state water control board environmental protection agency ......hydro‐electric power plant name...

State Water Resources Control Board

California Environmental Protection Agency

DRAFT

APPENDIX X*: HYDROPOWER AND ELECTRIC GRID ANALYSIS OF LOWER SAN JOAQUIN RIVER FLOW

ALTERNATIVES

February 2012

*Lettering of Appendix to be determined during the preparation of the Draft Substitute Environmental Document

DRAFT Evaluation of San Joaquin River Flow and Southern Delta Water Quality Objectives and Implementation

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Appendix X DRAFT Hydropower and Electric Grid Analysis of Lower

San Joaquin River Flow Alternatives

X.1 Table of Contents Appendix X DRAFT Hydropower and Electric Grid Analysis of Lower San Joaquin River Flow

Alternatives .............................................................................................................. X‐1

X.1 Table of Contents ............................................................................................................. X‐1

X.2 Introduction ..................................................................................................................... X‐2

X.3 Hydropower Generation Effects ...................................................................................... X‐3

X.3.1 Methodology .................................................................................................................... X‐3

X.3.2 Results .............................................................................................................................. X‐6

X.4 Overview of the Transmission System in Central California ............................................ X‐8

X.4.1 California Independent System Operator ........................................................................ X‐8

X.4.2 Sacramento Municipal Utility District ............................................................................ X‐12

X.4.3 Turlock Irrigation District ............................................................................................... X‐14

X.5 Capacity Reduction Calculation and Power Flow Analysis ............................................ X‐16

X.5.1 Capacity Reduction Calculation Methodology ............................................................... X‐16

X.5.2 Power Flow Assessment Methodology .......................................................................... X‐19

X.5.3 Power Flow Simulation Tools ......................................................................................... X‐21

X.5.4 Assumptions for Facilities .............................................................................................. X‐21

X.5.5 Results and Conclusions ................................................................................................. X‐22

X.6 References ..................................................................................................................... X‐23

State Water Resources Control Board California Environmental Protection Agency

DRAFT Hydropower and Electric Grid Analysis of Lower San Joaquin River Flow Alternatives


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X.2 Introduction ThisappendixprovidesestimatesofthepotentialeffectsonhydropowergenerationandelectricgridreliabilityintheLowerSanJoaquinRiver(LSJR)watershedcausedbyimplementingtheLSJRflowalternatives.TheLSJRflowalternativesproposetoaltertheFebruarythroughJuneflowontheStanislaus,Tuolumne,andMercedRivers(LSJRtributaries),whichcouldaffectreservoiroperationsandsurfacewaterdiversionsandtheassociatedtimingandamountofhydropowergenerationfromtheLSJRwatershed.

ThisanalysisreliesontheStateWaterResourcesControlBoard(StateWaterBoard)watersupplyeffectsmodel(WSE)toestimatetheeffectsoftheLSJRflowalternativesonreservoirreleasesandstorage(elevationshead)andallowablediversionstooff‐streamgenerationfacilities,andthencalculatestheassociatedchangeinmonthlyandannualamountsofenergyproduced.Thisoutputthenprovidesinputtoelectricgridreliabilitymodeling,whichevaluatesthepotentialforthesechangestoeffectelectricgridreliabilityunderpeakloadandoutagecontingencyscenarios.

TherearethreedifferentLSJRflowalternatives,eachconsistingofspecifiedpercentageofunimpairedflowrequirementfortheStanislaus,Tuolumne,andMercedRivers.Foraparticularalternative,eachtributarymustmeetthespecifiedpercentageofitsownunimpairedflowatitsmouthwiththeLSJRduringthemonthsofFebruarythroughJune.Thepercentageunimpairedflowrequirementsare20%,40%and60%respectivelyforeachalternative,butonlyapplywhenflowsareotherwisebelowaspecifiedtriggerlevel.Also,flowsmustnotdropbelowspecifiedlevelsoneachtributary,andtogethermustmaintainaminimumflowontheSJRatVernalis.SpecifictriggerandminimumflowlevelsandotherdetailsoftheLSJRflowalternativesarepresentedinSection3.2oftheSubstituteEnvironmentalDocument(SED),andarethebasisforhowthealternativesaremodeledinthisappendix.

NumeroushydropowergenerationfacilitiesonthethreeLSJRtributariesareevaluatedinthisanalysis.Themajorfacilitiespotentiallyeffected,however,arethoseassociatedwiththeNewMelonesReservoir(NewMelonesDam)ontheStanislausRiver,1NewDonPedroReservoir(NewDonPedroDam)ontheTuolumneRiver,andLakeMcClure(NewExchequerDam)ontheMercedRiver.FigureX‐1showsthelocationoftheseandotherhydropowerfacilitiesinandaroundtheLSJRwatershed.

1TheTullochreservoirandhydropowerplantontheStanislausRivercouldalsobeaffectedbytheproject.However,thisisarelativelysmallfacility,ratedat18MW.Therefore,anyimpactassociatedwithareductioninitscapacityontheCaliforniainterconnectedgridislikelytobeminimal




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Figure X‐1. Location of hydropower facilities in the LSJR watershed (Source: Ventyx)

X.3 Hydropower Generation Effects TheanalysisinthissectionestimatesthepotentialeffectsontimingandamountofhydropowergeneratedbyhydropowerfacilitiesontheLSJRtributariescausedbyimplementingtheLSJRflowalternatives.Theseeffectswouldbeduetochangesinthetiming,ratesofrelease,andelevationheadatmajorreservoirsandchangestoallowablediversionstooff‐streamfacilitiesassociatedwithmeetingthepercentunimpairedflowrequirementofaparticularalternative.Estimatesofpotentialchangestoreservoirreleases,changesinreservoirelevations,andallowableoff‐streamdiversionsareprovidedbytheStateWaterBoardWSEmodelasdescribedinChapter5ofAppendixX(drafttechnicalreport).Thehydropowergenerationeffectsarepresentedasbothannualandmonthlychangesfromthebaseline.Theoutputfromthemodelinginthissectionprovidesinputtotheelectricgridreliabilityanalysisinthesubsequentsections.

X.3.1 Methodology

ForeachoftheLSJRflowalternatives,thisanalysisestimatestheamountofhydropowerthatwouldbegeneratedfromthevariousfacilitiesontheLSJRtributariesforcomparisonagainsttheamountgeneratedunderbaselineconditions.Baselineconditionsarethosefromthe“Current(2009)Conditions”CALSIMIImodelrunfromtheCaliforniaDepartmentofWaterResource’sStateWaterProjectReliabilityReport2009.

