions of the distribution system. This charge can be based on the greater of the current month’s maximum demand, or the maximum demand occurring in any of the preceding 11 months.

Transmission Demand Charge $12.00/kilowatt year or $1.00/month

Fixed This charge is for services provided by the bulk transmission system. It should be based on the rolling average of the maximum on‐peak demand for the system

Production Demand Charge $96.00/kilowatt year or $8.00/month

Fixed Includes the fixed costs of generation and the infrastructure that connects generation to the bulk transmission system.

Energy Charge Charges would vary based on time of use, such as $0.058/kWh for summer on‐peak and $0.038/kWh for winter off‐peak

Variable Recovers all of the variable costs associated with the production or purchase of power, most notably fuel and environmental costs.

Charges based on a hypothetical vertically integrated electric utility providing a bundled service.

TheratecomponentsofaGeneralServicePrimaryVoltageClassareoutlinedbelowassumingthefollowingoperatingconditions:

All customers have the same meter costs and the average cost of secondary service linesconsistent with the applicable line extension policy (customer’s requiring a greater level ofserviceinvestmentmakeanappropriatecontributionfortheexcessinvestment).

Customer costs include a minimum system component for local distribution facilities at theprimarylevel.



Remainingprimaryrelatedcostsareincludedinthedistributiondemandcharge.

Theutilityisstronglysummer‐peakingforthe4months,JunethroughSeptember.

Partial requirements customers take service under this rate and the applicable back‐up andstandbyservicerate.

Customers who require unique service arrangements either make a contribution in aid ofconstructionforexcessfacilitiesortheypayaseparatefixedcharge.

Table 4 ‐ Rate structure for General Service Primary Voltage Class

RATESTRUCTURE(Billedamount)

TYPEOFCHARGE DESCRIPTIONOFCHARGE

Annual Customer Charge $600.00/year or $50.00/month

Fixed Charges that support the customer service functions of a utility (e.g., billing, meter reading, distribution connection)

Primary Distribution Facilities Demand Charge $24.00/year or $2.00/kilowatt of billed demand

Fixed Charge based on the greater of the current month’s maximum demand or the maximum demand occurring in any of the preceding 11 months payable in monthly installments.

Transmission System Demand Charge $11.75/kW‐year or $0.98/month

Fixed Charge based on the rolling average of the maximum on‐peak demand occurring in the hours of 12 noon through 9 pm weekdays in the months of June through September payable in twelve monthly installments

Production Peak Demand Charge $94.00/kW‐year or $7.84/month

Fixed Charge based on the rolling average of the maximum peak demand occurring during the hours of 12 noon through 9 pm weekdays in the months of June through September payable in twelve monthly installments.

Production Base Load Demand Charge $6.86/kW per month

Fixed Charge based on the actual maximum demand occurring monthly regardless of the time the demand occurred.

Energy Charges Variable

Variable The energy charges hereunder shall be determined from time to time to recover the total variable costs associated with the production, purchase and delivery of energy to the Company’s transmission system including any volumetric charges imposed under an RTO/ISO Tariff. The summer season is defined as the months of June through September. The charges effective for the twelve months commencing June 1, 2014 are as follows: • Summer On‐Peak (Hours 10 AM to 11 PM weekdays excluding holidays) $0.568 per kWh

• Summer Off‐Peak (All other hours in the season) $0.0441 per kWh

• Winter On‐Peak (Hours 6 AM to 10 AM and 5 PM to 9 PM weekdays excluding holidays) $0.0451 per kWh

• Winter Off‐Peak (All other hours in the season) $0.0372 per kWh

Asthesetworatestructuresillustrate,manyoftheunitchargesforprimarycustomersare lowerbecause generation and transmission capacity related costs reflect lower primary voltage losses.For primary distribution costs, the lower charge represents the exclusion of secondary facilities



from the cost of service at the distribution level. The lower energy‐related charges are also theresult of lower losses. The higher customer charge reflects higher metering and service costs,includingusingprimaryminimumsystemcostsforserviceatthislevel.Thisgeneralpatternwillberepeated for each additional rate schedulewith chargesdeclining as the result of fewer facilitiesand lower losses. Inaddition,chargessuchastheresidualgenerationcostsortransmissioncostswilldifferbasedonclassloadcharacteristics.

