Application16‐09‐003(FiledSeptember1,2016)

BEFORETHEPUBLICUTILITIESCOMMISSIONOFTHESTATEOFCALIFORNIA

ApplicationofSouthern CaliforniaEdisonCompany(U338E)forApprovalofits2016RateDesignWindowProposals.

TESTIMONYOFDR.BARBARAR.BARKOVICHANDCATHERINEE.YAPONBEHALFOFTHECALIFORNIALARGEENERGYCONSUMERSASSOCIATIONANDTHECALIFORNIAMANUFACTURERS&TECHNOLOGYASSOCIATION

INSOUTHERNCALIFORNIAEDISONCOMPANY’S2016RATEDESIGNWINDOW

April28,2017

TESTIMONYOFDR.BARBARAR.BARKOVICHANDCATHERINEE.YAP

I. INTRODUCTION

Q1. Pleasestateyournamesandbusinessaddress.

A1. OurnamesareBarbaraR.BarkovichandCatherineE.Yap.Ourbusiness

addressesareBarkovich&Yap,Inc.,44810RosewoodTerrace,Mendocino,

California,95460andP.O.Box11031,Oakland.California,94611.

Q2. Pleasestateyourqualifications.

A2. OurStatementsofQualificationsareattachedasAppendixAandAppendix

B.

Q3. Onwhosebehalfareyoupresentingthistestimony?

A3. WearetestifyingonbehalfoftheCaliforniaLargeEnergyConsumers

Association(CLECA)andtheCaliforniaManufacturers&Technology

Association(CMTA).CLECAisanorganizationoflargeindustrialelectric

customersofPacificGasandElectricCompany(PG&E)andSouthern

CaliforniaEdisonCompany(SCE).Thesecompaniesareinthesteel,cement,

industrialgas,mining,pipeline,andbeverageindustries.Theysharethefact

thatelectricitycostscompriseasignificantportionoftheircostsof

production.CMTAworkstoimproveandenhanceastrongbusinessclimate

forCalifornia's30,000manufacturing,processingandtechnologybased

companies.Since1918,CMTAhasworkedwithstategovernmenttodevelop

balancedlaws,effectiveregulationsandsoundpublicpoliciestostimulate

economicgrowthandcreatenewjobswhilesafeguardingthestate's

environmentalresources.CMTArepresentsbusinessesfromtheentire

manufacturingcommunity‐‐aneconomicsectorthatgeneratesmorethan

$250billioneveryyearandemploysmorethan1.5millionCalifornians.

SomeoftheCLECAandCMTAmembercompaniesarebundledservice

customersandsomeareservedunderdirectaccess(DA)arrangements,but

forallofthemthecostofelectricityiscriticallyimportant.Neitherthe

currentindustrialbundledserviceratesnorDAservicewithhigh,long‐term

costresponsibilitysurcharge(CRS)feesmeetsthetestofcompetitiveelectric

rateswhencomparedtoratespaidbytheirout‐of‐statecompetitors.

Withitsambitiousclimategoals,Californiashoulddoallitcanto

ensurecost‐basedelectricratesthatenableindustryandindustrialelectric

customerstomaintainmanufacturinginCaliforniawherepoweriscleaner,

butcostlier.Thiswillsupportthestate’sclimategoaltoavoidcarbon

emissionsleakage.1

Q4. Whatisthepurposeofyourtestimony?

                                                       1 Thestateshouldavoidincreasesinpowercoststhatwouldpushtheproductionofenergy‐intensivemanufacturedproductsoutofCalifornia,wherethepoweriscleanerandgreenerbuthigherincostthanelsewhere.IfthesehighercostsleadtothesubstitutionofimportedproductswithhigherembeddedemissionsforproductsmadeinCalifornia,overallGHGandotheremissionswillincrease. 

A4. OurtestimonyaddressesmostissuespresentedinSouthernCalifornia

EdisonCompany’s(SCE’s)2016RateDesignWindow(RDW)proceeding

presentedinChaptersIthroughVI.WedonotaddressChapterVII.

Q5. Whyisthisproceedingofinteresttoyourclients?

A5. CLECAandCMTAmembersareallservedontimeofuse(TOU)rates.SCE’s

proposaltochangeitsTOUperiodsthuswillhaveanimpactontheir

electricitybills.Inaddition,respondingtothepricesignalssentbyratesfor

thesedifferentTOUperiodsmaywellaffecttheiroperations.Thus,they

haveastronginterestinthisproceedinganditsoutcome.Furthermore,

CLECAandCMTAwerepartiestothesettlementofSCE’slastGeneralRate

Case(GRC)Phase2proceedingwhichincludedanagreementtoconsider

newTOUperiodsforSCEinthisRDWproceeding.

Q6. Pleasedescribethestructureofyourtestimony.

A6. First,wewilladdressSCE’sproposaltochangeTOUperiodsfornon‐

residentialcustomers.Second,wewilladdressSCE’stimeframefor

implementingthesechanges.Third,wewilladdressSCE’sproposed

changestoitsCriticalPeakPricing(CPP)eventperiod.Fourth,wewill

addressSCE’sproposedchangestoitsReal‐TimePricing(RTP)rate

schedule.

II. SCE’SPROPOSALTOCHANGETOUPERIODS

A. Marginal Cost Analysis

Q7. PleasedescribewhatSCEhasconsideredinitsproposaltochangeTOU

periods.

A7. SCEhasforecastgeneration‐relatedmarginalcostsfortheyear2024.Ithas

chosenthatyearsothatanyTOUperiodsthatresultfromadecisioninthis

proceedingwillreasonablyreflectfuturecostsforasix‐yearperiod,which

representstwothree‐yearGRCperiods.SCE’sforecastreflectsthenetload

shapeforecastfor2024,whichisloadlessintermittentrenewable(solarand

wind)production.Thenetloadreflectstheshiftingofdemandsonthe

electricalsystemwhenintermittentrenewableproduction,particularly

solarproduction,fallsoffasthesungoesdown.Wholesalemarketprices

arehighestduringthislaternetloadpeakperiod.Inaddition,wholesale

pricesarelowestduringperiodswhenthereareample,and,attime,excess

amountsofrenewableenergyascomparedtothelevelofcustomerloadson

thesystem.

SCE has also considered whether it should introduce some time

differentiation to its distribution-related-rates, based on an assessment of whether

distributed-related marginal costs vary by TOU period.

Q8. IsSCE’sproposalconsistentwithD.17‐01‐006intheTOURulemaking,R.

