20180501PacifiCorp Updated 2017 IRP.pdf

Y ROCKY MOUNTAIN
HP,}Y,E,^"N"-,
May 1,2018
VA OWRNIGHT DELIWRY
REC T IVEI)
2010 HfiY - l lH 9: 0?
iUiiii* irUBLlC
t.lT I l.lTl [$ r]OMM ISSION
1407 W. North Temple, Suite 330
Salt Lake City, Utah 84116
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington
Boise, ID 83702
RE: Case No. PAC-E-17-03
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
FOR APPROVAL OF THE 2017 INTEGRATED RESOURCE PLAI\
Dear Ms. Hanian:
Please find enclosed an original and seven (7) copies of PacifiCorp's 20lT lntegrated Resource
Plan ("IRP") Update. A copy of the report is also available electronically on PacifiCorp's website,
at www.pacificom.com. PacifiCorp is also providing data discs with this filing that support and
provide additional details for analysis described in the document. Disc I is public, and Disc 2
contains confidential information. Confidential information in the 2017 IRP Update will be
provided to parties who have signed a non-disclosure agreement in the referenced case. Rocky
Mountain Power requests that interested parties contact the state manager listed below for a copy
of the non-disclosure agreement that must be executed and submitted prior to obtaining a copy of
the confi dential information.
PacifiCorp's 2017 IRP Update summarizes updates since the 2017 IRP was filed. Highlights are
as follows.
l) An updated resource portfolio reflecting updates to load forecast, market prices and other
model inputs;
2) The status of the 8Y2020 projects since IRP was filed;
3) A description of resource planning, procurement activities; and
4) A status update on action plan items from the 2017 IRP.
AII formal correspondence and regarding this filing should be addressed to:
Ted Weston
Rocky Mountain Power
1407 W. North Temple, Suite 330
Salt Lake city, Utah 84116
Telephone : [phone]
Fax [phone]
Email : ted.weston@fracifi corp.com
Yvonne Hogle
Rocky Mountain Power
1407 W. North Temple, Suite 320
salt Lake city, Utah 84116
Telephone: (801 ) 220-4050
Fax: [phone]
Email : yvonne.hogle@Facifi corp.com
Idaho Public Utilities Commission
May 1,2018
Page2
Communications regarding discovery matters, including data requests issued to Rocky Mountain
Power, should be addressed to the following:
By E-mail (preferred):datarequest@pacifi corp.com
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah St., Suite 2000
Portland, OR97232
Informal inquiries may be directed to Shay LaBray at [phone] or Ted Weston at
[phone].
Very Truly Yours,
"^..D
Vice President, Regulation
Enclosures
cc Jim Yost, Idaho Governor's Office (without enclosures)
Benjamin J. Otto, Idaho Conservation League (without enclosures)
Mark Stokes, Idaho Power Company (without enclosures)
Terrie Carlock, Idaho Public Utilities Commission (with enclosures)
Matt Elam, Idaho Public Utilities Commission (with enclosures)
Randall Budge, Racine, Olson, Nye, Budge & Bailey (without enclosures)
Nancy Kelly, Western Resource Advocates (without enclosures)
7OI7 INTEGRATED
RESOURCE PLAN
UPDATE
May 1,2018
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PacrnCoRP
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This 2017 lntegroted Resource Plon Update is based upon the best available information ot the
time of preparotion. The IRP action plan will be implemented as described herein, but is subject
to change os new information becomes ovoiloble or as circumstonces change. lt is PocifiCorp's
intention to revisit and refresh the IRP action plan no less frequently than onnuolly. Any refreshed
IRP action plan will be submitted to the Stote Commissions for their informotion.
For more information, contact:
PacifiCorp
IRP Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
(s03) 813-s24s
irp@ pacificorp.com
http ://www. pacificorp. com
Cover Photos (Top to Bottom):
Wind Turbine: Marengo Wind Project
Solar: Pavant Solar Plant
Transmission: Sigurd to Red Butte Transmission Line
Demand-Side Management: Smart thermostat
Pacific Power wattsmart Business Customer Meeting
Thermol-Gas: Blundell-Geothermal Plont
PecrrConp 2017 IRP Upna'rn TABLE oF CoNTENTS
Tesrp oF CoNTENTS
TABLE OF CONTENTS I
INDEX OF TABLES tv
INDEX OF FIGURES ....... vl
CHAPTER 1 _ EXECUTIVE SUMMARY
201 7 IRP Upolrr HrcHlrcurs ..
Loao-aNo-REsouncE BRlaNc E
PREpERRSo PoRrrolro Upnars.
CHAPTER 2 - INTRODUCTION
CHAPTER 3 _ THE PLANNING ENVIRONMENT
FpneRal Polrcy Upoare ..
FoorntL Cuutrg Ca,qNco LTGISLATIzN ..
Now Souncr Pznronu,.qI'{co Srtt'to.anos ron Ctnnottt Eutsstows - Cmty Am Acr $ I I I (e)
C.tnsou Eutsstou Gutoottr,tts ron Extsrwc Souncts - Cmtn Am Acr $ I I I (o)
CLe.tN An Acr Crurrru.t PoLturn'trs - N.trtot't,nL Auarcur Am QutLtrr ST,tNDARDS
RrctoNtLHur
Mo nc u av .tu o H,azt noo u s A m P o uurt t'trs
Cotr Counusrtou RtstouALS...........
lVtrrn Qu,aurr Sr.tNDARDS......
2 0 I 5 Ttx Extet'toon Lsc t startoN................
2017 Ttx RrronuAcr.
Srarn Por-rcy Upoarp
CtLnowu
Orccow....
WtsruucroN.........,..
Ur,sH..........
GntrNaouss Gts Eutsstot t Poaronutttcr Srtuotnos
ENpRcy Garpwev TRaNsurss roN PRocRarra PIaNN rNc .
ENpncv INasar-aNcE MeRrEr
CHAPTER 4 _ LOAD-AND-RESOURCE BALANCE UPDATE
INrnooucuoN ............
Svsrsu CoNcroeNr Pear Loao Fonecasr.
WrNo aNo SolaR. Qualrrvmc Facrlrrv RpsouRcs UpoarEs
Upoateo Capacrrv Loao-aNp-RpsouRce Bar-aNce
Loao+trr o- Rtsounc t B.aLdr't c o C o upor,tqnrs.......................
Clptcrv Bat,qucr DrroaMINATtoN AND Rrsuns.....
Eurncy BlLtNcr Resutrs...............
1
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5
7
9
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23
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23
24
27
27
3l
48
PacrrrCoRp -2011 tRP UPDATE,Tn BLIt or, CoNlr,lN'ts
CHAPTER 5 _ MODELING AND ASSUMPTIONS UPDATE....
GENenal AssuvprroNS..............
INrttnou Rtres........
Dtscouyr FtcroR ..........
PnooucrroN Ttx Cnrorrs (PTC9.......
Fnowr Orrtco Tnqws.tcrtoNs (FOTs)
Srocntsruc Ptntuqrsns................
Ftoxtsts RESERVE Sruoy
NaruRar- Gas aNo Powsn MaRrer Pnrce UpoarEs .....
Ntruntt G.as lLqRKEr Pntcos
Powzn Mtnxer P nrc85...........
CaReoN Dtoxrpp Eurssror.r Polrcv
Suppr-v-Sros RpsouRcES ..............
INrna-HouR Drsparcs CRsorr
INrna-HouR DrsparcH Cnrorr FuRrnpR ExplonarroN
CHAPTER 6 _ PORTFOLIO DEVELOPMENT
INrRooucrroN
REcroNal HezE CasE DErrNrrroNS
RrcroNer- Heze CasE ANelysrs AND Rrsulrs....
Dtvr JoaNsroN UNr 3
Jru Bruocnn Uurcs I & 2..........
Ntucurow Utwr 3
CaoLLd UNr 4
CHAPTER 7 _ ENERGY VISION 2O2O UPDATE
INrnooucrroN ............
ENencv VrsroN 2020 PnorEcr Upoeres ................
MoooLtuc auo A ppnoac ru ]untvtny.................
CovnroN AssuuprroN Upoares
P ruco-pottcr 9ceu.tntos................
Fooentt T,ax Rtre ....
Pnooucuow T,ax Cnrorc Mooeuuc.
WrNIo RepowpRn tG ...............
ErrtatNcr lupnorcuoNTs AND Exrot'toto Pnoncr Lut..
P no oucru or't Tax C nrotrs au o C usro ugn B u't g r trs ..........
Upolroo D,qrl,4t'to ASSUMPTIINS
RopoworuNc RtsuLrs.....
Npw Wn{o auo TReNsMrssroN (CounmEo Pnorecrs).........
Wt u o P noL ecrs ............
2017R RFP..........
TnaNsutsstor't Pnottcrs ..
WvourNc CPCNs......
Pnooucrtoy T.au Crcorrs AND Cusrousn Bot'twrcs
...69
69
69
70
7l
73
75
78
5l
87
1l
87
87
88
89
90
9t
9t
92
93
98
98
98
99
t00
t00
PACII..ICoRP _ 2OI7 IRP UpOerE Taele or CoNrENrs
Uponoo Dar, lt'to ASSUMPTIqNS.......
Ntw Wtttro n'to Tnlt'tsutsstoN Rtsuns
CoNcr-usroN................
t0l
t02
105
CHAPTER 8 _ PORTFOLIO DEVELOPMENT 107
INrRooucrroN ............
20 I 7 IRP Upoare PRpppnRro Ponrrolto...
RrNpwasle PoRrrolro SraNoaRos (RPS)
CaneoN DroxrpE Ev tsstoNs
Pnomcrpo ENeRcv Mtx...........
SENsrrrvrrv SruorEs
Busrrur.ss P t,tt t Stt'tstrIVITy .........
F oors C aao x I Setrtstrtwrr.......................
107
107
l14
116
lt6
n7
117
lt9
CHAPTER 9 _ PORTFOLIO DEVELOPMENT t2t
INrRooucrroN t2t
t2t
123
t23
124
125
125
DsscRrprroN op TnaNSMISSIoN Sruptps.....
TRaNsrrrssroN Ivpacr AsssssveNr - SceNnnto I
TRRNsvrssroN Itrrpacr Asspssl,tpNr - SceNanto 2
TnaNsvrssrou IHapacr AssEssl,lENr - SceNnnlo 3
TnaNsvrssroN Iupecr AssEssvENr - SceNeRto 4
CoNclusroNS..............
CHAPTER 10 _ ACTION PLAN STATUS UPDATE 127
Rsr{pwes LE Rpsouncs AcrtoNs
TRaNsrrarssroN AcrtoNS ................
Fnv Manrsr PuRcuasE AcrtoNs
DsrrreNo SroE MaNaGEMENT (DSM) AcrtoNs
Coal RssouRcE AcrtoNs
...........127
...........130
........... 13 l
...........133
........... I 33
APPENDIX _ ADDITIONAL LOAD FORECAST DETAILS 137
Ixopx op TaBLES
Tasr-B 1.1 - CovrpARrsoN op 2017 IRP UpoarE wrrH 2017 IRP PRspBRReo Ponrpor-ro
(Mrcawarrs) .............
TaeI-p 3.1- ENEncy Gerpwav SecuENr IN-Senvrcp Darps
Teer-p 4.1 -QualrFyrNc Facrr-rry Wn'{o PPAs.........
Taslp 4.2 - QualrFyrNc Fecrlrry Solen PPAs
Taslr 4.3 - SuuvER Ppar Capacrry CoNrRreurrou Var-ues poR WNo aNo So1aR........
Taels 4.4 - Suvruen PBar - Sysreu Capacrry Loao aNo REsouRcs BalaNCE wrrHour
Reso uRc e A o o rrrous, 20 1 7 IRP Upoar n (20 I 8-2027 )
Tasr,B 4.5 - WrNreR Pear - Svsrpv Clpactrv Loao aNo ResouRcp BRIaNCE wrrHour
RrsouRcr AoorrroNs,2017 IRP Upoare (201 8-2027)
Taels 4.6 - SurraupR Prar - SysrEv Capacrry Loao aNo RrsouRcE BalaNCE wrrHour
RrsouRcE AoorrroNs,20lT IRP (2018-2027\ ................38
Taele 4.7 WnrEn PEar - Sysrpu CapRcrry Loao aNo RrsouRce BaI-RNCE wrrHour
RssouRcs AoorrroNs,20lT IRP (2018-2027) ................40
Tasr-B 4.8 - SuvrvrER PsRr- Svsrpu Cepacrry Loao aNo RpsouRcs BalaucE wrrHour
Rnsouncs AoorrroNs,20lT IRP UpoarE LESS 2017IRP (2018-2027) . .............................42
TaeI-p 4.9 - WmrpR Pear - Svsrpur Cepacrry Loao aNo REsouRcs Bar-aNCE wrrHour
RrsouRcE AporrroNs,20lT IRP UpoarE LESS 2017 IRP (2018-2027) .... ... ... ................44
Taslp 5.1 - Maxruuu Avarr-aeI-s FRoNr Orprce TRaNsacrroNS By MRRrcr Hus .......... ...... 52
TasLs 5.2 - Upoareo Cosr or Sor-aR ResouRcps (50 MWac SrNclE Axrs Tnacrmc) ........... 60
Taer-s 5.3 - Upoareo Cosr or Wnqo RrsouncEs ................. 6l
Taelp 5.4 - Upoarso Cosr or ENsncy SronacE, 2017 DortARS........... ................62
Taet-p 5.5 - Upoareo Suppry-Srop RssouRce TRelE................ ............ 63
TaeLp 5.6 - Upoareo Suppry-Srop RpsouRcs Tae1E................ ............64
Taslp 6.1 -RecroNar- Hazp Casp AssuMprroNs ................. 70
Tler-r 6.2 -PVRR Cosr/(BrNenrr) on ruE Davs JonNsroN UNrr 3 INsralr- SCR EeurpMENr
Casp RuanvE To tlg.p.2017 IRP Upoarp PRETERTo PoRrpolro ey PRrcp-Por-rcy
ScpNanro ..................73
Tasre 6.3 - PVRR Cosr/(BeNrrrr) on rue Jrvr BRrocpR UNrrs I & 2 Iusrall SCR EeurpueNr
aNo RprrnE 2037 Case Rrr-arrvp ro rHE 20l7IRP Upoarp PnepsRrup PoRrrolro av
Pruce-Polrcy ScEuanro............... ................74
Taet-e 6.4 - PVRR Cosr/(BnNErrr) on rHE NaucsroN UNrr 3 Mexnruvr Ges CoNvpRSroN AND
RprrRp 2029 Ctsp. Rslarrvp ro rHE 20l7IRP Upoarp PReppRRBo Ponrrolro ev PRrcE-
Por-rcy ScpNaRro.. ......................76
TaeI-e 6.5 - PVRR Cosr/(Bnuerrr) or ruE NaucuroN UNrr 3 Lrvrrpo Gas CoNvpRSroN AND
RprrRp 2029 Casp. Rrlarrvp ro rHE 20l7IRP Upoare PRppeRRro PoRrpolro av PRrcE-
Por-rcv SceNaRro.. ...................... 78
Taer-E 6.6 - PVRR Cosr/(BnNurrr) on rue CHolle UNrr 4 Gas CoNvpRsroN AND RprrnE 2042
CesE RnlnrrvE To tup.2077IRP Upoare PnsrBRRBo PoRrrouo ey Pnrcp-Por-rcv
ScENanro 80
TaeLp 7.1 - Pnolecr-sy-PRomcr SO Mooel eNo PeR PVRR(o) (BeNerrr)/Cosr oF
RrpowpRrNc wrrH Merruu Narunal Gas aNo Mporuv CO2 PzucB Por.rcy Assuuprrolls
($ urr-r-roN) ................ 93
Teslp 7.2 - Pnolecr-sv-PRorncr SO Mooel auo PaR PVRR(n) (BeNnrrr)/Cosr oF WrNo
RppoweRrNc wrrH Low Narunal Gas aNo No CO2 Pnrcs Por-rcy AssunaprroNs .......
.6
22
,24
,25
29
,34
36
94
PacIplConp _ 20 I7 IRP UPDATE TABLE on CoNreNrs
lv
PACIFICORP _2017 IRP UpoarE TAtlt.lt ot,CoN't t,N Is
Taer-E 7.3 - PnolECr-By-PRoJECT NoMrNal REvENuE REeUTREMENT PVRR(D) (BENEFTT)/Cosr
op WrNo RspowERtNG............... ...................95
Taslp 7.4 - NorrarNRl LEvpr-rzeo NEr BpNpprr psn MWH op INcneH,lENral ENsRcv Ourpur
AFTER Repow8RtNG............... .....96
Tasr-E 7.5 - SO Moosr- nNo PaR PVRR(o) (BeNenrr)/Cosr oF WrNo REpowenrNc................. 96
Taet-s 7.6 -NovrNal RsvBtrup ReeurneueNr PVRR(o) (BENenrr)/Cosr op WrNo REpoweRrNc
Taet-s 7.7 -20L7RRFP FtNal SuoRrltsr
Tler-e 7.8 - SO Moosl aNo PnR PVRR(o) (BeNenrr)/Cosr oF rHE ColasrNeo PRo:ecrs .....
Taer-B 7.9 - NourNal ReveNur RequrneveNr PVRR(o) (BeNenrr)/Cosr oF THE CoNasrNso
Pno:Ecrs 103
Taele 8.1 - CourpARrsoN or 2017 IRP UpoarE wrrH 201 7 IRP PRppERREp PoRrpolro.......... 108
Taele 8.2 -2017 IRP UpoarE Survtrr,trR CRpncrry Loao aNo REsouRcE BRlaNcE ............... 109
Taelp 8.3 -2017IRP Upoerg WrNrrn Cnpncrrv Loao RNo REsouRce BalaNce ln
Taer-E 8.4 - PacrrrCoRp's 2017 IRP UroATE, DErRreo PReppRRso PoRrpolro .................... I l3
Tasle 8.5 - PVRR Cosr/(Beuenrr) on rus BusrNrss PI-RN Rplerrve ro rHE 2017 tRP UpoRre
PRsrpRRro PoRrrolro ............ I 19
Teslp 9.1 - Assuvrpo Coal-UNrr RETTREMENTS rN THE 2017 IRP PRepsRRso PoRrpolro ......122
Taet-e l0.l -2017IRP AcroN PI-aN Srarus UpoarE ........127
Taele A.l - Fonscasrso ANNual Loao GRowrH, 2018 runouaa2027, Rr GENeRarroN, PRE-
DSM........... ................137
Taele A.2 - FoReclsrpo Amlual CoNcrosNr Pear Lono er GENEnerroN, pRE-Dsrra ..........138
Taer-E A.3 - Axm;al Loao GRowrH CHANGE, er GENEnarroN, PRS-DSM............................. 138
Taelp A.4 - Amrual CotNctoeNr Peer GRowru CsaNcE ar GENsRarroN, PRS-DSM.......... 139
Taele A.5 - Sysrev ANuual REran Sales FoRpcasr 2018 runoucu2027 , posr-DSM ......139
Taelp A.6 - Axuual Loao GRowrH CsaNcE: 2017 IRP FonEcasr lEss 2017 IRP UpoarE
FoRscasr AT RETerL, Posr-DSM ...............140
Tler-p A.7 - Fonpcasrpo Rgterl Seles Gnowru m ORpcoN, posr-DSM .............141
Taele A.8 - FonEcasreo REran Sar-es GRowru rN WasurNcroN, posr-DSM ......................141
Taet-e A.9 - FonEcasrso REran SalEs GRowrH rN CalrpoRNre, posr-DSM............ .............142
Taele A.l0 - Fonscasrpo Rsran Salns GnowrH rN UrAH, posr-DSM ...............142
Teelp A.l I - Fonscasrgo RErarL Sar-ps GRowru rN IDAHo, posr-DSM .............. 143
Teele A.l2- Fonecasrgo RErRrr- Sar-ps GRowru rN WyourNc, posr-DSM..........................143
.97
101
102
Ixor,x op FtcuRES
PecrprConr -2011 tRP UPDATE TABLE op CoNrsNls
FrcuRE
Ftcuns
FrcunE
I - Svsrpv CorNcroENr Prar Loao
2 - Powen aNo NaruRar- Gas PRrce Corr,tpaRrsoNs (NonarNar-)
3 - Capacrrv PosrrroN CovpaRrsoN ...........
a..J
,.4
..5
l9
.23
.24
aa.JJ
.46
.47
FrcuRB 3.1 - ENency Garpway Map..........
FrcuRp 4.1 -FonEcASrED AuNual Loao (GWH)
FtcuRe 4.2 - FonpcASrED AuNuar- CorNcrosNr PrRr Loao (MW)
FrcuRB 4.3 - SurraurR Capacrry PosrrroN Covpazuson CHaRr.....
FrcuRr 4.4 - SurrarraeR Sysrsur Clpacrry PosrrroN TRBNo
Frcunp 4.5 - WrNrsn Svsrpv Capecrry PosruoN TneNo.
FtcuRp 4.6 - Easr SuuupR PosrrroN TRpNo
Frcuna 4.7 - WEsr Suulasn PosrrroN TnpNo
FIcuRp 4.8 - Sysrev Avsnace MoNrHly ENpRcy Posrrrous
FrcuRe 5. I - ScaraRS..............
FrcuRE 5.2 - HpNnv Hue NeruRal Gas PRrcps (Noumal)
FrcuRE 5.3 -AvBnecr ANNual Flar Palo VpRop Er-EcrRrcrry PRrcps (Nounel) ......
FIcunE 5.4-Avenace Alwual Hpavv Loao Houn Par-o Venoe ElpcrRrcrry PRrces(Novrual) ................57
FrcuRp 5.5 -Avenace AxNual Flar Mro-CoLUMBTA Er-scrRrcrrv Pnrces (Noumal) .......... 58
FIcuRp 5.6 - Avpnacs AxNuar- Hgavv Lono Houn Mro-Coluvrsra Et-ecrRrcrrv PRrces(NourNar) ................58
Frcunr 5.7 - MEoruu COz PnrcE ....... 59
FrcuRr 5.8 - Norr4rNrar- YsaR-ev-Ypen EsceLarroN FoR DrrrERsNr RpsouRcE TypEs............ 60
FrcuRr 6.1 -FonwaRo PRrcp Cunvg AssuvprroNs ............. .................. 7l
Frcunp 6.2-CvrnLATrvE INcruesE/(Drcnrese) rN PoRrnolro ResouRcES UNDER rus Davp
JonNsroN UNrr 3 INsralr- SCR EeurpMENr (Pzuce-ScrNARro MM) ......... ......72
Frcunp 6.3 -CurauLATrvE INcruesa/(Drcnresr) rN PoRrroLro RpsouRcES UNDER rus Jru
BRrocpn UNrrs I & 2 INsrar-l SCR EqunueNr aNo Rrrne2037 (Pnrce-SceNanro MM)
.................74
Ftcunr 6.4 - CuvulArrvE INcnrase/(Decnease) w PoRrpolro ResouRcES UNDER THE
NaucnroN UNrr 3 Maxrvuv Ges CoNveRSroN RNo RprrRe 2029 (Pwce-SceNenro MM)
....,.,,.....,...76
FrcuRp 6.5 - CuuuLATrvE Iucnnesr/(Dacnease) rN PoRrnolro ResouRcES UNDER THE
NaucuroN UNrr 3 Lrurrro Ges CoNvpRSroN (Pnrce-SceNARro MM).............................. 78
FrcuRp 6.6 - CuruuLATrvE INcnrasr/(Decruasn) rN PoRrnoLro ResouRcES UNDER rne CHor-la
Uurr 4 Ges CoNvaRSroN (Pruca-ScrNARro MM).......... ..................79
FtcuRp 6.7 - Davp JouxsroN UNrr 3 SCR Pnorpcr MnesroNs ScHsouLE .............................. 8l
FrcuRs 6.8 -Jna Bnrocpn UNrrr I SCR Pnolscr MrlssroNg Scusou18.............. .....82
FrcuRp 6.9 -Jrru BRrocpR UNrr 2 SCR Pnorecr MresroNp ScsEou18.............. ..... 83
FtcuRp 6. l0 - NaUGHToN UNrrr 3 Maxruuu NaruRar- Gas CoNvERSToN PRorecr MnEsroueScHpour-e. .................84
FtcuRs 6.1 I - NaUGHToN Uurr 3 Lrurrso Narunal Gas CoNvpRSroN PRolecr MresroNE
Scnpoulp. .................85
Ftcunr 6.12- Csolle Uutr 4 Narunal Gas CoNveRSroN PRorecr MresroNe Scupoulp .... 86
FrcuRe 7.1 - HsNny Hue NarunaL Gas Pnrce AssuuprroNs.............. .................... 89
FtcuRp 7.2-COz PRrcp AssuuprroNs.............. ..................... 90
VI
..47
..48
..49
.55
.56
.57
PACIFICoRP -2017 IRP Upo,,rre TABLE op CoNreNrs
FrcuRe 8.1 -ArwuAL SrATE RPS Covpr-TANCE Fonscasr.115
FrcuRp 8.2 - CorrapARrsoN or COz EvrssroN FoRrcasrs BETWEEN rsa2017 IRP UpoarE
PRpprRruo Ponrrorro AND THE 2017 IRP PRrpERneo PoRrror-ro
FrcuRs 8.3 - PnolpcrEo ENsRcv Mtx wrru 2017 IRP Upoars PRerrRruo PoRrpolro
ll6
RBsouRcps tt7
FrcuRs 8.4 - CuvulArrvE INcnease/(Decnrase) m 2017 BusrNnss Plau RNo 2017 IRP
Upoerp PRrpBRRen PoRrpor-to .................. I 18
vl1
PncrFrConp -2017 IRP UPDA rE TABLE op CoNreNls
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vlll
PACIFICoRP _2017 IRP Upoarg CuapreR I -Exscunvs Survrvanv
CHaprER 1- Exscurrvp SUvTMARY
PacifiCorp submitted its 2017 Integrated Resource Plan (lRP) to state regulatory commissions on
April 4, 2017. That plan provides a framework for future actions that PacifiCorp will take to
provide reliable and reasonably priced service for its customers through the least-cost, least-risk
resource portfolio. The 2017 IRP Update reflects resource planning and procurement activities that
have occurred since the 2017 IRP and presents an updated load-and-resource balance and an
updated resource portfolio consistent with changes in the planning environment. The 2017 IRP
Update also provides a status update forthe action plan filed with the 2017 IRP in Chapter 10. In
presenting the updated load-and-resource balance and updated resource portfolio, PacifiCorp
shows changes relative to the 2017 IRP which covers the 2017 to2036 planning horizon. In the
2017 IRP Update PacifiCorp also addresses recommendations and requirements identifiedby its
state regulatory commissions during the 2017 IRP acknowledgement or acceptance process.
2017 IRP Update Highlights
PacifiCorp's long-term planning process involves balanced consideration of cost, risk, uncertainty,
supply reliability/delivery, and long-run public policy goals. The following summarizes the key
highlights of PacifiCorp's2017 IRP Update:
PacifiCorp's2017 IRP Update preferred portfolio includes updated cost-and-performance
information for the Energy Vision 2020 projects, which include l,3l 1 MW of new wind,
repowering just over 999 MW of existing wind capacity, and the new 140-mile, 500
kilovolt (kV) Aeolus-to-Bridger/Anticline transmission line in Wyoming. Collectively,
these resources contribute to meeting the capacity need identified in PacifiCorp's updated
load-and-resource balance and are on track to be in service by the end of2020. The Energy
Vision 2020 projects continue to be a central feature of the 2017 IRP Update least-cost,
least-risk preferred portfolio and will provide substantial benefits for customers.
The 1,311 MW of new wind projects were identified through a robust competitive
bidding process. Updated economic analysis of these new wind resources, enabled by
the Aeolus-to-Bridger/Anticline transmission line, shows that they will provide
substantial customer benefits. In addition to creating construction jobs and tax revenue
in the state of Wyoming, the new wind projects will qualify for the full value of federal
production tax credits (PTCs) and generate zero-fuel-cost energy.
The new 500-kv, 140-mile Aeolus-to Bridger/Anticline transmission line, which is
needed to strengthen the electric reliability of PacifiCorp's transmission system, will
provide critical voltage support to the Wyoming transmission network, mitigate the
impact of outages on the existing system, enhance the company's ability to comply
with mandated reliability and perforrnance standards, and reduce line losses. The new
transmission line will also relieve existing transmission constraints, increase transfer
capability and enable interconnection of new capacity.
The 999 MW of repowered wind facilities located in Oregon, Washington and
Wyoming, will provide substantial customer benefits and optimize the existing wind
fleet by using new technology that increases zero-fuel-cost energy production, reduces
a
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PACIFICoRP _2017 IRP UPDATE Cuep'tln 1 - ExECUTIVE SUMMARY
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ongoing operating costs by avoiding capital expenditures related to component failures,
renews the existing wind fleet with new turbines that extend the useful life of the wind
facilities by up to 13 years, requalifies the wind facilities to receive the full value of
PTCs for another l0 years, and improves delivery of wind energy into the transmission
system through enhanced voltage support and power quality.
With reduced loads and lower renewable resource costs, the updated preferred portfolio
contains no new natural gas resources through the 20-year planning horizon. This is the
first time an IRP has not included new fossil-fueled generation as a least-cost, least-risk
resource for PacifiCorp.
Through the end of 2036, the updated preferred portfolio includes over 2,700 MW of new
wind resources, 1,860 MW of new solar resources, 1,877 MW of incremental energy
efficiency resources, and approximately 268 MW of direct-load control resources.
The 201 7 IRP Update preferred portfolio continues to assume existing owned coal capacity
will be reduced by 3,650 MW through the end of 2036.
In accordance with action items in the 2017 IRP action plan, PacifiCorp completed unit-
specific coal studies in the 2017 IRP Update for Naughton Unit 3, Cholla Unit 4, Dave
Johnston Unit 3, and Jim Bridger Units I and2. Consistent with the findings from these
studies, the 2017 IRP Update continues to assume no incremental selective catalytic
reduction (SCR) emission-reduction systems will be needed to satisfy regional haze
compliance obligations. PacifiCorp continues to assume Cholla Unit 4 retires at the end of
2020, Dave Johnston Unit 3 retires at the end of 2027, and Jim Bridger Units I and 2 retire
at the end of 2028 and2032, respectively. The 2017 IRP Update assumes Naughton Unit
3 retires end of January 2019, shifted one month from the 2017 IRP that assumed retirement
at the end of2018.
On March 28,2017, President Trump issued an Executive Order directing the U.S.
Environmental Protection Agency (EPA) to review the Clean Power Plan (CPP) and, if
appropriate, suspend, revise, or rescind the CPP, as well as related rules and agency actions.
On October 10,2017, the EPA issued a proposal to repeal the CPP and the EPA will take
comments on the proposed repeal until April 26,2018. In addition, the EPA published in
the Federal Register an Advance Notice of Proposed Rulemaking December 28, 2017,
seeking public input on, without committing to, a potential replacement rule. The public
comment period for the Advance Notice of Proposed Rulemaking concluded February 26,
2018. PacifiCorp will continue to follow activities related to the CPP; however, the
company has not included the CPP in its assumptions for the 2017 IRP Update. Rather, the
2017 IRP Update includes a medium COz price assumption starting in 2030 to reflect
possible regulatory changes in the future.
On December 22,2017, President Trump signed into law H.R. I (Tax Reform Act) which
generally impacts PacifiCorp for tax years beginning in 2018 and going forward. The Tax
Reform Act reduced the federal corporate income tax rate from a top rate of 35 percent to
an across-the-board federal corporate income tax rate of 2l percent. The Tax Reform Act
left intact the federal tax credit rules and phase-outs for wind and solar facilities as enacted
in the 2015 tax extender legislation. Public utility property will no longer be eligible for
2
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PACIFICoRP - 2OI7 IRP Upoarg CuRpTp,n I - EXECUTIVE SUMMARY
bonus depreciation for property placed in service after September 27,2017 , unless it was
subject to a written binding contract on September 27 ,2017. PacifiCorp's 2017 IRP Update
accounts for the Tax Reform Act, and updated economic analysis of Energy Vision 2020
projects are greater than originally estimated in the 2017 IRP despite the reduction in
federal corporate income tax rate.
a As shown in Figure 1.1 PacifiCorp's most recent coincident system peak load forecast, is
down relative to the 2017 IRP. On average, across the first ten years of the planning period,
the coincident system peak is down by roughly 424 MW relative to the 2017 IRP reflecting
a less favorable outlook for the industrial segment and the adoption of more efficient
appliances by residential customers.
re 1.1 -Coincident Peak Load
a Figure 1.2 shows that forecasted natural gas and energy prices have declined from those in
the 2017 IRP through about the 2030-2031 time frame. Domestic gas price forecasts
continue to be driven down by growth in unconventional shale-gas plays. This in turn
(combined with lower forecasted regional loads) impacts forward market power prices.
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Figure 1.3 summarizes the 2017 IRP Update capacity load-and-resource balance, before acquiring
new resources and making firm market purchases, alongside the load-and-resource balance from
the 2017 IRP. The load-and-resource balance capacity need has decreased by an average of 408
MW, relative to the 20l7IRP, reflecting a lower load forecast and an increase in qualifying facility
contracts. The capacity need in both the 2017 IRP and the 2017 IRP Update increases at the end
of January 2019 due to the assumed early retirement of Naughton Unit 3 and at the end of 2020
due to the assumed early retirement of Cholla Unit 4. The 2017 IRP Update load-and-resource
balance continues to show acapacity need throughout the planning period, but this need has been
reduced relative to the 2017 IRP by 204 MW in 2018 rising to 539 MW by 2027.