HydropowerfacilitiesontheLSJRtributariesweregroupedintofourcategoriesforthisanalysis,basedonwheretheyarelocatedrelativetothethreemajortributarydamsandwhethertheyarein‐streamfacilitiesoroff‐stream.TableX‐1containsalistofthehydropowerfacilitiesontheLSJRgroupedintothesecategories,alongwithsomebasicfacilityinformation.



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Hydropower generated from in‐stream facilities is estimated by inputting reservoir head and/or release rates obtained from the WSE model into the power equation presented below. As described in Chapter 5 of Appendix X (draft technical report) the WSE model provides estimates of reservoir operations and allowable surface water diversions associated with the different SJR flow alternatives. For simulation of each alternative the WSE model used diversion delivery rule (cutback) curves developed to match end‐of‐September (carryover) storage from the baseline CALSIM model run as closely as possible. Special attention was given to not exceeding the number of times reservoir storage dropped below set minimum levels of 300 thousand acre‐feet (TAF), 500 TAF, and 200 TAF for New Melones, New Don Pedro, and Lake McClure, respectively. If different diversion delivery rule curves are used to model the LSJR flow alternatives, resulting reservoir storage levels and release rates, and associated amounts and timing of hydropower generated would also be different. In general, curves that maintain higher levels of diversion deliveries will result in lower reservoir levels and reduced overall hydropower generation.

Power generated from facilities at the major dams, or facilities in‐stream and downstream of the major dams, was calculated using the following power equation on a monthly time step:

where HP is the total horsepower generated by the facility, ep is the power plant efficiency, (80% in all facilities except New Melones), ۟γ is weight of water, Q is the flow released from the reservoir and through the turbines, and hg is the elevation head behind the dam. The reservoir release rates (Q) and reservoir elevations (hg ) are obtained from the WSE model output for each alternative and from CALSIM for the baseline condition. All hydropower facilities were assumed to operate within the constraints of the facility; spills causing flows greater than capacity do not produce energy above the maximum capacity. In‐stream facilities located downstream of the major dams were assumed to have constant hg equal to the maximum head of the reservoir as these facilities are generally run‐of‐the‐river. Calculations for the New Melones facility use separate factors that allow the power plant efficiency (ep) to change with respect to change in elevation head and flow rates (Medellin‐Azuara, pers. comm. 2011). Horsepower obtained from the above equation is then converted to megawatts and multiplied by the number of hours in the month to result in megawatt (MW) hours of energy per month.

An off‐stream facility is one supplied by diversions of surface water from the associated river. Power generated from off‐stream facilities use the following equation to determine the effect of each alternative compared to the baseline on a monthly basis:

∆Power = (TotD(alternative) – TotD(Baseline)) / TotD(baseline) x Nameplate Capacity

where the ∆Power is calculated in MW, TotD is the allowable surface water diversion from the WSE model for the associated tributary (for the respective alternative and baseline), and the nameplate capacity is the maximum generating capacity of the power facility. The amount of power produced in these facilities under baseline conditions is conservatively assumed to be the nameplate capacity.

Hydropower generated from facilities upstream of the major dams on the Stanislaus and Tuolumne Rivers is assumed to be unaffected by the LSJR flow alternatives. Storage capacity of the associated reservoirs as used to shift flows between spring and summer months is limited and much less than the capacity available downstream in the major reservoirs to make up any such difference. The Merced River has no major hydropower reservoirs upstream of Lake McClure (New Exchequer Dam).




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Table X‐1. List of hydropower facilities in the LSJR watershed (CEC 2012).

RiverBasin

Hydro‐electricPowerPlantName

NameplateCapacity(MW)

%ofPowerCapacityinBasin

LocationRelativetoRimDam

Stanislaus

Woodward 2.85 0.3% Offline

Frankenheimer 5.04 0.5% Offline

Tulloch 17.10 1.8% Inline

Angels 1.40 0.1% Upstream

Phoenix 1.60 0.2% Upstream

Murphys 4.50 0.5% Upstream

NewSpicer 6.00 0.6% Upstream

SpringGap 6.00 0.6% Upstream

Beardsley 9.99 1.1% Upstream

SandBar 16.20 1.7% Upstream

Donnells‐Curtis 72.00 7.7% Upstream

Stanislaus 91.00 9.7% Upstream

ColliervillePh 249.10 26.5% Upstream

Collierville 253.00 26.9% Upstream

NewMelones 300.00 32.0% RimDam

UpstreamCapacity 710.79 75.7% NA

AffectedCapacity 227.99 24.3% NA

Tuolumne

StoneDrop 0.20 0.0% Offline

Hickman 1.08 0.2% Offline

TurlockLake 3.30 0.5% Offline

LaGrange 4.20 0.7% Inline

UpperDawson 4.40 0.7% Upstream

MoccasinLowhead 2.90 0.5% Upstream

Moccasin 100.00 16.6% Upstream

RCKirkwood 118.22 19.6% Upstream

DionR.Holm 165.00 27.4% Upstream

DonPedro 203.00 33.7% RimDam


AffectedCapacity 211.78 35.2% NA

Merced

Fairfield 0.90 0.8% Offline

Reta‐CanalCreek 0.90 0.8% Offline

MercedID–Parker 3.75 3.2% Offline

Mcswain 9.00 7.6% Inline

MercedFalls 9.99 8.4% Inline

NewExchequer 94.50 79.4% RimDam


AffectedCapacity 119.04 100% NA




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X.3.2 Results

TableX‐2containsasummaryoftheaverageannualhydropowergenerationchangeoneachofthetributariesduetothealternatives.Generally,asthepercentofunimpairedflowalternativeincreases,theamountofpowergeneratedannuallyisreduced.ThesechangesarealsorepresentedasapercentofbaselinegenerationinTableX‐3.Themonthlypatternoftheaveragechange(over82yearsofsimulation)inhydropowergenerationfromtheentireLSJRwatershedispresentedinFigureX‐2.ThisshowsageneralincreaseinenergybeingproducedinMayandJune,asmoreflowisbeingprovidedinthosemonthsbytheLSJRflowobjectiveswhencomparedtobaseline.AdecreaseduringJulyandAugustisduetoacorrespondingreductioninreservoirreleasesduringthosemonths.TheseeffectsaremorepronouncedasthepercentageofunimpairedrequirementoftheLSJRflowalternativesincreases.

ThecorrespondingrelativeeffectonrevenuesfromhydropowergenerationwillbeslightlygreaterasthepriceofenergyisgenerallylessduringFebruarythroughJunewhencomparedtoJulyandAugust.AnevaluationofthecorrespondingrevenuelossandassociatedeconomiceffectswillbeevaluatedelsewhereintheSED(tobedetermined).

Table X‐2. Average Annual Baseline Hydropower Generation and Difference from Baseline by Tributary.

AlternativeStanislaus(GWh)

Tuolumne(GWh)

Merced(GWh)

ProjectArea(GWh)

Baseline 437 628 403 1,467

20%UF ‐10 0 0 ‐10

40%UF ‐19 ‐9 ‐9 ‐37

60%UF ‐31 ‐18 ‐18 ‐66

GWh=gigawatthours

Table X‐3. Average Annual Hydropower Generation Difference as Percent Change from Baseline by Tributary.

AlternativeStanislaus(%dif)

Tuolumne(%dif)

Merced(%dif)

ProjectArea(%dif)

Baseline 100% 100% 100% 100%

20%UF ‐2% 0% 0% ‐1%

40%UF ‐4% ‐2% ‐2% ‐3%

60%UF ‐7% ‐4% ‐5% ‐6%




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10 11 12 1 2 3 4 5 6 7 8 9

20% UF 9.1 1.4 1.4 3.7 -3.9 -13.5 -30.8 -5.0 11.4 4.1 4.6 7.9

30% UF 4.5 -1.1 -0.8 1.0 -3.4 -10.3 -20.7 13.4 13.8 -9.0 -7.6 -0.3

40% UF 1.7 -2.9 -2.3 -1.8 -4.3 -9.7 -11.7 26.6 17.6 -23.0 -19.8 -7.0

50% UF -1.1 -4.5 -4.2 -3.3 0.9 -4.3 -2.5 29.4 18.7 -36.8 -32.0 -12.3

60% UF -3.0 -6.0 -5.7 -5.0 5.8 1.8 6.0 28.6 18.7 -48.7 -42.4 -16.5

-60

-50

-40

-30

-20

-10

0

10

20

30

40

Av

erag

e C

han

ge

in N

et G

ener

atio

n(G

W-h

rs p

er n

mo

nth

)

Calendar Month of Year

Net Energy Generation Compared to Baseline

20% UF 30% UF 40% UF 50% UF 60% UF

Figure X‐2. Change in Average Monthly Hydropower Generation Across 82 Years of Simulation Associated with the LSJR Flow Alternatives When Compared to Baseline




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X.4 Overview of the Transmission System in Central California

Thefollowingisabriefoverviewofthetransmissionsystemsandthebalancingauthoritiesinwhichthethreehydropowerplants,NewMelones,NewDonPedro,andNewExchequerarelocated.2ThebalancingauthoritiesarelistedinTableX‐4anddiscussedinthesectionsbelow.ThisinformationisdiscussedtoprovidecontextforthecapacityreductioncalculationandpowerflowanalysisdiscussedinSectionsX.5andX.6.

Table X‐4. Balancing Authority of Power Plants Under Study

PowerPlant BalancingAuthority

NewExchequer CaliforniaIndependentSystemOperator(CAISO)

NewMelones SacramentoMunicipalUtilityDistrict(SMUD)

NewDonPedro TurlockIrrigationDistrict(TID—68%)andSMUD—32%

Source:SNLFinancialLC.DistributedunderlicensefromSNLNote:DonPedroHydroPowerPlantisjointlyownedbyTIDandModestoIrrigationDistrict(MID).SMUDperformstheBalancingAuthorityfunctionforMID’sportionoftheplantwhileTIDisthebalancingauthorityforitsportion.

X.4.1 California Independent System Operator

TheCaliforniaPublicUtilitiesCommission(CPUC)adoptedtheResourceAdequacy(RA)programin2004withthetwinobjectivesof(i)providingsufficientresourcestotheCaliforniaIndependentSystemOpera(CAISO)toensurethesafeandreliableoperationofthegridinrealtime,and(ii)provideappropriateincentivesforthesitingandconstructionofnewresourcesneededforreliabilityinthefuture(CaliforniaPublicUtilitiesCommission2011).AspartoftheRAprogram,eachLoadServingEntity(LSE)isrequiredtoprocureenoughresourcestomeet100%ofitstotalforecastloadplusa15%reserve.Inaddition,eachLSEisrequiredtofilewiththeCommissiondemonstratingprocurementofsufficientLocalRAresourcestomeettheirRAobligationsintransmissionconstrainedLocalAreas.EachyearCAISOperformstheLocalCapacityTechnical(LCT)Studytoidentifylocalcapacityrequirementswithinitsterritory.TheresultsofthisstudyareprovidedtotheCPUCforconsiderationinitsRAprogram.TheseresultsarealsobeusedbytheCAISOforidentifyingtheminimumquantityoflocalcapacitynecessarytomeettheNorthAmericanElectricReliabilityCorporation(NERC)reliabilitycriteriausedintheLCTStudy(CaliforniaIndependentSystemOperator2010).

TheLCTstudyidentifiestheLocalCapacityRequirement(LCR)undernormalandcontingencysystemconditions.ThethreesystemconditionsunderwhichLCRisevaluatedaregivenbelow:

CategoryA:NoContingencies

CategoryB:Lossofasingleelement(N‐1)

2Entitiesresponsibleformaintainingload‐generationbalanceintheirareaandsupportingthefrequencyoftheinterconnectedsystem.




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CategoryC:CategoryBcontingencyfollowedbyanotherCategoryBcontingencybutwithtimebetweenthetwotoallowoperatingpersonneltomakeanyreasonableandfeasibleadjustmentstothesystemtoprepareforthesecondCategoryBcontingency.

ForanygivenareaorsubareatherequirementforCategoryA,BandCarecomparedandthemoststringentonewilldictatethatarea’sLCRrequirement.FigureX‐3showsthe10LCRareasinCAISOforstudyyear2012.TheNewExchequerhydropowerplantliesintheGreaterFresnoLCRarea.GreaterFresnoLCRareaisthereforediscussedbrieflybelow.