15‐12‐012?

A8. Yes.Itisbasedonutility‐specificmarginalcosts.Itsendspricesignalsthat

reflectthechangingcostprofileoftheCaliforniaIndependentSystem

Operator(CAISO)wholesalemarket.Itbalancessendingaccurateprice

signalswithaTOUstructurethatisnottoocomplexforcustomersto

understandorrespondto.Itshouldprovidepricesignalsthatwillbe

reflectiveoffutureelectricitycostsforatleast6years.

Q9. PleasedescribeSCE’sforecastofgeneration‐relatedmarginalenergycosts.

A9. SCEforecasthourlylong‐termmarginalwholesalegenerationenergycosts

basedonforecastmarket‐clearingpricesintheCAISOmarketusing

productioncostsimulation.Thesemarginalenergycostsreflecttheeffect

onmarketpricesofincreasingamountsofintermittentrenewable

generation,withhigherpricesduringthelaternetloadpeakandlower

pricesduringperiodsofhighrenewableoutput.Itsresultsareconsistent

withthosepresentedinR.15‐12‐012.

Q10. PleasedescribeSCE’sforecastofgeneration‐relatedmarginalcapacitycosts.

A10. SCEdevelopedhourlymarginalgenerationcapacitycosts(MGCC)that

reflectbothpeakandflexiblegenerationcapacityrequirements.2Flexible

capacityisneededtoaddressrampingrequirementsassociatedwith

increasedintermittentrenewableproduction.Thisisthefirsttimetheneed

forflexiblecapacityhasbeenconsideredindetermininggeneration‐related

capacitycosts.Inthepastonlysystemcapacitycostswereconsidered.

                                                       2SCE‐1,Garwackiat13.

SCEstartswiththecostofanadvancedcombustionturbine(CT),

whichisthetypeofCTthatwouldbeusedforflexibility,asitisfast‐start

andfast‐ramping.3SCEthenallocatesthecostofthisCTtobothsystem

capacityneedsandflexiblecapacityneedsbasedontheproportionofthe

systempeaktothesizeofthelargestsystemramp.4SCEassignsthepeak

capacityshareofmarginalgenerationcapacity‐relatedcoststoindividual

hoursusingLossofLoadExpectation(LOLE).5SCEthenassignsthe

flexibilitycapacityshareofmarginalgenerationcapacity‐relatedcoststo

individualhourswithinthedailythree‐hourrampasestablishedunderthe

currentinterimflexiblecapacitydefinition.6SCEidentifiesthehourswhen

thereismostlikelytobeaneedforflexiblecapacityandassignsweights

basedonthesizeoftheramp,allocatingtheflexiblecapacitycosttothe

second(30%ofcost)andthirdhours(70%ofcost)oftherampinorderto

sendapricesignalthatwilllessentheeffectoflargerampsthatmaycause

systemreliabilityissues.7

Q11. Whichmonthsandhoursshowthegreatestsystemcapacityneed?

A11. ThemonthsareJune,August,andSeptemberforhoursending817tohours

ending21.9

Q12. Whichhoursshowthegreatestflexiblecapacityneed?

                                                       3SCE‐1,Hopperat21.4SCE‐1,Bakerat32.5SCE‐1,Hopperat23‐24.6SCE‐1,Bakerat29.ThatdefinitionwasadoptedinD.14‐06‐050.7 Ibid.at30.8 ThehourendingconventionisusedbytheCAISO.9SCE‐1,Hopperat27.

A12. SCE’stestimonysayshoursending17and18.However,asshowninFigure

3‐10,thereissomeneedinhourending19aswell.10

Q13. HowdoesSCEallocateMGCCbetweensystemandflexiblecapacity?

A13. SCEusestheratioofthemaximumforecastramprequirementtothe

maximumforecastpeakloadrequirement.Thatdeterminesthepercentage

ofthecostassignedtoflexibilitycapacity.Therestisassignedtosystem

capacity.SCEestimatesthat40%oftheMGCCisassociatedwithflexibility

and60%withsystempeak.11

Q14. WhatisyourresponsetoSCE’sproposaltouseforecastmarginalenergy

costs(MECs)for2024toassessproperTOUperiodsfortheperiod

beginningin2018?

A14. Wefinditreasonable.CAISOforecastsshowtheeveningrampgetting

increasinglysteepoverthenextseveralyears12,withlowerornegative

pricesduringtheafternoonsandhigherpricesintheevenings,justasSCE

hasforecast.

Q15. WhatisyourresponsetoSCE’suseofanadvancedCTtodevelopmarginal

generation‐relatedcapacitycosts?

A15. Wesupportit.AnadvancedCTiswelldesignedtomeetbothsystempeak

andflexibilityneeds.

                                                       10SCE‐1,Bakerat31.11Ibid.at32. 12 AgendaandPresentation‐FlexibleResourceAdequacyCriteriaMustOfferObligationPhase2‐SupplementalIssuePaper.pdf.,December9,2016,p.15. 

Q16. WhatisyourresponsetoSCE’sallocationofmarginalgeneration‐related

capacitycostbetweensystemandflexiblecapacityneeds?

A16. WewouldpreferforSCEtouseanLOLE‐typeanalysisthatincorporates

bothflexibilityandsystemcapacityneedsintheanalysisinordertoassign

hourlyresponsibilityforcapacityrequirements.Webelievethatthis

approachissuperiortoSCE’sproposedtwo‐partallocationbetweensystem

capacityandflexibilityneedsfollowedbyaseparatecostassignmentto

hours.

We understand from its recent demand response application, A. 17-01-

018, that SCE may have developed such analysis since it filed this RDW, and

expect that it will be used in its Test Year (TY) General Rate Case (GRC) Phase 2

testimony expected in June 2017. For the purposes of this proceeding, SCE’s

two-part allocation process of allocating costs associated with flexibility

requirements versus system peak requirements is acceptable to us as an interim

methodology. However, we do have concerns about bifurcating MGCC into two

different categories, since the same resources provide both system or peak

capacity and flexible capacity. Resources that ramp up to follow the evening

ramp also serve the evening peak. Thus, there is a classical joint cost problem in

that this capacity provides both ramping and capacity at peak. We are hoping that

this issue will be addressed in greater detail in SCE’s upcoming GRC Phase 2

proceeding.

Q17. HowdoesSCEassessthetimevariationofmarginaldistributioncosts?