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Table I . I reports the 2017 IRP Update preferred portfolio and differences relative to the 2017 IRP
preferred portfolio. The table shows the resource mix that achieves a l3-percent planning reserve
margin in each reported year. As compared to the 2017 IRP preferred portfolio, changes in the
resource mix reflect updates to Energy Vision 2020 new wind resources and a reduced load
forecast that result in removal of the need for a new natural gas simple cycle combustion turbine
(SCCT) and combined cycle combustion turbine (CCCT) and reduced reliance on higher risk
market transactions throughout the 20-year planning horizon. As was the case in the 2017 IRP
preferred portfolio, PacifiCorp continues to plan to meet its customers' needs largely through the
acquisition of cost-effective Energy Vision 2020 resources, energy efficiency (Class 2 demand-
side management (DSM)) resources, and front-office transactions (FOTs), over the next ten years.
5
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Preferred Portfolio Update
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PecrprConp - 2017 IRP Upoarp CH,qprgn 2 _ INTRODUCTION
CHaprER 2 - IxrnoDUCTroN
This 2017 IRP Update describes resource planning activities that occurred after the 2017 IRP was
filed in April 2017, presents an updated load-and-resource balance, an updated resource portfolio
consistent with changes in the planning environment, and provides a status update on the action
plan filed with the 2017 IRP. In presenting the updated load and resource balance assessment and
updated resource portfolio, PacifiCorp shows changes relative to the 2017 IRP and relative to its
fall 201 7 l}-year business plan (Business Plan), which covers the 201 8 to 2027 planning horizon.
In this update PacifiCorp also addresses recommendations and requirements identified by its state
regulatory commissions during the 2017 IRP acknowledgement process, as applicable.
PacifiCorp updated the 2017 IRP Update preferred portfolio reflect updates to forecasted loads,
resources, market prices, and other model inputs. The 2017 IRP Update also includes the most
recent analysis of Energy Vision 2020 projects, which includes new wind and transmission, plus
wind repowering.
Chapters I and2 of the 2017 IRP Update provide summary information. Chapter 3 describes the
current planning environment, load updates, resource updates, state and federal policy updates,
and Energy Gateway transmission planning and project completion forecast. Chapters 4 provides
updated load-and-resource balance information. Chapter 5describes changes to key inputs and
assumptions relative to those used for the 2017 IRP. Studies conducted in response tothe2017
IRP coal resource action plan items are discussed in Chapter 6. A summary of Energy Vision 2020
is presented in Chapter 7. Chapter 8 presents the updated resource portfolio. Chapter 9 presents
transmission studies consistent with the 2017 IRP action plan. A status update on the 2017 IRP
Action Plan is provided in Chapter 10. The Appendix provides additional load forecast details.
7
PrrcrprConp - 20 l7 IRP UpoerE CuaprEn 2 - TNTRODUCTION
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8
Cneprpn 3 - TuE, PTaNxING ExvnoNMENT
PRCIT.ICt;np 20 I7 IRP UPDAI.I,CHAPTER 3 -Tua PLANNTNG ENVIRONMENT
Federal Policy Update
Federal Climate Change Legislation
To date, no federal legislative climate change proposal has been passed by the U.S. Congress.
Federal climate change legislation is not anticipated in the near term, but remains possible in the
mid- to long-term.
New Source Performance Standards for Carbon Emissions - Clean Air Act
$ 111(b)
New Source Performance Standards (NSPS) are established under the Clean Air Act for certain
industrial sources of emissions determined to endanger public health and welfare. On October 23,
2015, the U.S. Environmental Protection Agency (EPA) finalized a rule limiting carbon emissions
from coal-fueled and natural-gas-fueled power plants. New natural-gas-fueled power plants can
emit no more than 1,000 pounds of carbon dioxide (COz) per megawatt-hour (MWh). New coal-
fueled power plants can emit no more than 1,400 pounds of COz/MWh. The final rule largely
exempts simple cycle combustion turbines from meeting the standards.
The NSPS was appealed to the U.S. Court of Appeals - D.C. Circuit and oral argument was
scheduled for April 17 ,2017 . However, oral argument was deferred and the court held the case in
abeyance for an indefinite period of time. Until such time as the EPA undertakes fuither action to
reconsider the NSPS or the court takes action, any new fossil-fueled generating facilities
constructed by relevant registrants will be required to meet the NSPS established in the EPA's
October 23,2015 final rule.
Carbon Emission Guidelines for Existing Sources - Clean Air Act $ 111(d)
On August 3,2015, EPA issued a final rule, referred to as the Clean Power Plan (CPP), regulating
carbon emissions from existing power plants. The CPP required states to develop standards of
performance, which are the degree of emissions limitations achievable through the application of
the best system of emission reduction (BSER).
EPA's proposal calculated state-specific emission rate targets to be achieved based on the BSER.
The final CPP established the BSER as including: (a) heat rate improvements; (b) increased
utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased
deployment of new and incremental non-carbon generation placed in service after 2012. The
compliance period would have begun in2022, with three interim periods of compliance and with
the final goal to be achieved by 2030. The CPP was expected to reduce COz emissions in the power
sector to 32 percent below 2005 levels by 2030.
On March 28,2017 , President Trump issued an Executive order directing EPA to review the CPP
and, if appropriate, suspend, revise, or rescind the CPP, as well as related rules and agency actions.
On October 10, 2017, EPA issued a proposal to repeal the CPP and the public comment period on
EPA's proposal closed April26,2018. In addition, EPA published an Advance Notice of Proposed
9
PeclprConp -2011 IRP UpoarE CIIAP'II]R 3 TIIE PLANNTNG ENVIR0NMENT
Rulemaking in the Federal Register December 28, 2017, seeking public input on, without
committing to, a potential replacement rule. The public comment period for the Advance Notice
of Proposed Rulemaking concluded February 26, 2018. Given the current status of the CPP,
PacifiCorp does not assume applicability of any CPP emission limits in the 2017 IRP Update.
Clean Air Act Criteria Pollutants - National Ambient Air Quality Standards
The Clean Air Act requires EPA to set National Ambient Air Quality Standards (NAAQS) for six
criteria pollutants that have the potential of harming human health or the environment. The
NAAQS are rigorously vetted by the scientific community, industry, public interest groups, and
the general public, and establish the maximum allowable concentration allowed for each "eriteria"
pollutant in outdoor air. The six pollutants are carbon monoxide, lead, ground-level ozone,
nitrogen dioxide (NOx), particulate matter (PM), and sulfur dioxide (SOz). The standards are set
at a level that protects public health with an adequate margin of safety. If an area is determined to
be out of compliance with an established NAAQS standard, the state is required to develop a state
implementation plan (SIP) for that arca. And that plan must be approved by EPA. The plan is
developed so that once implemented, the NAAQS for the particular pollutant of concem will be
achieved.
In October 2015, EPA issued a final rule modifying the standards for ground-level ozone from
75 parts per billion (ppb) to 70 ppb. Under the final rule, EPA is required to designate areas in the
country as being in "attainment" or "nonattainment" of the revised standards by October 2017.
State compliance dates will be set depending on the ozone level in the area. EPA is currently in
the process of making attainment/nonattainment classifications. PacifiCorp facilities will only be
affected to the extent they are located in an ozone nonattainment area.
On January 9,2018, EPA published the results for the air quality designations for the 2010 SOz
primary NAAQS-Round three in the Federal Register. The Utah county of Emery, where
PacifiCorp's Hunter and Huntington Generation Stations are located, was classified as
attainment/unclassifiable. The Wyoming counties of Campbell and Lincoln, where PacifiCorp's
Wyodak and Naughton generation stations are located, were classified as
attainment/unclassifiable. The eastern portion of Sweetwater County, where PacifiCorp's Jim
Bridger generation station is located, was classified as attainment/unclassifiable. PacifiCorp's
facility has conducted on-site ambient SO2 monitoring to demonstrate compliance and is currently
working with the state and federal agencies to terminate the monitoring site. Converse County,
where PacifiCorp's Dave Johnston generation station is located, will not be designated until
December 31,2020- The classification of attainment/unclassifiable maintains the regulatory status
quo for the affected facilities. PacifiCorp facilities located in areas classified as
attainment/unclassifiable will be required to demonstrate ongoing compliance by performing
modeling every three years using actual facility emission data.
On January 23,2017, Gadsby and Lake Side were identified as major sources subject to Utah's
serious nonattainment area SIP for PMz.s and PMz.s precursors. On April 28, 2017, PacifiCorp
submitted a best-available control measure analysis for Gadsby and Lake Side to Utah Department
of Air Quality for review. PacifiCorp proposed ammonia limits for the Gadsby and Lake Side
facilities. Utah has until December 31, 2019 to demonstrate attainment through modeling or
monitoring. If the state cannot demonstrate attainment through the measures proposed in the SIP,
then the Lake Side and Gadsby facilities may be subject to more stringent environmental
regulation.
l0
PaCIpIConp _2017 IRP UPDATE CHAPTER 3 -THE PLANNTNG ENvTRoNnapNT
Regional Haze
EPA's regional haze rule, finalized rn1999, requires states to develop and implement plans to
improve visibility in certain national park and wilderness areas. On June 15,2005, EPA issued
final amendments to its regional haze rule. These amendments apply to the provisions of the
regional haze rule that require emission controls known as the best available retrofit technology
(BART) for industrial facilities meeting certain regulatory criteria with emissions that have the
potential to affect visibility. These pollutants include fine PM, NOx, SOz, certain volatile organic
compounds, and ammonia. The 2005 amendments included final guidelines, known as BART
guidelines, for states to use in determining which facilities must install controls and the type of
controls the facilities must use. States were given until December 2007 to develop their
implementation plans, in which states were responsible for identifying the facilities that would
have to reduce emissions under BART guidelines, as well as establishing BART emissions limits
for those facilities. States are also required to periodically update or revise their implementation
plans to reflect current visibility data and the effectiveness of the state's long-term strategy for
achieving reasonable progress toward visibility goals. On December 14,2016, EPA issued a final
rule setting forth revised and clarifying requirements for periodic updates in SIPs. States are
currently required to submit the next periodic update by July 31,2021. EPA's final action on the
regional haze rule amendments was published in the Federal Register on January 10, 2017, and
has been appealed by several states and industry groups. On January 17,2018, EPA announced its
decision to revisit certain aspects of the 2017 regional haze rule revisions. EPA intends to
commence a notice-and-comment rulemaking process and expressed plans to finalize EPA
guidance documents for regionalhaze SIP revisions due in202l. On January 30,2018, the U.S.
Court of Appeals - D.C. Circuit issued an order holding the case in abeyance and directing EPA
to submit a status report every 90 days, starting April 30,2018.
The regional haze rule is intended to achieve natural visibility conditions by 2064 in specific
national parks and wilderness areas, many of which are located in Utah and Wyoming where
PacifiCorp operates generating units, as well as Arizona where PacifiCorp owns but does not
operate a coal unit, and in Colorado and Montana where PacifiCorp has partial ownership in
generating units operated by others, but are nonetheless subject to the regional haze rule.
Utah Regional Haze
In May 2011, the state of Utah issued a regional haze SIP requiring the installation of SO2, NO*
andPMcontrolsonHunterUnitsland2andHuntingtonUnitsIand2.lnDecember2012,EPA
approved the SOz portion of the Utah regionalhaze SIP and disapproved the NOx and PM portions.
EPA's approval of the SOz SIP was appealed to federal circuit court. In addition, PacifiCorp and
the state of Utah appealed EPA's disapproval of the NOx and PM SIP. PacifiCorp and the state's
appeals were dismissed. In June 2015, the state of Utah submitted a revised SIP to EPA for review
and approval with an updated BART analysis incorporating a requirement for PacifiCorp to retire
Carbon Units I and 2, recognizing NOx controls previously installed on Hunter Unit 3, and
concluding that no incremental controls (beyond those included in the May 201I SIP and already
installed) were required at the Hunter and Huntington units. On June 1,2016, EPA issued a final
rule to partially approve and partially disapprove Utah's regional haze SIP and propose a federal
implementation plan (FIP). The FIP final rule requires the installation of selective catalytic
reduction (SCR) controls at four of PacifiCorp's units in Utah by August 4,2027: Hunter Units I
and 2, and Huntington Units 1 and 2. On September 2, 2016, PacifiCorp and other parties filed
1l
PacrilCoRp -2017 IRP Upnarr Crrapren 3 - TrrE PLANNTNG ENvnoNur,Nr
petitions for administrative and judicial review of EPA's final rule and requested a stay of the
effective date of the final rule. Unless EPA's FIP is stayed or reversed, the controls are required to
be installed by August 4, 2O2l . On September I l, 2Ol7 , the U.S. lOth Circuit Court of Appeals
granted the petition for stay and the request for abatement. The compliance deadline of the FIP
and the litigation will be stayed indefinitely pending EPA's reconsideration.
On January 30,2074, EPA published its final action in Wyoming, published in the Federal
Register, requiring installation of the following NOx and PM controls at PacifiCorp facilities:
o Jim Bridger Unit 3 by December 3 l, 2015: SCR equipment. Jim Bridger Unit 4 by December 3 l, 2016: SCR equipmento Naughton Unit 3 by January 30,2019: SCR equipment and a baghouseo Jim Bridger Unit2 by December 31, 2021: SCR equipmento Jim Bridger Unit I by December 3 l, 2022: SCR equipmento Dave Johnston Unit 3: SCR within five years or a commitment to shut down in 2027o Wyodak: SCR equipment within five years
Different aspects of EPA's final action were appealed by a number of entities. PacifiCorp appealed
EPA's action requiring SCR at Wyodak and was granted a stay of the Wyodak SCR requirement
pending resolution of the appeals. For Naughton Unit 3, EPA indicated support for the conversion
of the unit to natural gas in its final action and stated that it would expedite consideration of the
gas conversion once the state of Wyoming submitted the requisite SIP amendment. PacifiCorp
obtained a construction permit and revised regional haze BART permit from the state of Wyoming
to convert Naughton Unit 3 to natural gas in 2018. In late 2017 PacifiCorp submitted a petition to
the state of Wyoming requesting that the requirement to convert Naughton 3 to natural gas be
delayed one year which was approved by the state of Wyoming. The permit allows PacifiCorp to
continue with coal-fueled operation through January 30,2019, with the option of gas conversion
available thereafter. The Wyoming Department of Environmental Quality submitted a proposed
revision to the Wyoming SIP, including a change to the Naughton Unit 3 compliance date, to the
EPA for review and approval November 28,2017.
Arizona Regional Haze
EPA took final action approving the Arizona regional haze SIP revision and withdrawing the FIP
for the Cholla power plant on March 16,2017 allowing Cholla Unit 4 to continue coal-fueled
operations through April 30, 2025, with the option to convert to burn natural gas by July 31,2025.
Colorado Regional Haze
ln2016, the owners of Craig Unit 1, state and federal agencies, and parties to previous Colorado
regional haze settlements reached an agreement to propose an alternate regional haze compliance
plan for Craig Unit I that incorporated retirement of the unit by December 31,2025, with an option
for conversion of the unit to natural gas by August 31,2023. The terms of this agreement were
approved by the Colorado Air Quality Board on December 15, 2016. The Colorado Department of
Public Health and Environment submitted the associated Colorado SIP amendment for EPA's
t2
Wyoming Regional Haze
Pe,crrrConp -2017 IRP Upoare CHAPTER 3 _ THa PLANNTNG ENVIRoNMENT
review and approval on May 27,2017. EPA's review and approval process is expected to carry
through 2018.
Mercury and, Hazardous Air Pollutants
The Mercury and Air Toxics Standards (MATS) became effective April I 6,2012. The MATS rule
requires that new and existing coal-fueled facilities achieve emission standards for mercury, acid
gases and other non-mercury hazardous air pollutants. Existing sources were required to comply
with the new standards by April 16,2015. However, individual sources may have been granted up
to one additional year, at the discretion of the Title V permitting authority, to complete installation
of controls or fortransmission system reliability reasons. In June 2015, the U.S. Supreme Court
found that EPA did not properly consider costs in making its determination to regulate hazardous
pollutants from power plants. In December 2015, the U.S. Court of Appeals - D.C. Circuit ruled
that MATS may be enforced as EPA modifies the rule to comply with the Supreme Court decision.
By April 2015, PacifiCorp had taken the required actions to comply with MATS across its
generation facilities.
Coal Combustion Residuals
Coal Combustion Residuals (CCRs), including coal ash, are the byproducts from the combustion
of coal in power plants. CCRs have historically been considered exempt wastes under an
amendment to the Resource Conservation and Recovery Act (RCRA); however, EPA issued a final
rule in December 2014 to regulate CCRs for the first time. Under the final rule, EPA will regulate
CCRs as non-hazardous waste under Subtitle D of RCRA and establish minimum nationwide
standards for the disposal of CCRs. The final rule was effective October 19,2015. Under the final
rule, surface impoundments utilized for CCRs may need to close unless they can meet more
stringent regulatory requirements. PacifiCorp operates seven impoundments and four landfills that
are subject to the final rule. Three impoundments are currently being closed.
The final CCR regulation was self-implementing; however, in December 2016 the Coal
Combustion Residuals Regulatory Improvement Act was signed, which sets forth the process and
standards for EPA approval (and withdrawal) of a state's permitting program for CCR units. A
state may incorporate either the requirements of the EPA rule into its permit program or other state
requirements that, based on site-specific conditions, are at least as protective as the EPA rule.
On March 1,2018, EPA proposed to amend the April 2015 final CCR rule. EPA is proposing to
allow states or EPA the ability to incorporate flexibilities into the coal ash permit programs of
state, and EPA-issued permits. Comments on the rule amendment were due April 30, 2018, and
EPA plans to hold a public hearing on the proposal.
Water Quality Standards
Cooling Water Intake Structures
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for
maintaining and improving water quality in the U.S. through a program that regulates, among other
things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling-
water-intake structures reflect the "best technology available for minimizing adverse
environmental impact" to aquatic organisms. ln May 2014, EPA issued a final rule, effective
October 2014, under $ 316(b) of the Clean Water Act to regulate cooling-water intakes at existing
l3
PncrplConp _2017 IRP UPDATE CHAPTER 3 -Tug PLANNTNG ENVIRONMENT
facilities. The final rule established requirements for electric-generating facilities that withdraw
more than two million gallons per day, based on total design intake capacity, of water from waters
of the U.S. and use at least 25 percent of the withdrawn water exclusively for cooling purposes.
PacifiCorp's Dave Johnston generating facility withdraws more than two million gallons per day
of water from waters of the U.S. for once-through cooling applications. Jim Bridger, Naughton,
Gadsby, Hunter, and Huntington generating facilities currently use closed-cycle cooling towers
but withdraw more than two million gallons of water per day. The rule includes impingement(i.e.,
when fish and other aquatic organisms are trapped against screens when water is drawn into a
facility's cooling system) mortality standards and entrainment (i.e., when organisms are drawn
into the facility) standards. The standards will be set on a case-by-case basis to be determined
through site-specific studies and will be incorporated into each facility's applicable water permit
(i.e., either NPDES permit or storm water permit).
Effluent Limit Guidelines
EPA first issued effluent guidelines for the Steam Electric Power Generating Point Source
Category (i.e., the Steam Electric effluent guidelines) in 1974, with subsequent revisions in 1977
and 1982. On November 3, 2015, EPA finalized revised effluent-limit guidelines. The rule
prohibits the discharge of bottom ash or fly ash transport water and directly impacts the Wyodak,
Dave Johnston, and Naughton facilities. On September 18, 2017, EPA postponed certain
compliance dates for the Steam Electric effluent guidelines. EPA intends to conduct a new
rulemaking regarding the appropriate technology bases and associated limits for the best available
economically achievable technology effluent limitations and pretreatment standards for existing
sources requirements applicable to flue gas desulfurization (FGD) wastewater and bottom ash
transport water discharged from steam electric power plants. The earliest compliance date for
plants to meet the new FGD wastewater and bottom ash wastewater limitations is as soon as
possible beginning November l, 2020.
2015 Tax Extender Legislation
On December 18, 2015, President Obama signed tax extender legislation (H.R. 2029) that
retroactively and prospectively extended certain expired and expiring federal income tax
deductions and credits.
Bonus Depreciation
Bonus depreciation under the 2015 Tax Extender Legislation was superseded by the 2017 Tax
Reform Act. Please refer to the bonus depreciation discussion under the 2017 Tax Reform Act
section of this chapter.
Production Tax Credit (Wind)
The production tax credit (PTC), currently 2.4 cents per kilowatt-hour (inflation adjusted), has
been extended and phased out for wind property for which construction begins before January l,
2020, as follows:
o 2015 - 100% retroactiveo 2016 - 100% (construction begins before January 1,2017)
t4
. 2017 -80% (construction begins before January 1,2018)o 2018 - 60% (construction begins before January 1,2019)o 2019 - 40% (construction begins before January 1,2020)
Production Tax Credit (Geothermal and Hydro)
The PTC for geothermal and hydro were granted a two-year extension as follows (no phase-out
period was adopted):
. 2015 - 100% retroactiveo 2016 - 100% (construction begins before January l, 2017)
307o Energy Investment Tax Credit (Wind)
The investment tax credit (lTC) has been extended and phased out for wind property for which
construction begins before January 1,2020, as follows:
o 2015 - 30% retroactive
t 2016-30% (construction begins before January 1,2017)o 2017 -24% (construction begins before January 1,2018)o 2018 - 18% (construction begins before January 1,2019)
o 2019 - 12% (construction begins before January 1,2020)
307o Energy Investment Tax Credit (Solar)
The ITC has been extended and steps down for solar property for which construction begins before
January 1,2022, as follows:
o 2015 - 30% retroactiveo 2016 -30% (construction begins before January 1,2017)o 2017 - 30% (construction begins before January l, 2018)o 2018 -30% (construction begins before January 1,2019)
o 2019 -30% (construction begins before January 1,2020)
o 2020 - 26% (construction begins befbre January 1,2021)o 2021-22% (construction begins before January 1,2022)o 2022 - l0% (construction begins on or after January 1,2022)
2017 Tax Reform Act
On December22,2077, President Trump signed into law H.R. I (Tax Reform Act) which generally
impacts PacifiCorp for tax years beginning in 2018 and going forward.
Reduction in the Federal Corporate Income Tax Rate
The Tax Reform Act reduced the federal corporate income tax rate from a top rate of 35 percent
to an across-the-board federal corporate income tax rate of 2l percent.
l5
PecrprConp -2017 IRP Upoerp Crmprsn 3 - THs PLANNTNG ENVTRoNMENT
Bonus Depreciation
100 percent bonus depreciation was enacted for property placed in service after September 27 ,
2017, with a phase-out beginning in2023. However, this new provision for bonus depreciation
does not apply to public-utility property. Public-utility property is no longer eligible for bonus
depreciation ifplaced in service after September 27,2017, unless it was subject to a written binding
contract on September 27,2017 . For public-utility property subject to a written binding contract
on September 27,2017, and placed in service during 2018,40 percent of the eligible cost of the
property qualifies for bonus depreciation. For public-utility property subject to a written binding
contract on Septemb er 27 , 2017 , and placed in service during 2019, 30 percent of the eligible cost
of the property qualifies for bonus depreciation. For public-utility property placed in service after
December 31,2019, there will be no bonus depreciation.
Wind Investment and Production Tax Credits and Solar Investment Tax Credits
The Tax Reform Act left intact the federal tax credit rules and phase outs for wind and solar
facilities as enacted in the 2015 Tax extender Legislation.
California
Under the authority of the Global Warming Solutions Act, the Califomia Air Resources Board
(CARB) adopted a greenhouse gas cap-and-trade program in October 2011, with an effective date
of January 1,2012; compliance obligations were imposed on regulated entities beginning in 2013.
The first auction of greenhouse gas allowances was held in California in November 2012, and the
second auction in February 2013. PacifiCorp is required to sell, through the auction process, its
directly allocated allowances and purchase the required amount of allowances necessary to meet
its compliance obligations.
In May 2014, CARB approved the first update to the Assembly Bill (AB) 32 Climate Change
scoping plan, which defined California's climate change priorities for the next five years and set
the groundwork for post-2020 climate goals. In April 2015, Governor Brown issued an executive
order to establish a mid-term reduction target for California of 40 percent below 1990 levels by
2030. CARB has subsequently been directed to update the AB 32 scoping plan to reflect the new
interim 2030 target and previously established 2050 target. In July 2017, California Governor Jerry
Brown signed AB 398, extending the state's California Cap and Trade program from January l,
2021 through December 31, 2030.
ln 2002, California established a renewable portfolio standard (RPS) requiring investor-owned
utilities to increase procurement from eligible renewable energy resources. California's RPS
requirements have been accelerated and expanded a number of times since its inception. Most
recently, Governor Jerry Brown signed into law Senate Bill (SB) 350 in October 2015, which
requires utilities to procure 50 percent of their electricity from renewables by 2030. SB 350 also
requires California utilities to develop integrated resource plans that incorporate a greenhouse gas
emission reduction planning component. The California Public Utilities Commission is currently
developing rules to implement this new program.
l6
PeCIpICoRp - 2017 IRP UPDATE CHAPTER 3 _TuT PLANNTNG ENVm.oNMENT
PncrprConp -2017 IRP Upoa.t,CHAPTER 3 _ TUE PLANNTNG ENVIRONMENT
Oregon
Ln2007, the Oregon Legislature passed House Bill (HB) 3543 - Global Warming Actions, which
establishes greenhouse gas reduction goals for the state that: (l) end the growth of Oregon
greenhouse gas emissions by 2010; (2) reduce greenhouse gas levels to l0 percent below 1990
levels by2020; and (3) reduce greenhouse gas levels to at least 75 percent below 1990 levels by
2050. In 2009, the legislature passed SB 101, which requires the Public Utility Commission of
Oregon (OPUC) to submit a report to the legislature before November I of each even-numbered
year regarding the estimated rate impacts for Oregon's regulated electric and natural gas
companies of meeting the greenhouse gas reduction goals of l0 percent below 1990 levels by 2020
and 15 percent below 2005 levels by 2020. The OPUC submitted its most recent report
November 1,2016.
ln 2007, Oregon enacted SB 838 establishing an RPS requirement in Oregon. Under SB 838,
utilities are required to deliver 25 percent of their electricity from renewable resources by 2025.
On March 8, 2016, Governor Kate Brown signed SB 1547-8, the Clean Electricity and Coal
Transition Plan, into law. SB 1547-8 extends and expands the Oregon RPS requirement to
50 percent of electricity from renewable resources by 2040 and requires that coal-fueled resources
are eliminated from Oregon's allocation of electricity by January 1,2030- The increase in the RPS
requirements under SB 1547-8 is staged-27 percentby 2025,35 percent by 2030,45 percent by
2035, and 50 percent by 2040. The bill changes the renewable energy certificate (REC) life to five
years, while allowing RECs generated from the effective date of the bill passage until the end of
2022 from new long-terrn renewable projects to have unlimited life. The bill also includes
provisions to create a community-solar program in Oregon and encourage greater reliance on
electricity for transportation.
Washington
In November 2006, Washington voters approved Initiative 937 (l-937), the Washington Energy
Independence Act, which imposes targets for energy conservation and the use of eligible
renewable resources on electric utilities. Under l-937, utilities must supply 15 percent of their
energy from renewable resources by 2020. Utilities must also set and meet energy conversation
targets starting in 2010.
In 2008, the Washington Legislature approved the Climate Change Framework E2SHB 2815,
which establishes the following state greenhouse gas emissions reduction limits: (l) reduce
emissions to 1990 levels by 2020; (2) reduce emissions to 25 percent below 1990 levels by 2035;
and (3) by 2050, reduce emissions to 50 percent below 1990 levels or 70 percent below
Washington's forecasted emissions in 2050.
In July 2015, Govemor Inslee released an executive order that directed the Washington
Department of Ecology to develop new rules to reduce carbon emissions in the state. Ecology
initiated the rulemaking process in September 2015 and finalized the Clean Air Rule on January 5,
2016. While the rules for the Clean Air Rule were being finalized by the Department of Ecology
in September 2016, a lawsuit was filed by a coalition of employer groups challenging the
Department of Ecology's authority to implement the rule. In December 2017, Washington's
Superior Court concluded that the Department of Ecology did not have the authority to impose the
t7
PACIFICORP - 2017 IRP UPDATE CIIap.I.IIn 3 _TIIn PLANNING ENVIRoNMEN.I
Clean Air Rule without legislative approval. As a result, the Department of Ecology has suspended
the rule's compliance requirements.
Utah
In March 2008, Utah enacted the Energy Resource and Carbon Emission Reduction Initiative,
which includes provisions to require utilities to pursue renewable energy to the extent that it is cost
effective. It sets out a goal for utilities to use eligible renewable resources to account for 20 percent
of their 2025 adjusted retail electric sales.
On March 10,2016, the Utah legislature passed SB ll5-The Sustainable Transportation and
Energy Plan (STEP). The bill supports plans for electric vehicle infrastructure and clean coal
research in Utah and authorizes the development of a renewable energy tariff for new Utah
customer loads. The legislation establishes a five-year pilot program to provide mandated funding
for electric vehicle infrastructure and clean coal research, and discretionary funding for solar
development, utility-scale battery storage, and other innovative technology and air quality
initiatives. The legislation also allows PacifiCorp to recover its variable power supply costs
through an energy balancing account and establishes a regulatory accounting mechanism to
manage risks and provide planning flexibility associated with environmental compliance or other
economic impairments that may affect PacifiCorp's coal-fueled resources in the future. The
deferrals of variable power supply costs went into effect in June 2016, and implementation and
approval of the other programs was completed by January 1,2017.
Greenhouse Gas Emission Performance Standards
Califomia, Oregon and Washington have all adopted greenhouse gas emission performance
standards applicable to all electricity generated in the state or delivered from outside the state that
is no higher than the greenhouse gas emission levels of a state-of-the-art combined cycle natural
gas generation facility. The standards for Oregon and California are currently set at 1,100 lb
COzlMWh, which is defined as a metric measure used to compare the emissions from various
greenhouse gases based on their global warming potential. In March 2013, the Washington
Department of Commerce issued a new rule, effective April 6, 2013, lowering the emissions
performance standard to 970lb COzlMWh.
Energy Gateway Transmission Program Planning
As discussed in the 2017 IRP, the Energy Gateway transmission project continues to play an
important role in PacifiCorp's commitment to provide safe, reliable, reasonably priced electricity
to meet the needs of our customers. Energy Gateway's design and extensive footprint provides
needed system reliability improvements and supports the development of a diverse range of cost-
effective resources required for meeting customers' energy needs. The IRP has incorporated
Energy Gateway as part of a solution for delivering the least cost resource portfolio for multiple
IRP planning cycles. PacifiCorp continues to develop methods, in parallel with current industry
best practices and regional transmission planning requirements, to better quantify all the benefits
of transmission that are essential to serve customers. For example, Energy Gateway is designed to
relieve operating limitations, increase capacity, and improve operations and reliability in the
existing electric transmission grid. Figure 3.1 shows a high-level geography of the Energy
Gateway transmission proj ect.
l8
PecrrConr - 2017 IRP Upoars CuapTpn 3 -Tup, PLANNTNG ENVIRoNMENT
Figure 3.1 - Energy Gateway Map
I'VAgHliltrTOH
Energy Gateway
Wallulr
HONTANA
?tWYOFIIHC
coLotADo
OEEG(}H IDAHO
Crrtia lxhl
CALI TORH IA
Crdrr
N EYA DT
Sigirdl
P{ur te
f od Buua/
Af,IZONA HEW I.tEXtCO
Energy Gateway Transmission Project Updates
Wallula to McNary (Segment A)
This project meets the requirements under PacifiCorp's Open Access Transmission Tariff to
provide transmission service to a point-to-point transmission customer when the existing
transmission system does not have the capacity to serve the need. In addition, this project is needed
to improve reliability and support future resource growth. These requirements will continue to
drive the project forward. The OPUC issued a Certificate of Public Convenience and Necessity
(CPCN) in September 2011. Local, state and federal permitting is complete and the majority of
private rights of way have been acquired. The next steps will be completion of all detailed design,
issuing the construction contract and completing construction. The project is on-track to complete
permitting efforts and construction for a 2018 in-service date.
Pa.illcorp r€6ll rervlcs ar€e
New tl?nsmlsrlon llner:
- 500 kV mtnlmum volEge
- :145 kv mhtrnum YolEga
* 130 kV mtntmum yolEge
a E(lrang rubdalon
O NGrv rubcEtton
l9
This map is for general reference only and reflects current plans. It may not reflect the final routes, construction
sequence or exact line configuration.
PectptConp -2017 IRP UpoerE CHAPTER 3 THa PLANNTNG ENvInONUeNT
Gateway West (Segments D and E)
Under the National Environmental Policy Act (NEPA), the U.S. Bureau of Land Management
(BLM) has completed the environmental impact statement (EIS) for the Gateway West project.
The BLM released its final EIS on April26,2013, followed by the record of decision (ROD) on
November 14, 2013, providing a right-of-way grant for all of Segment D and part of Segment E
as discussed below:
Gateway West (Segment Dl): A single-circuit230 kV line that will run approximately 75
miles between the existing Windstar substation in eastem Wyoming and the planned
Aeolus substation near Medicine Bow, Wyoming.
Gateway West (Segment D2): A single-circuit 500 kV line running approximately 140
miles from the planned Aeolus substation to a new annex substation (Anticline) near the
existing Bridger substation in western Wyoming; and a single-circuit 230 kV line running
approximately 14 miles from the Shirley Basin substation near Medicine Bow to the
planned Aeolus substation, also near Medicine Bow; and a single-circuit 345 kV line
running approximately five miles from the planned Anticline substation near Point of
Rocks, Wyoming, to the existing Jim Bridger substation. PacifiCorp received a conditional
CPCN from the Wyoming Public Service Commission on April 12,2018.
a
Gateway West (Segment D3): A single-circuit 500 kV line running approximately 200
miles between the new annex substation (Anticline) and the Populus substation in southeast
Idaho.