Figure X‐3. Local Capacity Area Map of CAISO (Source: 2012 Local Capacity Technical Analysis, CAISO)




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Locational Capacity Requirement in Greater Fresno Area

TableX‐5showsthehistoricalLCR,peakload,andtotaldependablelocalareagenerationfortheGreaterFresnoarea.TheexhibitalsoshowstheLCRasapercentageofthetotaldependablelocalgeneration.Forexample,in2011,theLCRinGreaterFresnowas2,448MWwhilethepeakloadstoodat3,306MW,or,theLCRwas74%ofthepeakload.Atthesametime,thetotaldependablegenerationstoodat2,919MWwhichmeantthattheLCRwas84%ofthetotaldependablegeneration.Inotherwords,in2011GreaterFresnohadsufficientlocalresourcesavailabletomeetitsLCRrequirements.

Table X‐5. Local Capacity Needs vs. Peak Load and Local Area Generation for Greater Fresno Area

Year LCR(MW)PeakLoad(MW)

LCRas%ofPeakLoad

DependableLocalAreaGeneration(MW)

LCRas%ofTotalAreaGeneration

2006 2837 3117 91% 2651 107%

2007 2219 3154 70% 2912 76%

2008 2382 3260 73% 2991 80%

2009 2680 3381 79% 2829 95%

2010 2640 3377 78% 2941 90%

2011 2448 3306 74% 2919 84%

Source:Year2006to2011LocalCapacityTechnicalAnalysis,CAISO

CAISOalsoidentifiessub‐areaswithinthelargerLCRarea.Itispossiblethatthesub‐areasareresourcedeficientalthoughthelargerareamayhavesufficientresourcestomeetitsLCRrequirement.For2011,GreaterFresnoLCRareawasdividedintothreesub‐areas:Wilson,Herndon,andHenrietta.WhileWilsonandHerndonhadsufficientresourcestomeettheirLCRrequirement,Henriettashowedadeficiencyof4MWunderCategoryCcontingencyconditions.

TheWilsonsub‐arealargelydefinedconstraintsonimportingpowerintoFresno.Foryear2011,themostcriticalcontingencywasthelossoftheMelones—Wilson230kilovolt(kV)lineoverlappedwithoneoftheHelmsunitsoutofservice.TheworstoverloadunderthiscontingencyoccurredontheWarnerville‐Wilson230kVlineandestablishedaLCRof1,997.AnumberofgenerationunitsintheWilsonsub‐areawerefoundtobecapableofreducingtheoverloadonthislinewithvaryingdegreeofeffectiveness.Exchequerwasoneoftheseunits.

In2011,themostcriticalcontingencyfortheHerndonsub‐areawasthelossoftheHerndon#1230/115kVtransformeroverlappedwithKerckhoffIIgeneratoroutofservice,whichestablishedaLCRof1132MWin2011astheminimumgenerationcapacitynecessaryforreliableloadservingcapabilitywithinthissub‐area.

IntheHenriettasub‐area,thetwomostcriticalcontingencies,(i)lossofHenrietta230/70kVtransformerbank#4andGWFPowerunit,and(ii)lossofHenrietta230/70kVtransformerbank#4andoneoftheHenrietta‐GWFHenrietta70kVline,togetherestablishedalocalcapacityneedof57MWin2011astheminimumcapacitynecessaryforreliableloadservingcapabilitywithinthissub‐area.However,underthecategoryCcontingency,theLCRinHenriettaexceededthetotaldependablegenerationby4MWfortheyear2011implyingthatloadwouldneedtobeshedifthemostcriticalcategoryCcontingencyweretohappen.





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Transmission Expansion Plans and New Generator Additions

Intheboardapproved2010/2011transmissionplan,CAISOidentifiedanumberoftransmissionupgradesthatareneededintheGreaterFresnoareatomaintainsystemreliabilitybetween2011and2020.PG&Eproposedanumberofprojectstomitigatethesereliabilityviolationsduringthe2010requestwindow(CAISO2011).AlistofmajorPG&EprojectsthatwerefoundtobeneededbyCAISOformaintainssystemreliabilityintheGreaterFresnoAreaisgiveninTableX‐6.

Table X‐6. Reliability Based Transmission Projects in Greater Fresno

TransmissionProjectName Purpose In‐ServiceDate

KerckhoffPH#2—Oakhurst115kVLineProject

RelieveexpectedoverloadontheCorsgoldToOakhurst115KVlineunder2016‐2020systemconditions

2015

Wilson115kVAreaReinforcementProject

Relieveanumberofreliabilityviolationsexpectedunder2015‐2020systemconditions

2015

OroLoma70kVAreaReinforcementProject

RelieveOverloadsonlinesandtransformersintheOroLomaAreaunder2015‐2020systemconditions

2015

Source:CAISOandPG&E

AnumberofgeneratorsarealsoseekinginterconnectionintheGreaterFresnoAreabetweennowand2014.TableX‐7providesalistofselectedprojectsthatareatanadvancedstageoftheinterconnectionprocess.

Table X‐7. Expected New Generator Additions in Greater Fresno

FuelType InterconnectingSub‐Station Capacity ExpectedIn‐ServiceDate County

NaturalGas GatesSubstation230kVbus 600 6/1/2014 KINGS

NaturalGas HenriettaSubstation70kVbus 150 5/31/2013 KINGS

Solar JacobsCornerSubstation70kVbus

20 4/2/2012 KINGS


20 5/1/2012 KINGS


20 6/1/2012 KINGS

Solar ArcoSubstation70kVbus 20 6/30/2013 KINGS

Solar Corcoran‐Kingsburg#1115kVline

20 8/1/2013 KINGS

Solar Henrietta‐Guernsey70kV 20 12/31/2011 KINGS

Solar OroLoma115kV 20 12/25/2011 MERCED

Solar Dairyland—Legrand115kV 20 1/1/2012 MADERA

Solar Henrietta‐TulareLake70kV 20 12/31/2012 KINGS

Solar HenriettaSub70kVBus 20 12/31/2012 KINGS

Solar Arco70kV 20 1/15/2013 KINGS

Source:CAISOGeneratorInterconnectionQueue





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X.4.2 Sacramento Municipal Utility District

TheSacramentoMunicipalUtilityDistrict(SMUD),establishedin1946,isthenation’ssixthlargestcommunity‐ownedelectricutilityintermsofcustomersserved(approximately590,000)andcoversa900squaremileareathatincludesSacramentoCountyandasmallportionofPlacerCounty.TheserviceterritoryofSMUDisshowninFigureX‐4.