A17. SCEpositsthatwithincreasingdistributedenergyresources(DER),the

distributionsystemwill“increasinglyservetwodifferentfunctions:(1)a

peakcapacityfunctiontomeetpeakcustomerdemand,whichistime‐

dependent(andshouldbeusedtoinformthehourlyallocationof

distributioncosts);and(2)agridornetworkfunctionthatenablesthebi‐

directionaltransferofenergytoandfromcustomers,whichisnottime‐or

peak‐dependent.”13SCEindicatesitwillperformfurtheranalysisinitsGRC

Phase2application,butproposesaninterimmethodologyinthisRDW.

Thatinterimmethodologydividesdesigndemanddistributioncostsinto

peak‐andgrid‐relatedcomponents.Thepeaksub‐componentistime‐

differentiatedanditsassignmenttohoursisreflectedinSCE’sTOUperiod

marginalcostanalysis.Thegridsub‐componentisnottime‐differentiated

andisnotincludedintheTOUanalysis.

Q18. HowdoesSCEdeterminewhichcostsfallintothetwocategories?

A18. SCEusesaccountingcostsfromtheFERCUniformSystemofAccounts.It

statesthatsub‐transmissioncapitalexpendituresaregenerallyplannedto

considerpeakloadneedsandsoassignsthemtothepeakcapacitypartof

designdemand.Itassignslandfordistributionsubstationsandlinestothe

gridsinceitrelatestophysicalconnectivityofcustomerstothegrid.It

assignsdistributionsubstationstopeak.Distributionlinesmeetbothpeak

andconnectivityneedsandSCEassignsthemtothetwocategoriesbasedon

distributioncircuitmiles.Radiallinesincludingsecondaryvoltagecircuit

                                                       13 SCE‐1,Behlihomjiat34.

miles(74%ofcosts)areassignedtogrid.Theremainingprimarycircuit

lines(26%)areassignedtopeak.Theresultis60%ofcostsarepeak‐

relatedand40%arenon‐peak‐related.14

Q19. HowdoesSCEassignthesecoststohours?

A19. SCEhasdevelopedaPeakLoadRiskFactor(PLRF)methodology.15Inhours

inwhichacircuitloadfallsbelowtheplanningthresholdtriggeringareview

ofcircuitneeds,theneedissetatzero.Thehoursinwhichcircuitloadis

greaterthan73%areconsideredpeakloadsandassignedavalueofone.

Thepeakloadoccurrencesaresummedforallcircuitsineachhouranda

relativeratioisdeterminedforthesehourlyvalues,calledthePLRF.To

captureloaddiversityacrosscircuits,SCEidentifiedthePLRFbyhourfor

eachcircuitandaggregateditacrossallcircuitsonthesystem.Basedonthe

2014datausedbySCEforthisanalysis,individualcircuitsdonot

necessarilypeakwhenthesystemloadpeaks.

Forecastingto2024,withincreasingamountsofdistributedenergy

resources(DER),SCEanticipatesthatthetimingofcircuitpeakdemands

willshifttolaterinthedayandthatpeakingmayoccuronthedistribution

circuitsandsubstationslaterintheday.16SCEcalculatedPLRFvaluesbased

onanetloadshapeafterforecastingDERonindividualcircuits.ThePLRF

percentageweremultipliedbythepeakcapacity‐drivenpartofmarginal

                                                       14Ibid.at38.15Ibid.at39. 16 Ibid.at41.

distributioncoststodeterminethehourlyallocationofmarginal

distributioncosts.

Q20. WhatisyourresponsetoSCE’seffortstotime‐differentiatepartofits

distributionmarginalcosts?

A20. Itisnotstrictlyamarginalcostanalysissinceitusesaccountingcosts.

However,SCEhasmadeareasonablefirstattempttotime‐differentiate

marginaldistributioncostswherethecostsdoindeedvarybytimeofday.

Wenotethatthehoursofhighercostsarebroaderthanthehoursofneed

andcostforgeneration‐relatedmarginalcosts.WeagreewithSCEthat,

sinceitused2014datainitsanalysis,futurepeak‐relateddistributioncosts

arelikelytooccurlaterintheday.

Q21. DoesSCEprovidemarginaltransmissioncosts?

A21. No,itdoesnot.AsSCEpointsout,itscostallocationandtransmissionrates

aresetbytheFederalEnergyRegulatoryCommission(FERC).FERCusesa

12‐CPallocation,i.e.onebasedoneachrategroup’saverage12‐month

coincidentpeakcontribution.Furthermore,SCEpointsoutthatmostofthe

capacityplannedforonthetransmissionsystemisaresultof1)howthe

transmissionnetworkaddressesdirectionalpowerflowsforreliability,2)

movementofpowerfromgenerationsourcestoload,and3)frequency

modulationandcongestionmanagementonthenetwork.17Thus,new

                                                       17 Ibid.at43‐44.

transmissionisnotbuilttomeetpeakloadbuttomeetnetwork

requirements.

Q22. WhatisyourresponsetoSCE’streatmentoftransmissioncosts?

A22. WesupportitandSCE’sreasons.

B. Proposed Changes to TOU Periods

Q23. HowdoesSCEtranslateitsresultsintoTOUperiods?

A23. SCEproposestoretainitstwoseasons:summer(JunethroughSeptember)

andwinter(OctoberthroughMay).ItproposesnomorethanthreeTOU

periodsinaseason.ItsproposedhoursforitrevisedTOUperiodsareas

follows:18

 

Q24. HowdoesSCEsupportitsproposedTOUperiods?

                                                       18SCE‐1,Kan,at47. 

A24. SCEstatesthatitsproposedTOUperiodsandseasons“morecloselyalign

TOUperiodswithacoststructurethatreflectsthenet‐loadcurveandSCE’s

marginalcosts.”19Itreferstothemarginalcostsdiscussedinthesectionof

thistestimonyabove.SCE’sFigureIV‐2020overlaysthecurrentTOUperiods

onitsforecastof2024averagehourlycosts,lookingatbothweekdaysand

weekends.Itsanalysisshowsthatthecurrentsummeron‐peakperiodof

noonto6pmdoesnotcapturehighercosthourslaterinthedayand

includesmanylow‐costmid‐dayhours.Itsproposaltochangethesummer

on‐peakperiodto4‐9pmforbothweekdaysandweekendsresultsinaTOU

periodthatincludesthehighest‐costhours.21

SCE’s proposal to change the winter weekday and weekend mid-peak

period to 4-9 pm, matching the summer peak period, also ensures that the new

mid-peak period covers the highest cost hours in the winter. SCE also proposes a

change in its treatment of weekends. Currently, all weekend hours are off-peak.