Gateway West (Segment E)
The BLM released its final EIS April 26, 2073, followed by the ROD November 14, 2013,
providing a right-of-way grant for most of the project. The agency chose to defer its decision on
the western-most portion of the project located in Idaho in order to perform additional review of
the Morley Nelson Snake River Birds of Prey Conservation Area. In September 2014, the BLM
announced their intent to conduct a supplemental EIS for the final two segments. A draft
supplemental EIS was published in March 2016 and a frnal ROD was issued January 19,2017. On
April 17, 2017 the Interior Board of Land Appeals remanded the January 2017 ROD back to BLM
for reconsideration. In response to a request from Idaho Govemor Otter to the Secretary of the
lnterior, the January 2017 ROD for the Gateway West project was officially rescinded and
remanded back to the BLM Idaho State Office for further consideration. President Trump signed
the Fiscal Year 2017 Consolidated Appropriations Act into law in May 2017, which included an
agreement to route segments 8 and 9 of the Gateway West Transmission Line Project through the
Morley Nelson Snake River Birds of Prey National Conservation Area (NCA). House Resolution
2 I 04 directs the Secretary of Interior to grant right of way for the route (Alternative I ) through the
NCA. The BLM published the final environmental assessment for segments 8 and 9 on January 5,
2018. The ROD for segments 8 and 9 was approved on April 19,2018.
a
20
PncrFrConp -2011 IRP UPDATE CIIAP'IIIR 3 TI III PI,ANNIN(i ENVIRoNMIjN I
Gateway South (Segment F)
The BLM published its Notice of Intent in the Federal Register in April 201l, followed by public
scoping meetings throughout the project area. Comments on this project from agencies and other
interested stakeholders were considered as the BLM developed the draft EIS, which was issued in
February 2014. A ROD was issued by the BLM in January 2017 , and by the U.S. Forest Service
in May 2017. PacifiCorp will continue to assess construction timing to best meet customer and
system needs. PacifiCorp continues to work with the federal agencies on meeting notice-to-
proceed requirements.
Boardman to Hemingway (Segment H)
Energy Gateway Segment H represents a significant improvement in the connection between
PacifiCorp's east and west control areas and will help deliver more diverse resources to serve its
customers in Oregon, Washington and Califomia. Idaho Power leads the permitting efforts on this
project and PacifiCorp continues to support the permitting efforts under the conditions of the
Boardman to Hemingway Transmission Project Joint Permit Funding Agreement. The Bureau of
Land Management's Record of Decision was issued in November of 2017, this will be followed
by the U.S. forest Service Record of Decision and the Oregon Energy Facilities Siting Council's
final order on the Site Certificate.
In-Service Dates
Table 3.1 summarizes the in-service dates for segments of the Energy Gateway transmission
project.
2t
Segment & Name Description
Approximate
Mileage Status and Scheduled In Service
(A)
Wallula-McNary 230 kV, single circuit 30 mi . Status: local permitting completedr Scheduled in service: 20 I 8, sponsor driven
(B)
Populus-Terminal 345 kV. double circuit 135 mi o Placed in service: November 2010
(c)
Mona-Oquirrh
500 kV single circuit
345 kV double circuit 100 mi o Placed in service: May 20 l3
Oquirrh-Terminal 345 kV double circuit l4 mi . Status: rights-of-way acquisition underway
o Scheduled in-service: 2021
(D1)
Windstar-Aeolus
New 230 kV single circuit
Re-built 230 kV single
circuit
75 mi . Status: permitting continues
o Scheduled in-service: 2019-2024
(D2)
Aeolus-
Bridger/Anticline
500 kV single circuit 140 mi
. Status: permitting continues
o Conditional CPCN received April 2018r Rights-of-way acquisition underwayr Scheduled in-service: 2020
(D3)
Bridger/Anticline-
Populus
500 kV single circuit 200 mi . Status: permitting continues
o Scheduled in-service: 2020-2024
(E)
Populus-Hemingway 500 kV single circuit 500 mi . Status: permitting continues
o Scheduled in service:2020-2024
(F)
Aeolus-Mona 500 kV single circuit 400 mi o Status: permitting contlnues. Scheduled in service:2020-2024
(G)
Sigurd-Red Butte 345 kV single circuit 170 mi o Placed in service: May 2015
(H)
Boardman-
Hemingway
500 kV single circuit 500 mi
. Status: pursuing joint-development and/or firm
capacity opportunities with project sponsors
o Scheduled in service: sponsor driven
PactprConp 20 lT lRP UPDATE CHAPTER 3 -THE PLANNING ENVIRONMENT
Table 3.1- E t In-Service Dates
Energy Imbalance Market
PacifiCorp and the California Independent System Operator (CAISO) launched the energy-
imbalance market (EIM) November 1,2014. The EIM is a voluntary market and the first western
energy market outside of California. The EIM provides for more efficient dispatch of participating
resources in real-time through an automated system that dispatches generation across the EIM
footprint, which cuffently includes PacifiCorp, NV Energy, Puget Sound Energy, Arizona Public
Service, Portland General Electric, Idaho Power Company, Powerex, and the CAISO balancing
authority areas (collectively, EIM Area). Entities scheduled to join the EIM include the Balancing
Authority of Northem Califomia (April 2019), Seattle City Light (April 2020), Los Angeles Dept.
of Water and Power (April 2020), and Salt River Project (April 2020). CENACE Baja California
is investigating future entry into the market. PacifiCorp continues to work with the CAISO,
existing and prospective EIM entities, and stakeholders to enhance market functionality and
support market growth.
22
Cueprpn 4 - LoaD-AND-RpsouRCE Baraxcn,
Upoarp
This chapter presents an update to PacifiCorp's load-and-resource balance. Updates to
PacifiCorp's long-term load forecasts (both energy and coincident peak load) for each state and
the system as a whole are summarized in the Appendix. Updates to PacifiCorp's load forecast,
resources, and capacity position are presented and summarized in this chapter.
The2017 IRP Update relies on PacifiCorp's August20lT load forecast. Figure 4.1 compares
PacifiCorp's most recent load forecast to the forecast used for the 2017 IRP. Figure 4.2 compares
PacifiCorp's most recent coincident system peak load forecast to the forecast used for the 2017
IRP. Considering that PacifiCorp analyzes incremental energy efficiency and direct-load control
programs as demand-side resource options in its IRP, both figures exclude incremental energy
efficiency savings and direct-load control capacity included in the updated resource portfolio. The
compounded average annual gowth rate (CAGR) for system load is 0.55 percent over the period
2018 through2027. The CAGR for system coincident peak is 0.54 percent over the period 2018
through 2027.
4.1- Forecasted Annual Load
68,000
66,000
64,000
62,000
60,000
56,000
54,000
52,000
50,000
,.t. ff dP" ""Pt ,O ,S ,{F ,of ,"t ,$
--
.-rF2otT tRp +2017lRP Update
PaCmICoRr _2017 IRP UPDATE CHAPTER 4 _ LOAD-AND-RESoURCE BALANCE UPDATE
23
Introduction
System Coincident Peak Load Forecast
PACIFICoRP - 20 I7 IRP UPDATE CHarrsn 4 - Loao-eNn-RESoURCE BeLeNcs UPDATE
4.2 - Forecasted Annual Coincident Peak Load
Table 4.1 and Table 4.2 summarize the capacity from wind and solar power-purchase agreements
(PPAs) with qualifying facilities (QFs) that have or are expected to come online over the 2017 -
2021time frame assumed in the 2017 IRP Update compared to the 2017 IRP.
Table 4.1 - Qualifying Facility Wind PPAs
,-^
--
".t. ,.,r}t "{,," "{| "NP ,sP "s} ,of "s,t ,$
I 1,s00
I1,000
10,500
10,000
9,000
-(F20l7lRP +-2017lRP Update
9,500
WY t7 J t7 JCasper Wind (Chevron)
IChopinWAl01l0
239 38Everpower(r)WY
Foote Creek II WY 2 0 2 0
4Foote Creek III WY 25 4 25
9 60 9Latigo Wind UT 60
Mariah Wind OR l0 I 10 I
40 6Meadow Creek Project - Five Pine ID 40 6
24
Wind and Solar Qualifying Facility Resource Updates
2017IRP Preferred
Portfolio 2017IRP Update
Qualifying Facilities State Capacity
(M\Y)
L&R
Balance
Capacity
at
System
Peak
(M!v)
Capacity
(Mw)
L&R
Balance
Capacity
at
System
Peak
(Mrv)
PaCIpICOnp _2017 IRP UPDATE Cna.prEn 4 - Loao-aNo-RESoURCE BALANCE UpDATT
(1) New since the 2017 IRP
Table 4.2 - Qualifying Facility Solar PPAs
2017 IRP Preferred
Portfolio 20l7IRP Update
Qualifying Facilities
Meadow Creek Project - North Point
State
ID
Capacity
(Mw)
80
L&R
Balance
Capacity
at
System
Peak
(Mw)
l3
Capacity
(Mw)
80
L&R
Balance
Capacity
at
System
Peak
(Mw)
13
Monticello Wind (')UT 79 13
Mountain Wind Power I WY 61 l0 6l 10
Mountain Wind Power II WY 80 l3 80 l3
Orchard Wind WA 40 5 40 5
Oregon Wind Farms I & II OR 65 8 65 8
Orem Family Wind OR l0 I l0 I
Pioneer Wind Park I WY 80 13 80 13
Power County Wind Park North ID Z)4 23 4
Power County Wind Park South ID ./.)4 23 4
Spanish Fork Wind Park2 UT 19 -J t9 J
Three Mile Canyon WA l0 I l0 I
Tooele Army Depot t't UT J 0
Small Wind WY 0.2 0 0.2 0
TOTAL - Purchased Wind 6s4 97 975 148
2017 IRP Preferred
Portfolio 2017IRP Update
Qualifying Facilities State Capacity
(Mw)
L&R
Balance
Capacity at
System
Peak (MW)
Capacity
(Mw)
L&R
Balance
Capacity at
System Peak
(Mw)
Adams Solar Center OR l0 6 l0 6
Bear Creek Solar Center OR 10 6 l0 6
BeattY Solar(3)OR 5 3
Beryl Solar UT J I J I
Black Cap Solar II OR 8 5 8 5
Bly Solar Center OR 9 6 9 6
Buckhorn Solar UT J I J I
Cedar Valley Solar UT 3 I 3 I
Chiloquin Solar OR l0 5 10 5
Collier Solar OR l0 6 l0 6
25
PACIFICoRP _2017 IRP UPDATE CHApIE,R 4 - Lono-a,No-REsouncp, Be,leNce Uppern
Elbe Solar Center OR l0 6 l0 6
Enterprise Solar UT 80 47 80 47
Escalante Solar I UT 80 47 80 47
Escalante Solar II UT 80 47 80 47
Escalante Solar Ill UT 80 47 80 47
Ewauna Solar OR I I I I
Ewauna Solar 2 OR 3 2 J 2
SunE Solar XVII Proiect 1 - 3 (2)UT 9 5 9 5
Granite Mountain - East UT 80 47 80 47
Granite Mountain - West UT 50 30 50 30
Granite Peak Solar UT J 1 )1
2 I 2 IGreenville Solar UT
Iron Springs UT 80 47 80 47
Ivory Pine Solar OR 10 6 l0 6
Laho Solar UT J I 3 I
Merrill Solar OR l0 l0 6
Milford Flat Solar UT J 2 J 2
IMilford Solar 2 UT J I J
Norwest Energy 2 (Neff)OR l0 6 l0 6
Norwest Energy 4 (Bonanza)OR 6 4 6 4
6Norwest Energy 7 (Eagle Point)OR 10 6 l0
Norwest Energy 9 Pendleton OR 6 3 6 J
OR Solar 2, LLC (Agate Bay)OR 10 6 l0 6
OR Solar 3, LLC (Turkey Hill)OR 10 6 10 6
8 5OR Solar 5, LLC (Merrill)OR 8 5
OR Solar 6, LLC (Lakeview)OR 10 6 l0 6
OR Solar 7, LLC (Jacksonville)OR r0 6 l0 6
OR Solar 8, LLC (Dairy)OR l0 6 l0 6
Pavant Solar UT 50 29 50 29
Pavant Solar II LLC UT 50 30 50 30
Pavant Solar III LLC UT 20 12 20 12
5Quichapa Solar l- 3 UT 9 5 9
Sage I Solar (r)WY 20 8
Sage II Solar tr)WY 20 8
Sage III Solar trr WY 18 7
3 2South Milford Solar UT J 2
26
2017 IRP Preferred
Portfolio 2017IRP Update
Qualifying Facilities State Capacity
(M!Y)
L&R
Balance
Capacity at
System
Peak (MW)
Capacity
(Mw)
L&R
Balance
Capacity at
System Peak
(Mw)
6
PaCIpIConp - 2017 IRP UPDATE CTTapTe,R 4 _ LoAD-AND-RESoURCE BALANCE UPDATE
2017 IRP Preferred
Portfolio 2017lRP Update
Qualifying Facilities State Capacity
(Mw)
L&R
Balance
Capacity at
System
Peak (MW)
Capacity
(Mw)
L&R
Balance
Capacity at
System Peak
(Mw)
Sprague River Solar OR 1 5 7 5
Sweetwater Solar WY 80 48 80 48
Three Peaks Solar UT 80 41 80 47
Tumbleweed Solar OR l0 5 10 5
Utah Red Hills Renewable Park UT 80 41 80 47
Woodline Solar OR 8 5 8
Small Solar UT I 0 I 0
TOTAL - Purchased Solar 1,145 679 1,197 699
( I ) New since the 20 I 7 IRP
(2) Formerly Fiddler's Canyon Solar l-3
(3) Contract terminated
Updated Capacity Load-and-Resource Balance
Load-and-Resource Balance Components
Capacity and energy balances make use of the same load-and-resource components in their
calculations. The main component categories consist of the following: resources, obligation,
reseryes, system position, new Energy Vision 2020 wind, and available front-office transactions
(FOTs).
The resource categories include resources by type-thermal, hydroelectric, renewable, QFs,
purchases, existing Class I demand-side management (DSM), sales, and non-owned reserves.
Categories in the obligation section include load, private generation, intemrptible contracts,
existing Class 2 DSM, and new Class 2 DSM from the updated resource portfolio. Both resources
and obligations can be represented as either a positive or negative value, which is consistent with
how these elements are represented in portfolio modeling.
A description of each of the resource categories, including a description of variances from the
summer load-and-resource balance in the 2017 IRP, is provided below.
Existing Resources
Thermal
This category includes all thermal plants that are wholly owned or partially owned by PacifiCorp.
The capacity balance counts thermal plants at maximum dependable capability at time of system
summer or winter peak, as applicable. The energy balance also counts them at maximum
dependable capability, but de-rates them for forced outages and maintenance. This includes the
existing fleet of coal-fueled units, and six natural-gas-fueled plants. These thermal resources
account for roughly two-thirds of the firm capacity available in the PacifiCorp system. lnthe2017
27
5
PacrprConp -2017 tRP UPDATE Cuaprsn 4 - Lono-aNn-RESoURCE BALANCE Upoarp,
IRP Update, certain coal plants had small increases in the assumed capacity when compared to the
2017 IRP. These changes reflect a reduced level of parasitic load associated with installation of
selective catalytic reduction systems, which results in a 16 MW increase in summer capacity
relative to the 2017 IRP.
Hydroelectric
This category includes all hydroelectric generation resources in PacifiCorp's system, as well as a
number of contracts providing capacity and energy from various counterparties. The capacity
balance counts these resources by the maximum capability that is sustainable for one hour at the
time of system summer peak, an approach consistent with current Western Electric Coordinating
Council (WECC) capacity-reporting practices. The energy associated with stream flow is
estimated and shaped by the hydroelectric dispatch from the Vista Decision Support System
model. Also accounted for are energy impacts of hydro relicensing requirements, such as higher
bypass flows that reduce generation. Over 90 percent of the hydroelectric capacity is on the west
side of the PacifiCorp system. An updated hydro generation forecast reflects changes to the
Umpqua River hydro facilities peak capacity projections with varying impacts in specific years
throughout the planning period.
Renewable
This category includes geothermal and variable (wind and solar) renewable resource capacity. The
capacity balance counts geothermal capacity at the maximum dependable capability while the
energy balance counts the maximum dependable capability after forced outages. The capacity
contribution of wind and solar resources, represented as a percentage of resource capacity, is a
measure of the ability for these resources to reliably meet demand. PacifiCorp defines the peak
capacity contribution of wind and solar resources as the availability among hours with the highest
loss-of-load probability. PacifiCorp updated its capacity contribution values for solar and wind
resources, differentiated byresource type and balancing authority area in the 20l7IRP and uses
these same capacity-contributionvalues, as shown in Table 4.3 below, in the 2017IRP Update.
PacifiCorp's wind repowering project results in a net two MW increase in peak capacity by 2021.
28
PactprConp -2017 IRP UPDATE CHaprpn 4 - LoAD-AND-REsounce BALANCE Upon'rs
East Balancing Authority Area West Balancing Authority Area
Wind Fixed Tilt
Solar PV
Single Axis
Tracking
Solar PV
Wind Fixed Tilt
Solar PV
Single Axis
Tracking
Solar PV
Capacity
Contribution
Percentage
15.8%37.gyo 59.7%ll.8Yo s3.9%64.8%
Table 4.3 - Summer Peak C Contribution Values for Wind and Solar
Purchases
This includes all major purchase contracts for firm capacity and energy in the PacifiCorp system.l
The capacity balance counts these by the maximum contract availability at the time of system
summer peak. The energy balance counts contracts at optimal economic model dispatch. Purchases
are considered firm and thus planning reserves are not held for them. There were no changes in
purchases from what was assumed in the 2017 IRP.
Oualifyine Facilities
All QFs that provide capacity and energy are included in this category. Like other purchases, the
capacity balance counts non-wind and non-solar QFs at maximum system summer peak
availability. The capacity balance counts wind and solar QFs using the assumed capacity-
contribution values summarized in Table 4.3 above. The energy balance counts QFs at expected
generation levels. By 2022, the addition of incremental wind and solar QF contracts increases
system capacity at the time of peak load by 7l MW. Other QF contracts increase the capacity at
the time of peak load by an additional six MW.
Disoatchable Load (Class I DSM)
Existing dispatchable load control program capacity is categorized as an increase to resource
capacity. This is in line with the treatment of DSM capacity in the latest version of the System
Optimizer model that PacifiCorp uses to select resources. There were no changes in Class I DSM
from what was assumed in the 2017 lRP.
Sales
This includes all contracts for the sale of firm capacity and energy. The capacity balance counts
these contracts by the maximum obligation at time of system summer peak and the energy balance
counts them by expected model dispatch. All sales contracts are firm and thus planning reserves
are held for them when accounting for these contracts in the capacity balance. There were no
changes in sales from what was assumed in the 2017 IRP.
Non-owned Reserves
Non-owned reserve capacity is categorized as a decrease to resource capacity to represent the
capacity required to provide reserves as a balancing authority for load and generation that are in
PacifiCorp's balancing authority area (BAA) but not owned by PacifiCorp. There are a number of
counterparties that operate in PacifiCorp control areas that purchase operating reserves. The annual
reserve obligation is about 3 MW and 38 MW on the west and east BAAs, respectively. The non-
owned reserves do not contribute to the energy obligation because this requirement is for capacity
only. The non-owned reserves were updated in the 2017 IRP Update resulting in a small, three-
MW decrease relative to the 2017 IRP.
' PacifiCorp has curtailment contracts for approximately 172 MW on peak capacity that are treated as firm purchases.
PacifiCorp has the right to curtail a customer's load as needed for economic purposes. The customer in tum may or
may not pay market-based rates for energy used during a curtailment period.
29
Obligation
The obligation is the total electricity demand that PacifiCorp must serve, consisting of forecasted
retail load less private generation, existing Class 2 DSM, new Class 2 DSM from the preferred
portfolio, and intemrptible contracts. A description of each of these obligation categories,
including a description of variances from the summer load-and-resource balance in the 2017 IRP,
is provided below.
Load and Private Generation
The largest component of the obligation is retail load. In the 2017 IRP, the hourly retail load at a
location is first reduced by hourly private generation at the same location. The system coincident
peak is determined by summing the net loads for all locations (topology bubbles with loads) and
then finding the highest hourly system load by year. Loads reported by east and west BAAs reflect
loads at the time of PacifiCorp's coincident system summer peak. The energy balance counts the
load on a monthly basis by on-peak and off-peak hours. Summer peak loads net of private
generation are lower in the 2017 IRP Update than in the 2017 IRP.
PacifiCorp's2017 IRP Update load forecast was finalized in August 2017. Relative to the load
forecast prepared for the 2017 IRP, PacifiCorp system sales decrease over the planning period.
While economic conditions continue to improve following the most recent recession, a less
favorable outlook for select industrial customers results in lower sales projections relative to the
2017 IRP. Further, the2017 IRP Update forecast projects that residential customers are likely to
use more efficient appliances, which results in a lower residential forecast relative to the 2017 IRP
load forecast.
Furthermore, the 2017 IRP Update incorporates a methodological update for the treatment of
private generation and how it affects the coincident peak. In previous IRPs, the load forecast
summed the hourly output for seven different private-generation sources to produce the hourly
private-generation shape within each state. For the 2017 IRP Update, since a high percentage of
forecasted private generation is solar (>90yo), a more appropriate methodology was adopted to
weight the seven individual private-generation sources by annual capacity. This improvement to
the methodology results in better alignment of solar occurring at the time of coincident peak than
was identified when using the prior, unweighted approach.
Class 2 DSM
An adjustment is made to load to remove the projected embedded Class 2 DSM as a reduction to
load. Due to timing issues with the vintage of the load forecast, there was a level of 2016 Class 2
DSM that was not incorporated in the forecast for the 2017 IRP. The 2016 Class 2 DSM forecast
of 100 MW was accounted for by adding an existing Class 2 DSM resource in the load-and-
resource balance; this adjustment was not required for the 2017 IRP Update because the 2016
projected embedded Class 2 DSM is included in the load forecast. The DSM line also includes the
selected Class 2 DSM from the 2017 IRP Update resource portfolio, which, consistent with a
reduction in overall load, results in a decrease in incremental Class 2 DSM totaling 77 MW by
2027 when compared to the 2017 IRP.
30
PacIrICOnp - 20I7 IRP UPDATE CHAPTER 4 - LOAD-AND-RESOUNCE BALANCE UPNRTP
PeCIpICoRT - 20I 7 IRP UPDATE CHapren 4 - Loap-nNo-R-esouRcs BeleucE Upoa.rs
Intemrptible Contracts
PacifiCorp has intemrptible contracts for approximately 195 MW of load intemrption capability.
These contracts allow the use of 195 MW of capacity for meeting reserve requirements. Both the
capacity balance and energy balance count these resources at the level of full load intemrption
available. Intemrptible resources directly curtail load and thus full planning reserves are not held
for the load that may be curtailed. As with Class I DSM, this resource is categorized as a decrease
to the peak load. There were no changes in intemrptible contracts from what was assumed in the
20l7IRP.
Planning Reserves
Planning reserves represent an incremental planning requirement, applied as an increase to the
obligation to ensure that there will be sufficient capacity available on the system to manage
uncertain events (i.e., weather, outages, variable resources) and known requirements (i.e.,
operating reserves).
System Position
The system position is the resource surplus or deficit after subtracting obligation plus required
reserves from total resources. While similar, the system position calculation is slightly different
for capacity and energy. Thus, the position calculation for each of these balances are presented in
their respective sections later in this chapter.
Energy Vision 2020 Wind
For the 2017 IRP Update, PacifiCorp has incorporated capacity from the new Energy Vision 2020
wind projects as a separate line item starting in 2021. While these projects are undergoing a
regulatory review and approval processes, the capacity contribution associated with these wind
resources, and their associated impact on the system position, is provided for informational
purposes.
Available FOTs
As is the case with Energy Vision 2020 wind resources, PacifiCorp also shows available capacity
from uncommitted FOT resources. These resources are shown as the amount of uncommitted
FOTs that could be used to satisfy any remaining short system capacity position (after accounting
for the capacity contribution from Energy Vision 2020 wind resources) up to the maximum level
of FOT procurement assumed available for planning purposes. As is the case with Energy Vision
2020 wind resources, these data are shown for informational purposes. Any resource that is lower
cost and lower risk can displace FOTs when selecting resources in the preferred portfolio.
Capacity Balance Determination and Results
Methodology
The system position, which represents the projected capacity need, nets existing resources against
the projected obligation while accounting for planning reserves. The basic formulae used to
establish the system position are summarized below.
3l
PACIF.IC0RP - 20 I 7 IRP UPDATE CsaprEn 4 - LoAD-AND-RrsouRcp BALANCE UpDATE
Existing Resources: Thermal + Hydro * Renewable + Firm Purchases + Qualifying
Facilities + Existing Class I DSM - Firm Sales - Non-owned Reserves
The peak load, intemrptible contracts, existing Class 2 DSM, and new Class 2 DSM from the
preferred portfolio are netted together for each of the annual system summer and winter peaks, as
applicable, to compute the annual peak obligation:
Obligation: Load - Intemrptible Contracts - New and Existing Class 2 DSM
The amount of reserves to be added to the obligation is then calculated. This is accomplished by
the net system obligation calculated above multiplied by the l3 percent target planning reserve
margin (PRM) adopted for the 2017 IRP. The formula for this calculation is:
Planning Reserves: Obligation x PRM
The annual system capacity position is derived by adding the computed reserves to the obligation,
and then subtracting this amount from existing resources as shown in the following formula:
System Capacity Position: (Existing Resources) - (Obligation * Reserves)
Informational Calculations
As discussed above, for informational purposes, PacifiCorp has also shown how the system
capacity position is affected by Energy Vision 2020 wind resources:
System Position with New Energlt Vision 2020 ltind: (System Capacity Position) +
(New EV 2020 Wind)
Similarly, and also for informational purposes, PacifiCorp also shows how the potential acquisition
of uncommitted FOTs could be used, if lower cost and lower risk than other resource alternatives,
to meet any remaining system capacity shortfall:
Net Surplus (Deficit) : (System Position with New Energy Vision 2020 Wind) +
(Uncommitted FOT's to meet remaining Need)
"Uncommitted FOT's to meet remaining Need" refers to that portion of available FOT's
that could be used to meet any remaining capacity deficit calculated in the "System Position
wAllew EV 2020 Wind" calculation without exceeding the maximum level of FOT
procurement assumed available for planning purposes.
Figure 4.3 summarizes the 2017 IRP Update capacity load-and-resource balance, prior to acquiring
any new resources and making firm market purchases, alongside the load-and-resource balance
from the 2017 IRP. Before accounting for Energy Vision 2020 wind resources and uncommitted
FOTs, PacifiCorp shows a capacity deficit beginning 2018. This deficit is lower, on average, than
in the 2017 IRP by approximately 408 MW over the 2018-2027 time frame due in large part to the
decreased load forecast net ofprivate generation.
32
PeCmrConp - 20 I 7 IRP UPDATE CHAPTER 4 - LOAD-AND-RESoURCE BALANCE UpoeTT,
r:OlTlRP
, 201 7 tRP Update
20 llt 20le l(r20 l0tl 202(;2\)27
o
(2o0)
(4OO)
( r,0oo)
( l,20o)
( r,4oo)
2023 20:.1 2025
(600)
( 80o)
201 I
4.3 - Summer Position Co Chart
Table 4.4 through Table 4.7 present the capacity load-and-resource balance details from the 2017
IRP Update and the 2017 IRP for the summer and winter peak. The load-and-resource balance
tables show the system position before Energy Vision 2020 wind resources and uncommitted
FOTs. Line-item differences between the 2017 IRP and2017 IRP Update are shown in Table 4.8
and Table 4.9.
JJ
Pe.Cm,rCOnp - 20 I 7 IRP UPDATE Cuaprsn 4 - LoAD-AND-RESoURCE BALANCE UpDATE
Table 4.4 - Summer Peak - System Capacity Load and Resource Balance without Resource
Additions, 20 I 7 I RP Update (2018-2027) (Megawatts)2
ClalendarYear 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
First
Theml
Hydroelectric
Renewable
Purchases
Qualifying Facilities
Class I DSM
Sales
Non-Omed Reserues
Fas t Fxis ti ng Resources
tlad
Private Ceneration
lntemptible
DSM
East oHigation
Planning Resenes (13%)
East OHigation + Reserres
East Position
AwilaHe Front Oflice Transactions
6,403
t07
t96
249
@8
323
(65s)
(15)
7236
6,t23
l14
t94
249
691
323
(65s)
(35)
7,004
6,91 I
( 166)
( le5)
(l7r)
6378
855
6,t23
rt4
199
249
743
323
(655)
(35)
7,061
5,736
l14
197
221
735
(175)
(3s)
7,117
5,736
l4
190
221
738
323
(t75)
(15 )
7,112
7,n5
(220)
( le5)
(l le)
6382
855
5,736
ll4
190
22t
734
323
(t75)
(15 )
7,1 08
5,736
93
190
221
679
323
( 148)
(3s)
7,061
5,736
93
lm
t2t
674
323
(t48)
(15)
6,955
5,654
93
180
t2l
670
323
(66)
(35)
6,941
5,654
93
180
t2l
666
323
(66)
(15)
6,937
7,365
(169)
( 195)
(5s5)
6,346
6,853
( 108)
( 195)
( ll8)
6,432
862
6,972
( 20:)
( 195)
€16)
6)49
851
7,200
( l -19)
318
7,041
(213)
(le5)
1273\
6360
852
7,254
(l{6)
318
7 ?{q
(214)
(r95)
(1 l0)
6,421
7,281
(220)
318
7,321
(?42)
(195)
(460)
6424
7,322
(252\
( res)
(50e)
636s
857 860 860 853 850
7,294
(sn)
318
7,233
(22e)
318
7,212
(es)
318
7284
(32e)
318
7,218
(277)
318
7,196
(260)
318
7236
(12{)
318
West
Thennal
Hydroelectric
Renewable
Purchases
Qualifying Facilities
Class I DSM
Sales
Non-Onned Reserues
West kisting Resources
had
Private Crnemtion
Intemptible
DSM
West oUigation
Planning Reserues ( I 3olo)
West OHigation + Reserws
West Position
AuilaHe Front Office Transactions
2,254
861
m
l8
235
J
( l6s)
(3)
3294
3,238
( t3)
0
(G)
3,161
2,254
747
88
I
220
3
1165)
(l)
3,146
3,279
( l9)
0
( 9-1)
3,166
') )\l
7q)
95
I
227
J
( l6s)
(3)
3,203
2,254
&3
95
I
203
0
(r6l )
(3)
3,034
3,312
(31 )
0
(1.14)
3,137
3,545
(51l)
I,352
2,254
587
65
I
194
0
(lr0)
(l)
2,988
2,254
624
65
I
187
0
(l r0)
(l)
3,018
3,351
(42)
0
(l8l)
3,129
407
2,254
655
60
I
185
0
(80)
(l)
3,072
3,366
(48)
0
( le8)
3,120
406
3,526
({s3)
t,352
2,254
655
60
I
184
0
(80)
(3)
3,072
) )\4
645
59
I
182
0
( 80)
(j)
3,058
) )\t
658
58
I
150
0
(80)
(3)
3,039
3,572
(21e1
13s2
3,578
({-12 )
r,352
3,293
(2s )
0
(lll)
3,t46
3,554
(3sl)
l3s2
3,331
(37)
0
( l6l)
3,132
3,539
(ssr)
r 3s2
3,535
(sl8)
l Js2
3,395
(55)
0
(2 r4)
3,126
406
3,533
(.16 r )
1352
3,4t5
(63)
0
(228)
3,124
3,s30
(1721
1352
3,436
(71)
0
(lll)
3,123
3,529
({e0)
l3s2
4ll 412 4W 408 407 406 406
System
Total Resources
OHigation
Reserws
OHigation + ReserEs
System P6ition
New Dr'2020 Wind
System Pcition w/ NewWind
AmilaUe Front OII!ce Transactions
Uncommited FOT's to meet remaining Need
Net Surflus (Deficit)
10,530
9.594
1,273
10,867
(137)
0
(337)
I,670
337
0
10,150
9,544
t,266
10,81 I
(661 )
0
(66r )
1,670
661
0
10,264
9,495
t.260
10,755
(.190)
0
(.190)
t,670
490
0
10,15 I
9,497
1,260
10,757
(606)
207
(399)
1,670
399
0
l0,l0l
9,5 t3
1,262
10,775
(675)
207
(,168)
1,670
468
0
10,126
9,526
1,2@
10,790
(6il)
207
(.157)
1,670
457
0
10,t33
9,541
1,26
r0,807
(674)
207
(467)
1,670
467
0
t0,u7
9,550
1,267
10,8 l7
(7e0)
207
(583)
1,670
583
0
9,999
9,490
t,259
10,749
(7.1e)
1,670
542
0
9,976
9,469
t,256
t0,725
(750)
1,670
543
0
207
(512)
207
(s-li)