Figure X‐4. SMUD Service Territory in California (Source: California Energy Commission 2012)





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Aspartofthebiennialresourceadequacyandresourceplanassessmentsforpublicallyownedutilities,CaliforniaEnergyCommission(Commission)publisheditsbiennialreportinNovember2009detailingtheneedandavailabilityofgenerationresourcestomeetthefutureloadandplanningreservemarginrequirementswithintheterritoryofpublicallyownedutilities(CaliforniaEnergyCommission2009).ThereportindicatesthatSMUDwillbeabletomeetitsresourceadequacyrequirementsinthenearterm;however,in2018SMUD’sgenerationresourcesmaynotbesufficienttomeetitsloadandplanningreservemarginobligations.Thedeficiencyexpectedin2018isestimatedat347MW,buttheCommissiondoesnotexpectthistobeanissueduetotheleadtimeavailabletoresolvetheexpecteddeficiency.


SMUDalsocarriesoutanannual10yeartransmissionplanningprocesstoensurethatNERCandWesternElectricityCoordinatingCouncil(WECC)ReliabilityStandardsaremeteachyearofthetenyearplanninghorizon.Majorprojectsthathavebeenproposedin2010transmissionplanforthe2016to2020timeperiodarelistedinTableX‐8(SacramentoMunicipalUtilityDistrict2010).TheseprojectsareexpectedtoimprovethereliabilityofSMUD’selectricsystemaswellasincreaseitsloadservingcapability.

Table X‐8. Proposed Transmission Upgrades in SMUD from 2016–2020

ProjectName ProjectDescriptionExpectedIn‐ServiceDate

Franklin230/69kVSubstation NewDistributionSubstation May31,2016

O’Banion‐Sutter230kVDoubleCircuitTransmissionLineConversion

AddcircuitbreakerstoconvertO’Banion‐Sutterlinetodoublecircuittowerline

May31,2016

Installationof200MVArtransmissioncapacitors

Installtransmissioncapacitors May31,2019

400MWIowaHillPumpStorageFacility NewHydropowerPlantintheUpperAmericanRiverProject

May31,2020

Lake‐Folsom230kVandFolsom‐Orangevale230kVReconductoring

ReconductortheLake‐Folsom–Orangevale230kVLines

May31,2020

TheNewMelonesPowerPlantphysicallyresidesintheCAISOBalancingAuthorityArea.However,SierraNevadaRegion(SNR)3,SMUDandtheCAISOoperateNewMelonesasapseudo‐tiegenerationexportfromCAISOintotheSMUDBalancingAuthorityArea(WesternAreaPowerAdministration2010).ThisarrangementimpliesthatNewMelonesiselectronicallyandoperationallyincludedaspartoftheSMUDBalancingAuthorityArea.ForpurposesofQualifyingCapacity,SNRhasdesignatedtheNewMelonesPowerPlantaspartoftheCentralValleyProject(CVP)resourceintheSMUDBalancingAuthorityArea.ThelocationofNewMelonesisalsoshowninFigureX‐5.

3Western,SierraNevadaRegion(SNR),isacertifiedschedulingcoordinatorandanLSEforcertainloadsandresourceswithintheCAISOBalancingAuthorityArea.





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Figure X‐5. Location of New Melones and Proposed 400 MW Iowa Hill Hydro Plant (Source: Ventyx)

X.4.3 Turlock Irrigation District

TheTurlockIrrigationDistrict(TID)operatesasaBalancingAuthoritylocatedbetweenSacramentoandFresnoinCalifornia’scentralvalley(CaliforniaTransmissionPlanningGroup).Westley230kVandOakdale115kVlinesprovideimportaccessforTID.TheTIDBAincorporatesall662squaremilesofTID’selectricserviceterritory(FigureX‐6)aswellasa115kVloopwiththree115kVsubstationsownedbytheMercedIrrigationDistrict(MercedID).TheMercedIDfacilitiesareinterconnectedtoTID’sAugustandTuolumne115kVsubstationsandarelocatedjustsouthofTID’sserviceterritoryandnorthoftheCityofMerced.TIDisthemajorityownerandoperatingpartneroftheDonPedroHydroelectricProjectwith68.46%ownershipandMIDhasa31.54%ownership.





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Figure X‐6. Turlock irrigation District Service Area (Source: California Transmission Planning Group 2011)


TIDiscurrentlyworkingontwomajorgenerationprojects.Oneofthese,theAlmond2PowerPlanthasbeenapprovedbytheBoardofDirectorswhiletheRedMountainBarPumpedStoragePowerPlantprojectisinthestudyphase.KeycharacteristicsandbenefitsoftheseprojectsaresummarizedinTableX‐9(TurlockIrrigationDistrict2011).

Table X‐9. Summary of Almond 2 and Red Mountain Bar Power Plants

ProjectName KeyCharacteristics ProjectObjective(s)ExpectedIn‐ServiceDate

Almond2PowerPlant(174MW)

Natural‐gasfiredsimple‐cyclepeakingpowergenerationfacility.LocatedinStanislauscounty.

MeetreliabilityobligationsasaBalancingAuthority.Improvetheeconomy,efficiency,andflexibilityoftheDistrict'selectricalsystemincludingtheintegrationofintermittentrenewableresources.

2012

RedMountainBarPumpedStorage(880MW)

JointprojectwithMID.LocatednearSonorainTuolumneCounty.

ProposestousetheexistingDonPedroReservoirasthelowerpoolfromwhichtopumpwatertoanewlyconstructedupperreservoir.Improvereliabilityoftheelectricgridbyquicklyreplacingsolarandwindgeneratedelectricitythatcouldvarysignificantlywithweatherconditions.