SCE proposes to change this and include mid-peak hours as well as off-peak

hours on weekends. SCE found that summer and winter weekends and weekdays

have similar daily cost patterns but that costs are lower on weekends.22 Finally,

SCE proposes to create a new super off-peak period for weekdays and weekends

in the winter from 8 am to 4 pm recognizing particularly weak prices during that

time interval.

                                                       19 Ibid.20Ibid.,at49.21Ibid.,at56.22Ibid.,at66.

Q25. DoesSCE’sproposalperfectlymatchthemarginalcostsinitsanalysis?

A25. SCEhasusedjudgmentincreatingTOUperiodsfromthesemarginalcosts.

Its“overarchinggoalfordefiningseasonsandTOUperiodsistogroup

togetherhourswithsimilarcostsand,atthesametime,obtainreasonable

separationincostsbetweenTOUperiods.”23Whilecapturingthehoursof

highest‐andlowest‐costhours,SCEclassifiedtheremaininghoursbasedon

costandotherfactors,suchasachievingsomedegreeofsimplicityand

limitingthenumberofseasonsandTOUperiods.24Thehighestcosthours

occurinJune,August,andSeptemberduringtheperiod4‐9pm.withthe

exceptionofsomemoderatelyhigh‐costhoursduringhourending18in

NovemberandDecember.25Thelatterareassociatedprimarilywithflexible

capacityneed.26Forallmonthsoftheyear,thehighestcosthoursfallwithin

the4‐9pmperiod.

Thelowest‐costhoursoccurduringJanuary‐May,with95%inthe

period9amto3pminMarch,AprilandMay.27Thismid‐daytroughoccurs

toalesserdegreefromOctoberthroughFebruary.28

SCEalsoanalyzedthemid‐rangecosthours.Itsanalysisidentified

thesecostsasoccurringlargelyfrom10pmto12amandfrom12amto8

                                                       23Ibid.at51.24Ibid.at53.25Ibid.,at54.26TheCAISO’sanalysishasdemonstratedthatthehighestrampsoccurinNovemberandDecember.AgendaandPresentation‐FlexibleResourceAdequacyCriteriaMustOfferObligationPhase2‐SupplementalIssuePaper.pdf.,December9,2016at15.27SCE‐1,Kan,at59.28Ibid.at60.

am.29Thecostsforthehoursfrom10amto3pmfromJunethrough

Septemberalsooccurfrequentlyinthesemid‐costhoursandaresimilar.30

SCEexercisedjudgmentwithrespecttoseveral“border”hours,that

is,hoursending(referredtoasHE)9,16,and22.31SCEchosetogroupthem

withneighboringTOUperiodstoachieveconsistencybyseason.For

example,3‐4pmislowerincostinthenon‐summermonthsandhigherin

costinthesummer.Becausethishour“typicallyrepresentsthebeginningof

theramp”intheafternoon,SCEconcludedthatincludingitintheperiod

from9amto3pmwouldprovideaprice‐signaltoencourageusage,which

wouldhelpincreaseloadandflattenthestartoftheramp.32SCEincluded8‐

9am(HE9)withthehoursof9amto3pm,sinceitislowercostthanthe

previoushours.33

Similarly,SCEchosetoincludethe9‐10pmhour(HE22)inthe

period10pmto8amsinceitoccursafterthepeaknetloadasitdecreases

andthereislessneedtocreateanincentivetoreduceusageinthishourby

includingitinthe4‐9pmtimeperiod.34

Q26. WhatisyourresponsetoSCE’sproposedchangedTOUperiods?

A26. Wegenerallysupportthechanges,becauseSCE’sanalysishasshownthem

tobecost‐basedusingSCE’sforecastofmarginalcostsfor2024.SCEhas

                                                       29Ibid.at62.30Ibid.at64.31Ibid.32Ibid.33Ibid.34Ibid.

testedtheseTOUperiodsusingvariousstatisticaltestsandtheresults

supportSCE’sproposal.WhereSCEhasexercisedjudgment,itappearstous

tobesound.

CLECAand,ingeneral,theCMTAmemberspreferthecurrentoff‐

peakweekendrates.However,theCAISODepartmentofMarketMonitoring

Reportfor2015showsthatmanyofthelargestrampsintheyearoccuron

weekends.35Thus,thereisasignificantweekendrampwithrelatedcosts

forflexiblecapacityandassociatedenergycosts,makingitdifficulttojustify

retentionofentirelyoff‐peakratesontheweekends.

Q27. DoyousupportSCE’sproposaltohaveonlytwoseasonsandnottoincludea

springseasonwithlowerrates?

A27. SCEhasproposedtoreflectthelowercostsofthespringseasonthroughits

Real‐TimePricingratescheduleaswellasitsproposedsuper‐offpeakrates.

Dependingonwhethercustomersrespondtothepricingsignalsfromthese

alternatives,itmaybeworthwhiletoconsideranoptionallower‐costspring

seasoninthefuture.Goingforward,SCEshouldstudy1)whetheritsRTP

rateoptionanditssuper‐off‐peakrateproposalsufficientlycapturethecost

differentialbetweenspringmonthsandsummerandwintermonths,2)

whethertheseoptionsareunderstandableandaccessibletocustomerson

TOUratesduringthenextseveralyearsand3)howwellcustomersrespond

tothem.

                                                       35 CAISO2015AnnualReportonMarketIssuesandPerformance,p.212.

C. Implementation of New TOU Periods

Q28. HowhasSCEproposedtoimplementitsnewTOUperiodsfornon‐

residentialcustomers?

A28. SCEproposestoimplementthemonOctober1,2018,assumingadecisionis

reachedinthisproceedingbytheendof201736.ItbelievesthatanOctober

changewillmitigatebillimpactsbecausewinterratesarelowerthan

summerratesingeneralandcustomerswillhavetimetoadaptbeforethe

2019summerseason.SCEalsostatesthatitwilltaketimeforitsbilling

systemtoreflectthechangeinTOUperiods.37Weagreethatmakingthe

changeinTOUdefinitionsduringthewintermonthsiswiserthan

embarkingonthechangeduringthesummermonths,althoughitisn’t

imperativethatthefirstmonthofthechangebeOctober.However,werea

decisioninthisproceedingtobedelayed,wewouldnotsupportwaiting

anotheryear,untilOctober2019,toimplementthenewrates.Inaddition,

SCEshouldconsiderwhetherratesbasedonthenewTOUperiodscouldbe

implementedonanopt‐inbasisforcustomersafterthedecisioninthis

proceedingbeforeallcustomersareconvertedtoratesbasedonthenew

TOUperiods.PG&EhasmadesuchaproposalinA.16‐06‐013.38

Q29. WillSCEuseitsrevisedmarginalcoststomakeanychangestotherevenue

allocationatthattime?