2 The DSM line includes selected Class 2 DSM from the 2017 IRP Update resource portfolio.
34
7,183
12261
( le5)
( 365)
63e7
PACIFICoRP - 20 17 IRP UPDATE CHApTER 4 - Lono-aNo-RESoURCE BRleNcs Upoere
Table 4.4 (cont.) - Summer Peak - System Capacity Load and Resource Balance without
Resource Additions, 201 7 IRP Update (2028-2036) (Megawatts)3
C-alendarYear 2028 2029 2030 2031 2032 2033 2034 2035 2036
Fast
Theml
Hydroelectric
Renewab le
Purchases
Quali$ing Facilities
Class I DSM
Sales
Non0wned Reserues
li'lst Fxisting Resources
toad
Private Genemtion
Interruptible
DSM
Fast oHigation
Planning Resewes (13%)
Fist Obligation + Reserws
Fast Position
AlailaUe Front OfIice Trans actions
4,892
93
180
121
662
323
(66)
(35)
6,171
7,445
(288)
( le5)
(602)
6"360
4,892
93
180
t2l
655
323
(66)
(35)
6,t64
4,459
93
t26
t2t
&8
323
0
(15)
5,736
4,459
93
126
t2l
637
323
0
(35)
5,725
7,ffi
(261)
(res)
(771\
6,413
4,102
93
t26
t2l
s89
323
0
(35)
s32O
7,789
(308)
(l9s)
( rJ35)
6Asr
4,021
93
126
121
584
323
0
(35)
s234
7,872
(333)
(le5)
(863)
6,481
868
4,Ul
93
126
t2l
532
323
0
(-15)
5,182
7,953
(354)
(tes)
(8e2)
6,512
872
7 384
(2,20f)
318
4,102
93
126
t2l
60s
)25
0
(3s )
s337
4,53s
93
158
t2t
652
323
(66)
(35)
5,782
852 855
7,521
(l0l )
(195)
(645)
6378
7,601
(324)
( r95)
(690)
6J93
7,249
(t,467)
3r8
7,543
(236)
(re5)
(734)
6J78
7 232
(r,4e6)
318
7.716
(284)
(re5)
(tt05)
6432
856 854 8s9 862 8@
7 213
(l,042)
318
7,233
(r,068)
3r8
7,294
( 1,957 )
318
7 349
(2,1 l 6)
318
7,272
( r ,s47)
318
73rs
( l,99s)
318
West
Thernnl
Hydroelectric
Renewable
Purchases
Quali&ing Facilities
Class I DSM
Sales
Non-Owned Reserues
West Eristing Resources
Load
Private Generation
lntemrptible
DSM
West oHigation
Planning Reserues (l3o%)
West Obligation + Reser\,€s
West Position
ArrailaHe Front Office Transactions
1,541
653
53
I
96
0
(78)
(3)
2264
2,2s4 l,9m 1,900
653 653 6s3
55 54 54
lll
t49 138 133
000
(80) (78) (78)
(3) (3) (3)
3,030 2,666 2,660
1,900
653
53
I
t32
0
(7li )
(3)
2,659
1,900
6s3
53
I
99
0
(7n)
(3)
2,626
3,532
(80)
0
rlOlr
3,149
449
3,559
(e33)
t3s2
1,541
6s3
53
I
97
0
(78)
(3)
226s
1,541
6s3
53
I
97
0
(78)
(3)
2264
3,575
( r00)
0
(322)
3,1s2
3,s62
(r,2e8)
t3s2
1,541
653
53
I
94
0
(24)
(3)
2316
3,4s7
(78)
0
(2ss)
3,124
q6
3,530
(s00)
t)52
3,s03
(86)
0
(268)
3,150
410
3,560
(894)
t3s2
3,495
(e3)
0
(280)
3,122
3,528
(867)
r,352
3,5 l3
(72)
0
(2er)
3,150
3,559
(e00)
t3s2
3,554
(8e)
0
(3 r3)
3,152
3,s62
(1,297)
3,620
(lll)
0
(332\
3,176
3,589
(t J2s)
t3s2
3,6t2
(t221
0
(342)
3,149
409
3,558
(1,2.r2)
1352
406 409 410 4to 413
tem
Total Resources
OHigation
Reserrts
Ouigation + Reserws
System Pmition
Newf,V2020 Wind
System Position il NewWind
ArailaHe Front OIIIce Trans actions
Uncommited FOT's to meet remining Need
Net Surflus (Deficit)
9,201
9,4U
1,258
10,743
(r,s42\
2U
( 1,335)
1,670
1,335
0
8,830
9,s28
t,2g
1o,792
( I,962)
207
( l,7ss)
1,670
t,670
(ri6)
8,442
9,514
t,262
to,777
(2.334)
207
(2.127\
t,670
1,670
(.ls8)
8,395
9,527
1,2&
lo,79l
(2,396)
207
(2, l 8e)
1,670
|,670
(sle)
8,35 I
9,5O
r,268
10,83 l
(2,480)
207
12.273\
1,670
t,670
(601)
7,602
q 5R5
1,27t
10,856
(3,254)
207
(3,M7)
1,670
1,670
( I.378)
7,585
9,603
t,274
10,877
(3,293)
207
(3,0rJs)
7,497
9,658
1,281
10,938
(3,441)
207
(3,234)
1,670
1.670
( r.564)
7,497
9,661
1,281
10.943
(3,lu5)
207
(3,23n)
r,670
1,670
( l..ll6)
1,670
t,670
( 1.s69)
3 The DSM line includes selected Class 2 DSM from the 2017 IRP Update resource portfolio.
35
PACIFICORP _2017 IRP UPDATE CHeprsn 4 - Loeo-eNn-Rrsouncs BALANCE UpDATE
Table 4.5 - Winter Peak - System Capacity Load and Resource Balance without Resource
Additions,2017 IRP Update (2018-2027) (Megawatts) a
CalendarYear 2018 2019 2020 2O2l 2022 2023 2021 2025 2026 2027
['qs f
Thernal
Hydroelectric
Renewable
Purchases
Qualifying Facilities
Class I DSM
Sales
Non-Owned Reserves
Fqqt Bdsting Resources
toad
Private Cenemtion
Intemptible
DSM
East oHigation
Planning Reserues (13%)
East OHigation + Reserws
East Pmition
AuilaHe Front Ollice Transactions
6513
72
t%
734
691
0
(173)
(3s)
7,998
6,233
72
t99
734
742
0
(173)
(35)
7,772
5 5qO
(0)
(le5)
(84)
sSrr
6,233
72
197
734
740
0
(173)
r l5r
7,768
5,U6
72
190
235
745
0
(173)
(35 )
6,879
5,U6
72
190
235
736
0
(l7j)
(ls)
6,870
5,846
72
lm
23s
682
0
(r7l)
(3s)
6,816
5,846
72
lm
l2l
6'78
0
( r.l8)
1.r5)
6,723
5,846
72
lm
t21
673
0
( l;18)
(35)
6,714
5,763
72
180
t2t
@
0
(66)
(35)
6,700
5,763
72
180
tzt
658
0
(66)
(35)
6,703
5,560
(0)
(les)
(56)
s3r0
6,025
1,973
318
5,629
(0)
(tes)
(il r)
s323
6,04t
1,727
318
5,69
(0)
(re5)
( r.+7)
5328
6,045
8-1.1
3l ti
5,730
(0)
(le5)
(lni)
5J52
5,785
(0)
( r95)
(2ltt)
5372
724
6,096
720
318
5,823
(0)
(re5)
(253)
5375
6,099
625
318
5,804
(0)
(le5)
(328)
s,280
5,992
7tt
318
5,825
(0)
(les)
(363)
s267
5,977
723
318
5,877
(0)
( re5)
(2er)
5392
716 716 7t7 718 721 724 726 712 7tO
6,026
1,716
3r8
6,073
797
3l8
6,1 l8
600
318
West
Therrnal
Hydroelectric
Renewable
Purchases
QualiSing Facilities
Class I DSM
Sales
Non-Omed Reserues
West kisting Resources
Inad
Private C-€neration
Intenuptible
DSM
West obligation
Planning Reserves (13%)
West Obligation + Reseres
West Position
AuilaHe Front OIIice Transactions
2,316
917
90
I
224
0
(162)
(3)
3r83
2,316
943
95
I
211
0
( 162)
(3)
3,402
2,316
940
95
I
n0
0
(ls4)
(3)
3,415
785
95
I
195
0
(ls4)
(3)
3,235
3,408
(0)
0
(ll0)
3,278
2,316
784
65
I
183
0
(r li)
(3)
3,233
2,316
786
65
I
t77
0
(l l3)
(3)
3228
783
60
I
t76
0
(81)
(l)
325r
2,316
747
59
I
175
0
(81)
(3)
3,253
3,498
(0)
0
(2r r)
3,247
427
3,714
(-16 l )
rJs2
2,3t62,316 2,3t6 2,316
784 794
58 56
l1
t7t 144
00
(81) (81)
(3) (3)
3246 3227
3,342
0
0
l 55)
3,246
427
3,713
(3-10)
1,352
3,723
(321 )
t3s2
3,384
(0)
0
(l0s)
3,274
3,705
(2e0)
t3s2
3,704
(468)
rJs2
3,431
(0)
0
(ts2)
3,279
3,705
(.r7.1)
t3s2
3,455
(0)
0
(17.i)
3,242
3,709
({8l )
lJ52
3,473
(0)
0
( le3)
3,280
426
3,707
({s6 )
lJs2
3,521
(0)
0
(228)
3,293
428
3,721
("17s)
r3s2
3,547
(0)
0
(241)
3303
429
3,732
(s06)
t3s2
3,376
(0)
0
(t3o)
3,295
428 426 426 126 427
System
Total Resources
OHigation
Reserws
OHigation + Reseres
System Position
New EV2020 Wind
System Pmition il NewWind
Awilable Front OlIice Transactions
nmited FOT'S to meet remaining Need
Net Surpus @eficit)
207
446
1 The DSM line includes selected Class 2 DSM from the 2011 IRP Update resource portfblio.
I 1,381
8,596
1,143
9,739
t,@3
0
|,643
1,67O
0
1,643
tt,t74
8,606
1,144
9,750
1,425
0
1,425
1,670
0
1,425
I 1,183
8,@2
I,144
9,745
1,438
144
1,582
I,670
0
1,582
l0,t l4
8,605
t,t44
9,749
365
10,103
8,631
t,147
9,778
324
207
531
1,670
0
531
10,044
8,655
I,1 50
9,805
239
I,670
0
446
s q75
8,6ss
I,l5l
9,805
t69
207
376
1,67O
0
376
9,971
8,678
l,l 54
9,832
139
9,949
8,573
l,l.l0
9,713
237
9,926
8,570
1,139
9,709
2t7
207
424
1,670
0
424
207
572
?o7
144
0
444
207
346
1,670
0
572
1,670 1,670
0
346
36
PncIrIConp _2017 IRP UPDATE Cuaprgn 4 - LoAD-AND-RssouRcp BALANCE UpDATE
Table 4.5 (cont.) - Winter Peak - System Capacity Load and Resource Balance without
Resou rce Additions, 20 I 7 IRP Update (2025-2036) (Megaw atts)s
CalendarYear 2028 2029 2030 203t 2032 2033 2034 2035 203 6
Fias t
Thernul
Hydroelectric
Renewable
Purchases
Qualifoing Facilities
Class I DSM
Sales
Non-Owned Reserues
toad
East &isting Resources
5,001
72
180
t2t
657
0
(66)
(35)
s,930
6,00s
(7s)
318
5,001
72
tu
t2t
653
0
(66)
(-ls)
5,911
4,94
72
126
t2t
650
0
(66)
r 15r
5,5r2
4,568
7Z
126
t2t
u6
0
0
(35 )
5,498
6,041
(0)
(le5)
(497\
s349
4,568
72
126
t2l
635
0
0
(35)
5,488
4,212
72
126
t2l
590
0
0
(r5)
5,086
4,130
72
126
tzt
570
0
0
f15)
4,985
4,130
72
t26
121
t75
0
0
rlSr
4,589
6,31 I
(0)
(l9s)
(615)
5,500
6,240
(l,6sr )
318
4,212
72
126
t2l
587
0
0
(3s)
5,083
Private Crneration
Intemptible
DSM
Planning Resewes (l3o%)
East Ouigation + Reserres
East Position
ArailaHe Front OIIice Transactions
5,884
(0)
(les)
(3e7)
tr'qst 6Higsti6n 5,292
713 717 718 721
5 q41
(0)
( les)
(429)
sJr9
6,036
(l 2s)
3r8
5,984
(0)
( r9s)
(461)
s326
6,043
(5-l I )
318
6,091
(0)
(re5)
i S)5r
s37l
6,094
(607)
318
6,150
(0)
(le5)
(s5l)
5,404
6,209
(0)
(tes)
l 57lt
5,440
6,173
( l ,090)
3r8
6,269
(0)
(les)
(594)
5,480
6,217
(1,233)
3r8
724 728 738 740
6,069
(s7l)
318
6,132
( I,045)
318
West
Thennal
Hydroelectric
Renewable
Purchases
Quali&ing Facilities
Class I DSM
Sales
Non-Owned Reserves
West E\isting Resources
Ioad
Private Ceneration
Intemlptible
DSM
West oHigation
Planning Reserues (13%)
West OHigation + Reser\,€s
West Position
ArailaHe Front Oflice Trmsactions
2,316
788
55
I
143
0
(8r)
(3)
3,219
1,962
788
54
I
133
0
(78)
(3)
2,856
t,962
788
53
I
102
0
(78)
(3)
2,826
t,962
788
53
I
98
0
(7ll)
(3)
2,82r
3,657
(0)
0
(ll6)
3341
434
1,fi2
788
53
I
97
0
(78)
(3)
2,461
3,684
(0)
0
(32e)
3,355
436
1,fi2
788
53
I
96
0
(78)
(3)
2,461
3,708
(0)
0
(341)
3367
438
1,602
788
53
I
95
0
(78)
(3)
2,460
3,731
(0)
0
(3s3)
3377
3,817
(1,357)
1352
1,ffiz
788
53
I
ll
0
(78)
(3)
237s
3,746
(0)
0
(365)
3J80
t,962
788
54
I
134
0
(78)
(l)
2,858
\ \1)
(0)
0
(260)
3312
431
3,743
(s24)
1352
3,599
(0)
0
(274)
3)2s
132
3,757
(899)
1352
3,615
(0)
0
(288)
3327
3,759
(90-r )
r352
3,636
(0)
0
(302)
3J33
3,766
(e.10)
t352
3,77 5
(es{)
l3s2
3,791
(r,330)
13s2
3,805
( l ,3.1,1)
t332
3,820
(r,,144)
432 433 439 439
System
Total Resources
Obligation
Reserws
Obligation + Reser\€s
System Position
New EV2020 Wind
System Position W NewWind
Auilable Front OfIice Trans actions
Uncommited FOT's to meet remaining Need
Net SurPus (Deficit)
9,149
8,6(X
1,144
9,748
(599)
207
(392)
8,769
8,&3
1,t49
9,792
( 1.024)
207
(8r7)
1,670
817
0
8,369
8,652
1,150
9,802
( 1..134)
207
(1.227\
1,670
1,227
0
8,324
8,682
I, t54
9,836
( 1.5 r2)
207
( 1.30.r)
1,670
1,304
0
8,309
8,7t2
r,158
9,870
( 1.561 )
207
( l.-154)
1,670
1,354
0
7,548
8,759
t,t&
9,923
(2.375)
207
(2. I 68)
r,670
t,670
(4ee)
7,543
8,807
1,170
9,978
(2..11.r)
207
(2.2?7\
1,67O
1,670
(558)
7,444
8,8s7
1,177
10,034
(2.590)
207
(2,382)
6,965
8,880
1,180
10,060
(3.09s)
207
(2,888)
t,670
1,670
( r,219)
1,670
392
0
1,67O
1,670
(7r 3)
s The DSM line includes selected Class 2 DSM from the2017 tRP Update resource portfolio.
)t
PaCIr.ICOnp - 20 I7 IRP UPDATE CHepTpn 4 - Loao-aNo-RESoURCE BALANCE UPDATE
Table 4.6 - Summer Peak - System Capacity Load and Resource Balance without Resource
Additions, 201 7 IRP (2015-2027) (Megawatts)6
CalendarYear 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Thernnl
Hydroelectric
Renewable
Purchases
Quali!ing Facilities
Class I DSM
Sales
Non-Orxned Reserues
East kisting Resources
tnad
6,406
106
201
249
646
323
(652)
(37)
7 241
6,126
l13
201
249
689
t/l
(65t)
r 17r
7,012
6,126
It3
201
249
681
)/)
(652)
(37)
7,004
7,250
( loo)
( le5)
(2e8)
6,657
5,739
ll3
l99
221
672
323
(t721
(37)
7,058
5,739
lt3
l9l
221
6t
323
(172\
(37)
7,038
5,739
ll3
l9l
22t
657
323
(t72t
(37)
7,034
7,509
(lr8)
( les)
(468)
6,728
900
5,739
92
l9l
22t
603
323
( l,16)
(37)
6,987
7,589
(r23)
( re5)
(.527)
6,744
x2
5,735
92
l9l
lzt
598
323
( 146)
(37)
6,878
7,688
(r3l)
( re5)
(s84)
6,779
907
5,&5
92
l8l
tzl
594
323
(63)
(37)
6,856
5,45
92
l8l
l2t
590
323
(63)
(37)
6,853
Private Ceneration
Intemptible
I)SM
Planning Reserves ( l3%)
East OHigation + Reserres
fast Pmition
AuilaHe Front OIfice Transactions
7,t02
(61)
ilq5r
( 190)
E st oHigation 6,657
891 887
7,\52
(83)
(t9s)
12461
6,629
7,516
(50{ )
318
7,353
(108)
( les)
(35s)
6,695
896
7591
(s33)
318
7,443
(l14)
( 195)
(,1r0)
6,725
900
7,692
( r,1l )
(le5)
(641)
6,714
898
1,612
(7s6)
318
7,774
(r53)
( 195)
(6971
6,729
900
7,629
(77 6\
318
891
7,548
(s{{ )
318
7,547
(306 )
3r8
7,624
(sn6)
318
7,628
(se{)
318
7,646
(6se )
318
7,685
(807 )
3r8
West
Theml
Hydroelectric
Renewable
Purchases
Qualirying Facilities
Class I DSM
Sales
Non-Owned Reserves
West kisting Resources
Ioad
Private Genemtion
Intemrptible
DSM
West obligation
Planning Reserues (13%)
West OHigation + Reseres
West Pmition
ArailaHe Front OIIice Transactions
2,247
859
93
l8
200
3
( 165)
(2)
32s3
2,247
717
93
I
2A
J
(165)
(2)
3,097
2,247
806
93
I
207
3
( l6s)
(2)
3,191
3,268
(ts)
0
(r52)
3,101
2,247
635
93
I
198
0
(l6l)
(2)
3,01I
3,291
( l7)
0
(r75)
3O98
403
3501
(48e)
rJs2
2,247
549
62
I
195
0
(il0)
(2)
2942
3,315
(20)
0
( 196)
3,099
403
3,502
(s60)
t3s2
2,247
u4
62
I
186
0
(il0)
(l)
3028
2,247
u4
55
I
150
0
(80)
(2)
3,0r 6
3,437
(37)
0
(278)
3,r22
406
2,247 2,247 2247
648 634 651
57 57 56
lll
185 184 182
000
(80) (80) (80)
(2) (2) (2)
3,056 3,042 3,056
3,192
(e)
0
(e7)
3,086
401
3,487
(2-1s )
lJs2
? )s,
(12)
0
(126)
3,1 l5
3,519
({23 )
13s2
3,338
(23)
0
(214')
3,101
403
3,505
(171\
1352
3,364
(26)
0
(212)
3,106
404
3,391
(2e)
0
(248)
3,1l4
405
3,4t4
(33)
0
(263)
3,117
405
3,523
(167\
l3s2
405 403
3,504
(313 )
l3s2
3,510
({s.r )
lJs2
3,518
({76 )
r3s2
3528
(s l -1)
1352
Total Resources
OHigation
Reserws
OHigation + Reserres
System Pmition
NewWind
System Pmition uy' NewWind
AmilaHe Front OIfice Transactions
Uncommited FOT's to meet remaining Need
Net Surflus @elicit)
t0,494
9,743
l,)O)
I 1,035
(s4r)
0
(s4l )
t,670
54t
0
10,109
9,743
1,292
I 1,035
(9)7\
0
(927\
1,670
921
0
10,194
9,758
1,294
I 1,052
(8s8)
0
(858)
1,670
8s8
0
10,069
9,793
1,298
I 1,092
( r,023)
174
(849)
t57O
849
0
9,980
9,824
r,302
n,t26
(1.r16)
t74
t972\
1,670
972
0
10,062
9,829
1,303
I 1,132
( r.070)
t74
(8e7)
I,670
897
0
10,043
q850
1,306
I 1,t56
(l.l ll)
174
(940)
1,670
940
0
1,670
t,l l0
0
9,912
9,831
1,303
l 1,135
( l.ll-.r )
1,670
1,049
0
9,869
9,851
1,306
n,t57
( 1.288)
174
( t.l l5)
1,670
l,l l5
0
9,920
9,892
l,3ll
n,203
( r.28,r)
174
( l.r r0)
174
( r,049)
6 The Load and Private Generation lines include an offsetting adjustment (average of 43 MW) from the 2017 IRP that
nets to zero. The DSM line includes selected Class 2 DSM from the 2017 IRP Pref'erred Portfolio.
38
[ast
PACIFICORP - 2OI7 IRP UPDATE Cuaprr,n 4 - Loa.o-euo-RESoURCE BALANCE Upoerp
Table 4.6 (cont.) - Summer Peak - System Capacity Load and Resource Balance without
Resource Additions, 201 7 IRP (2028-2036) (Megawatts)7
C'rlendar Ycar 2028 2029 2030 2031 2032 2033 2034 2035 2036
F'ast
Thernral
Hydroelectric
Renewable
Purchases
Qualifuing Facilities
Class I DSM
Sales
Non-Oumed Reserves
Eas t Eris ting Resources
had
Private C-€neration
lnterruptible
DSM
East oHigation
Planning Res erues ( l37o)
Fqst OUigation + Reserles
East Position
AmilaHe Front OIIice Transactions
4,883
92
l8l
t2t
586
323
(61)
(17)
6,087
4,883
92
181
t2t
s80
323
(61)
(37\
6,081
7,951
(182)
( r95)
(799\
6,775
906
7,681
(l,600)
318
4,526
92
159
tzt
576
323
(63)
(,17)
5,698
4,449
92
t27
t2t
562
323
0
(37)
5,637
8,299
(2s0)
(les)
(940)
6,914
4,092
92
t27
t2l
530
323
0
(37)
5,249
8,393
(27s)
(les)
(977)
6,946
4,092
92
127
t2l
5t4
323
0
(37)
5,232
8,460
(300)
(le5)
( 1.008)
6,957
4,010
92
127
t2l
506
323
0
(17)
5,143
8,584
(r23)
( res)
( r,037)
7,029
4,010
92
t27
t2t
454
323
0
(-r7)
5,091
8,72t
(-143)
(res)
( r.067)
7,1 l5
4,449
92
127
t2l
573
323
0
131 )
5,648
7,U2
(1fl)
(te5)
(749)
6,733
901
8,U4
(205)
( 195)
(rJ48)
6,796
909
7,70s
(2,007 )
318
8,152
(226\
( les)
(898)
6,832
7,746
(2,097)
318
9t4 924 928 930 939 950
7,634
(1.s47)
3r8
7,838
(2,201)
318
7,887
(2.6s4)
318
8,065
(2,97 4\
318
7,968
(2,ri2s )
318
7,875
(2,626)
318
West
Theml
Hydroelectric
Renewable
Purchases
Qualifying Facilities
Class I DSM
Sales
Non-Owned Reserues
\ves t Existing Resources
tlad
Private CEnemtion
Intemptible
DSM
West oHigation
Planning Reserues ( I 3oZ)
West OHigation + Reser\cs
West Position
AvailaHe Front OIIice Trmsactions
2,247
a4
52
I
149
0
(80)
(2)
3,0r2
3A6t
(42)
0
(2el)
3,128
q7
1,893
g4
5l
I
138
0
( 7r])
(2)
2,648
3,487
(4ti)
0
(104)
3,135
408
1,893
il4
5l
I
t33
0
(78)
(2)
2,643
3,512
(s6)
0
(3 l6)
3,140
t,893
g4
5l
I
132
0
(78)
(2)
2$42
3,536
(s)
0
(328)
3,144
N
1,893
644
5l
I
99
0
( 7tl)
(2)
2,608
3,559
(73)
0
(3.10)
3,147
1,534
644
5l
I
97
0
(78)
(2)
2,247
3,585
(82)
0
(3s0)
3,r54
1,534
&4
5l
I
97
0
(78)
(2\
2,247
3,608
(e2)
0
(360)
3,157
t,534
u4
5l
I
96
0
(7tt)
(2)
2246
3,634
( 102)
0
(370)
3,162
t,534
&4
5l
I
94
0
(21)
(2)
2298
3,ffi
(ilr)
0
(179)
3,168
409 4t0 410 .1il
3,534
(s22)
r352
3,543
(89{ )
t3s2
408
3,548
(e0s )
t3s2
3,553
(9u )
r)52
3,556
(e,ltt)
t3s2
3,564
(1,3r6)
t352
3,567
( r.-120)
l J52
3,574
(r..r27)
r352
412
3,580
( r .21r2 )
r352
System
Total Resources
OHigation
Reserws
OHigation + Reserws
System Position
NewWind
System Position w/ NewWind
AuilaHe Front Office Transactions
Uncommited FOT'S to meet remaining Need
Net Surflus (DeIicit)
9,89
9,86r
1,307
I 1,168
(2.068)
174
( I,n95)
1,670
1,670
(2?s\
8,729
9,910
t,314
n,223
(2.49s\
174
(2,32t\
1,670
t,670
(6sl)
8,341
9,936
|,3t7
1t,253
(2.912)
174
(2,718)
I,670
t,670
( I .06())
8,290
9,976
t,322
I 1,298
(-3.008)
t74
(2,834)
1,670
1,670
(r.l6s)
7,389
l0,l9l
I,350
I 1,541
("1.152)
174
(3,978)
7,389
10,283
t,362
n,&5
(4,2s6)
174
(.1.0It2)
1,670
1,670
( 1..1 r -.] )
1,670
1,670
( 1.309)
7 The Load and Private Generation lines include an offsetting adjustment (average of 43 MW) from the 2017 IRP that
nets to zero. The DSM line includes selected Class 2 DSM from the 2017 IRP Preferred Porttblio.
39
8,246
10,061
1,333
I 1,395
(1. l-19)
t74
(2.e75)
1,670
I,670
( l.-106)
7,496
10,100
1,338
I1,438
(3,s421
174
(3.76rJ)
1,670
1,670
(2.099)
7,479
10, I 14
1,340
n,454
(3.97s)
t74
(-r,801)
r,670
t,670
(2.131)
PeCmICOnp - 20 1 7 IRP UPDATE CHnprEn 4 - Loeo-eNo-RESoURCE, BaleNce UpDAlE
Table 4.7 Winter Peak - System Capacity Load and Resource Balance without Resource
Additions, 201 7 IRP (2018-2027) (Megawatts)8
ClalendarYear 2018 2019 2020 21121 2022 2023 2021 2025 2026 2027
trast
Theml
Hydroelectric
Renewable
Purchases
Qualifing Facilities
Class I DSM
Sales
Non-Owned Reseryes
Load
Fast Bisting Resources
6,514
72
201
688
2l
( 170)
(17)
8,023
6,234
72
201
734
680
2l
(170)
(371
7,73s
6,234
72
t99
734
676
2l
(170)
(17)
7,729
5,847
72
l9t
235
668
2l
( l70)
(,]7)
6,826
5,777
(.i tt )
I 195)
s288
5,U7
72
l9l
235
658
2t
( 170)
(37)
6,8r6
5,856
(40)
( 195)
(297).
5J23
5,847
72
l9l
235
604
2l
( 170)
( 37)
6,762
5,847
72
191
t2l
600
2t
( 116)
(-.i7)
6,670
5,843
72
l9t
t2l
595
2t
(t46)
(37)
6,661
5,753
72
l8l
t2t
591
2l
(6.1)
(37)
6,640
5,753
72
l8l
t2t
588
2l
(6.1)
(.17)
6,636
Private Generation
Intemptible
DSM
5,620
(20)
( 195)
( 132)
BastoHigation 5274
5,691
(19)
( 195)
(l7i)
s294
6,007
t,728
318
5,604
(15 )
( 195)
(llj)
5,161
5,857
1,872
3r8
5 q1)
(.+l)
( res)
(i40)
sJss
5,965
(44)
( r95)
(381 )
s343
6,063
607
318
5 q?o
(46)
( le5)
(42s)
s262
s,934
( 50)
(te5)
(.169)
5,220
6,W2
(54)
( le5)
(5lr)
sr32
Planning Reserues (13%)
Fast OHigation + Reserws
East Pmition
ArailaHe Front Oflice Transactions
7| 7t4 696 713 7t7 721 720 709 7M 718
5,985
2,039
3r8
600l
826
318
6,076
686
318
5g7l
689
318
5,924
716
318
6,050
586
318
6,040
776
318
West
Theml
Hydroelectric
Renewab [e
Purchases
Qualifying Facilities
Class I DSM
Sales
Non-Owned Reserves
West Existing Resources
Inad
hivate Crnemtion
Intemptible
DSM
West oHigation
Planning Reserues (13%)
West OHigation + Reserws
West Position
AnilaHe Front Oftce Transactions
2,308
915
93
I
192
0
(t62)
(2)
334s
3,29t
(2)
0
(109)
3,180
413
2,308
943
93
I
195
0
( 162)
(2)
3)77
3,306
IJ'
0
( 143)
3,160
4ll
2,308
937
93
I
197
0
( 154)
(2)
3381
3,417
(3)
0
(t74)
3239
42t
2,308
7U
93
I
190
0
( ls4)
(2)
32,21
3,360
(4)
0
(201)
3,155
410
2,308
782
62
I
183
0
(lll)
(2)
3221
3,379
(5)
0
(22s)
3,t49
409
2,308
783
62
I
t77
0
(lB)
(2)
32ls
3,400
(5)
0
(246)
3,149
409
2,308
779
57
I
t76
0
(81)
3238
2,308
786
56
I
175
0
(81 )
(2)
3244
3,542
(7)
0
(286)
3249
422
3,671
({2ri )
r3s2
2,308
784
53
I
t44
0
(81)
(2)
3207
2,308
7t36
55
I
t7t
0
(81)
(2)
3r38
35e3
(2{8)
1352
3,571
(r 9{)
l3s2
3,661
(2n0)
1352
3,565
(.1.1{)
1352
35s9
(338)
1352
3,558
(-1{-1)
t3s2
3,4t7
(6)
0
(267)
3,144
409
3,553
(-1l s)
l3s2
1 SSO
(7)
0
(304)
3247
422
3,49
(8)
0
(321 )
3,169
412
3581
(.17{)
t)s2
3,670
({-i l )
t)s2
System
Total Resources
OHigation
Reserws
OHigation + Reserws
System Poeition
l 1,369
8,453
1,124
9,578
|,791
I I,l t2
8,453
t,124
9,578
1,534
I I,l l0
8,400
t,\7
9,5 l8
t,592
t,670
0
t,592
I,670
0
655
r0,037
8,472
1,t27
9,599
438
9,978
8,503
I,l3l
9,634
344
1,670
0
517
9,908
8,487
1,129
9,616
?92
t,670
9,905
8,51 I
1,t32
9,93
262
1,670
0
436
9,878
8,467
1,t26
9,593
285
t74
459
1,670
0
459
9,843
8,501
I,130
9,632
2t2
174
386
t,670
0
386
NewWind 0
System Pmition w/ NewWind 1,791
AlailaHe Front OIfice Transactions
Uncommited FOT'S to meet remaining Need
Net Surflus (Delicit)
I,670
0
1,79t
0
1,592
174
655
t74
6t2
t74
517
t74
436
0
1,534
t74
466
t,670
0
1,534
1,670
0
6t2
0
466
8 The Load and Private Generation lines include an offsetting adjustment (average of 15 MW) from the 2017 IRP that
nets to zero. The DSM line includes selected Class 2 DSM from lhe 2017 IRP Prefened Portfolio.