StudyPhase





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X.5 Capacity Reduction Calculation and Power Flow Analysis

TheimplementationofoneofthealternativescouldincreasethehydropowergenerationatNewMelones,NewDonPedroandNewExchequerinthemonthsofFebruarythroughJunebecauseadditionalwaterwouldbereleasedfromthereservoirsduringthattimetomeettheunimpairedflowobjectivealternative.ButitcouldreducethehydropowergenerationduringthesummermonthsofJulythroughSeptemberbecauselesswaterwouldbestoredduringthosemonthsinthereservoirsasaresultofbeingreleasedearlierintheyear(e.g.,FebruarythroughJune).SincetheCaliforniagridismoststressedduringsummermonthsduetohighdemandforelectricity,areductioninhydropowercapacityduringthistimehasthepotentialofstressingthegridevenfurther.

ToassesstheimpactofdifferentunimpairedflowalternativesonCalifornia’selectricgrid,theoperationoftheelectricgridunderpeaksummerdemandconditionswassimulated.First,theoperationofthegridassumingthehydropowercapacityreductionswouldnotoccurwasexamined.Next,theanalysisisrepeated,butassumedthehydropowercapacityreductionswereimplemented.Bycomparingtheresultsofthetwosetsofanalyses,theeffectoftheProjectontheelectricgridaredetermined.The20%unimpairedflowalternativewouldleadtonegligiblepowercapacityreductionforthethreehydropowerplants,whilethetotaloutputofthethreeplantswouldreduceby5%and8%under40%and60%unimpairedflowalternatives,respectively.However,thecapacityreductionsunderthe40%and60%unimpairedflowalternativesdonotresultinreliabilityviolationsthatcouldnotberelievedbysimplegenerationre‐dispatch.Themethodologyandmodelsaredescribedindetailbelow.

X.5.1 Capacity Reduction Calculation Methodology

The‘WaterSupplyEffectsModel—SJRTributaries’developedbyStateWaterResourceControlBoardofCaliforniawasusedtoestimatetheimpactof20%,40%,and60%unimpairedflowalternativesonpowergenerationofthethreeaffectedhydropowerplants.Itsimulatedtheeffectsoftheunimpairedflowalternativesonmonthlyflowratesandreservoirstorageforeachmonthofthe82yearperiodbetweenwateryears1922and2003.Themodelalsotranslatedreservoirstorageintoavailableheadforgeneratingelectricpower.Exhibit3‐1showsthehead,whichisthedifferencebetweenthemaximumelevationandtail‐waterelevation,andthecorrespondingmaximumcapacityforNewMelones,DonPedroandExchequer.SincethepowergenerationcapacityinMWisdirectlyproportionaltotheavailablehead,themonthlycapacity(MW)ofaffectedhydropowerplantsundereachunimpairedflowalternativewasestimatedbyproratingthemaximumplantcapacitybytheavailableheadestimatedfromthemodel.Forexample,ifforanymonth,themodelestimatedavailableheadforNewMeloneswas500ft,thenusingtheheadandmaximumcapacityvaluesfromTableX‐10,itscapacityforthatmonthwasestimatedat256MW(300MWX[500feet/585feet]).





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Table X‐10. Existing Maximum Capacity

PowerPlantsMaximumElevation(Feet)

Tail‐waterElevation(Feet) Head(Feet)

MaximumCapacity(MW)

NewMelones 1,088 503 585 300

DonPedro 830 310 520 203

Exchequer 867 400 467 95

TheimpactofthereducedcapacityofthethreehydropowerfacilitiesonthereliabilityoftheCaliforniagridundersummersystemconditionswasevaluated.California’selectricgridismoststressedduringthesummermonthsofJunetoAugust,withpeakdemandtypicallyoccurringinthemonthofJuly.Therefore,foreachmonthofJulyduringthe82yearperiod,thetotalMWcapacityofthethreefacilitieswascalculated,separatelyforbaseline,20%,40%,and60%unimpairedflowalternatives.4Next,thepercentagechangeintotalMWcapacityfromthebaselinewasdeterminedforthethreeunimpairedflowalternatives,andthemaximumpercentagereductionwasselectedformodellingthethreehydropowerplantsinthepowerflow.ThepercentagechangeincapacityfrombaselinecapacityforeachJulymonthbetween1922and2003isshowninFiguresX‐7,X‐8,andX‐9,forthe20%,40%,and60%unimpairedflowalternativesrespectively.NegativevaluesindicateareductioninMWcapacitycomparedtobaseline.Theminimumnegativepercentagechange,ormaximumreductionincapacity,forthe20%unimpairedflowalternativeisnegligible.However,themaximumreductionincapacityis5%and8%for40%and60%unimpairedflowalternativesrespectively.Therefore,powerflowanalysisisconductedfor40%and60%unimpairedflowalternativesonly.

Figure X‐7. Percentage Change in Power Capacity from Baseline for July under 20% Unimpaired Flow Alternative

4Baselinereferstotheflowscenarioasitexiststodaywithoutimplementationoftheunimpairedflowalternatives.





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X.5.2 Power Flow Assessment Methodology

AccordingtoNERC,reliabilityofanelectricsystemcomprisesoftwointerrelatedelements—adequacyandsecurity.Adequacyreferstotheamountofcapacityresourcesrequiredtomeetpeakdemandandsecurityreferstotheabilityofthesystemtowithstandcontingenciesorothersystemdisturbances,suchasthelossofageneratingunitortransmissionline.Bothofthesereliabilityaspectscanbegaugedfromsub‐stationvoltagesandtransmissionlineloadings.AsteadystatepowerflowassessmentoftheCaliforniagridwasperformedtocheckifreductioninhydropowercapacitiesofthethreedamswouldadverselyimpactthegridreliabilityasdefinedbyNERC.5

Thepowerflowassessmentwasamulti‐stepprocess.Thesestepsarelistedbelowanddetailedfurtherbelow.

PrepareaBaseCase(Californiaelectricgridmodelundernormalandcontingencyconditionsassumingthefacilityisinnormaloperation).6

PrepareseparateChangeCases(Californiaelectricgridmodelundernormalandcontingencyconditionsassumingreducedoutputofthefacilities)for40%and60%unimpairedflowalternatives.7

Developcriteriaforselectionofgeneratorandtransmissioncontingencies.

Developcriteriaforvoltageandthermallimits.

Selecttheareaswheretransmissionline/transformerloadingsandsub‐stationvoltageswouldbemonitored.

Base and Change Case Development

TheBaseCasewasthelatest2011heavysummer(highsummerpowerdemand)electricgridmodeloftheentireWesternInterconnectiondevelopedbyWECC.ThiscasehadadetailedrepresentationoftheCaliforniaelectricgrid.