                                                       36 SCE‐1,Andersonat79.37Ibid.38A.16‐06‐013,PG&E‐8at10‐22and10‐23.

A29. No.ConsistentwiththesettlementadoptedinD.16‐03‐030inSCE’slast

GRCPhase2,thenewmarginalcostswillnotbeusedforrevenue

allocation.39Thus,SCEdoesnotproposetousethenewmarginalcoststo

changetheclasslevelallocationorrevenueortheseasonalandfunctional

recoveryofrevenues.40Itsaysupdatedmarginalcostswillbereflectedin

revenueallocationinitsTY2018GRCPhase2.41

Inthisproceeding,SCErecompiledthebillingdeterminantsforeach

rategrouptoreflecttheproposedTOUperiodsandthen“setandrebalanced

ratelevelsusingEqualPercentageofMarginalCosts(EPMC)scalarsto

ensureoverallrevenueneutralitybetweenthecurrentandproposedrate

schedules.42

Q30. DoesSCEproposetousetheupdatedmarginalcostsforanyotherpurpose?

A30. Yes.“SCEproposestoreplacethe2015GRCPhase2MECthatwereadopted

aspartofthesettlementwithaforecastofMECthatreflectstheexpected

hourlypriceprofileresultingfromgreaterlevelsofRPSresources.”43SCE

saysitwillonlyusetheproposedforecastMECtosetenergycharge

differentialsbetweenTOUperiodstobetteraligncostsandpricing.44

Q31. WhydidSCEusetheforecastMECstoreplacethe2015adoptedMECs?

                                                       39Paragraph4.C.1ofthesettlementadoptedinD.16‐03‐030.40SCE‐1,Thomas,at75.41Ibid.at76.42Ibid.at76.43Ibid.at75.44Ibid.

A31. SCEstatesthatthe2015TOUdifferentialsreflectconservativeassumptions

abouttheeffectofrenewablegenerationthatdonotreflectforecastprice

differentialsbyTOUperiod.45SCEhasconcludedthatupdatingtheMECs

willcreatemoreappropriatepricesignalsonaseasonalbasis,since,as

showninSCE’sTableV‐12,arelianceonthe2015MECswouldleadto

super‐offpeakratesthatarehigherthanoff‐peakrates.46

Q32. PreciselyhowdoesSCEproposetousetheseupdatedMECsforratedesign?

A32. SCEproposestousethenewMECstosetTOUpricedifferentialsforenergy

charges.SCEalsoproposestocontinuetosetdemandchargesbasedona

lowerMGCCcostthantheadoptedMGCCusedforrevenueallocation,

consistentwiththesettlement.

Q33. DoesSCEplantoeducatecustomersaboutthenewTOUperiodspriorto

implementingthem?

A33. Yes.SCE’stestimonyincludesaplanformarketing,education,andoutreach

(ME&O).SCEstatesthatcustomerswillneedtobeinformedand“tohave

timetoadjusttheirbusinessoperationsandmakeinvestmentstobetter

respondtothenewtimeperiods.”47Weagreethatcustomerswillneedtime

toadjusttothenewTOUperiods.However,ninemonthstoayearshouldbe

sufficient.Furthermore,asproposedabove,wethinkcustomerswhowish

                                                       45Ibid.at77.46 Ibid.at78.47SCE‐1,Anderson,p.80.

toswitchtothenewTOUperiodsbeforethatyearisoutshouldbeableto

participateonanoptionalopt‐inbasis.

D. Dynamic Pricing Program Changes

Q34. DoesSCEproposeanychangestoitsdynamicpricingratesduetotheseTOU

periodchanges?

A34. Yes.SCE’sdynamicpricingrateoptionsfornon‐residentialcustomersare

calledCriticalPeakPricing(CPP).SCEproposestochangetheCPPevent

periodfromthecurrent2‐6pmto4‐9pm.Thiswillmakeitconsistentwith

SCE’sproposednewsummerpeakperiodandsummerweekendandwinter

mid‐peakperiodsforbothweekdaysandweekends.

Q35. DoesSCEproposetomakeanyotherchangestoitsCPPrateschedules?

A35. Yes.SCEcurrentlyoverlaysCPPchargesandcreditsontoacustomer’sTOU

baserates.CPPeventchargesarecollectedona$/kWhbasisforall

electricityuseduringCPPeventsandCPPcreditsareusedtoreduce

participants’summeron‐peakratesonnon‐eventdays.Customerson

demand‐meteredrateschedulesreceiveacredittotheiron‐peakdemand

charges.Thosenotondemand‐meteredrateschedulescurrentlygeta

$/kWhcredittoalltheirsummerenergycharges.(Thishasoccurred

becauseatthetimeCPPratesweredeveloped,thelatterwerenotonTOU

rates.)SCEproposestoprovidetheCPPcredittothelattercustomersasa

$/kWhreductiontosummeron‐peakenergychargesonly,whichwillbe

consistentwiththetreatmentofdemand‐meteredcustomers.48

Q36. Doyousupportthisproposedchange?

A36. Yes.Fromaratedesignperspective,itisappropriatetohaveCPPcharges

andcreditsassociatedwiththeTOUperiodinwhichtheCPPeventsare

mostlikelytooccurandtotreatdemand‐andnon‐demand‐metered

customersinasimilarfashion.

Q37. HowdoesSCEproposetocalculatetheCPPeventcharge?

A37. Nowthatithasbifurcateditsgeneration‐relatedcapacitycostsintosystem

andflexible,SCEproposestoonlyreflectgenerationcapacityvalue

associatedwithsystemcapacityneedsforCPPevents.49Thisresultsina

reductionoftheCPPeventratefrom$1.37/kWhto$0.86/kWh,whichSCE

reducesto$0.80/kWh.SCEproposestophaseinthisCPPeventchargeover

twoyearswithachargeof$0.40/kWhinthefirstyear.50

Q38. HowdoesSCEproposetocalculatetheCPPcredit?

