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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 February 2012
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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
State Water Resources Control Board California Environmental Protection Agency
DRAFT Hydropower and Electric Grid Analysis of Lower San Joaquin River Flow Alternatives
DRAFT Evaluation of San Joaquin River Flow and Southern Delta Water Quality Objectives and Implementation
X‐3 February 2012
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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.
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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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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DRAFT Hydropower and Electric Grid Analysis of Lower San Joaquin River Flow Alternatives
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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
UpstreamCapacity 390.52 64.8% NA
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
UpstreamCapacity 0.00 0.0% NA
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
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)
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
Solar JacobsCornerSubstation70kVbus
20 5/1/2012 KINGS
Solar JacobsCornerSubstation70kVbus
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.
Transmission Expansion Plans and New Generator Additions
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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X‐15 February 2012
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Figure X‐6. Turlock irrigation District Service Area (Source: California Transmission Planning Group 2011)
Transmission Expansion Plans and New Generator Additions
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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Figure X‐8. Percentage Change in Power Capacity from Baseline for July under 40% Unimpaired Flow Alternative
Figure X‐9. Percentage Change in Power Capacity from Baseline for July under 60% Unimpaired Flow Alternative
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X‐19 February 2012
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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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X‐21 February 2012
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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‐22 February 2012
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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.
State Water Resources Control Board California Environmental Protection Agency
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X‐24 February 2012
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WesternAreaPowerAdministration(Western).2010.FinalResourceAdequacy(RA)Plan,FederalRegister72FR41317;SMUDCommentstoCAISOMarch10,2010DynamicTransferStrawProposal.Availableat:<http://www.caiso.com/276c/276cbecb37360.pdf.>Accessed:November2011.
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