Usingthecapacityreductionscalculatedearlier,twoChangeCasesweredevelopedforthehydropowergenerationfacilities.OneChangeCasewaspreparedforthe40%unimpairedflowalternativewiththeoutputofeachhydropowerfacilityreducedby5%ofitsvalueintheBaseCase.SecondChangeCasewasforthe60%unimpairedflowalternativewherethehydropowerfacilitiesweregenerating8%lessthantheiroutputintheBaseCase.TableX‐11summarizesthemodeledcases.

5 Power flow software models simulate the operation of the grid and calculate substation voltages and powerflowingontransmissionlines/transformers.Thesecalculatedvaluescanthenbecomparedwithstandardvoltagelimitsandline/transformerthermalratingstoidentifyviolations.6 Undernormalconditions,allgenerationandtransmissionfacilitiesareassumedtobeinservice.Contingencyconditionsrefertotheunplannedoutageofpowersystemequipment. 7 Undernormalconditions,allgenerationandtransmissionfacilitiesareassumedtobeinservice.Contingencyconditionsrefertotheunplannedoutageofpowersystemequipment.





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Table X‐11. List of Cases Modeled

CaseDescription OutputofHydroUnitsa NormalConditions ContingencyConditions

BaseCase Normal √ √

ChangeCase—40%UnimpairedFlowCase

Reducedby5% √ √

ChangeCase—60%UnimpairedFlowCase

Reducedby8%√ √

a. UnitsrefertoNewMelones,NewExchequer,andNewDonPedroFacilities

Contingency Selection Criteria

BaseandChangeCaseswereanalyzedforsinglecontingencyoutageofallthetransmissionfacilitiesrated115kVandabovewithinthebalancingauthorityofthegeneratingfacilitiesand230kVandaboveintheneighboringbalancingauthoritiesorregions.8Singlecontingencyoutageofallgeneratorsrated100MWorabove,bothwithinthebalancingauthorityofthefacilitiesandintheneighboringbalancingauthorities,werealsousedtoanalyzetheperformanceofelectricgridunderBaseandChangeCases.Inthepowerflow,allthefacilitiesareshowntobeapartofPG&EareawithSouthernCaliforniaEdison,NorthwestandSierraasneighboringregions.

Voltage and Transmission Line Limits

ThetransmissionlinelimitsusedinthestudywerethenormalandLong‐TermEmergency(LTE)ratings.Undernormalandcontingencyconditionstransmissionlineflowsareexpectedtoremainwithinthenormalandlong‐termemergencyratings,respectively.Similarly,voltagelimitswereestablishedrelativetothenominalvoltages.Undernormalconditionssystemoperatorsregulatenodalvoltageswithin±5%oftheirnominalvalues.Undercontingencyconditions,thislimitisrelaxedto±10%ofthenominalvalue.

Criteria for Monitoring Transmission Elements

WithintheBalancingAuthorityofthefacilities,thefollowingcriteriaformonitoringtransmissionline/transformerloadingsandsub‐stationvoltages:9

Alltransmissionlineswithnominalvoltagegreaterthan115KV.

Alltransformerswithbothnominalprimaryandsecondaryvoltagegreaterthan115KV.

IntheneighboringBalancingAuthorities,thefollowingcriteriaformonitoringtransmission/transformerloadingsandsub‐stationvoltages:

Alltransmissionlineswithnominalvoltagegreaterthan230KV.

Alltransformerswithbothprimaryandsecondaryvoltagegreaterthan230KV.

8Inthecontextofthisanalysis,neighboringregionorneighboringBalancingAuthorityisdefinedasaregionwhichhasadirecttransmissionlinkwiththeregioninwhichthefacilityislocated.9Theloadingofatransmissionlineortransformermeasuredasaratiooftheactualflowacrossthefacilityinamperesormega‐voltamperestotheratedvalueofcurrent.Inthisanalysis,onlythoselines/transformersarerecordedwhoseloadingexceeds90%oftheapplicablerating.





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TheWECCpathsinCalifornia(referredtoas“Interfaces”hereafter)werealsomonitored.ThesearelistedinTableX‐12.10

Table X‐12. WECC Paths Monitored

WECCPathNumber WECCPathName Location

15 Midway‐LosBanos BetweenCentralandSouthernCaliforniawithinthePG&EsystemandSouthofLosBanossubstation

24 PG&E‐Sierra BetweenNorthernCaliforniaandNevada

25 PacifiCorp/PG&E115kVInterconnection

SouthernOregon/NorthernCalifornia

26 Northern‐SouthernCalifornia BetweenPG&EandSouthernCaliforniaEdison

52 SilverPeak‐Control55kV SouthwesternNevada/CentralEasternCalifornia

60 Inyo‐Control115kVTie The115kVphaseshifterbetweenSCEandLDWP

66 COI BetweenOregonandnorthernCalifornia

76 AlturasProject betweennortheasternCaliforniaandwesternNevada

Source:WECCPathRatingCatalog

X.5.3 Power Flow Simulation Tools

TheGE®PositiveSequenceLoadFlow(PSLF)modelwasusedforthisanalysis.PSLFisidealforsimulatingthetransferoflargeblocksofpoweracrossatransmissiongridorforimportingorexportingpowertoneighboringsystems.Themodelcanbeusedtoperformcomprehensiveandaccurateloadflow,dynamicsimulation,shortcircuitandcontingencyanalysis,andsystemfaultstudies.Usingthistool,engineerscanalsoanalyzetransferlimitswhileperformingeconomicdispatch.PSLFcansimulatelarge‐scalepowersystemsofupto80,000buses.11

X.5.4 Assumptions for Facilities

TheassumptionsforthegenerationfacilitycharacteristicsandinterconnectionsubstationsareshowninTableX‐13.Otherassumptions,includingtransmissionfacilitynormalandlong‐termemergencyratings,transmissionlineimpedances,andsubstationnominalvoltagesweredefinedintheWECCpowerflowcasesusedfortheassessment.

Table X‐13. Unit Assumptions for the Engineering Assessment

UnitName UnitBusNumberinWECCPowerFlowCase InterconnectionVoltage(kV)

NewMelones 37561,37562 230

DonPedro 38550,38552,38554 69

Exchequer 34306 115

Source:WECCPowerFlowCaseandSNL.