A38. CPPeventchargesandcreditswillcontinuetobesetatarevenue‐neutral

level,soacustomerwithaclass‐averageloadshapewouldnotseeitsbill

changecomparedtotheotherwiseapplicabletariff.51SCEprovidesCPP

                                                       48 SCE‐1,Thomas,at89.49Ibid.at90‐91.50Ibid.at91.51 Ibid.at92.

creditsinTableVI‐1452ofitstestimony.Creditsorallrateschedulesexcept

TOU‐GS‐1areintheformofa$/kWcredit.

Q39. DoesSCEproposeanyotherchangesinCPPrates?

A39. Yes,SCEproposestosimplifyCPPrateoptions.Itproposestoeliminatethe

CPP‐LiterateoptionwithlowerCPPeventcharges,sinceitsnewproposed

eventchargesaresignificantlylowerforallcustomersonCPPrates.Italso

proposestoeliminatetheCapacityReservationChargehedgingoptionsince

onlytwocustomersareonthatrateoptionatanylevelofhedging.53

SCEcurrentlyprovidesoneyearofbillprotectionofcustomerson

CPPrates.SCEproposestochangethecurrentprovisionwherebyif

customersterminatetheirCPPrateparticipationbeforetheendof12

months,theylosebillprotectionandgiveupanyaccruedbillprotection

credits.SCEnowproposestoprovidecustomerswithbillprotectioncredits

iftheyendtheirparticipationontheprogrambeforetheendof12months.54

SCEproposesthatallnon‐residentialcustomersspendtwoyearson

TOUratesbeforebeingdefaultedtoCPPrates.55Italsoproposesthatthe

annualdefaultdatebeOctober1ofeachyear,afterthesummerseason.56

Q40. DoyouhaveapositionontheseproposedchangestodefaultCPPrates?

A40. Wedonotopposethem.

                                                       52Ibid.at92.53SCE‐1,Anderson,at92‐93.54Ibid.at94.55Ibid.at96.56Ibid.

Q41. WhendoesSCEproposetoimplementdefaultCPPratesforTOU‐GS‐1,TOU‐

GS‐2,andTOU‐PA‐3rateschedules?

A41. SCEproposestodosostartinginfall2018,phasingintheinitial

implementation.In2018‐2019,theCPPchargesandcreditsforallCPP

customersintheserategroupswillbesetbasedona$0.40/kWhevent

charge,whichwillbedoubledfor2019‐2020.

Q42. DoeSCEplanacustomereducationprogramforthesegroupsofcustomers?

A42. Yes,itdoes.

Q43. DoesSCEhaveanyotherCPPproposals?

A43. Yes.SCEproposestoexcludeTOU‐GS‐1customersfromdefaultCPPrates.It

citesthechallengeofreachingouttosomanysmallcommercialand

industrial(C&I)customersaswellastheexpectationthattheywillnot

meaningfullycontributetotheCommissionobjectiveofachievingload

reductionsthroughCPPrates.57SCEstatesthatwhenPacificGasand

ElectricCompanydefaulteditscustomerswithloadslessthan20kWtoCPP

rates,theresultwasaloadreductionoflessthan0.012kW/customerand

1.5MWinaggregate.58SCEalsopointsoutthatCPPisunlikelytobe

integratedintotheCAISOmarkets.59Givenallofthesefactors,SCEproposes

thatCPPratesforsmallC&Icustomersbegivenalowerpriorityandthatthe

                                                       57Ibid.at103.58Ibid.,FN121,at103andTableVI‐15,at105.59Ibid.,p.106.

CommissionfocusonprogramsthatcanbeintegratedintotheCAISO’s

markets.60

Q44. Doyouhaveapositiononthisproposal?

A44. Giventheamountofpotentialloadreductionduringeventperiods,weagree

thatdefaultCPPforTOU‐GS‐1customerscanbedeferred.

E. Real-Time Pricing

Q45. PleasedescribeSCE’sRTPrateschedule.

A45. SCE’sRTPrateschedulehashourlyratesthatvarybythemaximum

temperaturerecordedonthepriordayattheLosAngelesCivicCenterand

aredesignedtorecoverthegenerationrevenuerequirementofthe

otherwiseapplicabletariff.61CurrentRTPgenerationratesveryover5

weekdaytemperaturecategoriesinthesummer(fromextremelyhotto

mild),twoweekdaycategoriesforthewinter(highcostandlowcost)and

twocategoriesforweekends(highandlowcost).Onextremelyhotandvery

hotdays,thehighesthourlyratescanexceed$2/kWh.Attheotherextreme,

lowcostdayratescandropaslowaslessthan3cents/kWh.TableVI‐16

illustratesthisphenomenonforsecondarycustomers.62

SCE’stestimonyatTableVI‐17illustrateshowSCEexpectsits

projected2024marginalgenerationcoststoaffectRTPratesforTOU‐8‐

                                                       60Ibid.61SCE‐1,Thomas,p.108.62 Ibid.,p.109.

Secondarycustomers.63Giventhenewmarginalgenerationcapacityvalue,

annualmarginalenergycostforecasts,andrevenuerequirements,SCE

showsthatthehighestratesontheextremelyhotsummerweekdaycouldbe

over$9/kWh.Thelowestrateswouldbecloseto4cents/kWh.SCEsays

thattemperaturewillcontinuetobeatriggerhighlycorrelatedwithits

systempeakdemandsbutthatforecast2024generation‐relatedmarginal

costswillshifthighercosthourslaterinthedayandconcentratethemin

fewerhours.64Inaddition,theintroductionofflexiblecapacitymarginal

costsspreadsgeneration‐relatedcapacitycoststomultipleRTPdaytypes.

ThiscontraststocurrentRTPrates,whichhavenogenerationcapacityin

winteroronweekenddays.65

Q46. DoesSCEproposeanychangesintheRTPratescheduleresultingfromthis

changeincostpatternsamongthedaytypes?

A46. Yes.SCEproposestoreducethecurrentfivesummerweekdaydaytypesto

three.Thesewouldbebelow80degreesF,81‐90degreesF,andover90

degreesF.66Asaresult,asshowninTableVI‐18,thehighesthourly

generationratewoulddroptolessthan$4/kWh.67Thelowesthourly

generationrateswouldnotchange.

Q47. HasSCEperformedabillimpacttodeterminetheimpactofthesechanges

oncustomerscurrentlyonRTPrates?                                                       63Ibid.110.64Ibid.at110‐111.65Ibid.66Ibid.at111.67Ibid.at112.