40
t0,M7
8,,143
1,123
9,566
48r
Fast
Theml
Hydroelectric
Renewable
Purchases
Qualifiing Facilities
Class I DSM
Sales
Non-Owned Reserves
Eas t Exis ting Resources
Inad
Private Generation
Intemptible
DSM
East oHigation
Planning Reserves ( I 3%)
East Obligation + Reserr,ts
East Position
Awilable Front OIIice Trans actions
4,991
72
165
l2l
577
2l
(61)
(.37)
5,848
4,991
72
t8t
lzl
580
2l
(63)
(37)
s,867
4,634
72
t27
t2l
573
2t
(63)
(-37)
5,449
6,332
(73)
(195)
(624)
5,440
4,557
72
t27
tzt
570
2l
0
(37)
5,431
4,557
72
127
tzt
559
2t
0
(37)
5,420
6,4&
(89)
(te5)
(6e2)
5,488
4,2W
72
127
t2t
5t4
2t
0
(17)
5,018
6,545
(e8)
(le5)
(719)
5,532
4,200
72
127
t2t
5ll
2t
0
(17)
5,0r5
6,630
(r07)
(le5)
(741)
5,586
4,1 l8
72
t27
l2l
493
zl
0
( 37)
4,915
6,722
( ll5)
(te5)
(7$\
5,648
4,1 l8
72
t27
tzt
109
2t
0
( 37)
4,532
6,750
(r23)
(re5)
(786)
5,646
6,180
(s8)
( l9s)
(5s0)
s376
6,1 00
(23{ )
318
6,2ffi
(65)
(le5)
(587)
sAtg
6,149
(-r0l )
318
6,2&
(8r)
(195)
(661 )
s327
724 730 733 718 739 715 75t 760 759
6,172
(723)
318
6,04s
(6 l.l)
318
6,226
(806 )
318
6,277
(1,2s8)
318
6337
( I ,-i22)
318
6,408
( r ,.1e2 )
318
6,406
( r ,{t7{)
318
PnclpIConp _2017 IRP UPDATE Cueprr,n 4 _ Loeo-euo-RESoURCE BALANCE UpoeTE
Table 4.7 (cont.) - Winter Peak - System Capacity Load and Resource Balance without
Resource Additions, 201 7 IRP (2028-2036) (Megawatts)e
Calendar Year 202a 2029 2030 2031 2032 2033 2034 2035 2036
Therrol
Hydrcelectric
Renewable
Purchases
Qualifying Facilities
Class I DSM
Sales
Non-Owned Resewes
West Existing Resources
toad
Private Generation
Interruptible
DSM
West oHigation
Planning Reserues ( I 3oZ)
West OHigation 4 Reseres
West Position
Avrilable Front OIIice Transactions
4t2 413 412 427
2,308 1,9s4 1,9s4
7U 784 7U
52 5l 5l
ll1
143 134 133
000
(81 ) (78) (78)
(2) (2) (2)
3105 2,444 2843
1,954
784
5l
I
tw
0
(78)
(2)
2,812
1,954
784
5l
I
98
0
(78)
(l)
2,807
1,595
784
5l
I
97
0
(78)
(2)
2,448
3,628
( l8)
0
(.108)
3,202
3,618
( r,r 70)
t3s2
1,595
784
5l
I
97
0
(78)
(2)
2,447
1,595
7U
5l
I
96
0
(78)
(l)
2,446
3,668
(23)
0
(.1-13)
3212
3,630
( 1,r 8{)
r352
1,595
7U
5l
I
lt
0
(78)
(2)
2362
3,515
(10)
0
( i-17)
3,168
3,580
(-17s)
lJs2
3,538
(ll)
0
(351 )
3,r 75
3,588
(7{{ )
lJs2
3,546
(ll)
0
( i67)
3,167
3,578
(736)
rJs2
3,680
( l4)
0
(381 )
338s
3,7t2
(8ee)
1352
3,ffi7
( l6)
0
(3e5)
3,195
415
3,611
(80.1)
r3s2
3,&8
(21)
0
(.+10)
3,208
3,625
(r,r 78)
l3s2
3,654
(25)
0
(44s)
3,tE4
3,598
(r.2-16)
t3s2
.+16 417 4ltt 114
System
Total Resources
Obligation
Reseres
Obligation + Reserws
System Position
NewWind
System Position w/ NewWind
Arailable Front Ollice Trans actions
Uncommited FOT's to meet remaining Need
Net Surplus @eficit)
9,O72
8,545
1,t36
9,681
(60e)
t74
(435)
t,670
435
0
8,691
8,594
I,143
9,737
( r,0.1s)
t74
(87r)
1,670
871
0
8,292
8,607
1,144
9,751
( r.,+59)
174
( r,28s)
1,670
1,285
0
8,243
8,612
1,145
9,757
(1,514)
174
( l,r40)
1,670
1,340
0
8,228
8,683
1,154
9,837
( 1,609)
174
( 1,436)
1,670
t,436
0
7,46
8,734
l,l6l
9,895
(2,129',
t74
(2,2ss)
r,670
1,670
(586)
7,462
8,793
I,168
9,962
r ) i{)Or
174
(2,326)-
t,670
1,670
(6s71
7,361
8,860
I,t77
10,037
12,6761
174
(2,s02)
1,670
1,670
(833)
6,893
8,830
1,t73
10,003
(i.r r0)
174
(2,e36)
1,670
I,670
(1,267\
e The Load and Private Generation lines include an offsetting adjustment (average of l5 MW) fiom the 20 l7 IRP that
nets to zero. The DSM line includes selected Class 2 DSM from the 2017 IRP Preferred Portfolio.
4t
West
East
Theml
Hydmelectric
Renewable
Purchases
Qualifying Facilities
Class I DSM
Sales
Non-OMed Reseryes
Fas t Eris ting Resources
toad
Private Ccneration
Intemptible
DSM
East oHigation
Planning Resewes ( I 3olo)
FiNt OHigation + Reserws
F4s t Pcilion
Awilade Front OfIice Transactions
(l)
I
(6)
0
2
0
(l)
3
(s)
(1.+9)
(.17)
0
72
(22{)
(le)
(2s3 )
244
0
(2)
I
(8)
0
I
o
(l)
3
(8)
( 2.11 )
(8.3)
0
73
(2sl)
(31)
(2)
I
(l)
0
0
(3)
J
74
(2)
I
(l)
0
77
0
(3)
3
2
I
(l)
0
77
0
(3)
3
7E
9
I
(l)
0
76
0
(3)
3
t5
(370)
(ll0)
0
t32
(3,te)
(4s)
(3e4)
479
0
9
I
(l)
0
76
0
(-.i)
E4
(2)
I
(3)
(l)(2)
I
(l)
0
0
(3)
3
74
(l)
0
62
0
(3)
3
60
o
62
0
(ll
J
57
(283 )
276
0
(3.1E)
405
0
(37e)
438
0
(36s)
439
0
(.r0 l )
474
0
(.1-12 )
516
0
(278)
( r02)
0
72
(30E)
(40)
(3 r2)
(10s)
0
82
(33s)
(44)
(328)
(106)
0
90
(343)
(,ls)
(388)
462
0
(326)
( 108)
0
1M
(330)
(43)
(373)
447
0
r ltgt
(lll)
0
tt7
(323)
(42)
(368)
(lll)
n
124
(3ss)
(46)
(,108)
(lr6)
0
142
(3E3)
(s0)
PeCIpICOnp - 2017 IRP UPDATE CHAPTER 4 - LOAD-AND-RESOURCE BALANCE UPDATE
Table 4.8 - Summer Peak - System Capacity Load and Resource Balance without Resource
Additions,20l7 IRP Update less 2017IRP (2018-2027) (Megawatts)r0
Calendar Year 2018 2019 2020 2021 2022 2023 2021 2025 2026 2027
West
Therul
Hydrcelectric
Renewable
Purchases
Qualifying Facilities
Class I DSM
Sales
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bad
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\vest PGition
ABilaHe Front OIIice Transactions
44
(22)
0
l5
I
0
7
2
(2)
0
35
0
0
(l)
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32
75
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7
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27
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3
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26
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44
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065
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I
22
0
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OHigation + ReserEs
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New EV2020 Wind
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AwilaHe Flont Omce Transactions
Uncommitted F'llT's to meet remaining Need
Net Surdus (Delicit)
36
( l,l9)
( l9)
( 168)
2M
4l
( 199)
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26
70
(263)
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367
a
(303)
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440
108
(3,r2)
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494
87
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107
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82
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(38)
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120
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504450
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26
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0
(572\
0
r0 The DSM line reflects differences in Class 2 DSM resources between the 2011 IRP Update resource portfolio and
the2017 IRP Preferred Portfolio, which includes a level of 2016 Class 2 DSM (100 MW) that was not incorporated
in the load forecast for the 2017 IRP. The 2016 Class 2 DSM forecast of 100 MW was accounted for by adding an
existing Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP
Update because the 2016 projected embedded Class 2 DSM is included in the load forecast.
42
PacrprConp 2017 IRP UPDATE CsaprER 4 - Loeo-aNo-Rssounce BALANCE UpoerE
Table 4.8 (cont.) - Summer Peak - System Capacity Load and Resource Balance without
Resource Additions,2017 IRP Update less 2017IRP (2028-2036) (Megawatts)rr
Calendar Year 2024 2029 2030 203t 2032 2033 2034 2035 2036
East
Theml
Hydrcelectric
Renewable
Purchases
Quatifying Facilities
Class I DSM
Sales
Non-Owned Reserues
Fas t Exis ting Res ources
had
Private CEnemtion
Intemptible
DSM
East oUigation
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Fast Obligation + Reserws
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il
I
(l)
0
78
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0
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rrThe DSM line reflects differences in Class 2 DSM resources between the2017 IRP Update resource portfolio and
the2017 IRP Preferred Portfolio, which includes a level of 2016 Class 2 DSM (100 MW) that was not incorporated
in the load forecast for the 2017 IRP. The 2016 Class 2 DSM forecast of 100 MW was accounted for by adding an
existing Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP
Update because the 2016 projected embedded Class 2 DSM is included in the load forecast.
43
West
PacIpIConp - 2OI7 IRP UPDATE CHapren 4 _ Loeo-eND-RESoURCE BeLaNce UPDATE
Table 4.9 - Winter Peak - System Capacity Load and Resource Balance without Resource
Additions,20l7 IRP Update less 2017IRP (2018-2027) (Megawatts)r2
Calendar Year 20lE 2019 2020 2021 2022 2023 2024 2025 2026 2027
Theml
Hydrcelectric
Renewab le
Purchases
Qua[rying Facilities
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Sales
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bad
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r2 The DSM line reflects dift'erences in Class 2 DSM resources between the 2011 IRP Update resource portfolio and
the2017 IRP Pref-erred Portfolio, which includes a level of 2016 Class 2 DSM (81 MW) that was not incorporated in
the load forecast for the 2017 IRP. The 2016 Class 2 DSM forecast of 8l MW was accounted for by adding an existing
Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP Update
because the 2016 projected embedded Class 2 DSM is included in the load fbrecast.
44
69
(s)
o
Eas t
West
55
PACIFICORP _ 20 I7 IRP UPDATE Cuepren 4 - LoRo-eNo-Rssouncp BALANCE Upoare
Table 4.9 (cont.) - Winter Peak - System Capacity Load and Resource Balance without
Resource Additions,20lT IRP Update less 2017 IRP (2028-2036) (Megawatts)r3
CalcndarYear 202ra 2029 2030 2031 2032 2033 2031 2035 2036
Erst
Thetml
Hydroelectric
Renewable
Purchases
Qualifting Facilities
Class I DSM
Sales
Non-Ouned Reseryes
East Bisting Resources
trad
PriYate C€nemtion
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New EV2020 Wind
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0
(43)
0
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( -16)
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0
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13 The DSM line reflects differences in Class 2 DSM resources between the 2017 IRP Update resource portfblio and
the 2017 IRP Preferred Portfolio, which includes a level of 20 l6 Class 2 DSM (8 I MW) that was not incorporated in
the load forecast forthe 2017 IRP. The 2016 Class 2 DSM forecast of 81 MW was accounted forby adding an existing
Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP Update
because the 2016 projected embedded Class 2 DSM is included in the load forecast.
45
PACIFICORP -2017 IRP UPDATE CTupTeR 4 - Loeo-eNo-RESoURCE BALANCE UPDATE
Figure 4.4 through Figure 4.7 are graphic representations of the above tables for the 2017 IRP
Update annual capacity position for the summer system, winter system, east balancing area, and
west balancing area, respectively. Also shown in the system capacity position graphs are the
capacity contribution from Energy Vision 2020 wind resources and uncommitted FOTs, which as
discussed above, are provided for informational purposes.
Figure 4.4 - Summer System Capacity Position Trend
l2,ooo
10,000
8,O00
6,000
4,OOO
2,OOO
o
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
[]lll West trxisting Resources I East Existing Resources
r New EV2O20 Wind Uncommitted FOT's to meet remaining Need
+Obligation + 139/0 Planning Reseryes +Obligation
East Existing Resources
West Existing Resources
46
PACIFICoRP _201] IRP UPDATE Cueprgn 4 - LOAD-AND.RESOURCE BeIeNcg UPDATE
Etgqe
i rz.ooo
I O.(X)O
8,O00
6,O00
{.ooo
2,000
I 2.OO0
10,000
8,000
6,OOO
4.000
2,OOO
4.5 - Winter System Capacity Position Trend
U
o
2018 2019 2020 2021 2022 2023 2024 2025
tr- West Existing Resources
rNew EV2O20 Wind
*Obligation + 139lo Planning Reserues
2026 2027 202a 2029 2030 2031 2032 2033 2031 2035 2036
-
East Existing Resources
Uncommitted FO'f's to meet remaininq Need
+Obligation
Figure 4.6 - East Summer Position Trend
20ta 2019 2020 2021 2022 2023 2024 2025 2026 2027 202a 2029 2030 2031 2032 2033 2034 2035 2036
IEast Existing Resources r New EV202O Wind
East - Uncommitted FOT'S to meet remaining Need -GObligation + l3yo Planning Resenes
+East obligation
o
13oZ Reserues
East Existing Resources
West Existing Resources
East Existing Resources
47
I 37o Reserves
PacIpICOnr _ 2OI7 IRP UPDATE CHeprsR 4 - Loeo-aNo-RESoURCE Bal-aNcr UPDATE
4.7 - West Summer Position Trend
t2,ooo
I O,00()
West Existing Resources
8,OOO
I
E o.ooo l-rl=l
4,OOO
2,000
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 202a 2029 2030 2031 2032 2033 2031 2035 2036
r \[est f,xisting Resources West - Uncommitted Fot's to meet remaining need
+Obligation + 137" Planning Reseroes -swest obligetion
Energy Balance Results
The capacity position shows how existing resources and loads, accounting for coal unit retirements
and incremental energy efficiency savings from the 2017 IRP Update resource portfolio, balance
during the coincident summer and winter peak. Outside of these peak periods, PacifiCorp
economically dispatches its resources to meet changing load conditions taking into consideration
prevailing market conditions. In those periods when variable costs of system resources are less
than the prevailing market price for power, PacifiCorp can dispatch resources that in aggregate
exceed then-current load obligations facilitating off system sales that reduce customer costs.
Conversely, at times when system resource costs fall below prevailing market prices, system
balancing market purchases can be used to meet then-current system load obligations to reduce
customer costs. The economic dispatch of system resources is critical to how PacifiCorp manages
net power costs.
Figure 4.8 provides a snapshot of how existing system resources could be used to meet forecasted
load across on-peak and off-peak periods given the assumptions about resource availability and
wholesale power and natural gas prices. This snapshot does not reflect energy from Energy Vision
2020 wind resources. At times, resources are economically dispatched above load levels
facilitating net system balancing sales. At other times, economic conditions result in net system
balancing purchases, which occur more often during on-peak periods. Figure 4.8 also shows how
much energy is available from existing resources at any given point in time. Those periods where
all available resource energy falls below forecasted loads are highlighted in red, and indicate short
energy positions without the addition of incremental resources to the portfolio. During on-peak
periods and during off-peak periods, there are no energy shortfalls through the 2027 time frame,
however, the forecast shows on-going net balancing purchases in all years beginning 2018.
l)
48
5,000
4,000
3,000
2,000
1,000
0
nr$,""" r"J J o;^ -"*' op J C ."a' oP .J C ."$ "P J Ct 'J "/,J
On-Peak Energy Balance
rEnergy at or Below Load
-
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rNet Balancing Sale
Energy Available -
Net Balancing Purchase
-Load
5,000
4,000
3,000
2,000
1,000
0
of oi* ore ,J o$ o$ oP ."$ oP Jo/ o$ o/ ,"$ "t' J C' .,.*'.,u, .,J
Off-Peak Energy Balance
r Pnsrgy at or Below Load
r Energy Shortfall -Net
Balancing Sale
Energy Available -
Net Balancing Purchase
-Load
Pe,crr,rConp 2017 IRP UPDATE CuaprEn 4 LoAD-AND-RtSOUnCn Brrt.nNCE UpDA tE
re 4.8 -Positions
49
PncIpIConp 20IT IRP UPDATE CHaprEn 4 LoAD-AND-RESoURCE BalRNcs Upoarn,
[This page is intentionally left blank]
50
PaCrpIConp 20I7 IRP UPDATE Cue.pTgn 5 _ MODELTNG AND ASSUMPTIoNS UPDATE
CueprER 5 - MooELING AND Assul,rprroNs
Upoerp
Consistent with the 2017 IRP, the study period for the 201 7 IRP Update is 201 7 -2036, with a focus
on the 2018-2027 planning horizon. Updated resource portfolios were developed assuming a l3
percent planning reserve margin consistent with the stochastic loss-of-load-probability study
included in the 2017 IRP.
PacifiCorp has updated certain general assumptions in the 2017 IRP Update from the 201 7 IRP as
discussed below.
Inflation Rates
The20lT IRP Update model simulations and cost data reflect PacifiCorp's corporate inflation rate
schedule unless otherwise noted. A single annual escalation rate value of 2.27 percent is assumed
whereas 2.22 percent was assumed in the 2017 IRP. The annual escalation rate reflects the average
of annual inflation rate projections for the period 2017 through2036, using PacifiCorp's December
2017 inflation curve. PacifiCorp's inflation curve is a straight average of forecasts for gross
domestic product and consumer price index.
Discount Factor
The discount rate used in present-value calculations is based on PacifiCorp's after-tax weighted
average cost of capital (WACC). The value used for the 2017 IRP Update is 6.91 percent, updated
for the 2017 Tax Reform Act that reduced the federal income tax rate, up from 6.57 percent in the
2017 IRP. The use of the after-tax WACC complies with the Public Utility Commission of
Oregon's IRP guideline 1a, which requires that the after-tax WACC be used to discount all future
resource costs.lPresent-value revenue requirement values reported in the 2017 IRP Update are
reported in January 1,2017 dollars.
Production Tax Credits (PTCs)
The 2017 IRP Update model applies PTC benefits for eligible resources on a nominal basis rather
than on a levelized basis. This approach better reflects how the federal PTC benefits for these
projects will flow through to customers, conforms the treatment of PTC benefits with other costs
and benefits that are not actually spread over the life of an asset, and appropriately weights the
contribution of PTC benefits in present-value calculations.
t Public Utility Commission of Oregon, Order No. 07-002, Docket No. UM 1056, January 8,2001
51
General l
PACIFICORP - 20 I7 IRP UPDATE CuepTER 5 - MooaLNC AND ASSUMPTIONS UPDATE
Front Office Transactions (FOTs)
FOT modeling assumptions have not changed from the 2017 IRP to the 2017 IRP Update. Three
types of FOTs are modeled: an annual flat product, a heavy-load hour (HLH) July summer product,
and a HLH December winter product. An annual flat product reflects energy provided to
PacifiCorp at a constant delivery rate over all the hours of a year. The HLH transactions represent
purchases received 16-hours per day, six-days per week for July and December. Table 5.1 reports
the FOT resources included in the 2017 tRP and 2017 IRP Update modeling assumptions,
identifying the market hub, product type, annual capacity limit, and availability associated with
the product. PacifiCorp develops its FOT limits based upon its active participation in wholesale
power markets, its view of physical delivery constraints, market liquidity and market depth, and
with consideration of regional resource supply. Prices for FOT purchases are associated with
specific market hubs and are set to the relevant forward market prices, time period, and location,
plus appropriate wheeling charges, as applicable.
Table 5.1 - Maximum Available Front Office Transaction Quantity by Market Hub
Stochastic Parameters
PacifiCorp has not modified its stochastic parameters from the 2017 IRP in its 2017 IRP Update
modeling assumptions. PacifiCorp provided a detailed description of its stochastic parameters and
their development in Volume II, Appendix H of the 2017 IRP. While PacifiCorp discussed its
short-term correlation estimation process and calculation in Appendix H of the 2017 IRP, the
discussion did not include descriptions of the reason for the (sometimes) low correlations
subsequently requested by the Public Utility Commission of Oregon.2
2 See discussion and requirement to explain the reasons for the (sometimes) low correlations in the short-term
forecast pursuant to the Public Utility Commission of Oregon's 2017 IRP acknowledgement order issued April27,
2018, Docket LC 67.
Micl-Columbia (Mid-C)
Flat Annual ("7x24") or
Heavy Load Hour ("6X16")
Heavy Load Hour ("6X16")375
400
375
400
400 400
Caldornia Oregon Border (COB)
Flat Annual ("7x24") or
Heavy Load Hour ("6X16")
100 100Nevudu Oregon Border (NOB)
Heavy Load Hour ("6X16")
300 300Mona
Heavy Load Hour ("6X16")
52
Market Hub/Proxy FOT Product Type
Available over Study Period
Megawatt Limit and Availabitity
(Mw)
Summer
(July)
Winter
(December)
PeCIpIConp - 2017 IRP UPDATE CHApTER 5 - Moosr,rNc ANo AssuuprroNs UpDATE
The drivers for deviations can be different for different stochastic variables. One event can impact
a different combination of stochastic variables than another event. For example, load deviations
are usually due to weather/temperature deviations; generation deviations can also be driven by
weather deviations, renewable resource forecast deviations, and unplanned generator unit outages.
Power market prices can be affected by drivers that affect either load or generation, as well as the
unit commitment stack and the current marginal resource. For all of these categories, deviation
events which impact one part of PacifiCorp's system do not necessarily affect other parts of the
system, due to its geographic diversity and transmission constraints.
An example of low correlations from the 2017 IRP stochastic parameters is the correlation between
Kern-Opal natural gas price deviations, which can be caused by weather deviations in PacifiCorp's
east balancing area, and hydro, which is primarily driven by weather deviations in PacifiCorp's
west balancing area. Another example from the same table is the correlation between Mid-C power
market price deviations, which can be caused by drivers such as northwest weather deviations or
resource mix, and Wyoming load deviations, which can be driven by planned or unplanned
changes in industrial customer usage. Other examples include low correlations between different
load areas, which have deviations driven by local weather deviations and customer types, and low
correlations between west power markets (COB and Mid-C) and east power markets (PV and 4C),
which have deviations driven by regional factors, such as weather deviations, resource stacks, and
planned and unplanned outages.
Flexible Reserve Study
Appendix A of the Public Utility Commission of Oregon's 2017 IRP acknowledgement order
issued April27,2018 in Docket LC-67, states that "[n the IRP Update, PacifiCorp will model
natural gas and storage for meeting flexible reserve study needs." Due to the timing of the issuance
of the order following completion of analysis supporting the 2017 IRP Update, PacifiCorp was not
able to conduct an updated flexible reserve study to fully incorporate this requirement but plans to
update its flexible reserve study in the 2019 tRP. PacifiCorp's supply-side tables, Table 5.5 and
Table 5.6 included in later discussion in this chapter, includes a variety of natural gas and storage
resources, which can help meet the flexible reserve obligations associated with the company's
portfolio. PacifiCorp recognizes, however, that while the IRP models include flexible reserve
obligations, they may not capture all of the value associated with flexible resources such as natural
gas and energy storage resources, particularly intra-hour. For instance, flexible resources can
provide additional net benefits when dispatched in the energy imbalance market or when they defer
transmission and distribution system upgrades. PacifiCorp plans to further explore where possible,
the additional benefits and resource potential for various flexible resource applications, including
natural gas and storage, in the 2019 IRP.
Natural Gas and Power Market Price Updates
Portfolio modeling for the 2017 IRP Update was prepared using PacifiCorp's December 29,2017
official forward price curve (OFPC). OFPCs are produced for both natural gas and power prices
by point of delivery. For both natural gas and power, PacifiCorp's OFPCs are developed using
forward market prices in tandem with a fundamentals-based price forecast. The first72 months of
the OFPC, beginning with the prompt month, represent broker quotes or settled forward prices per
the end-of-quarter quote date, followed by l2 months of blended prices that transition to a market
fundamentals-based forecast, starting in month 85.
53
l
PacIpIConp _201] IRP UPDATE CHAP.I I,R 5 _ MODEI-tNG AND ASSiJMPTIONS UPDA.III
For the natural gas OFPC, the fundamentals-based component is developed using expert third-
party forecasting services with consideration given to underlying supply/demand assumptions,
forecast documentation, peer-to-peer forecast price comparisons, date of issuance, location
granularity, and forecast horizon. For power, the fundamentals-based component is produced using
AuroraXmpn (Aurora), a production cost simulation model. PacifiCorp's fundamentals-based
natural gas price forecast is a key driver the electricity price forecast produced using Aurora.
For wholesale power prices, PacifiCorp uses hourly price scalars, which are applied to monthly
on-peak and off-peak prices in the forward price curve, to derive hourly market price profiles that
vary by month and day type (i.e., weekdays, Saturdays, and Sundays/trolidays). The shape of the
hourly price curves or scalars were updated to reflect one year of day-ahead hourly market price
data available from the California Independent System Operator (CAISO). Prior to implementing
this update, PacifiCorp used five years of hourly Powerdex price data to develop its hourly price
scalars. The company's review of the Powerdex data shows that the five-year price history is not
supported by a significant volume of reported transactions and that the resulting hourly price
shapes do not align with hourly prices observed in operations that are being increasingly influenced
by growth in solar resources across the region. The updated hourly price scalars are supported by
a large volume of market transactions and produce hourly price profiles that are more aligned with
operational experience.
Figure 5.1 shows average hourly price profiles as derived from historical Powerdex alongside
hourly price profiles derived from historical CAISO data, which is used in the 2017 IRP Update.
In both figures, the hourly price profile is based on the average hourly prices from representative
months (January, April, July, and October).
54
PaCIpICORp - 2OI7 IRP UPDATE CuaprER 5 - MODELTNG AND ASSUMPTToNS Upoe.rE
re 5.1 - Scalars
Natural Gas Market Prices
PacifiCorp's December 2017 natural gas OFPC reflects a fundamentals-based forecast, issued
November 2017, heavily influenced by a cost-effective domestic supply expansion largely due to
growth in the Marcellus, Utica, and Permian plays.
The October 2016 natural gas OFPC, which was used in the 2017 IRP, was based on an expert
third-party long-term natural gas price forecast issued August 2016.
A significant price driver, since August 2016, has been the "rediscovery" of the Permian basin.
The Permian basin, located in west Texas and southeast New Mexico, is becoming as well known
for gas as it is for oil. It has been in production since 1920 but horizontal drilling and fracking have
liberated oil volumes, consisting of 20 percent - 50 percent natural gas, previously untouched.
Moreover the Permian contains six to eight geological formations, stacked on top of each other,
with each layer being its own reservoir. Thus, producers can access multiple reservoirs from the
same acreage. This stratification coupled with the potential for triple cash-flow streams (from
crude, natural gas, and natural gas liquids) yields low break-even prices with the associated gas
being ultra-low cost.3 It is produced solely as a by-product to oil drilling and its production is
indifferent to the price of natural gas. Thus, associated gas volumes may continue to enter the
market even when it is seemingly uneconomic to develop other natural gas resources.
Figure 5.2 compares the nominal annual Henry Hub natural gas prices from the October 2016
(2017 IRP), and December 2017 (2017 IRP Update) OFPCs.
140
r30
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3 Land Rush in Permian Basin, Were Oil Is Stacked Like a Layer Cake, January 11 ,2011 , New York Times.
55
/*
\
PacmlConp - 20 I 7 IRP UPDATE CHAPTER 5 _ MoogljNc AND ASSUMPTIONS UPDATE
(r-Hub Natural Gas Prices ominal
Power Market Prices
The natural gas fundamentals forecast described above is a key input to the Aurora model, and
consequently, the gas curve shape is reflected in wholesale electricity prices. Figure 5.3 and Figure
5.4 compare the average annual flat and heavy-load-hour electricity prices for the Palo Verde
market hub from the October 2016 and December 2017 OFPCs; Figure 5.5 and Figure 5.6 show
the comparison for the Mid-Columbia market hub.
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56
PACIFICORP _ 2OI7 IRP UPDATE CHepren 5 - Moopr-Nc AND AssuMpnoNs UpDATE
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Prices omrn
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Pa.crprConp -2017 tRP UPDATE CHAP.IER 5 _ MooeI-nc AND ASSUMPUONS UpoarE
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re 5.5 -Annual Flat Mid-Columbia Prices omrn
5.6 -Annual Load Hour Mid-Columbia Prices
On March 28,2017, President Trump issued an Executive order directing the U.S. Environmental
Protection Agency (EPA) to review the Clean Power Plan (CPP) and, if appropriate, suspend,
revise, or rescind the CPP, as well as related rules and agency actions. On October 10, 2017, EPA
issued a proposal to repeal the CPP and the public comment period on EPA's proposal closed April
26,2018. In addition, EPA published an Advance Notice of Proposed Rulemaking in the Federal
OO O\ O c.i ca S tr) \O f- oo O\ O N .a $ tr) \O
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58
a
Carbon Dioxide Emission Policy
PACIFICoRP - 20I7 IRP UPDATE CHApTER 5 - Mooer-rNc AND AssuMprroNs UpDATE
Register December 28, 2017, seeking public input on, without committing to, a potential
replacement rule. The public comment period for the Advance Notice of Proposed Rulemaking
concluded February 26, 2018. Given the current status of the CPP, PacifiCorp does not assume
applicability of any CPP emission limits in the 2017 IRP Update however, in the 201 7 IRP Update,
PacifiCorp does assume a medium COz price as shown in Figure 5.7 below.
re 5.7 - Medium COz Price
The cost for supply-side 50 MWac solar photovoltaic (PV) projects are updated to reflect lower
market costs for PV modules and mounting structures as well as the 30 percent tariff on imported
modules. Engineering and owner costs are decreased slightly to reflect increasing levels of
certainty for large commercial PV projects. The levelized cost of energy calculated from these
updated cost assumptions are more reasonably aligned with power-purchase agreement bids that
submitted into the recent 20175 Request for Proposals.
Projected costs, in real terms, during the 2O-year study period continue to reflect a downward trend
as in the 2017 IRP. Figure 5.8 shows the nominal year-by-year escalation percentages for wind,
solar and other resources. Wind and solar escalate below other resource options due to declining
cost curves for these resources.
$14
$12
sl0
$8
$6
s4
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$0
,$r$.Crs,"T"d'rSr{FrSr$,tr$rs,""P"pt"f, ,{i"ofrs-r$.us'
-Mediurn
59
Resources
25%
2.0%
1.5%
t.0%
0.5%
0.0%
-0.5%
-1.0%
-15%
-2.0%
-2.5%
-3.0%
no$ro.ororors)rof;of,of,of,olt o4rol*rof"us,ors)rs?"pf,eorof,ort o4rs.rd+N
-Wind -Solar -Other
Resources
PRcIpIC<IRp -20I] IRP UPDATE CHAPTER 5 - MoDELTNG AND ASSUMPTIONS UPDATE
5.8 - Nominal Y ear Escalation for Different Resource
Table 5.2 reports the updated cost assumptions for new single-axis tracking solar resources.
Table 5.2 - Updated Cost of Solar Resources - (50 MWec Single Axis Tracking)
Utah/Single Axis Tracking s 1.392 $ 19.690 $ 1.800 s 19.410
Oregon/Single Axis Tracking $1.421 st9.720 $1.114 s 19.440
60
Location/Technology
2017 IRP Update 2OIT IRP
Total (with
Owner's Costs)
$/Wac
Fixed O&M
$/kW-year
Total (with
Owner's Costs)
$nilAC
Fixed O&M
$/kW-year
2017$2016$
PAcIpIConp _2017 IRP UPDATE CHeprER 5 _ MODELTNG AND ASSUMPUoNS Upoarg
The resource capital costs for wind resources have been updated to more closely align with market
data for wind turbine and construction costs, as informed by bids submitted into the recent 2017R
Request for Proposals. Market conditions, more precise construction bids, and technology changes
led to cost reductions on a $/kW basis. As was the case in the 2017 IRP, PacifiCorp continues to
assume that that new projects will be built on leased land, and consequently, PacifiCorp has not
updated its fixed operations and maintenance (O&M) cost assumptions since the 2017 IRP. Table
5.3 summarizes the updated cost assumptions for new wind resources.
Table 5.3 - U Cost of Wind Resources
The 2017 IRP Update provides updated capital cost information for battery energy storage as
summarized in Table 5.4 below to reflect an update to capital costs, provided by DNV GL, based
on installations and contracts that have been executed for the installation of energy storage systems
in 2016 and 2017. DNV GL's "Cost Update to Battery Energy Storage Study" is included as
Volume II, Appendix P to the 2017 IRP. The average one-MW battery costs are estimates of the
total installation costs to PacifiCorp in2017 dollars. A change was made to the way lithium-ion
battery costs were calculated. The original20lT IRP costs for lithium-ion batteries were averaged
costs for NCM, LiFePO4, and LTO batteries. For the 2017 Update, it was determined that the
company is unlikely to procure LTO batteries, so updated lithium-ion battery costs are based on
average costs for NCM and LiFePO4battery systems.
Note that the costs represented in this update are averages based on the following assumptions:
Using a standardized 2O-year life required different operating profiles for the three battery
types listed. Both lithium-ion and sodium-sulfur batteries had similar profiles with 365
cycles per year: about halfofthe days at an 80 percent depth ofdischarge (DoD), and about
half of the days at a 20 percent DoD. This is a very simplified way of representing actual
complex usage profiles which may vary greatly depending upon use cases. Flow batteries
are assumed to be capable of operating at 500 cycles per year at 100 percent DoD.
Costs were developed using a proxy site, and an average additional owners cost of 2l
percent. Depending on the location, owner's costs may vary from less than l0 percent to
greater than 40 percent.
$ 1.465 $36.455 s r.800 $36.4s5Washington
st.444 s36.455 $1.114 $36.455Oregon
s 1.47s s36.455 $ l.8l 1 s36.4s5ldaho
$1.4r3 s36.4ss $ 1.73s $36.455Utah
$ 1.415 s36.455 $ l .737 s36.4ssWyoming
6l
2017IRP Update 2OTT IRP
Capital Cost
$/kw
Fixed O&M
$/kW-year
Capital Cost
$/kw
Fixed O&M
$/kW-year
2017$2016$
Location
PaclrIConp - 20 I7 IRP UPDATE CuapTen 5 _ MODELING AND ASSUMPTIONS UPDATE
Costs were validated against actual U.S. projects listed in the U.S. Department of Energy's
Global Energy Storage Database. For sodium-sulfur batteries, only projects with NGK
batteries in the six to eight MW range were listed. Therefore, sodium-sulfur batteries in the
one, two and four hour options are considered to unavailable (N/A).