10WECCPathsrefertoeitheranindividualtransmissionlineoracombinationofparalleltransmissionlinesonwhichthetotalpowerflowshouldnotexceedacertainvalueformaintainsystemreliability.11InPowerFlowmodelinga“bus”representsallthesub‐stationequipmentthatisatthesamevoltagelevelandisconnectedtogether.





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X.5.5 Results and Conclusions

Thousandsoftransmissionlines,nodalvoltages,andinterfacesundernormalsystemconditionsandcontingencyoutagesofhundredsoftransmissionlinesandgeneratorsweremonitoredundertheBaseandChangecases.TheBaseCasesub‐stationvoltagesandline/transformerloadingswerethencomparedwiththoseoftheChangeCases.Ifthecomparisonshowedthatsub‐stationvoltagesortransmissionline/transformerloadingsarewithinlimitsintheBaseCase,butoutsidethelimitsintheChangeCases(i.e.,the5%and10%identifiedinSection3.2.2),theunimpairedflowalternativescouldbeconsideredtohaveanadverseimpactonthereliabilityofCalifornia’selectricgrid.Resultsofthepowerflowassessmentarediscussedbelow.

Comparison between Base and Change Case Line/Transformer Loadings under Normal Conditions

Undernormaloperatingconditions,notransmissionlineortransformerwasfoundthatviolatedtheratingsexclusivelyintheChangeCases.

Comparison between Base and Change Case Line/Transformer Loadings under Line/Transformer Contingencies

WhenBaseandChangeCaseswerestudiedundertransmissionlineandtransformercontingencies,noline/transformerlimitviolationwasfoundfortheBaseCaseandthe40%unimpairedflowalternative.However,forthe60%unimpairedflowalternative,the230kVlinebetween“Borden”and“Gregg”substationsshowedaminorviolationundertheoutageofthe230kVlinebetween“Gregg”and“Storey”substations.Thisviolationwaseasilymitigatedthroughare‐dispatchofthethree“Helms”generatorunits(HelmsUnit1,2,and3).Thenewloadingofthemonitoredelementafterthisre‐dispatchwas99.81%.

Comparison between Base and Change Case Line/Transformer Loadings under Generator Contingencies

Undergeneratorcontingencies,noline/transformerlimitviolationswerefoundthatcouldbeexclusivelyattributedtothe40%and60%unimpairedflowalternatives.

Comparison between Base and Change Case Substation Voltages under Normal and Line/Transformer/Generator Contingencies

NovoltageviolationswerefoundthatcouldbeexclusivelyattributedtothereducedhydropowercapacityintheChangeCases.

Comparison between Base and Change Case Interface Loadings under Normal and Line/Transformer/Generator Contingencies

NoInterfacelimitviolationswerefoundthatcouldbeexclusivelyattributedtothereducedhydropowercapacityintheChangeCases.

Inconclusion,anengineeringassessmentwasperformedtodetermineifimplementationoftheunimpairedflowalternativesonthetributaries,andtheresultingchangeinhydropowergenerationatthehydropowerplants,wouldadverselyimpactthereliabilityofCalifornia’selectricgrid.





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Usingthe‘WaterSupplyEffectsModel—SJRTributaries’itwasdeterminedthe20%unimpairedflowalternativewouldleadtonegligiblepowercapacityreductionforthethreehydropowerplants,whilethetotaloutputofthethreeplantswouldreduceby5%and8%under40%and60%unimpairedflowalternatives,respectively.Thecapacityreductionsfor40%and60%unimpairedflowalternativeswerethenappliedtothesummerelectricgridmodeloftheWesternInterconnectionandsystemperformancewasevaluatedunderbothnormalandsinglecontingencyconditions.Therewerenoreliabilityviolationsthatcouldbeattributedtotheunimpairedflowalternatives,orwhichcouldnotberelievedbysimplegenerationre‐dispatch.

Basedontheresultsofthisstudy,theSanJoaquinRiverFlowObjectivesprojectwouldnotadverselyimpactthereliabilityofCalifornia’selectricgrid.

X.6 References CaliforniaEnergyCommission.2009.AnAssessmentofResourceAdequacyandResourcePlansof

PubliclyOwnedUtilitiesinCalifornia”,CaliforniaEnergyCommission,November.Availableat:<http://www.energy.ca.gov/2009publications/CEC‐200‐2009‐019/CEC‐200‐2009‐019.PDF>Accessed:November2011.

CaliforniaEnergyCommission.2012.CaliforniaPowerPlantDatabase(ExcelFile)at:.http://energyalmanac.ca.gov/electricity/index.html#table.AccessedFebruary2012.

CaliforniaIndependentSystemOperator.2010.2011LocalCapacityTechnicalStudy‐FinalReportandStudyResults.April.Availableat:http://www.caiso.com/planning/Pages/ReliabilityRequirements/LocalCapacityRequirements.aspx.Accessed:November2011.

CAISO.2011.2010‐2011TransmissionPlan.May18.Availableat:<http://www.caiso.com/2b88/2b8872c95ce10.pdf>.Accessed:November2011.

CaliforniaPublicUtilitiesCommission.2011.Availableat:http://www.cpuc.ca.gov.Accessed:November2011.

CaliforniaTransmissionPlanningGroup.2011.Availableat:<http://www.ctpg.us/images/stories/ctpg‐plan‐development/2011/07‐Jul/2011‐07‐18_TID_min_gen_req.pdf.>.Accessed:November2011.

Medellin‐Azuara,J.2011.Personalcommunication.UniversityofCalifornia,Davis,CA

SacramentoMunicipalUtilityDistrict(SMUD).2010.Ten‐YearTransmissionAssessmentPlan.December22.Availableat:<http://westconnect.com/filestorage/2010_SMUD_10YearPlan_Final.pdf>Accessed:November2011.

TurlockIrrigationDistrict.2011.Availableat:<http://www.tid.org/power/projects.>Accessed:November2011.

VentyxVelocitySuite.Licensedmappingdatabase.





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WesternAreaPowerAdministration(Western).2010.FinalResourceAdequacy(RA)Plan,FederalRegister72FR41317;SMUDCommentstoCAISOMarch10,2010DynamicTransferStrawProposal.Availableat:<http://www.caiso.com/276c/276cbecb37360.pdf.>Accessed:November2011.

state water control board environmental protection agency ......hydro‐electric power plant name...

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