A47. Yes.SCEhasfoundthatsomewillseeabillreduction,otherwillseeminor

changes,and12%willfacerateincreases,someasmuchas15‐20%.68

However,SCEbelievesthatsincecustomersontheseratestendtobevery

responsivetotheRTPpricesignals,thelattergroupwillshifttheirloadsin

responsetothechangedpriceprofilebasedon2024costsandnotactually

incursuchincreases.69

Q48. WhatisyourresponsetoSCE’sproposedchangestoRTPrates?

A48. TheproposedchangesappeargenerallyacceptabletoCLECAandCMTA.

III. NEEDFORCHANGESTOTOU‐RELATEDDEMANDRESPONSEINCENTIVES

Q49. SCEhasattemptedtominimizethechangestothesettlementreachedon

costallocationandratedesigninitslastGRCdecision.Doyoubelievethat

anyadditionalchangesareneededinthisratedesignwindowassociated

withthechangingTOUperiods?

A49. Yes,wethinkachangeiseitherneededinitsRDWdecisionorinSCE’s

pendingdemandresponse(DR)application(A.17‐01‐018)forprogram

changesin2018,orboth.WhileweappreciateSCE’sattemptstopreserveas

muchofthesettlementaspossible,theratedesignwindowproposalcreates

aseriousdisconnectbetweenTOU‐basedratesandTOU‐basedDR

incentives.Forexample,theBaseInterruptibleProgram(BIP)incentives

arecalculatedbasedonacustomer’saveragedemandinvariousTOU

                                                       68Ibid.at114.69Ibid.at113.

periods,particularlythesummeron‐peakandsummermid‐peakperiods.

TheBIPtariffspecifiesthehoursoftheseTOUperiods,whicharethe

currentTOUperiodhours.IftheTOUperiodschangeforthecustomer’s

otherwiseapplicableratebutdonotchangefortheBIPincentives,incorrect

pricesignalswillbesentandcustomerswillnotbeencouragedtohaveload

duringtheperiodswhenDRisgenerallymostneeded,i.e.theperiodsof

highestnetload.

Currently,theBIPincentive(in$/averagekW)isgreatestinthe

summeron‐peakperiod.Thisencouragesthecustomertohaveloadduring

thatperiodsothatitcanbeshedifnecessary.TheBIPincentiveoffsetsthe

on‐peakdemandcharge,reducingthecostofhavingthatloadonlineand

availabletoshed.Thisistrueforthesummermid‐peakperiodaswell,

wheretheincentivehelpsoffsetthemid‐peakTOUdemandcharge.IftheBIP

incentiveTOUperiodsdonotalignwiththeTOUperiodsinthecustomer’s

rateschedule,thecustomerwillhaveanincentivetohaveloadonlineduring

summernoonto6pm,whilethegreatestneedfortheresourceissummer

(orwinter)4‐9pm.

Inits2018DRapplication,A.17‐01‐018,SCEhasproposedtochange

theBIPTOUperiodsattheendofitsnextGRCPhase2proceeding,tomatch

theTOUperiodsproposedinthisratedesignwindow,andtodosointhe

2020DRmid‐cyclereviewfiling.70However,fromOctober2018,whenthe

                                                       70 A.17‐01‐018,SCE‐1,Vol.3at8.“Ifnecessary,SCEintendstosubmitupdateddesignsofproposedincentivestructuresinits2020mid‐cyclereviewinordertoalignincentiverates

ratesfromthisproceedingareproposedtogointoeffect,towheneverthe

nextGRCPhase2decisionisimplemented,orwhentheDR2020mid‐cycle

reviewresultsinadecision,therewillbeagap.Incorrectincentiveswillbe

setandincorrectpricesignalswilloccur.

InA.17‐01‐018,toprovideanexample,SCEproposesthattherebea

significantBIPincentiveforthewintermid‐peakperiod,becausetherewill

besignificantLOLEduringthatperiod.71Atpresent,thewintermid‐peak

incentiveisverysmall.Similarly,currentlythesummermid‐peakincentive

isfairlylarge,andSCEproposesthatitbecomemuchsmallerinthefuture.

Again,iftheTOUperiodsforBIPincentivesarenotchanged,customerswill

begivenlargerincentivestohaveloadduringtimeperiodswhentherewill

belessneedtodispatchtheDRprogramandlowerincentivesduringperiods

whentherewillbemoreneedtodispatchtheprogram.ChangestotheTOU

periodsforretailratesandfortheBIPincentivesmustbecoordinated

betweenA.17‐01‐018andthisRDWproceeding,sothatthisgapdoesnot

occur.ItisimportantthatthetimingofthechangeoccurwhenthenewTOU

periodsforretailratesfromtheRDWgointoeffect.Forthisreason,while

newTOUperiodsforDRincentivesmaybeadoptedinthe2018DR

Application,theyshouldonlygointoeffectwhentheTOUperiodschanges

associatedwiththisRDWoccur.DelayingtheTOUperiodchangesforDR

                                                                                                                                                                 structureswiththenewTOUperiodratesultimatelyadoptedinSCE’s2018GRCPhase2proceeding.”71A.17‐01‐018,SCE‐1,Vol.3at9.

programsuntilthe2020DRmid‐cyclereviewwouldresultinchangesbeing

madetoolate,andstillresultinamismatch.

IV. CAPONPARTICIPATIONINOPTIONR

Q50. WhatisOptionR?

A50. OptionRisarateoptionfornon‐residentialcustomerswithdemands

greaterthan20kWbutlessthan4MWthatuseon‐siterenewable

generation.Itisarateschedulethatlimitssubscriptiontoamaximumof

400MWofon‐siterenewablegeneration.

Q51. Whyisthecapanissueinthisproceeding?

A51. TheScopingRulinginthisproceeding,issuedonMarch21,2017,addedthis

issuetothescopeoftheproceedingafteraprotestbyCalSEIAclaimedthe

capwouldbereachedpriortoadecisioninthenextSCEGRCPhase2

proceeding;thepreviousSCEGRCPhase2proceedingresultedina

settlementagreementinwhichitwasagreedthatthenextGRCPhase2

wouldbethenextproceedingtoreviewanychangestothecap.72The

ScopingRulingalsostatesthatCalSEIAwasnotapartytothesettlement

adoptedinD.14‐12‐048butisaffectedbyitsconsequences.73

Q52. Whatisyourresponsetotheproposaltoaddressthecapissueinthis

proceedingratherthantheSCEGRCPhase2proceeding?