Table 5.4 - U Cost of 2017 Dollars
Due to extension in federal production tax credits (PTCs) and investment tax credits (ITCs), the
levelized cost of renewable resources are lower, not only due to updated capital costs and O&M
costs, but also due to the nominal treatment of tax credits to more closely align with how these
credits would get passed through to customers. Table 5.5 shows updated costs of the renewable
resources with and without applicable tax credits, considering timing of construction and in-service
dates. First year real levelized costs for wind and solar resources are presente d for 2017 , assuming
a 2018 wind project meets IRS guidance demonstrating the project began construction by January
1,2017, and for the last year in which PTCs (wind) and ITCs (solar) are phased down. Wind and
solar resources with online dates between 2019 and 202312024, the tax credit period, were
considered in the company's analysis.
Solar lTCs are now treated as an upfront benefit rather than being amortized over the life of the
asset. This approach is more consistent with how independent power producers can price ITC
benefits into PPA prices. Levelized costs for Pacific Northwest wind projects are shown at 38
percent, reflecting the upper range of performance anticipated from wind facilities in the region.
For modeling purposes, a commercial operation date of January I is assumed, which is a proxy for
December 3l of the prior year. The cost for Energy Vision 2020 new wind resources are also
shown in the Table 5.5 and Table 5.6, which reflect the aggregate cost of winning company-owned
bids from the 2017R Request for Proposals, but presented in 201 7 dollars.
62
Average I MW Battery Costs
Standardized ata20 year life.2hours | 4hor.,
Duration
I hour 8 hours
8MW
4 hours
1,319 1,014 862 786 831Installed Cost, $/kWh energy storage
Installed Cost, $/kW 1,319 2,029 3,449 6,289 3,324
N/A N/A N/A 1,036 N/AInstalled Cost, $/kWh energy storage
Installed Cost, $/kW N/A N/A N/A 8,286 N/A
1,936 1,365 1,080 937 1,049Installed Cost, $/kWh energy storage
Installed Cost, $/kW 1,936 2,731 4,320 7,499 4,195
Lithium Ion
Sodium Sulfur
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PncrprConp - 2017 IRP UPDATE CHAPTER 5 - MoopIruc AND ASSUMPTIONS UPDATE
Intra-Hour Dispatch Credit
The energy-imbalance market (EIM) provides economically optimized dispatch instructions to
participating units of PacifiCorp's fleet of diverse resources every five minutes. Prior to the ElM,
PacifiCorp would resolve load-resource imbalances within the hour through manual dispatches of
generation within its balancing authority area (BAA). With the introduction of the EIM, whose
footprint spans multiple BAAs, the aforementioned imbalances are resolved with least-cost
generation sourced from across the EIM footprint, on a five-minute basis. This sub-hourly dispatch
process increases efficiency and lowers cost. In addition, the EIM provides PacifiCorp with a way
to value the changes in generation within the hour through locational-marginal pricing at five and
fi fteen-minute intervals.
In contrast to actual operations, PacifiCorp's production cost models used to estimate the economic
value(s) of a resource plan over the long term are hourly dispatch models, which cannot capture
the sub-hourly benefits/requirements of generation flexibility, or the EIM benefits related to intra-
hour economic opportunities. For example, an hourly production cost model can replace a
megawatt-hour (MWh) from a generation resource with a market purchase of energy with no
recognition of the fact that electricity requirements do not stay constant across the hour. In this
scenario, value is lost at the sub-hourly level given that market purchases are fixed products that
have no intra-hour flexibility. These discrepancies between modeling and operations created a
need to develop an intra-hour dispatch credit in order to capture value realized from sub-hourly
dispatches to meet PacifiCorp's load-and-resource changes, as well as transfers across the EIM
footprint. The methodology for calculating the intra-hour dispatch credit for units participating in
EIM is discussed further below.
PacifiCorp's participation in the EIM includes PacifiCorp's submission of a balanced load-
resource hourly base schedule. Within the hour, the EIM provides PacifiCorp with fifteen-minute
advisory schedules and five-minute dispatch schedules. The determination of sub-hourly benefits
incorporates the difference among these three schedules, moving from the hourly schedule to the
fifteen-minute schedule and then to the five-minute schedule. By taking into account the cost of
generation, a margin is calculated and attributed to a specific unit in a specific interval. This margin
represents the intra-hour value reahzed through moving that unit in the EIM. EIM dispatches can
be in response to changes in PacifiCorp's load, changes in variable resources or changes in
transfers into or out of the BAA.
Determination of Intra-Hour Dispatch Credit:
Base = Pacif iCorp's Hourly Base Schedule
Dts = EIM's Fif teen Mtnute Aduisory Schedule
Ds = EIM's Ftue Mtnute Dispatch Schedule
Prs = EIM's Ftf teen Mtnute Market Price
Ps = EIM's Ftve Mtnute Market Prtce
Btd = Paci.f iCorp's Cost of Generati.on
Intra - Hour Dispatch Credit
= (Drs - Base) x Prs * (Ds - Dr.s) * Ps - (Ds - Base) x Btd
66
PeCIr.IConp 20I7 IRP UPDATE CHepTgR 5 - MoDELING AND ASSUMPTIoNS UPDATE
In the 2017 IRP Update, PacifiCorp incorporated unit specific intra-hour dispatch credits as part
of its 2017 IRP prefened portfolio and coal studies discussed in Chapter 6. The average intra-hour
dispatch credit value is $6.47 kwlyr based on the following units: Dave Johnston Units 3-4, Hunter
Unit 3, Huntington Units l-2, Jim Bridger Units 1-2, andNaughton Units l-3.
In addition to coal resources providing flexibility to the market, PacifiCorp is also exploring how
energy storage resources, such as batteries, have the potential to provide ElM-dispatch benefits
due to their ability to respond rapidly with no start-up costs, minimum load costs and an ability to
move both up and down across a varying capacity sizes. Some of the items that PacifiCorp is
reviewing for potential benefits of energy storage resources are storage capacity, charge and
discharge rates, efficiency, and degradation rates. PacifiCorp does not yet have any direct
experience with energy storage resources participating in EIM, and market structures for energy
storage resources continue to evolve, but as the market continues towards additional renewable
generation, incentives will continue to be explored towards resources with low cost minimum
operating levels while still supporting integration needs. PacifiCorp anticipates further exploration
and discussion of such credits with robust stakeholder engagement as part of its 2019 IRP public
input process.
67
Intra-Hour Dispatch Credit Further
PacIuConp - 20 I 7 IRP UPDATE CuapTT,n 5 _ MooELTNIc AND ASSUMPTIONS UPDA.TE
[This page is intentionally left blank]
68
PecrprConp - 2017 IRP Upoars CuaprER 6 - Rgcroue,t- HazE CnsEs
CueprER 6 - RpcroNAL Htzr, Casps
Introduction
IRP modeling is used to assess the comparative cost, risk, and reliability attributes of different
resource portfolios, each meeting a target planning reserve margin. These portfolio attributes form
the basis of an overall quantitative portfolio-performance evaluation.
This chapter discusses regional haze case definitions and presents study results developed in
accordance with action items 5c,5d,5e, and 59 of the 20l7lRP action plan. PacifiCorp used its
resource expansion plan model, the System Optimizer (SO) model, and its stochastic risk model,
the Planning and Risk model (PaR) to perform these studies under three price-policy scenarios.
Regional Haze Case Definitions
The four coal resource action items in the 2017 IRP action plan were studied relative to the 2017
IRP Update resource portfolio. [n addition to analyzing known and prospective regional haze
compliance requirements, these studies incorporate compliance cost assumptions related to the
Mercury and Air Toxics Standard (MATS), coal combustion residuals (CCR), effluent limit
guidelines (ELG), and cooling water intake structures as may be required under the Clean Water
Act (CWA).
Each compliance case drives the timing and magnitude of run-rate capital and operations and
maintenance costs for each individual coal unit in PacifiCorp's fleet. For instance, if a specific
regional haze compliance case assumes an early retirement for a given coal unit as part of a
compliance plan, the run-rate operating costs for that unit are customized to reflect the assumed
early closure date. This can include changes to the timing of planned maintenance throughout the
twenty year planning horizon and avoidance of future costs related to known or assumed MATS,
CCR, ELG or CWA compliance requirements, as applicable. Compliance alternatives for coal
units in any given compliance case can include, continued operations through the end of a unit's
assumed depreciable life, early retirement, conversion to gas-plant operations, or installation of a
selective catalytic reduction (SCR) system to continue operations with reduced emissions.
Individual unit outcomes under any regionalhaze compliance case will ultimately be determined
by ongoing rulemaking, results of litigation, and future negotiations with state and federal
agencies, partner plant owners, and other vested stakeholders. While the regionalhaze compliance
cases represent a range of strategic paths to be evaluated, no individual unit commitments are being
made at this time.
Table 6.1 summarizes key assumptions forregionalhaze compliance cases that address the four
coal resource action items studied in the 2017 IRP Update. The 201 7 IRP Update resource portfolio
assumptions are also included for reference.
69
PecrprConp 2017 tRP Upoare CHAPTER 6 - REGIONAL HAZE CASES
Table 6.1 -al Haze Case
NoSCRNOX+2021 NoSC&NOX+2022 NoSCR:NOX+2022 NoSCRNOX+2022 NoSCR;NOX+2022 NoSCRNOX+2022 NoSCR;NOX+2022
Ret.2042 Ret.2042 Ret.20.12 Ret.20,l2 Ret.2042 Ret.20.l2 Ret.2042
NoSCRNOX+2021 NoSCRNOX+2023 NoSCR;NOX+2023 NoSCR;NOX+2023 NoSCRNOX+2023 NoSCRNOX+2023 NoSCRNOX+2023
Re1.2042 Ret.2042 Ret.2042 Ret.2042 Ret.2042 Ret.2M2 Ret.2042
No SCR;
Ret.2036
No SCRI
Ret. 2036
No G&s Conv.
Ret. 201 tl
NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022
Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036
NoSCR;NOX+2023 NoSCR;NOX+2023 NoSCR;NOX+2023 NoSCR|NOX+2023 NoSCR;NOX+2023 NoSCR;NOX+2023
Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036
No SCR
Ret. 2028
No SCR
Ret. 2028
No SCR
Ret.2028
scP.t2/3tDo22
Ret 2037
No SCR
Ret. 2028
No SCR
Ret. 2028
No SCR
Ret.2028
No SCR
Ret. 2032
No SCR
Ret. 2032
No SCR
Ret. 2032
scR lz3l202l
Ret 2037
No SCR
Ret.2032
No G6 Conv.
Rer. l/30/2019
No SCR
Ret.2025
No G6 Conv.
Ret.1/30/2019
No SCR
Ret.2025
No Gu Conv.
Ret. l/302019
No SCR NO SCRRet.2032 Ret.2032
GaConv.l/312019 GsConv.42MW
b 6lln0l9 ll3l2019 to 5D0Dol9Ret.2029 Ret.2029
No Go Conv. No G6 Conv.
Ret.2020 Ret.2020
No G6 Conv.
Ret.1/30/2019
No Go Conv.
Ret.2020
No Gs Conv.
Rei. 2020
No G6 Conv.
Ret. 2020
No G6 Conv.
Ret.2020
No SCR
Ret.2025
No SCR
Ret.2025
No SCR
Ret.2025
No SCR
Ret. 2025
No SCR
Ret. 2025
No SCR
Ret.2027
No SCR
Ret.2027
scR + 2019
Ret.2027
No SCR
Ret.2027
No SCR
Ret.2027
No SCR
Ret. 2027
No SCR
Ret.2027
The following sections describe PacifiCorp's analysis consistent with 2017 IRP action plan items
5c, 5d, 5e, and 59. All studies incorporate updates to forecasted loads, resources, market prices,
and other modeling inputs and are compared to the 2017 IRP Update preferred portfolio that
includes the assumed retirement dates from the 2017 IRP preferred portfolio in order to assess the
present-value revenue-requirement differential (PVRR(d)) for the studied action.
PacifiCorp's SO model was used to develop resource portfolios under three price-policy scenarios
for a benchmark case (i.e., the 2017 IRP Update preferred portfolio and the alternative compliance
scenario. PVRR(d) analyses are used to quantify the benefit or cost of the regional haze
environmental compliance alternatives relative to the benchmark for each of the three price-policy
scenarios. The PVRR(d) for a given environmental compliance alternative is calculated as the
difference in system costs between the two PaR simulations-the benchmark simulation and the
alternative compliance scenario.
Each of the studies, which are described in more detail in the following sections of this chapter,
were perforrned using medium, high and low price-curve scenarios. The medium price scenario is
based on PacifiCorp's December 2017 official forward price curve (OFPC), consistent with
medium price assumptions used to develop the portfolio for the 2017 IRP Update.
Gt Cow.l2Rl/2024
b 6AnO25
R.et.2M2
70
Hunter I
Hlnter 2
lluntington I
Huntington 2
Jim BriQer I
Cholla {
Craig I
Daw Johnston 3
2017 IRP U@te
@ref. Port)
2017 tRP U@te
DJ] SCR
2017 IRP U@te 2017lRP Update
.tBt &.IR2
SCR NALBtr
2017 IRP Update 20l7IRP UFbte
NA[B 42 fr{w (f CHOI,{ GC
.lim BriQer 2
Naughton 3
Haze Case Analysis and Results
PacrprConp -2017 IRP UPDATE Cuaprsn 6 - RrcrouAl HAZE CASES
Figure 6.1 summarizes heavy-load hour (HLH) and light-load hour (LLH) wholesale power prices,
natural gas prices, and COz prices assumed for this analysis.l The low price-policy scenario
assumes there are no COz prices throughout the planning horizon.
Figure 6.1 - Forward Price Curve Assumptions2
Dave Johnston Unit 3
Consistent with action item 5c inthe 2017 IRP action plan, PacifiCorp has updated its analysis of
regional haze compliance alternatives and its analysis of the retirement of Dave Johnston Unit 3
by the end of 2027 as reflected in the 2017 IRP preferred portfolio. Dave Johnston Unit 3 is one
of four units located at the Dave Johnston plant in Glenrock, Wyoming. The EPA's final regional
haze federal implementation plan (FIP) requires the installation of SCR equipment at Dave
Johnston Unit 3 in 2019 or a commitment to retire Dave Johnston Unit 3 by the end of 2027 . The
major project schedule for Dave Johnston Unit 3 SCR is reported in Figure 6.7 at the end of this
chapter.
PacifiCorp's updated analysis compares installing SCR equipment by March 2019 with a case that
does not install SCR equipment but nonetheless retires Dave Johnston 3 in 2027. This analysis
shows that retirement at the end of 2027 without installing SCR equipment is lower cost than
installing SCR equipment.
t HLH prices cover hours ending seven through 22PPT, Monday through Saturday, excluding holidays. LLH prices
cover all other hours.
2 For presentation purposes, power prices reflect the average of Mid-Columbia and Palo Verde prices. Opal is the
natural gas market hub most applicable to natural gas conversion alternatives studied in the Naughton Unit 3
analysis.
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71
PaclprConp - 2017 IRP UpoRtE CHAPTER 6 - RECIONAI HAZE CASES
In the case SCR equipment is installed and Dave Johnston retires at the end of 2027, portfolio
changes are de minimis when compared to the preferred portfolio. This is expected because Dave
Johnston Unit 3 retains the same essential operating costs and characteristics with or without the
installation of SCR equipment. The most significant of these shifts in the resource portfolio
(changes in portfolio resources are less than 12 MW in all years of the study) is a decrease in
renewables additions in 2035. The sole driver for these small portfolio shifts is a slight (two MW)
reduction in Dave Johnston Unit 3 capacity associated with the SCR equipment. Figure 6.2
summarizes the cumulative change in resource portfolio nameplate capacity when SCR equipment
is installed in 2019 and Dave Johnston Unit 3 is retired at the end of 2027 as compared to not
installing SCR equipment and retiring at the end of 2027 wder the medium gas, medium COz
(MM) price-policy scenario. Positive values show cumulative resource portfolio additions and
negative values show the cumulative capacity of resources that are removed from the portfolio
when Dave Johnston Unit 3 is assumed to install SCR equipment and then retire at end of 2027 .
There are no notable portfolio changes resulting from installing SCR equipment in 2019 relative
to not installing SCR equipment.
Figure 6.2 - Cumulative Increase/(Decrease) in Portfolio Resources under the Dave
Johnston Unit 3 Install SCR
Table 6.2 reports the PVRR(d) impacts of installing SCR equipment in 2019 and retiring Dave
Johnston Unit 3 the end of 2027 relative to the 2017 IRP Update preferred portfolio that does not
install SCR equipment and includes retirement at the end of 2027 for each of the three price-policy
scenarios.
=a
q)
U
q)
6l
(J
n$r$.Croorslnd}rof ,s}rof ,obroilro*rof ,onors)rslrof ,oorof ,orb
I DSM r FOTs r Gas a Renewable I Gas Conversion r Early Retirement lRetirement
6
4
2
(8)
(10)
(12)
)
)
)
Q
(4
(6
72
PACIFICoRP - 20I 7 IRP UPDATE Cuapren 6 - Rcc;roNnr- HAZE CASES
Table 6.2 - PVRR Cost/(Benefit) of the Dave Johnston Unit 3 Install SCR Equipment Case
Relative to the 2017 IRP U Preferred Portfolio Price-Scenario
The PVRR(d) results are attributed almost entirely to the cost of the SCR equipment, and the slight
changes among price-policy scenarios are associated with the impact on system costs associated
with slight change in capacity of Dave Johnston Unit 3.
The net cost increase in each price-policy scenario does not support installing SCR equipment on
Dave Johnston Unit 3. Consequently, PacifiCorp continues to assume retirement of Dave Johnston
Unit 3 at the end of 2027 in the 2017 IRP Update.
Jim Bridger Units I & 2
Consistent with action item 5d in the 2017 IRP action plan, PacifiCorp has updated its analysis of
regional haze compliance alternatives relative to the Jim Bridger Units I and2 in the 2017 IRP
Update preferred portfolio. The 2017 IRP preferred portfolio assumed an early retirement date of
2028 for Jim Bridger Unit I and an early retirement date of 2032 for Jim Bridger Unit 2. The Jim
Bridger plant consists of four units and is located just outside of Rock Springs, Wyoming. The
Wyoming regional haze state implementation plan (SIP) and EPA's final regionalhaze FIP for
Wyoming require the installation of SCR on Jim Bridger Units I and 2 by the end of 2022 and
2021 respectively. The major project schedule for Jim Bridger Unit I SCR, and tJnit2 SCR is
reported in Figure 6.8 and Figure 6.9 at the end of the chapter.
PacifiCorp's updated analysis compares installing SCR equipment on Jim Bridger Units I and2
in 2022 and 2021 respectively with retirement in 2037 versus the 2017 IRP Update preferred
portfolio assumption, where Jim Bridger Unit I is assumed to retire in 2028 followed by Jim
Bridger Unit 2 in 2032 with no SCR installations. This analysis shows that the early retirement
scenario without the installation of SCR equipment is lower cost.
In the case where it is assumed that SCR equipment is installed and the Jim Bridger units retire at
the end of 2037, the continued operation of the Jim Bridger Units I and2 fills incremental net-
capacity needs beginning 2029, driving a lower need for incremental renewables, demand-side
management (DSM) and front-office transaction (FOT) resources over the 2029 to 2036 time
frame. Figure 6.3 summarizes the cumulative change in resource portfolio nameplate capacity
when SCR equipment is installed at Jim Bridger Unit I in 2022 and Jim Bridger Unit 2 in 2021
under the medium gas, medium COz price-policy scenario. Positive values show cumulative
resource portfolio additions and negative values show the cumulative capacity of resources that
are removed from the portfolio when SCR equipment is installed at Jim Bridger Unit 1 in 2022
and Jim Bridger Unit 2 in 2021. In the medium natural gas, medium COz price-policy scenario,
notable resource portfolio changes resulting from installing SCR equipment and retiring Jim
System Optimizer PaR Stochastic MeanPVRR(d) Costi(Benefit)
($ million)Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
High COz
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
High COz
Change from
17 IRP Update Pref-Port $e4 $e7 $ 106 s 100 $l0r $ 105
t5
-
=a
(.)cl
clI
q)
L)
,$r**r*ero"r,ors)rsProf ,$of ,obroilro$ror)r*
r DSM r FOTs r Gas a Renewable I Gas Conversion r Early Retirement iRetirement
1 ,000
500
(s00)
(1,000)
( 1,500)
(2,000)
PACIFICORP _ 20 I7 IRP UPDATE CHAPTER 6 - REGIoNAL Heze CesTs
Bridger units in 2037 relative to not installing SCR equipment and retiring Jim Bridger Units I
and2 early include:
The installation of SCR in 2021 and 2022 results in minimal shifts in DSM and FOTs in
the years leading up to the retirement dates assumed in the preferred portfolio.
Starting in2029, the continued operation of Jim Bridger Unit I with SCR displaces FOTs
and DSM.
Starting in 2030, the continued operation of Jim Bridger Unit 1 with SCR and the
continued operation of Jim Bridger Unit2 with SCR in 2033 displaces renewable
resource additions (both wind and solar).
Figure 6.3 - Cumulative Increase/(Decrease) in Portfolio Resources under the Jim Bridger
Units I & 2Install SCR E and Retire 2037 arro
Table 6.3 shows the PVRR(d) impacts of installing SCR equipment at Jim Bridger Unit 1 in2022
and Jim Bridger Unit 2 in 2021 and retiring at the end of 2037 relative to the 2017 IRP Update
preferred portfolio that does not install SCR equipment and includes early retirement at the end of
2028 for Jim Bridger Unit I and 2032 for Jim Bridger Unit 2 for each of the three price-policy
scenarios.
Table 6.3 - PVRR Cost/(Benefit) of the Jim Bridger Units | & 2Install SCR Equipment
and Retire 2037 Case Relative to the 2017 IRP Update Preferred Portfolio by Price-Policy
Scenario
a
a
a
Change from
l7 IRP Update Pref-Port $ 157 $179 $ 193 $89 $83 $rs0
74
IIr-
PVRR(d) Cost(Benefit)
($ million)
System Optimizer PaR Stochastic Mean
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
High COz
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
Hieh COr
PACIFICORP 20 I7 IRP UPOETE CuapTgR 6 REcIoNaI- HAZE CASES
The following summarizes observations and results for installing SCR equipment at Jim Bridger
Unit I in 2022 and Jim Bridger Unit 2 rn 2021 and retiring at the end of 2037 relative to the 2017
IRP Update preferred portfolio that does not install SCR equipment and includes early retirement
at the end of 2028 for Jim Bridger Unit I and 2032 for Jim Bridger Unit 2 under medium natural
gas price, medium COz price-policy scenario:
o Fuel costs increase due to the extended years of Jim Bridger Units I and 2 operation
beginning in2029 and the displacement of renewable resources and FOTs which do not
carry a fuel expense.o Extended operations of Jim Bridger Units I and 2 reduces system balancing purchases,
offsetting fuel cost increases.
. SCR installation in202l and2022 increases capital costs.o Extended operations of Jim Bridger Units I and 2 increases emissions costs relative to the
preferred portfolio.
o Offsetting costs and benefits result in a net $83 million cost (PaR stochastic mean), as the
value of extended generation does not fully offset the cost of SCR installation.
o PaR, which has additional granularity and more refined unit commitment and dispatch
logic relative to the SO model, reports a PVRR(d) that shows installation of SCR is lower
cost when compared to the SO model results. PaR is able to mitigate costs with increased
spot market net sales. However, PaR results still show that installation of SCRs is higher
cost.
Naughton Unit 3
Consistent with action item 5e inthe2017 IRP action plan, PacifiCorp has updated its analysis of
regional haze compliance altematives for Naughton Unit 3. The 2017 IRP preferred portfolio
assumed an early retirement date of 2018 for Naughton Unit 3. The Naughton plant consists of
three units for a combined generating capability of 637 MW and is located near Kemmerer,
Wyoming.
PacifiCorp's updated analysis includes two gas conversion cases for Naughton Unit 3. The first
case analyzes the full gas conversion of Naughton Unit 3 in June 2019 with retirement in2029,
increasing its capacity slightly from 280 MW to 285 MW. The second case analyzes a limited gas
conversion of Naughton Unit 3 that would enable the plant to run on gas at a lower generating
capacity of 42 MW, without the capital investment of a full gas conversion, and also with
retirement in 2029. These cases are compared to the 2017 IRP Update preferred portfolio
assumption where Naughton Unit 3 is assumed to retire at the end of January 2019. This analysis
shows that the early retirement scenario without the gas conversion is lower cost whereas a limited
gas conversion of Naughton Unit 3 and retirement in 2029 shows benefit in two of the three price-
policy scenarios. Each case is discussed in more detail below.
Naughton Unit 3 - Maximum Generating Capacity Gas Conversion
This case studies conversion of Naughton Unit 3 to natural gas with the capital investment
necessary to enable it to operate up to 285 MW generating capacity in June 2019 with retirement
in 2029. The case creates a lower incremental capacity need beginning in the summer of 2019,
which drives the need for lower replacement resources over the 2019 to 2029 time frame. The
75
PecrprConp -2017 IRP UPDATE CHlprEn 6 RrcroNnr- Hnze Cases
major project schedule for Naughton Unit 3 maximum gas conversion is reported in Figure 6.10
at the end ofthis chapter.
Figure 6.4 - Cumulative Increase/(Decrease) in Portfolio Resources under the Naughton
Unit 3 Maximum Gas Conversion and Retire 2029 Price-Scenario MM
Table 6.4 shows the PVRR(d) impact of converting Naughton Unit 3 to natural gas with maximum
generating capacity and retiring at the end of 2029 relative to the 2017 IRP Update preferred
ponfolio that includes early retirement at the end of January 2019 for Naughton Unit 3 for each of
the three price-policy scenarios.
Table 6.4 - PVRR Cost/(Benefit) of the Naughton Unit 3 Maximum Gas Conversion and
Retire 2029 Case Relative to the 2017 IRP Update Preferred Portfolio by Price-Policy
Scenario
PVRR(d) Cost/(Benefit)
($ million)
System Optimizer PaR Stochastic Mean
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
High COz
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
High COz
Change from
l7 IRP Update Pref-Port s58 $63 $11 $64 $71
=a
q)
ctU()
G
U
"$r*"Cr*ors|r0.r$rSn$robr$ne$rdno+n$n$no+n{,*no+.r!rbr DSM r FOTs I Gas a Renewable r Gas Conversion r Early Retirement Retirement
400
300
200
100
(100)
(200)
(300)
(400)
(500)
(600)
76
Figure 6.4 summarizes the cumulative change in resource portfolio capacity when Naughton Unit
3 is assumed to convert to gas and retire in 2029 relative to the 20 1 7 IRP Update preferred portfolio
that includes early retirement of Naughton Unit 3 at the end of January 2019 under the medium
gas, medium COz price-policy scenario. Positive values show cumulative resource portfolio
additions and negative values show the cumulative capacity of resources that are removed from
the portfblio when Naughton Unit 3 is assumed to convert to gas in June 2019 and retire in 2029.
The conversion of Naughton Unit 3 to full capacity natural gas operation from 2019 through2029
reduces the capacity need for west side summer FOTs during this period with the exception of
2021 and 2022. Dut',ng this two-year window, the system's ability to transfer capacity from the
Naughton Unit 3 location (in the Utah North topology bubble) to the west becomes constrained
and no offsetting displacement of capacity resources is available.
$61
PACIF.ICORP - 20 I7 IRP Upna.rE Cueprp,R 6 - RecroNal Haze Casgs
The PVRR(d) results indicate that the fixed costs of converting and operating Naughton Unit 3 as
a natural gas fueled facility with maximum generating capability are not covered by the operational
benefits accounting for reduced FOT and DSM. The PVRR(d) ranges from 561 million to $71
million higher costs for Naughton Unit 3 when assumed to operate at maximum generating
capacity under this gas conversion scenario relative to the 2017 IRP Update preferred portfolio
that assumes Naughton Unit 3 retires at the end of January 2019.
The cost increase in each price-policy scenario does not support converting Naughton Unit 3 to
gas with maximum generating capacity in June 2019 with an assumed retirement in 2029 relative
to early retirement in January 2019 as is assumed in the 2017 IRP Update preferred portfolio.
Naughton Unit 3 - Limited Gas Conversion
This case studies a limited gas conversion of Naughton Unit 3, allowing continued operation
through 2029, but reducing unit capacity from its current level of 280 MW to 42 MW . This limited
conversion option takes advantage of existing natural gas-fueling arrangements, eliminating the
capital investment that would be required to operate the unit up to its maximum generating
capability. Similar to the case that assumes maximum gas-conversion capacity, the limited gas
conversion is assumed to occur in June 2019 with retirement of the unit in 2029, which creates a
lower incremental capacity need beginning in the summer of 2079 and a lower need for
replacement resources over the 2019 to 2029 time frame. The major project schedule for Naughton
Unit 3 minimum gas conversion is reported in Figure 6.11 at the end of the chapter.
Figure 6.5 summarizes the cumulative change in resource portfolio nameplate capacity when
Naughton Unit 3 is assumed to convert to gas on a limited basis and retire in 2029 relative to the
2017 IRP Update preferred portfolio that includes early retirement of Naughton Unit 3 at the end
of January 2019 under the medium gas, medium COz price-policy scenario. Positive values show
cumulative resource portfolio additions and negative values show the cumulative capacity of
resources that are removed from the portfolio when Naughton Unit 3 is assumed to convert to gas
on a limited basis in June 2019 and retire in2029. The portfolio changes are similar to those from
the Naughton Unit 3 maximum gas conversion case and mainly include the reduction of FOT and
a reduction of DSM in2029.
71
PecmIConp _ 20 I7 IRP UPDATE Cueprpn 6 - REGTONAL Hezp Ceses
Figure 6.5 - Cumulative Increase/(Decrease) in Portfolio Resources under the Naughton
Unit 3 Limited Gas Conversion and Retire 2029
Table 6.5 shows the PVRR(d) impact of converting Naughton Unit 3 to natural gas with limited
generating capacity and retiring at the end of 2029 relative to the 2017 IRP Update preferred
portfolio that includes early retirement at the end of January 2019 for Naughton Unit 3 for each of
the three price-policy scenarios.
Table 6.5 - PVRR Cost/(Benefit) of the Naughton Unit 3 Limited Gas Conversion and
Retire 2029 Case Relative to the 2017IRP Update Preferred Portfolio by Price-Policy
Scenario
With limited fixed costs, this case shows there is potential for benefits of operating the unit at a
limited capacity, accounting for reduced FOT and DSM. This is evidenced by the slight benefits
coming out of the SO model for the low gas, zero COz and medium gas, medium COz price-policy
scenarios. The SO model benefits shown for these price-policy scenarios warrant further analysis
of the Naughton Unit 3 plant in the2019IRP. PacifiCorp will continue to assume early retirement
of Naughton Unit 3 in January 2019 in this 2017 IRP Update while continuing to evaluate the
economics of gas conversion options in the 2019 IRP.
Cholla Unit 4
Consistent with action item 59 in the 2017 IRP action plan, PacifiCorp has updated its analysis of
regional haze compliance alternatives for Cholla Unit 4. With consideration of environmental
compliance and unit economics, the 2017 IRP preferred portfolio assumed Cholla Unit 4 retires in
2020. The Cholla plant consists of four units for a combined generating capability of 995
megawatts. PacifiCorp owns 37 percent of the plant's common facilities and all of Unit 4 which
,o$ro*r$roons|rsPror)rof ,of ,obroilro*rof ,eorc|rclrof nororof ,pnbr DSM r FOTs r Gas ;e Renewable r Gas Conversion I Early Retirement I Retirement
=2
60
40
20
(20)
(40)
(60)
(80)
(100)
Change from
l7 tRP Update Pref-Port ($4)($0.4)$13 $0.s $3 $11
78
PVRR(d) Cost/(Benefit)
($ million)
System Optimizer PaR Stochastic Mean
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
High COz
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
Hieh COz
PacrprConp - 2017 IRP Upoarp Cuaprnn 6 - REGToNAL Hezs Casps
was commissioned in 1981 with a generating capability of 395 MW. Arizona Public Service
Company owns Units 1,2 and 3 and operates the entire facility. EPA has approved the Arizona
SIP incorporating an alternative regional haze compliance approach that avoids installation of SCR
equipment with a commitment to cease operating Cholla Unit 4 as a coal-fueled resource by the
end of April2025, with the option of natural gas conversion thereafter. The major project schedule
for Cholla Unit 4 gas conversion is reported in Figure 6.12 at the end of the chapter.
PacifiCorp's updated analysis compares a scenario where it is assumed Cholla Unit 4 continues to
operate as a gas-fueled facility by the end of April2025 and assuming retirement in 2042 to the
2017 IRP Update preferred portfolio, which assumes Cholla Unit 4 retires at the end of 2020. This
analysis shows that the early retirement scenario without the gas conversion is lower cost.
In the case that assumes conversion of Cholla Unit 4 and retirement in 2042, extended operation
of the resource fills a projected capacity need beginning 2021, driving a lower need for incremental
renewable resources, DSM and FOT resources over the 2021 to 2036 time frame. Figure 6.6
summarizes the cumulative change in resource portfolio nameplate capacity under the medium
natural gas, medium COz price-policy scenario when Cholla Unit 4 is assumed to convert to gas
and retire in 2042 relative to the 2017 IRP Update preferred portfolio that includes early retirement
of Cholla Unit 4 at the end of 2020. Positive values show cumulative resource portfolio additions
and negative values show the cumulative capacity of resources that are removed from the portfolio
when Cholla Unit 4 continues to operate and is assumed to convert to gas at the end of April 2025
retire in 2042.In the medium natural gas, medium COz price-policy scenario, continued operation
of Cholla Unit 4 after 2020 followed by conversion to natural gas in 2025 reduces FOT and DSM
resources. Beginning 2030, wind and solar resource additions are also reduced.