ROLE OF ADVANCED TECHNOLOGIES Perhapstheprimaryreasonratestructureshavenotchangedsignificantlyduringthepastcenturywasduetoalackoftechnologytomeasureandappropriatelychargeforavarietyofutilityservices.Untilrecently,utilitiesdidnotpossessthetechnologyandcapabilityformeasuringandrecordingdataforeachofitsindividualcostdrivers.

Today’ssmartmetersandadvancedmeteringinfrastructure(AMI)enableutilitiestomeasuremorethan monthly kWh consumption. The technologies and back office software programs enableutilitiestoproducedynamicpricinginformationforcustomersandmeasure,record,billandcreditbasedon theusage levelsofeachservice.Examplesof additional servicesadvanced technologiescantrackinclude:

Timedifferentiatedenergycostsincludingcriticalpeakprices; Demandsbytimeofuseandbymaximumdemandregardlessoftime;and Powerfactormeasurement.

Smartmeterspermitawidervarietyandtypeofpricesignalsthatcanremoveratesubsidiesandsendbetter,morecost‐effectivepricesignalstocustomers.Withsmartmeters,eachdifferentratecomponentmaybebilledseparately,enablingcustomerstopayforonlytheservicestheyuse.

OTHER CONSIDERATIONS In addition to the various unbundled charges described above, it will be important to overlayseasonalanddiurnalcostcharacteristics,criticalpeakpricingandtime‐of‐usepricing,loadcontrolcredits and other yet to be developed programs that reduce loads and create cost savings thatwouldnotbereflectedinrates.Thus,wewouldexpecttoseeenergypricesthatvarybyseasonandby time of day based on time periods defined by cost differences, where appropriate. It will beimportant to develop seasonal and diurnal periods based on the underlying marginal costsrecognizingthatforsomeutilitiesthoseperiodsmayvaryindifferentpartsoftheirsystems.Thiswouldbethecasewhereaportionoftheutilitydeliverysystemisservedoffanelectricallyisolatedloadnodeofthetransmissionsystem.Wherethesystemreceivesservicefromisolatedfacilities,thecostofthesefacilitiesandserviceshouldbeborneonlybythecustomersusingtheseservices.Ifthesystemisfullyintegrated,thecostsofdifferentnodesshouldbeaveragedacrossthosenodes.

Itisalsoimportanttorememberthatbecauseunbundledrateseliminateintra‐classsubsidiesthatareincludedinmanyoftoday’straditionalratestructures,certainpolicygoalscouldnolongerbeviablyreflectedaspartoftherate.Assuch,programssuchaslowincomebillassistancewouldneedtobeaddressedindirectlythroughfixedbillcreditsfundedbyaseparateratecomponent.

Ultimately these unbundled rates will be designed to recover the utility’s class‐related revenuerequirements. The resulting price signals will be significantly more efficient from an economic



perspectiveresultinginlessresourcewasteandmoreeconomicallyefficientpowersystems.Akeyelementofthesuccessfulimplementationofunbundledrateswillbetoeducatecustomersonhowthe rates reflect the underlying costs of particular utility services and how the customer canmanageelectricityusetoreducethosecosts.Overall,suchratesareexpectedtogenerateefficiencygainsforbothcustomersandtheutility.