                                                       72JointMotionforApprovalofSettlementAgreementinA.13‐12‐015,August14,2014,AttachedSettlementAgreementat8.73 ScopingRulingat6.

A52. Wehaveseveralconcerns.First,CalSEIAwasapartytoA.13‐12‐015.

Althoughitdidnotsignthesettlementagreement,thedecisionadoptingthe

settlementmakesitveryclearthatCalSEIAdidnotformallyopposethe

settlement.74Thus,CalSEIAdidnotacttoraiseanyconcernsaboutwaiting

untilthenextSCEGRCPhase2toaddressthecaponOptionRwhenitcould

havedoneso.Second,whiletheScopingRulingsaysthat“CalSEIAalso

statesthatSCE’sanalysisshowsthatOptionRforsolarcustomersisacost‐

neutraloption”,75noevidencehasbeenpresentedtosupportthatassertion.

Indeed,SCEdidpresenttestimonyinA.13‐12‐015showingthatOptionR

didcausecost‐shifting.Anyrateoptionthatcausescost‐shiftingto

customersonotherrateoptionsisnotcost‐neutralbydefinition.Thus,the

issueofchangingthecapcannotbeaddressedwithoutconsiderationofcost‐

shiftingtoothercustomersontherateschedulesthatincludeOptionR.The

issueofcost‐shiftingshouldbeexaminedinaproceedingwherethecostof

servicebasisforOptionRcanbefullyevaluatedbeforethecapisraised.

ThelogicalplacetodothatistheGRCPhase2proceedingthatSCEis

expectedtofileinJuneofthisyear.

V. CONCLUSION

Q53. Doesthiscompleteyourtestimony?

A53. Yes,itdoes.

 

                                                       74 D.14‐12‐048at4.75ScopingRulingat6.

APPENDIX A

QUALIFICATIONSOFBARBARAR.BARKOVICH

BarbaraR.BarkovichhasaBAinPhysicsfromtheUniversityofCaliforniaat

SanDiego,anMSinUrbanandPolicySciencesfromtheStateUniversityofNew

YorkatStonyBrook,andaPh.D.inEnergyandResourcesfromtheUniversityof

CaliforniaatBerkeley.

Dr.BarkovichworkedonenergyandenvironmentissuesfortheNational

ScienceFoundationin1974‐75.Dr.BarkovichworkedfortheCPUCin1975‐1983,

endingupasDirectorofPolicyandPlanning.InhertimeattheCommission,she

dealtwithbroadenergypolicyissues,aswellasrevenueallocationandratedesign,

marginalcostdevelopment,electricresourceissues,includingtransmissionand

generation,andrepresentationoftheCommissionattheLegislature,theGovernor’s

Office,andCongress.

Dr.Barkovichnextspentalmosttwoyearsrunningashort‐termfinancing

programatamajorbankholdingcompany.Sincethen(1985),shehasbeena

consultantandexpertwitnessonenergy(especiallyelectricity)andregulatory

matters,includingmarginalcost,costallocationandratedesign,electricindustry

restructuring,electricresourceanalysis,duediligenceforenergyprojects,and

negotiationsonbehalfofelectricconsumerswithutilitiesandenergyservice

providersonpricingandservicematters.

Dr.BarkovichhasalsoservedontheCaliforniaIndependentSystemOperator

GoverningBoardandtheEnergyEngineeringBoardoftheNationalResearch

CouncilandcurrentlyservesasChairoftheBoardofDirectorsoftheCalifornia

PowerExchange.

 

APPENDIXB

QUALIFICATIONSOFCATHERINEE.YAP

Q1. Pleasestateyournameandbusinessaddress.

A1. MynameisCatherineE.YapandmyaddressisBarkovich&Yap,Inc.,P.O.Box

11031,Oakland,California94611.

Q2. Pleasestateyourqualificationstoofferthistestimony.

A2. IamaprincipalinthefirmofBarkovich&Yap,Inc.,andhavebeenconsultinginthe

utilityregulatoryareaforaboutthirtyyears.Duringthistime,Ihavedirected

and/orperformedmajorexaminationsofcost‐of‐servicerequirements,allocation,

ratedesign,andcustomerbilleffectsforelectric,naturalgas,andsolidwaste

utilities.IhavetestifiedonnumerousoccasionsbeforetheCaliforniaPublicUtilities

Commission(Commission)andincivilproceedings.Ihaveconsulted

internationallyonissuesrelatedtonaturalgasindustrystructureandmarginalcost

allocationandratedesign.

Priortothis,IwasemployedfornineyearsbytheCommission.Mostrecently,Iwas

responsibleformanagingtheEnergyRateDesignandEconomicsBranchofthe

PublicStaffDivision(PSD).Thisbranchwasresponsiblefordevelopingcostof

service,ratedesign,andeconomicstudies,suchassalesforecastingand

productivityassessment,forbothelectricandgasutilities.Membersofthebranch

wereresponsibleforpresentingexperttestimony,developingcostofservice

studies,anddesigningunbundledratesforthenaturalgasutilitiesduringthe

Commission’sextensivehearingsongasindustrystructureandratedesign

implementation.Duringthistime,Iparticipatedextensivelyintheformulationof

policyregardingtheappropriatestructureforthenaturalgasindustryinCalifornia.

Previously,IwastheSupervisoroftheGasSupplyandRequirementsSectionofthe

FuelsBranchofthePSD.Iwasresponsiblefordirecting,andinsomecases

performing,advancedtechnicalstudiesthatevaluatedCaliforniagasutility

operationsandassociatedcontracts,investments,andexpenses.Ialsoactedasthe

highestleveltechnicalrepresentativeoftheCommissiononnaturalgasmattersand

 

wasinvolvedinnumerousnegotiatedsettlementsinvolvingnaturalgaspipelines,

distributionutilities,producers,andstateandfederalregulatoryagencies.

Priortothat,IwasastaffeconomistinthePolicyDivisionactingasaconsultantto

theExecutiveDirectorandtovariousCommissioners.Ialsotestifiedonnumerous

occasionsasanexpertwitnessregardingavarietyoftechnical,economic,and

financialmattersrelatedtoelectricandnaturalgasutilities.

IhaveaB.A.inchemicalphysicsfromtheUniversityofCaliforniaatSantaCruz,and

aM.S.inEnergyandResourcesfromtheUniversityofCaliforniaatBerkeley.Ihave

alsotakencourseworkinfinance,accounting,andorganizationtheoryfromthe

UniversityofCalifornia,Extension,andGoldenGateUniversity.