Figure 6.6 - Cumulative Increase/(Decrease) in Portfolio Resources under the Cholla Unit
4 Gas Conversion and Retire 2042 Medium Natural Gas
Table 6.6 shows the PVRR(d) impact of assuming Cholla Unit 4 converts to natural gas in 2025
and retires at the end of 2042 relative to the 2017 IRP Update preferred portfolio that includes
early retirement at the end of 2020 for each price-policy scenario.
79
.r$r**r*er&ors)r0rSr{$ro6r$ro*rdr*
r DSM r FOTs r Gas I Renewable r Gas Conversion I Early Retirement , Retirement
600
400
200
z (200)
(400)
(600)
(800)
( 1,000)
Change from
17 IRP Update Pref-Port $r29 $128 $ 168 $l l4 $6e $ 104
PecrprConp - 201 7 IRP UpDRTp Cuaprpn 6 - RncroNnl HAZE CASES
Table 6.6 - PVRR Cost/(Benefit) of the Cholla Unit 4 Gas Conversion and Retire 2042 Case
Relative to the 2017 IRP U Preferred Portfolio Price-Scenario
The following summarizes observations and results from this study under the medium natural gas
price, medium COz price-policy scenario:
Fuel and variable operation and maintenance costs increase when Cholla Unit 4 continues
generating and then converts to natural-gas-fueled operations in2025. These costs are
offset by reduced costs from new DSM and FOT.
Increased thermal generation when Cholla Unit 4 continues to operate until2042 as a
natural-gas-fueled resource enables more spot market sales and reduces spot market
purchases. These benefits are offset by increased COz emission costs starting in 2030.
Fixed costs related to Cholla Unit 4 are incurred after 2020 for operations and gas
conversion in2025. This is offset by lower fixed costs for renewables.
The PVRR(d) reported out of the SO model is nearly the same the medium natural gas, medium
COz and low natural gas, zero COz price-policy scenarios. PaR, which has additional granularity
and more refined unit commitment and dispatch logic relative to the SO model, reports a lower net
cost in the medium natural gas, medium COz price-policy scenario. However, these results still
show that it is lower cost to retire Cholla Unit 4 in 2020. Overall, the increase in present-value
system costs in each price-policy scenario does not support converting Cholla Unit 4 to natural gas
at the end of April2025. Subject to further evaluation PacifiCorp will continue to assume early
retirement of Cholla Unit 4 at the end of 2020 in the 2017 IRP Update while continuing to evaluate
the economics of early retirement and gas conversion options in the 2019 IRP.
a
a
a
80
System Optimizer PaR Stochastic MeanPVRR(d) Cost/(Benefit)
($ million)Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
Hieh COz
Low Gas,
Zero COz
Med Gas,
Med COz
High Gas,
Hieh COz
PACIF-ICoRP 20 I7 IRP UPOATE Cnnpren 6 - RecroNel Haze CesEs
Figure 6.7 through Figure 6.12 show illustrative timelines for each regional haze study
6.7 - Dave Johnston Unit 3 SCR Milestone Schedule
Pmject DeveloPment
Receive Owner's Engineer developnrcnt work propGal
Devebpment phase Appropriatbn Request approved
Ffue gas baseline fbw and perfomnce test progmm compbte
Des@ basis studies complete
NFPA 85 Code complhnce review and fumace draft study
Conlrm interconnection requLements
Begin wDEQ AQD construction pemit applbatbn
Complete EPC contract technical specilEation
Comphte phnt stakeholder review ofdraft A version ofProject Execution Phn
Finalire tumkey template EPC contract and exhibits
Complete EPC cont.act RFP rehted p.@urement approvab
Request for EPC contract propcab rcleased ftr bil
EPC cotract proposab due
Begin reguht6y filing applications
Prepare wyming Certilpate of Public Covenience and Necessity Oder Appliation
Prepare Utah Code Section 5,t I 7-402 preapproBl applicatim
Prepore Oregon IRP acknowbdgercnt filing (2015 IRP)
Complete memorandm to "short-lbt" EPC contractoE and begin negotiatbns
Shoft-list EPC Contract presenhtions and complete regotiatbns
Submil and receive WDEQ AQD coNtructlr pemit
Project Executbn Phn baselire Version 0 approved
Submit and receive Wyoming Cenilrcate ofPublic Convenbnce and Necessity Order
Submit and receive Utah Code Sectbn 5,1-17-402 preapproval
Submit and receive Oregon IRP acknowhdgement
Prcj€ct lmplementation
Impbmentatbn Appropriation Request approved
EPC Contract Effective Date (May 31,2016)
Cmplete boib. and air Eeheater structumlreinforcement detailed engireering
Boibr and ai preheater reinforcerent mat€rials onsih
Begin scope devebpment economizer modfratbns
Complete ecmmizer modifrcations dehiled engineering
Econmizer modilpation mabrhb msite
EPC c@tract pre{uhgc work cmpbte (September 2018)
EPC cotract rechanbal compbtion (November 2018)
EPC coract subshnthl compbtion (Janury 2019)
EPC cotract fmal compbtix (July 2019)
81
Actil ity Descriptiotr -==={ ",' ",, .,,
o?oa OCOa ?aao
-=:=
OOOC
a:: ii6cCd
Compliance
PacrprConp - 2017 IRP Upoere Cuep'Ien 6 RgcIoNaI HAZE CASES
6.8 - Jim Unit I SCR ect Milestone Schedule
Prcjeci Development
Receive Owne/s Engineer developrnent wffk propGal
Develop(reil phase Apprcpriation Req@st aprf,oved
FIue gas boselhe fk)w and perfomrce test program compbrc
Design basb studbs complete
NFPA 85 Code compliance review ard fumce &aft study
Confm inErconnection rcquiremenb
Begin WDEQ AQD construction pemit application
Complere EPC conkact lechnhal specilEarion
Complete plant stakeholder rcview ofdraft A venion ofProject Execution Plan
Finalire tmkey temphte EPC contract and exhibits
Complete EPC conract RFP rebted prourement apprcvals
Reqrest for EPC contmct proposals released for bid
EPC contract proposab due
Begin regulatory filing applications
Pr€p6rc Wyoming Ceflifrcare of Public Convenience and Necessity order Application
Preparc Ubh Code Seclbn 5,1 I 7-402 preapproval applhatbn
Preparc Orcgff IRP acknowledgemnt filing (2015 IRP)
Complete memmndum to "shon-lbt" EPC conractm and begin negotiatbffi
Shon-lbt EPC ContEcl presenhlbm and cmplete negotiatbm
Submi andreceive WDEQ AQD co$wcrion pemit
Prcject Executbn Phn boseline Vereih 0 approved
Submit and receive Wyoming CenilEate of Public Convenbrce and Necessity Order
Submh and receive Ubh Cod€ Sectbn 5+17-.102 prca@mval
Submit and receive Oregon IRP acknowledgement
PDject ImpleDctrbtiotr
Implemenbtion Apprcprirtion Reqwst aproved
EPC Contract Effective Date (December 31.2019)
Cmpbte boiler and air preheater strrctural reinforcement deEiled engineering
Boibr and air preheater reinforcement mteriab onsite
Begin scope development eco@mizer modifpatioN
Complete economizr nrcdilEarioN d€uiled engineering
Ecmomizer modifEation maErials oNite
EPC cmract prc-o&ge work compleb (Jme 2022)
EPC contract mchanhal compbtion (Augut 2022)
EPC cmtract subEtantbl completion (Ocbber 2022)
EPC coract f@l completion (Ap. 2022)
82
Actiyit-v D€scription =5=5????Cto?o occc o?oc
:;in.
CCCO
x.'.'F'
atJ)C
Complirnce
PRcm'rCoRp - 2017 IRP Upoeru Csapren 6 - R-acroNnl HAZE CASES
6.9 - Jim Unit 2 SCR ect Milestone Schedule
PDject DeveloPmeot
Receive Owre/s Engimer devebpinent wck propGal
Devebprreil ptEe Apprcpriatbn ReqEst appmved
FhE gs baselift fbw and perfomnce tesl progmm comphte
Design basis studbs cmplele
NFPA 85 Code compliance review and flmce dmft study
Confm ifr ercmrection requiremefr s
Begin WDEQ AQD costretion pemit application
Complete EPC contract Echnical specifration
Complere phd shkeholder rcview of draft A ve6im of Prcject Execulion PIan
Fimlize turnkey remphb EPC contmct and exhibits
Compbrc EPC cffict RFP rchted pr@rcmenl appmvah
ReqEst ftr EPC cmmct propGab rebased for bil
gPC contract prcpGab d@
Begin rcgulatory filing applbatbN
Prepare Wyoming CedfEate of Public Convenicnce ard Necessiry Order Applicalion
Prepare Uah Code Sectix 54-17-402 prcapproval application
Prepare Oregon IRP acknowledBement filing
Compbte memoBndm to "shd-list" EPC conEacto6 and begin regotiatbN
Shon-list EPC Cotuact prcsenhtioff and cmplete regdiatim
Submit and receive WDEQ AQD coBmtbn pemit
Prcject Execuim Phn baselire Ve6ih 0 approved
Submit ard receive wyming CerlilEate of Public Convenierce and Necessity Order
Submit and receive Ubh Code Sectim 54- 17-402 preapprcBl
Submit and receive Oregon IRP acknowledgemeft
Pmject Implementetion
Implemenhtion Appropriatim ReqEst approved
EPC Conhct Effective Date (December 3l,20lE)
Complete boiler and air preheater strotml rcinforcerent dehiled engireering
Boiler and air preheater reinforcemen! mteriab mite
Begin scope dewbprnent ecomizer rrcdifrcatkxB
Complele ecmmiEr modifEaliN de6iled engireering
Ecmmizer modifuation materials oNite
EPC cmmc! pre-oMge wdk conplete (Jue 2021)
EPC conmct reclEnical compbtion (Aug6t 2021)
EPC conmct subsBntial completion (October 2021)
EPC cmract fMl compbtim (Apr 2021)
83
Activity Description
OCOO =55-OOOO innn
atCOO OOOC OCOO
Compli.uc.
PacmrConp - 20 17 IRP UpoRre CHAPTER 6 - REGIONAL Heze CnSES
Figure 6.10 - Naughton Unit 3 Maximum Natural Gas Conversion Project Milestone
Schedule
PmFcl DevelopmeDt
Technbal Studies
Develop EPC cotract technaal specilpatbn and RFP package
Obtain WDEQ pemit (corected) P002ll l0 date (March 17, 2017)
Obhin WDEQ BART permit MD-604242 date (March 7,2012)
Obtain WDEQ BART pernit (modifEatbn) MD-15946 date (Jure 20, 2014)
Intercomection prcess foa removal from system
EPC contract lechnbal specifuatin and RFP dGmeft
EPC contract RFP
EPC conftact propGal eva[atbn
Iilercomectih preess for new gereratbn
Regubtory and ecorcmic rcview
NEPA ES compliarce review
EPC Conhact regdhtions; confom d@ments for contract
Devebp prcject executbn phn
Prepare and approve imphmentatir APR
Impbmenhtin APR approval date (December 5, 2017)
NaMlgas suppty cmtract RFP
Natml gas suppy cont.act negotbB
Prcject IEpleEeution
DiscontinE c@l-flreling date (Janury ]0, 2019)
EPC c@tract executim date (December 8,2017)
EPC conhct execution perbd to Mechanical Completion (> 10 months)
Natural gas supply contract execution (December 3, 2017)
Gas supply contract constrctbn perild
Natuml gas supply tb-in
Tie-in outage
EPC c@tBct rcchanialcmpbtbn date (Jue 30,2019)
EPC c@mct sub6hnital cmpbtion date(September 2q 2019)
EPC c@mct lmalcmpbtlh date (Jan@ry 30, 2020)
84
Acaivity Description
Proiect Period
{2018 2ul9 2020
o o o
,/
Ntual gs convasion
PACIFICORP -2017 IRP UPOATP CHAPTER 6 - R-E,CIONAI- HAZE CESPS
6.11 - Nr Unit 3 Limited Natural Gas Conversion Milestone Schedule
-
II
-
II
/
a
l
Prcject Development
Technical Studbs
Obtain WDEQ pemit (conected) P0021 I l0 date (March lZ 201 7)
Ohain WDEQ BART pemit MD-6042A2 dah (March 7,2012)
Ohain WDEQ BART permit (modiflcation) MD-I5946 date (Jm 20,2014)
Ohain WDEQ Tith V pemit modilEation
Reguhtory and economic review
PmFct Implementation
Dbcontinue c@l-fuelhg date (Janury 23, 2019)
Removal ofc@l puherizers frm seilice complete date (Janury 10, 2019)
Saft natual gas opemtbn date (Janmry 21, 2019)
85
701 5201{
=
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Activity Description
PACIFICoRP _2017 IRP UPDATE CHAPTER 6 - REGIoNAL Heze Casps
6.12 - Cholla Unit 4 Natural Gas Conversion ect Milestone Schedule
Pm.iect Development
Technical studies
Develop EPC contract technical speciflcation and RFP package
Obtain ADEQ comtruction pemit
Obtain ADEQ BART pemit
Contract preparatioro: EPC and NFPA 85 compliance scopes ofwork
EPC contract RFP
EPC contract negotiatims; confoming dcments for contract
NFPA 85 compliance review, scope development and tramient analysis
Develop prcject execution plan
Prepare and approve implementation APR
Implementation APR approval date (Janwry 1,2024\
Natual gas supply conkact R-FP
Natual gas supply contract negoliatiom
Pmhct Implementation
Discontinue cml-fueling date (December 31, 2024)
EPC conkact execution date (Janury l, 2024)
EPC confact executim period to Mechanical Completion (18 months)
Natwal gas supply contract execution date (Janury 1, 2024)
Natual gas supply contract consluction period
Natual gas supply tie-in
Tie-in outage
EPC contract MechanicalCompletion (May 2025)
EPC contract Substantial Completion (AugNt 2025)
EPC contract Final Completion (December 2025)
86
,fi'r 1 'r at) ))n7 1 ',.l', t )o)\
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PACIFICORP - 2017 IRP Uponrc CHAPTER 7 - ENERGY VISIoN 2O2O UPDATE
CuaprER 7 - ExsRGy Vrsrox 2020 UppATE,
Introduction
PacifiCorp's 2017 Integrated Resource Plan (IRP) presented its preferred portfolio, identifying
least-cost, least-risk resources providing near-term and long-term benefits to customers. The 2017
IRP preferred portfolio included 1,100 MW of new Wyoming wind resources, enabled by the
proposed Aeolus-to-Bridger/Anticline transmission line, and maximizing customer benefits
through wind production tax credits (PTCs). In addition, the preferred portfolio reflected
repowering 905 MW of existing wind resources by the end of 2020, re-qualifying these zero-
emission resources to receive the full value of PTCs for an additional ten years. These three major
components of the preferred portfolio (new wind and transmission, plus repowering) are
collectively described as the Energy Vision 2020 projects, providing significant net benefits to
customers over the 2}-year planning horizon.
This chapter summarizes updated analysis of Energy Vision 2020 resources. The 201 7 IRP Update
preferred portfolio includes 1,311 MW of new Wyoming wind, the Aeolus-to-Bridger/Anticline
transmission line, and just over 999 MW of repowered wind. By displacing higher cost
uncommitted market purchases and other resources, the 2017 IRP Update preferred portfolio
continues to provide the least-cost, least-risk means of meeting system needs identified in
Chapter4. This chapter also describes analysis conducted since filing the 2017 IRP, outlines
regulatory milestones and concludes with considerations for the 2019 lRP.
The 2017 IRP lays out PacifiCorp's long-term plan to deliver reliable electricity supply at a
reasonable cost. The 2017 IRP identified the best mix of resources to serve customers overthe
short- and long-term, based on an analysis of the costs and risks associated with various resource
portfolios. The2017 IRP identified the preferred portfolio as the least-cost, least-risk portfolio that
could be delivered through specific action items to deliver resources at a reasonable cost and with
manageable risks, while ensuring compliance with state and federal regulatory obligations.
PacifiCorp's 2017 IRP identified wind repowering as a least-cost, least-risk resource- The 2017
IRP also identified significant new wind (Wind Projects) and transmission resources
(Transmission Projects) as a component ofthe least-cost, least-risk resource portfolio (collectively,
the Combined Projects).
After filing the 2017 [RP, PacifiCorp conducted a comprehensive updated economic analysis in
support of its application for approval of the Energy Vision 2020 projects in Idaho, Utah, and
Wyoming. Consistent with analysis in the 2017 IRP, this analysis demonstrated that wind
repowering and the Combined Projects will provide substantial customer benefits. Additional
filings, incorporating updated data and assumptions to reflect results of the 2017R Request for
Proposals (RFP), changes in the federal income tax rate for corporations, an updated load forecast,
and updated market price and COz price assumptions.
Energy Vision 2020 project risks have been materially reduced since the 2017 IRP. When the
company made its initial filings, it was uncertain whether federal tax-reform legislation would be
87
PACIFICoRP - 20 I7 IRP Upoare CHApTER 7 - ENERGy VrsroN 2020 Uponra
introduced and how that legislation might impact PTC benefits, which are critical to the economic
benefits of the Energy Vision 2020 projects. Similarly, atthat time, the company had not yet issued
the 2017R RFP and had not received firm pricing for wind resource bids solicited through a
competitive bidding process. At this time, these uncertainties have been eliminated and replaced
with known tax law changes and competitive pricing for repowering and the Combined Projects.
Also since filing the 2017 IRP, PacifiCorp received conditional certificates of public convenience
and necessity (CPCNs) for the Aeolus-to-Bridger/Anticline transmission line, the TB Flats I & II
wind project, the Cedar Springs wind project, the Ekola Flats wind project, and associated network
upgrades from the Wyoming Public Service Commission. These CPCNs are required to secure the
necessary rights-of-ways, which has been initiated, before construction begins.
In the latest analysis that serves as the basis for the 2017 IRP Update, the company analyzed nine
different scenarios, each with varying natural gas and carbon dioxide (COz) price assumptions
(price-policy scenarios).r Both repowering and the Combined Projects continue to show significant
customer benefits which are quantified and described later in this chapter.
Modeling and Approach Summary
PacifiCorp uses two models to optimize and evaluate the least-cost, least-risk portfolio for meeting
customer needs and minimizing system costs. For this update, and consistent with the 2017 [RP,
these models were used to evaluate dozens of economic scenarios and sensitivities to inform an
updated preferred portfolio, demonstrating continuing customer benefits as a result of the Energy
Vision 2020 projects.
The System Optimizer (SO) model operates by minimizing operating costs for existing and
prospective new resources, subject to system load balance, reliability and other constraints.2 Over
the 2O-year planning horizon, it optimizes resource additions subject to resource costs and capacity
constraints (summer peak loads, winter peak loads, plus a target planning reserve margin for each
load area represented in the model). In the event that an early retirement of an existing generating
resource is assumed for a given planning scenario, the SO model will select additional resources
as required to meet summer and winter peak loads inclusive of the target planning reserve margin.
The Planning and Risk model (PaR) uses the same common input assumptions described fbr the
SO model with additional data provided by the SO model results (i.e., the selected resource
portfolio).3 While the SO model solves to ensure there is sufficient capacity for each case, PaR
considers stochastic-driven risk metrics to the evaluation of the studies. While PaR cost-risk
metrics are ultimately used when selecting a preferred portfolio in the IRP, SO model results
remain valuable and informative.
' The COu price assumptions used in the Energy Vision 2020 results analysis in this chapter were inadvertently
modeled in2012 real dollars instead of nominal dollars. Consequently, the PVRR(d) net benefits in the six price-
policy scenarios that use medium and high COz price assumptions are conseryative.
2 For a detailed description of System Optimizer's role in IRP analysis, please refer to the PacifiCorp 2017 IRP,
Chapter 6 Modeling and Portfolio Evaluation Approach, pages 145- 156, which is publicly available at the following
website link: http://www.pacif-rcorp.com/es/irp.html.I For a detailed description of the Planning and Risk model's role in IRP analysis, please refer to the PacifiCorp 2017
IRP, Chapter 6 - Modeling and Portfolio Evaluation Approach, pages 156-169, which is publicly available at the
following website link: http://www.pacifi corp.com/es/irp.html.
88
PACIFICoRP _ 2OI7 IRP UPDATE CgepTEn 7 - ENERGY VISION 2O2O UPDATE
During the period between the April 4,2017 filing of the 20l7lRP and the preparation of this
2017 IRP Update, PacifiCorp has continued to refine its economic analysis supporting the Energy
Vision 2020 projects. The analysis represented here incorporates the most current modeled
assumptions, reflecting: (l) updated cost-and-performance assumptions for the wind repowering
project and the Combined Projects; (2) current price-policy scenario assumptions, including more
current natural gas and COz prices; (3) recent changes in the federal tax rate for corporations, and
(4) nominal modeling of production tax credits. This most recent analysis also incorporates the
updates and refinements made in the second half of 2017, which included updates to PacifiCorp's
load forecast. This section summarizes updates to price-policy scenario assumptions, federal tax
assumptions, and PTC modeling assumption that are applicable to the updated analysis of the wind
repowering project and the Combined Projects.
Price-policy Scenarios
The repowering project economic analysis uses nine price-policy scenarios, developed by pairing
three natural-gas price forecasts (low, medium, and high) with three COz price forecasts (zero,
medium, and high). The medium natural-gas price assumptions were derived from PacifiCorp's
December 2017 offrcial forward price curve (OFPC). The low and high natural gas price
assumptions and the medium and high COz price assumptions are based on assumptions adopted
by third-party experts. Figure 7.1 shows natural gas price assumptions and Figure 7.2 shows the
COz price assumptions used in the updated analysis.
7.1-Hub Natural Gas Price
$10
$e
$8
$z
Etu
Ess
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$3
$2
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$0 oO O\ O N .O $ tr) \O (-- oO O\ O N .a $ tr) \Oc.l c..l N c\l c.l (\ c.l N c\ c.l .a .o .n .o .o ca ca
99999VVV99999999U99C\ C\ N N N a.l c.l c.i c.l ..1 c.l N o.l a.l o..l c.l .-l c.] a.l
-I-Low MedGas(Dec20l7OFPC) -e-High
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-J-D-D-* t't'{'{
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89
Common Assumption Updates
PncrrrConp 20 l7 IRP UponrE CIIAP,IER 7 ENERGY VISION 2O2O UpoaTE
7.2 - COz Price
Federal Tax Rate
PacifiCorp's updated analysis assumes a 2l percent federal income tax rate as provided in H.R. l,
which was passed by Congress on December 20, 2017, and became law on December 22, 2017 .
Based on an assumed net state income tax rate of 4.54 percent, the effective combined federal and
state income tax rate used in the updated analysis is24-587 percent. The effective combined federal
and state income tax rate affects PacifiCorp's post-tax weighted average cost of capital, which is
used as the discount rate in the SO model and PaR. With the changes in tax law, PacifiCorp's
discount rate was updated from 6.57 percent, as was assumed in the 2017 IRP, to 6.91 percent.
The modified income tax rate also affects the capital revenue requirement for all new resource
options available for selection in the SO model.
Finally, the updated income tax rate affects the tax gross-up of all PTC-eligible resources. As noted
above, the current value of federal PTCs is $24lMWh, which equates to a $3 1.82lMWh reduction
in revenue requirement assuming an effective combined federal and state income tax rate of 24.587
$0 I.{-I'-I-|-}{-|-E{-}.{-I-}{-I-I-{-I
,P'-'-O-{l 'P'
oF
G
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90
Capital revenue requirement is levelized in the SO and PaR models to avoid potential distortions
in the economic analysis of capital-intensive assets that have different lives and in-service dates.
This is achieved through annual capital recovery factors, which are expressed as a percentage of
the initial capital investment for any given resource alternative in any given year. Capital recovery
factors, which are based on the revenue requirement for specific types of assets, are differentiated
by each asset's assumed life, book-depreciation rates, and tax-depreciation rates. Because capital
revenue requirement accounts for the impact of income taxes on rate-based assets, the capital
recovery factors applied to new resource costs in the SO model were updated for each of
Pacifi Corp's system simulations.
PACIFICORP 20 I7 IRP UPOATE Csap'mn 7 - ENERGy VrsroN 2020 UponlE
In recent analysis including this 2017 IRP Update, the Company applied PTC benefits on a nominal
basis rather than on a levelized basis. This approach better reflects how the federal PTC benefits
for the repowered assets and Wind Projects will flow through to customers, conforms the treatment
of PTC benefits with other costs and benefits that are not actually spread over the life of an asset,
and appropriately weights the contribution of PTC benefits in present-value calculations.
Wind Repowering
Recent advancements in wind generation technology, including innovations in wind turbine design
and control systems, allow modern wind turbines to generate greater energy from available wind
resources. To take advantage of these recent technologies, PacifiCorp intends to repower most of
its Wyoming wind fleet (Glenrock I, Glenrock III, Rolling Hills, Seven Mile Hill I, Seven Mile
Hill II, High Plains, McFadden Ridge, and Dunlap);the Marengo [, Marengo II and Goodnoe Hills
facilities in Washington; and the Leaning Juniper facility in Oregon. The combined current
capacity of these facilities is just over 999 MW, with 594 MW in Wyoming, 304.6 MW in
Washington, and 100.5 MW in Oregon.
Efficiency Improvements and Extended Project Life
Wind repowering involves the installation of new rotors with longer blades and new nacelles with
higher-capacity generators. Longer blades increase the wind-swept area of the wind turbine and
allow it to produce more energy at lower wind speeds. The nacelle is the housing that sits atop the
tower and contains the gear box, low- and high-speed shafts, generator, controller, and brake. The
new nacelles will include sophisticated control systems and more robust mechanical and generator
components necessary to handle the greater loads that come with longer blades. Together, the new
rotors and nacelles are estimated to increase wind project generation by approximately 26 percent.
In addition, the innovative technologies provide for greater control of power quality and voltage,
allowing PacifiCorp to more easily integrate the energy from the wind facilities into the
transmission system and support the reliability of the grid. The new equipment also reduces future
operating costs and extends the useful life of each wind plant by at least l0 years. PacifiCorp
intends to file new depreciation rates in 2019. At that time, PacifiCorp will reset the 30-year
depreciable life of the repowered wind facilities, effectively extending the depreciable life of the
facilities by l0 to l3 years.
Over the current life of the repowered facilities, incremental annual energy production is
approximately 738 GWh. Over the extended life, the incremental annual energy production is
approximately 3,500 GWh. Importantly, because the wind repowering project involves efficiency
improvements to existing facilities, these benefits can be achieved without the costs and
complexity of permitting and constructing wholly new facilities.
9l
percent, adjusted for inflation over time. The impact of the updated income tax rate assumptions
were applied to all PTC-eligible resource alternatives available in the SO model.
Production Tax Credit Modeling
PacIplConp -2017 IRP UPDATE Cueprsn 7 - ENs,ncv VrsroN 2020 Upoarp
Production Tax Credits and Customer Benefits
The cost-effectiveness of the wind repowering project is driven in part by the fact that repowering
requalifies PacifiCorp's existing wind facilities for PTCs, which are set to expire l0 years from
their original commercial operation date (expiration dates range from 2016 through 2020).
Currently, wind facilities qualifying for the PTC receive 2.4 cents per kilowatt-hour-or
$24lMwh-a value that is adjusted annually based upon an inflation index.
To requalify for PTCs, the repowered wind facility must meet the Internal Revenue Service's 80120
test-meaning that the fair market value of the retained property (i.e., the tower and foundation)
is no more than20 percent of the facility's total value after installation of the new property (i.e.,
nacelle and rotor). PacifiCorp has designed its wind repowering project to satisfy this test to ensure
that the repowered wind facilities are PTC eligible.
Further, to ensure the repowered facilities are eligible for 100 percent of available PTC benefits,
in December 2016, PacifiCorp contracted with global wind industry leaders General Electric, Inc.,
and Vestas-American Wind Technology, Inc., to purchase new wind-turbine generator equipment.
These "safe-harbor equipment" purchases allow the repowered wind facilities to qualify for 100
percent of the value of PTCs, assuming commercial operation by the end of 2020.
PacifiCorp's construction schedule will maximize the value of the existing PTCs by minimizing
the period between the expiration of the original PTCs and the eligibility for the new PTCs. The
original PTCs expire l0 years after each plant became commercially operational. Thus, the PTCs
for most of the facilities will expire in 2018 and 2019. Achieving commercial operation in2019
for most of the facilities will minimize the time during which any wind facilities are ineligible for
PTCs.
Updated Data and Assumptions
During the period between the April 4,2017 filing of the 2017 IRP and the preparation of this
2017 IRP Update, PacifiCorp has continued to refine its economic analysis supporting the wind
repowering project. In addition to the assumption updates summarized earlier in this chapter, the
updated analysis of the wind repowering project incorporates the most current cost-and-
performance assumptions for the wind repowering project.
Cost estimates for the wind repowering project have been updated consistent with findings from
technical review studies. These technical review studies have led to a change in turbine
specifications at the Leaning Juniper facility to ensure turbine loading remains within allowable
limits. Project costs have been updated to account for the need to strengthen foundations at the
Leaning Juniper and Goodnoe Hills facilities. Updated cost assumptions also reflect information
received through a competitive bidding process for installation, foundation retrofits, as applicable,
and other construction services needed to complete the wind repowering project.
Performance estimates for the wind repowering project have been updated to reflect: a) updated
turbine specifications for nearly all facilities, including larger rotor diameters and higher capacity
generators for the Wyoming wind facilities; b) a change in turbine specifications at the Leaning
Juniper and Goodnoe Hills facilities; c) the incorporation of four years of historical production
data and increased wake losses into the estimates of increased energy production for the repowered
92
PACIFICoRP 2O I7 IRP UPONTE CHAPTER 7 - ENERGY VISIoN 2O2O UPDATE
facilities; and d) increased incremental energy production at the Marengo I and II facilities to
reflect a modified interconnection agreement that will allow the facilities to operate at their full
repowered capacity.
Repowering Results
The SO model and PaR were used to calculate the present-value revenue requirement differential
("PVRR(d)") between a simulation with and without the wind repowering project after applying
the modeling updates summarized above. These simulations continue to cover a forecast horizon
out through 2036. PacifiCorp also updated its calculation of the PVRR(d) from the change in
nominal revenue requirement due to the wind repowering project through 2050.
Proj ect-by-Proj ect Results
Table 7.1 summarizes the PVRR(d) results for each wind facility within the scope of the wind
repowering project under the medium natural gas price, medium COz price-policy scenario. The
PVRR(d) between cases with and without wind repowering are shown for each wind facility based
on system modeling results from the SO model and for PaR, before accounting for the substantial
increase in incremental energy beyond the 2036 time frame. When applying medium natural gas,
medium COz price-policy assumptions, benefits from repowering the Leaning Juniper wind
facility are equal to costs. All other wind facilities are projected to deliver net benefits.
Table 7.1 - Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Repowering
with Medium Natural Gas and Medium CO2 Price million
Table 7.2 summarizes the PVRR(d) results for each wind facility within the scope of the wind
repowering project under the low natural gas price, zero COz price-policy scenario. The PVRR(d)
between cases with and without wind repowering are shown for each wind facility based on system
modeling results from the SO model and for PaR, before accounting for the substantial increase in
incremental energy beyond the 2036 time frame. When applying low natural gas and zerc COz
price-policy assumptions, costs from repowering the Leaning Juniper wind facility are slightly
higher than the benefits. All other wind facilities are projected to deliver net benefits.
Glenrock I ($2s;($2 t;($2:1
Glenrock 3 ($s;($z;(sz;
Seven Mile Hill I ($::;($24;($2e)
($z;($z)($z;
(s l7)(s l3)($ l3)High Plains
McFadden Ridee ($s;(S+1 ($+1
($30)($26)($27\Dunlap Ranch
Rolline Hills (st2)(se)($ l0)
Leaning Juniper s0 $0 $0
(s35)($33)($34)Marengo I
Marengo 2 ($ls;($ t+1 ($ls1
Goodnoe Hills (s l8)($ l8)($lq)
Total (s20s)($ l 80)(s l 89)
93
Wind Facility SO Model
PVRR(d)
PaR Stochastic-
Mean PVRR(d)
PaR Risk-Adjusted
PVRR(d)
Seven Mile Hill2
($22)Glenrock I ($z t;($z t;
Glenrock 3 ($7)($6)(s6)
Seven Mile Hill I ($241 ($28)($20;
($6)Seven Mile Hill 2 ($o;($o;
Hieh Plains ($ 12)($e)($ l0)
McFadden Ridee ($+)($:)($3)
Dunlap Ranch ($2s1 ($zz1 ($2+;
Rolline Hills ($e)($7)(s7)
Leaning Juniper $6 $3 s4
(s26)Marengo I (5221 ($2s;
Marengo 2 ($l t)($ l0)(sl l)
Goodnoe Hills ($ t:;($ls)(sl s)
Total (s1s7)($ 1 49)($ I s6)
PRcrprConp -2011 IRP UPDATE CHnprsn 7 - ENERGy VrsroN 2020 Upoarp
Table 7.2 - Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind
with Low Natural Gas and No CO2 Price Assu million
Table 7.3 summarizes the PVRR(d) results for each wind facility calculated off of the change in
annual nominal revenue requirement through 2050 for both price-policy scenarios. Unlike the
results summarized in Table 7 .l and Table 7 .2, these results account for the substantial increase in
incremental energy beyond the 2036 time frame. Each of the wind facilities within the scope of
the proposed repowering project show net benefits with repowering under the medium natural gas
and medium COz price-policy scenario and all facilities show net benefits under the low natural
gas and zero CO2 price-policy scenario, except for the Leaning Juniper wind facility, where the
benefits are equal to the costs. However, these results are conservative, as the assumed benefits do
not account for the capacity value of the repowered wind facilities in the period when they would
have otherwise hit the end of their depreciable lives (i.e., beyond 2036).