ThebenefitsofunbundledSmartRateswillaccruetoeverystakeholdergroupeventhoughsomememberswillpaymorefortheservicestheybuyandotherswillpayless.Customerswhopaymorebenefit fromreceiving the correctprice signal andunderstand thebenefitsof alternative choicesrelated toDSMandDG investments. For theutility,unbundledrateswillnotchange theutility’srevenuerequirementintotal,butwillimpactthestabilityofrevenuesfavorablyandwillcausetheutilitytobemoreproactiveinitsmarketingofunbundledservicestocustomers.Itwilllikelytakesubstantialeffortonthepartoftheutilitytoeducatestakeholdersofthesebenefitsinarisingcostenvironment.ItistheSmartRatesthatwillallowcustomerstouseelectricitymoreefficientlyandallowtheutilitytorecoveritscostsfromcustomerswhocausethosecoststobeincurred.Whiletheutilitywillbeeconomicallyindifferentasratedesignschange,itwillalsobenefitfrombetterpricesignalsasconsumersadapt to thecost causative factors that formthebasis forunbundledrates.Changing rate design will also impact customers who have made investments based on theeconomicsignalsof the19thCenturyratesandsomeof those investmentswillno longerbecosteffective.The issueof customerstrandedcostswillbeadifficultelementof the transition,but isinevitablebecauseoftechnologicaladvancesinmeteringandinutilityoperations.

The end result of unbundled rates will be a more cost effective and better integrated utility system to

the benefit of economic growth and new investments that enhance the efficiency of the utility grid.

This new customer paradigm is a prerequisite for improving the safety and reliability of the utility

system.


BLACK & VEATCH | Appendix A 17

Appendix A Aselectricratesbecomeunbundled,itisimportanttounderstandtheconceptofdemandbilling.Theconceptofdemandbillingisoneofmeasuringthemaximumcapacityoftheelectricutility’ssystemusedinanyparticularperiodofmeasurement.LoadvariesfrommomenttomomentbasedontheactualuseofelectricappliancesincludingmotorloadssuchascompressorsinHVACsystemsorrefrigeratorsandfreezers.Lightingloadvariesevenfromminutetominuteaslightsareturnedonandoff.Someloadsruncontinuouslywhileotherloadsoperateinfrequently.Thenetresultisthatanyparticularcustomercanhaveadifferentloadshapeonadailybasis.

Figure A‐1 Daily Residential Hourly Load Shape

FigureA‐1showsatypicaldaysummerandwinterloadshapeandthepeakdayforbothseasons.Thepeakhourdemandforthiscustomeroccursinthesummerandis3.2kW.Thisisthecustomer’snon‐coincidentpeakdemandbasedonanhourlymeasure.HourlydemandaveragesthekWhusageovertheunderlyingmeasurementinterval.Forexample,thisdemandmaybeaverageoverfour‐15minuteintervalsasillustratedinFigureA‐2.


BLACK & VEATCH | Appendix A 18

Figure A‐2 Summer Peak Hour kW per Interval

FigureA‐2illustratestheaveragingoffour‐15minuteintervalstoderivethecustomer’smaximumdemand.Maximumdemandisalsomeasuredusingshorterintervals.TableA‐1providesthedemandinkWforeachofthethreepossiblemeasurementintervals.

INTERVAL kWDEMAND

15Minutes 4kW

30Minutes 3.5kW

60Minutes 3.2kW

SincethekWmeasureofcapacityrequiredtomeetthecustomer’sloadisthemaximumdemandontheutilitysystem,the15‐minuteintervalismorerepresentativeoftherequiredcapacityfortheutility’slocaldistributionfacilities.Inanyevent,thechoiceofthemeasurementintervalhaslittleimpactoncustomers’billsexceptforcustomerswithhighlyvariableloads.Thereasonforthisisthecostsarefixedandthehighermeasureofdemandresultsinalowerunitchargeforthecustomer.

Asdiscussedearlier,therearemanydifferentbillingdemandsthatarerelevantforcostrecoverypurposes.Thesamemethodofcalculationisusedineachinstancealthoughthehourorhoursofmeasurementmaydiffer.Thatis,somemeasuresofdemandmightbedefinedasoccurringwithinaspecificrangeofhours.Forexample,thedemandmaybedefinedasoccurringbetweenthehoursof1p.m.and‐4p.m.Sinceourdataisreportedonanhour‐endedbasis,thepeakdemandwouldbemeasuredasthemaximumdemandoccurringduringthehoursof14through16above.Inthatcase,thedemandwouldbe3kWoccurringathour16.

2.83

4

3

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

16:15 16:30 16:45 17:00

Time in 15 Minute Intervals

kW per Interval

Average kW=3.2 kW for Peak Hour

kW Deman

d