94
Wind Facility SO Model
PVRR(d)
PaR Stochastic-
Mean PVRR(d)
PaR Risk-Adjusted
PVRR(d)
PACIFICoRP -2017 IRP UPDATE Crr.,rpT[n 7 ENrnc;y VrsroN 2020 UpDAlr,
Table 7.3 - Project-by-Project Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of
Wind million
A fuither assessment of the magnitude of the PVRR(d) results must be considered in relation to
the specific attributes of the repowered wind facility, including the size of the facility, the expected
cost to repower the facility, and the level of annual energy output expected after the new equipment
is installed. For example, the PVRR(d) for McFadden Ridge shows a $7 million benefit when
repowered (using medium natural gas and medium COz price-policy assumptions)-the lowest
PVRR(d) among all of the project-by-project results. The PVRR(d) benefit for McFadden Ridge
is approximately 74 percent of the $50 million benefit for Marengo I, which yields the highest
PVRR(d) among all of the project-by-project results. However, the current capacity of McFadden
Ridge (28.5 MW) is approximately 20 percent of the current capacity of Marengo I (140.4 MW).
Similarly, the expected energy output after repowering McFadden Ridge (approximately I l7 GWh
per year) is approximately 24 percent of the expected energy output after repowering Marengo I
(approximately 488 GWh per year).
A reasonable metric to evaluate the relative benefits among the wind facilities that captures the
specific attributes of each facility is the nominal levelized net benefit per incremental MWh
expected after the facility is repowered. This metric captures the specific repowering cost for each
facility net of the specific benefits of each facility per incremental MWh of energy expected after
the facility is repowered. Table 7.4 shows the nominal levelized net benefit of repowering per
MWh of expected incremental energy output after repowering for each wind facility. When using
medium natural gas, medium COz price-policy assumptions, the table shows the Seven Mile Hill
II facility produces the largest net benefit per incremental MWh ($37lMWh), and Leaning Juniper
produces the smallest net benefit per incremental MWh ($7/MWh).
Wind Facility Medium Natural Gas
and Medium COz
Low Natural Gas and
Zero COz
Glenrock I ($::1 ($::1
Glenrock 3 (s1l)($o;
Seven Mile Hill 1 ($4t1 ($40)
Seven Mile Hill2 (sto;($o)
High Plains ($221 ($6)
McFadden Ridee ($7)($z;
Dunlap Ranch ($:e1 ($23)
Rolline Hills ($ts;($s;
Leaning Juniper ($8)s0
Marengo 1 ($so1 ($zz1
Marengo 2 ($20)($21
Goodnoe Hills ($26)($ll;
Total ($2az;($ t zo)
95
Medium Natural Gas
and Medium COz
Low Natural Gas
and Zero COzWind Facility
Glenrock I $29lMWh $29lMWh
s l6lMWhGlenrock 3 $28lMWh
$30/MWh $29lMWhSeven Mile Hill I
Seven Mile Hill2 $36lMWh $23lMWh
s5/MWhHigh Plains S I7lMWh
s l7lMwh s5/MWhMcFadden Ridge
Dunlap Ranch $28lMWh sl7/Mwh
Rolline Hills s1g/MWh $7/MWh
$7/MWh $0/MWhLeaning Juniper
Marengo I $25lMWh sr l/Mwh
Marengo 2 $21lMWh $8/MWh
s26lMWh $ l8/MWhGoodnoe Hills
Weiehted Average s23lMWh s l4lMWh
PACIFICoRP _2017 IRP UPDATE ClrAprER 7 - ENERGy VrsroN 2020 UpDAlr,
Table 7.4 - Nominal Levelized Net Benefit per MWh of Incremental Energy Output after
All Repower Project Results
Table 7.5 reports that in this latest analysis over a Z}-year period, repowering reduces customer
costs in all nine price-policy scenarios. The outcome is consistent in both the SO model and PaR
results. Under the central price-policy scenario, assuming medium natural-gas, medium COz price-
policy assumptions, the PVRR(d) net benefits range between $180 million, when derived from
PaR stochastic-mean results, and $204 million, when derived from SO model results. PaR risk-
adjusted results range from $146 million when assessed with low natural gas, medium COz price-
policy assumptions to 5260 million when assessed with high natural gas, medium COz price-policy
assumptions. In the expected medium natural gas, medium COz price-policy scenario, wind
repowering results in PaR risk-adjusted customer benefits of $ 189 million.
Table 7.5 - SO Model and PaR d of Wind owerl million
Projected system net benefits increase with higher natural-gas price assumptions, and similarly,
generally increase with higher COz price assumptions. Conversely, system net benefits generally
decline when low natural-gas prices and low COz prices are assumed. This trend holds true when
looking at the results from the two simulations used to calculate the PVRR(d) for all nine of the
PaR Risk-
Adiusted PVRR(d)Price-Policy Scenario SO Model
PVRR(d)
PaR Stochastic
Mean PVRR(d)
(s I se)($ l4 l)(s148)Low Gas, Zero COz
Low Gas, Medium COz ($ I 58)($ I 3e)($ t +o;
($ 1 73)Low Gas, High CO:($ I s:;($ I os;
Medium Gas, Zero COz ($20 1 )($l7l)($ 1 80)
Medium Gas, Medium COz ($204)($ I 80)(s 1 8e)
(s I e3)($203)Medium Gas, High COz ($2 I s)
Hieh Gas, Zero COz ($2s7)($234)($z+o;
High Gas, Medium COz ($zoo;(s248)($260)
Hieh Gas, Hish COz (s273)(s240)($2s2)
96
PacrrrConp -2017 IRP UPDATE CHAPTER 7 _ ENERGY VISIoN 2O2O UPDATE
price-policy scenarios. Importantly, both models continue to show that the net benefits from the
wind repowering project are robust across a range of price-policy assumptions.
The wind repowering project creates these benefits by:
. Increasing energy production from the wind facilities by approximately 25-7 percenq. Reducing ongoing operating costs associated with aging wind turbines;. Extending the useful lives of the wind facilities by at least l0 years;. Increasing the output of renewable energy from existing assets, while avoiding the
environmental impacts and view-shed issues associated with new facilities;. Reducing customer costs by requalifying the wind facilities for PTCs for an additional l0
years; and. Improving the ability of the wind facilities to deliver cost-effective renewable energy into
the transmission system through enhanced voltage support and power quality.
These benefit trends hold true for annual data over the period 2017 through 2050. Table 7.6
summarizes the updated PVRR(d) results for each price-policy scenario calculated off of the
change in annual nominal revenue requirement through 2050.
Table 7.6 - Nominal Revenue of Wind million
When system costs and benefits from the wind repowering project are extended through 2050,
covering the full depreciable life of the repowered wind facilities, the wind repowering project
reduces customer costs in all nine price-policy scenarios. Customer benefits range from Sl21
million in the low natural gas, medium COz price-policy scenario to $466 million in the high
natural gas, high COz price-policy scenario. Under the central price-policy scenario, assuming
medium natural-gas prices and medium COz prices, the PVRR(d) benefits of the wind repowering
project are $273 million. While changes in federal income tax law have reduced net benefits
relative to the economic analysis summarized prior to the passage of H.R. l, the wind repowering
project continues to provide significant customer benefits in all price-policy scenarios, and the
updated economic analysis reconfirms that upside benefits outweigh downside risks.
Repowering Project Upside
The PVRR(d) results presented in Table 7.1 throughTableT.6 do not reflect the potential renewable
energy credits (REC) value of incremental energy output from the repowered facilities. Accounting
Low Gas, Zero COz ($ I 27)
Low Gas, Medium COz ($lzt;
Low Gas, High COz ($223)
Medium Gas, Zero COz ($224)
($273)Medium Gas, Medium COz
Medium Gas, High COz (s321)
High Gas, Zero COz ($38e)
Hieh Gas, Medium COz ($386)
High Gas, High COz (s466)
97
Price-Policy Scenario Annual Revenue Requirement PVRR(d)
CHAPTER 7 - ENERGY VISION 2O2O UPOaTT
for the updated performance estimates discussed above, customer benefits for all price-policy
scenarios would improve by approximately $6 million for every dollar assigned to the incremental
RECs that will be generated from the repowered facilities through 2036. Benefits for all price-
policy scenarios would improve by approximately $12 million for every dollar assigned to the
incremental RECs that will be generated from the repowered f-acilities through 2050. Quantifying
the potential upside associated with incremental REC revenues is intended to simply communicate
that the net benefits from the repowering project could improve if the incremental RECs can be
monetized in the market. Moreover, as noted earlier, none of the economic analyses account for
the capacity value of the repowered wind facilities in the period when they would have otherwise
hit the end of their depreciable lives (i.e., beyond 2036).
New Wind and Transmission (Combined Projects)
Analysis conducted in the 2017 IRP covered a wide range of studies, including regional haze cases,
price-policy cases and sensitivities. Wyoming wind was consistently selected in the optimized
portfolios of nearly all cases, up to the maximum capacity of Wyoming wind capable of
interconnecting to the transmission system without incremental investment in Energy Gateway
transmission infrastructure. Based on these results, PacifiCorp further analyzed Energy Gateway
sensitivities. This analysis showed that the combination of new wind and new transmission
resulted in the least-cost, least-risk combination of resources to meet load and resource needs over
the 2}-year planning horizon. Enabled by the transmission projects described later in this chapter,
and based on the results of PacifiCorp's 201 7R RFP, 1,3 I I MW of new wind resources will be
placed in service by the end of 2020, creating substantial benefits for customers.
Wind Projects
Extension of federal PTCs created a time-limited opportunity for PacifiCorp to acquire significant
cost-effective, zero-fuel cost wind resources, generating PTCs from the Wind Projects that will
help meet projected capacity needs and provide substantial benefits for customers. The additional
capacity from the Wind Projects will reduce reliance on more costly and less certain resources, in
particular uncommitted front office transactions (market purchases) over the near term and defer
the need for higher-cost resource alternatives over the long term. While not valued as part of this
analysis, the new wind energy will also produce additional RECs, further increasing the value of
these new resources.
To achieve the full customer benefits of the PTCs, PacifiCorp must develop the Wind Projects
with the Transmission Projects and bring them into service together. The Wind Projects are not
economic without the Transmission Projects, which are needed to relieve existing congestion and
to interconnect new PTC-eligible wind facilities in high-wind areas of Wyoming. The
Transmission Projects are not economic without incremental cost-effective wind facilities
producing zero-fuel-cost energy and PTCs.
2017R RFP
The 2017 IRP Update preferred portfolio relies on the extensive analysis conducted in the
Company's 2017R RFP, and advances PacifiCorp's commitment to low-cost energy with plans to
98
PACIFICORP - 20 I7 IRP Upoerp
PACIFICoRP 20I7 IRP UPOnrg CrreprER 7 ENERGY VISIoN 2O2O UpoarE
add 1,3 1 I MW of new Wyoming wind resources by the end of 2020.4 These new zero-emission
wind facilities will connect to a new 14O-mile, 500 kV transmission line running from the Aeolus
substation near Medicine Bow, Wyoming, to the Jim Bridger power plant (a sub-segment of the
Energy Gateway West transmission project). In addition to providing significant economic
benefits for PacifiCorp's customers, the wind and transmission project will reduce market reliance,
improve transmission reliability, and provide economic development benefits.
PacifiCorp received initial bids for Wyoming wind projects on October 17,2017, and initial bids
for non-Wyoming wind projects on October 24, 2017 . The 2017R RFP was well received by the
market, as indicated by the fact the company received Wyoming wind proposals from nine bidders
offering 49bid alternatives for 13 wind projects. PacifiCorp also received non-Wyoming wind
proposals from five bidders offering l5 bid alternatives for six wind projects. In aggregate,5,2l9
MW of new wind resource capacity was bid into the 2017R P.FP (4,624 MW of Wyoming wind
and 595 MW of non-Wyoming wind).
The 2017R RFP was monitored by two independent evaluators-one retained by PacifiCorp and
appointed by the Public Utility Commission of Oregon and one retained by the Public Service
Commission of Utah-and resulted in a final shortlist consisting of four projects: (l) the TB Flats
I & II project providing 500 MW of capacity in Carbon and Albany Counties, Wyoming; (2) the
Cedar Springs project providing 400 MW of capacity in Converse County, Wyoming; (3) the
Ekola Flats project providing 250 MW of capacity in Carbon County, Wyoming; and (4) the Uinta
project providing l6l MW of capacity in Uinta County, Wyoming. Together, these least-cost,
least-risk projects will provide l,3ll MW of zero-fuel cost, emission-free generation to serve
PacifiCorp's customers. Approximately 1,150 MW of this capacity (TB Flats I & II, Cedar
Springs, and Ekola Flats) is located within the transmission-constrained area of PacifiCorp's
transmission system in eastern Wyoming and is enabled by the Aeolus-to-Bridger/Anticline
transmission line. The remaining 161 MW of capacity (Uinta) is located in westem Wyoming.
PacifiCorp selected the final-shortlist projects after performing detailed and comprehensive
economic analysis of all bids received. Using the same models and methodology used in the2017
IRP, PacifiCorp determined the optimum combination of bids to maximize customer benefits.
Extensive modeling confirms that the final shortlist resources meet both near-term and long-term
resource needs and are the least-cost, least-risk path available to serve PacifiCorp's customers.
PacifiCorp's risk assessment further demonstrates that the final-shortlist resources provide
substantial customer benefits across nearly every natural gas and COz price-policy scenarios
studied. Relative to the 201 7 IRP, the 2017R RFP results demonstrate increased customer benefits
from the new wind resources, in combination with construction of the Aeolus-to-Bridger/Anticline
500-kV transmission line and associated infrastructure (transmission project).
Transmission Projects
While the Aeolus-to-Bridger/Anticline transmission line has long been recognized as an integral
component of PacifiCorp's long-term transmission planning, its construction and that of the other
components of the Transmission Projects has not been economic until now. The Transmission
Projects will contribute to meeting PacifiCorp's short- and long-term capacity need and will
strengthen the overall reliability of the existing transmission system.
120t7 Wind IRP issued September 27,2011 , approved by the Public Service Commission of Utah on September 22,
2017 , and the Public Utility Commission of Oregon on September 27 , 20ll
99
PACIFICoRP _ 2017 IRP Upoarg CHaprpn 7 - ENsncy VISIoN 2020 Upnem
Congestion on the current transmission system in eastern Wyoming limits the ability to deliver
energy from eastem Wyoming to the Jim Bridger area. The Aeolus-to-Bridger/Anticline line will
relieve this congestion and increase the transmission capacity across Wyoming by approximately
950 MW.s The Transmission Projects will allow PacifiCorp to interconnect 1,3 I 1 MW of wind
resources and create substantial benefits for customers throughout its service area. Construction of
the Transmission Projects will also enable PacifiCorp to more efficiently use existing generation
resources in Wyoming to serve loads in Utah, Wyoming, Idaho, and the Pacific Northwest. The
Transmission Projects also better position PacifiCorp to interconnect future resources in
southeastern Wyoming and provide greater flexibility in managing existing resources.
In addition to increasing the transmission capacity out of southeastern Wyoming, the Transmission
Projects will also provide critical voltage support to the Wyoming transmission network and
enhance the overall reliability of the transmission system by adding incremental new transmission
capacity westbound between the company's existing thermal and renewable facilities, the
proposed Wind Projects in eastern Wyoming, and other sources of energy in northern Utah.
Additional transmission paths will mitigate the impact of outages on the existing system. The
Transmission Projects will also enhance PacifiCorp's ability to comply with mandated North
American Electric Reliability Corporation and Western Electricity Coordinating Council
reliability and performance standards.
The Aeolus-to-Bridger/Anticline line is also an important component of PacifiCorp's Energy
Gateway Transmission project and has long been recognized as a key transmission segment in the
region's long-term transmission planning. By acting on this time-limited opportunity to develop
the Transmission Projects and the associated Wind Projects, PacifiCorp can deliver substantial
benefits for its customers.
Wyoming CPCNs
On April 12,2018, PacifiCorp received conditional CPCNs for the Aeolus-to-Bridger/Anticline
transmission line, the TB Flats I & II wind project, the Cedar Springs wind project, the Ekola Flats
wind project, and associated network upgrades from the Wyoming Public Service Commission.
These CPCNs are required to secure the necessary rights-of-ways, which has been initiated, before
construction begins.
Production Tax Credits and Customer Benefits
The substantial customer benefits resulting from the acquisition of the Wind Projects reflects the
fact that these facilities can qualify for 100 percent of federal PTCs by achieving commercial
operation by December 31, 2020.
PacifiCorp's approach to the Combined Projects is to mitigate risk and ensure that appropriate off-
ramps exist in the project review, approval, and implementation processes before significant
capital outlays or commitments are made in case the necessary approvals are not received, project
economic benefits erode, or the associated benefits are placed at risk. With timely regulatory
5 The updated economic analysis assumes the incremental transfer capability is 750 MW. Subsequent transmission
studies have confirmed the transfer capability is 950 MW. Consequently, the economic analysis presented in this
chapter is conservative.
100
PACIFICORP 2OI7 IRPUPOATT,CuapTER 7 - ENERGY VISION 2O2O UPDATE
reviews and approvals, and successful transmission rights of way (ROW) acquisition, PacifiCorp
fully expects it will successfully meet the requirements necessary to ensure eligibility for 100
percent of the PTCs.
Updated Data and Assumptions
During the period between the April 4,2017 filing of the 20ll IRP and the preparation of this
2017 IRP Update, PacifiCorp has continued to refine its economic analysis supporting the
Combined Projects. In addition to the assumption updates summarized earlier in this chapter, the
updated analysis of the Combined Projects incorporates the most current cost-and-performance
assumptions.
Wind Projects
Table 7.7 presents the winning wind bids from the 2017R RFP. The updated best-and-final pricing
received on December 21,2077 was used in the model analysis to establish the winning projects,
and the model results are presented later in this chapter. The total capacity of the winning bids is
1,31 I MW, assuming commercial operation by the end of 2021.
Table 7.7 - 2017R RFP Final Shortlist
The TB Flats I & II and Ekola Flats projects are company-benchmark resources that will be
developed under engineer, procure, and construction (EPC) agreements. The Uinta project is being
developed by Invenergy Wind Development under a build-transfer agreement (BTA). The Cedar
Springs project is being developed by NextEra Energy Acquisitions as a 50-percent BTA and a
5O-percent power-purchase agreement (PPA). In total, the updated final shortlist includes 361 MW
that will be developed under BTAs, 750 MW of benchmark capacity that will be developed under
EPC agreements, and 200 MW that will deliver energy and capacity under a PPA.
In aggregate, the winning bids are expected to operate at a capacity-weighted average annual
capacity factor of39.4 percent.
Transmission Interconnection-Restudy Process
Separate from the 2017R RFP process, the company completed an interconnection-restudy process
to ensure that interconnection studies reflected the most current long-term transmission plan to
construct the Aeolus-to-Bridger/Anticline D.2 segment of the Energy Gateway project by the end
of 2020. PacifiCorp transmission restudied, in serial interconnection-queue order, interconnection
requests that do not already have an interconnection agreement to determine whether the staging
TB Flats I & II (PacifiCorp)Carbon & Albany
Counties, WY 500
Cedar Springs (NextEra Energy
Acquisitions)Converse County, WY 400
Ekola Flats (PacifiCorp)Carbon County, WY 250
Uinta (Invenergy Wind Development)Uinta County, WY 161
101
Proiect Name (Bidder)Location Capacity (MW)
PacrprConp - 2017 IRP UpoaTp CnAp l'[ri 7 ENr:ncv VrsroN 2020 Uppn'r r
of the Energy Gateway West project would affect the cost or timing of projects whose previous
interconnection studies depended on Gateway West in its entirety. Affected projects located in the
constrained area of PacifiCorp's transmission system in eastem Wyoming were restudied through
the point in the interconnection queue where additional segments of the Energy Gateway project
beyond just the Aeolus-to-Bridger/Anticline D.2 segment would be required to interconnect.
PacifiCorp transmission posted the restudied system-impact studies (SISs) on PacifiCorp's open
access same-time information system on January 29,2018, as well as certain updated restudied
SISs on February 9, 2018.
The interconnection-restudy process showed that the Aeolus-to-Bridger/Anticline transmission
line will enable interconnection of up to 1,5 l0 MW of new wind capacity within the constrained
area of PacifiCorp's transmission system in eastern Wyoming. However, to honor an executed
interconnection agreement with a 240 MW qualifying facility (QF) project in the area, PacifiCorp
must reserve sufficient interconnection capacity for this QF's interconnection, which results in an
incremental capacity of 1,270 MW. This is up from the 1,030 MW assumed in previous studies.
The interconnection-restudy process confirms that all bids selected to the 2017R final shortlist can
secure interconnection service either because they hold an interconnection-queue position that
does not require Energy Gateway South (Ekola Flats, TB Flats I and II, and Cedar Springs) or
because the project is not located in the constrained area of the company's eastern Wyoming
transmission system (Uinta).
New Wind and Transmission Results
As a component of the 2017R RFP, PacifiCorp produced updated portfolio-development studies
using the SO model to create a bid portfolio containing the least-cost combination of viable bids.
In choosing the least-cost combination of bids, the SO model was configured to select from all
viable bid altematives. Consistent with the increased interconnection capability identified during
the interconnection-restudy process, the SO model was also configured to select up to 1,270 MW
of bids located in this area of PacifiCorp's transmission system.
Table 7.8 summarizes the updated PVRR(d) results for each price-policy scenario. The PVRR(d)
between cases with and without the Combined Projects, reflecting the final shortlist from the
2017R RFP, are shown for the SO model and for PaR, which was used to calculate both the
stochastic-mean PVRR(d) and the risk-adjusted PVRR(d).
102
PecrprConp -2017 IRP Upoars CIIAP.I.I|R 7 ENI|RGY VISION 2O2O UPDA II.
Table 7.8 - SO Model and PaR PVRR(d) (Benefit)/Cost of the
Combined ects
Over a Zl-year period, the Combined Projects reduce customer costs in all nine price-policy
scenarios. This outcome is consistent in both the SO model and PaR results. Under the central
price-policy scenario, when applying medium natural gas, medium COz price-policy assumptions,
the PVRR(d) net benefits range between $357 million, when derived from PaR stochastic-mean
results, and $405 million, when derived from SO model results.
The Combined Projects create these benefits by:
. Reducing customer costs by generating significant PTC benefits;. Contributing to meeting system capacity needs, thereby reducing reliance on
uncommitted front office transactions (market purchases) in the near term and deferring
the need for higher cost resource alternatives over the long term;. Reducing system fuel costs;. Increasing transmission capability in a constrained area, enabling better use of resources;. Avoiding emissions costs in the medium and high COz price scenarios;
Table 7.9 summarizes the updated PVRR(d) results for each price-policy scenario calculated off
of the change in annual nominal revenue requirement through 2050.
Low Gas, Zero COz (185)(ls0)(156)
Low Gas, Medium COz (208)(t7e)(1 88)
Low Gas, Hieh COz (370)(337\(355)
Medium Gas, Zero COz (377\(3le)(334)
(40s)Medium Gas, Medium COz (3s7)(386)
Medium Gas, Hieh COz (48e)(448)(46e)
High Gas, Zero COz (6ee)(s68)(se6)
(716)High Gas, Medium COz (603)(633)
Hieh Gas, Hieh COz (781)(6e4)(728)
103
Price-Policy Scenario SO Model
PVRR(d)
PaR Stochastic-
Mean PVRR(d)
PaR Risk-Adjusted
PVRR(d)
Table 7.9 - Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of the
Combined ects million
When system costs and benefits from the Combined Projects are extended out through 2050,
covering the full depreciable life of the owned-wind projects included in the updated 2017R RFP
final shortlist, the Combined Projects reduce customer costs in seven out of nine price-policy
scenarios.
In those price-policy scenarios showing net benefits, customer net benefits range from $92 million
in the medium natural gas, zero COz price-policy scenario to $635 million in the high natural gas,
high COz price-policy scenario. Under the central price-policy scenario, when applying medium
natural gas, medium COz price-policy assumptions, the PVRR(d) benefits of the Combined
Projects are $167 million. The Combined Projects provide significant customer benefits in all
price-policy scenarios, and the net benefits are unfavorable only when low natural-gas prices are
paired with zero or medium COz prices. These results continue to show that upside benefits far
outweigh downside risks.
Potential Wind Projects Upside
The PVRR(d) results presented in Table 7.8 andTable 7.9 do not reflect the potential value of
RECs generated by the incremental energy output from the Wind Projects. Accounting for the
performance estimates from these wind facilities, customer benefits for all price-policy scenarios
would improve by approximately $34 million for every dollar assigned to the incremental RECs
that will be generated from the winning bids through2036. When calculated from expected wind
generation through 2050, customer benefits would increase by approximately $43 million in all
price-policy scenarios. Quantifying the potential upside associated with incremental REC revenues
is simply intended to communicate that the net benefits from the winning bids could improve if
the incremental RECs can be monetized in the market.
Also, projects with large wind turbines are expected to require less O&M costs because there are
fewer turbines on a given site. The default O&M assumptions applied to BTA and benchmark-
EPC bids in the updated economic analysis are based on the company's experience in operating
and maintaining the existing fleet of owned-wind facilities, and do not reflect expected cost savings
associated with operating and maintaining wind facilities proposing to use larger wind turbines.
Three of the winning bids--Invenergy Wind Development's Uinta project, the company's TB Flats
I & II project, and the company's Ekola Flats project--will use larger equipment for a portion of
the wind turbines at each facility. If the O&M cost elements applicable to the larger-turbine
104
Price-Policy Scenario Annual Revenue Requirement PVRR(d)
Low Gas, Zero COz 184
Low Gas, Medium COz 127
Low Gas, High COz (147)
Medium Gas, Zero COz (e2)
Medium Gas, Medium COz (167)
Medium Gas. Hieh COz (304)
High Gas, Zero COz (448)
High Gas, Medium COz (4ee)
High Gas, High COz (63s)
Pe,crprConp - 2017 IRP UPDAIE CTIAPTER 7 - ENERGY VISION 2O2O UponT.E
PecInIConp -2017 IRP UPDATE Cueprr,R 7 - ENERGY VISIoN 2O2O UPDATE
equipment are reduced by 42 percent, which is equivalent to an approximately l8-percent
reduction in total O&M costs, beyond the proposed O&M agreement period, customff benefits
calculated through 2036 for all price-policy scenarios would improve by approximately $19
million.
Finally, the updated economic analysis assumes the incremental transfer capability associated with
the Aeolus-to-Bridger/Anticline transmission line is 750 MW. Subsequent transmission studies
have confirmed the transfer capability is 950 MW. Consequently, the economic analysis presented
in this chapter is conservative.
PacifiCorp continues to pursue regulatory approvals for the Energy Vision 2020 projects,
consistent with the timing of the associated action plan items further described in Chapter 10.
The updated economic analysis of the wind repowering project supports repowering just over 999
MW of existing wind resource capacity located in Wyoming, Oregon, and Washington. The
updated economic analysis shows significant net customer benefits in all of the scenarios analyzed.
The wind repowering project will replace equipment at existing wind facilities with modern
technology to improve efficiency, increase energy production, extend the operational life, reduce
run-rate operating costs, reduce net power costs, and deliver substantial federal PTC benefits that
will be passed on to customers.
The results of the 2017R RFP confirm that the Combined Projects are the least-cost, least-risk
resources available to serve PacifiCorp's customers. The substantial volume of bids that were
submitted into the 2017R RFP produced competitive project costs, allowing PacifiCorp to obtain
greater wind generating capacity at lower overall capital costs, with increased net benefits for
customers. The Combined Projects show net customer benefits under all price-policy scenarios
through 2036 and in seven of nine scenarios through 2050.
105
Conclusion
PRcrprConp -2011 tRP Upoalg Cunprpn 7 - Eur:ncv VISIoN 2020 UpDATE
[This page is intentionally left blank]
106
PACIFICoRP - 2OI7 IRP UPDATE Cuaplrn 8 Pon'r'r,or.ro DEVELopMr.N r
CgaprER 8 - PonrFoLIo Dr,vEroPMENT
PacifiCorp used the System Optimizer (SO) model to develop an updated preferred portfolio based
on inputs and assumptions updated since the 2017 Integrated Resource Plan (IRP) was filed April
4, 2017. This updated resource portfolio is consistent with PacifiCorp's most recent load-and-
resource balance as described in Chapter 4. This chapter presents the 2017 IRP Update preferred
portfolio and a comparison of changes relative to the 2017 IRP preferred portfolio. This chapter
also includes a sensitivity comparing the 2017 IRP Update preferred portfolio to the fall2017
business plan.
The2017 IRP Update focuses on changes that occurred after PacifiCorp filed its 2017 IRP. These
include updates to load forecasts, changes in existing resources, any additions to PacifiCorp's
contracts with other entities, and changes to Energy Vision 2020 resources.
Table 8.1 summarizes the annual capacity in the 2017 IRP Update relative to the 2017 IRP
preferred portfolio for the l0-year period 2018 through 2027- Consistent with the change in
PacifiCorp's load-and-resource balance, the reduction in peak loads decreases the need to add new
resources relative the 2017 IRP. The reduction in load reduces front-office transaction (FOT) and
demand-side management (DSM) resources. An additional2ll MW of new wind is added as part
of Energy Vision 2020 new wind resources described in Chapter 7. The level of summer FOTs in
2027 is 493 MW, which is lower than in the 20l7IRP and below the assumed 1,575-MW FOT
limit. PacifiCorp has not updated its FOT limits for the 2017 IRP Update but will review its FOT
limits during the 2019 IRP public process. The updated portfolio does not include any natural gas
resources through the 2}-year planning horizon. Table 8.2 (summer) and Table 8.3 (winter)
summarizes the 2017 IRP Update load and resource balance, inclusive of incremental resources,
for 2018-2036, and Table 8.4 presents the2017 IRP Update preferred portfolio through 2036.
Class 2 DSM selections in the 2077 IRP Update were updated to reflect more current information
on actual and projected acquisitions in the near-term (2018-2020) and the value of Class 2 DSM
resources to the system. For 2018-2020, Oregon and Washington projections were modified to
reflect current Energy Trust of Oregon projections and the approved "Demand Side Management
2018-2019 Business Plan" filed with the Washington Utilities and Transportation Commission
(WUTC).' For Utah, 2018-2020 projections match the 2017 IRP preferred portfolio selections.
2018-2020 projections for California align with forecasted achievements in2018 and the 2017 IRP
preferred portfolio selections for 2019 and 2020. For 2018-2020 Wyoming Class 2 DSM was
updated to reflect proposed targets currently under review by the Wyoming Public Service
Commission. From 2021 on, the SO model optimized Class 2 DSM selections to reflect the
updated load-and-resource balance, and the associated value of Class 2 DSM in relation to other
resource alternatives over the medium and long term.
1 Washington Utilities and Transportation Commission, Docket UE-171092, Order 01, January 12,2018.
107
Introduction
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I
I
I
tl
t'
I'
I
I'
'll
l.'ll
PACTFTCoRP - 20 17 IRP Upoars Crraprsn 8 - Ponrpolro Devgloprr,rpNr
Table 8.2 - 2017 IRP Update Summer Capacity Load and Resource Balance (Megawatts)
( alendar Yc.rr 20 I a 20 l 9 2ll2ll 21121 21122 21123 21121 Zll25 2llzar 2027
Erst
Thel:l:ml
Hydrcelectric
Qualirying Facilities
Class I DSM
Sales
Non-Owned Reserves
TmnsfeB
6,43
t07
I
249
644
323
(6s5)
(3s)
62
7294
o
o
o
o
o
o
o
7,29,i
6,853
(loa)
o
(les)
o
o
(l ra)
6.432
462
462
6,123
I l4
194
249
69r
323
( 4r55 )
(-15)
231
7,235
o
o
o
o
o
I
I
a 236
6,91 I(16)
o
(res)
o
o
< tTat
637,i
455
455
(r, I 23
l14
t99
21.)
713
f 2-l
142
4,203
o
o
o
o
o
I
I
7,2O1
6.972
t l()l)
o
o
o
( ll(,)
6349
5,736
lt4
197
221
735
321
( t7s)
(35)(s)
a,oza
o
o
207
o
o
I
204
7,236
7,O30
(2r3)
o
(195)
o
o
(273)
6344
a5l
851
5.736
tt4
t90
22t
734
323
(ta5)
(3s)
(77)
7,O35
o
o
207
o
o
I
2()4
7,243
7,t04
(22O)
o
( res)
o
o
(3r9)
637lJ
453
as3
5,736
I 14
190
221
734
323
(| 75)
(-15)
(7 t>
'7,O3'7
o
o
207
o
o
I
204
'7.243
7,172
(226)
o
( res)
o
o
(-r6S)
6346
456
as6
5,736
93
t90
221
679
38
( l4a)
(3s)(r)
'7,'J6l)
o
o
207
o
o
I
2()4
7,26'i
7,248
<231)
o
(r9s)
o
o
(4lo)
6,4tJ9
459
459
5,736
93
190
t2t
674
323
(r+a)
loa
7,'J63
7,3U)
(142 )
o
( l<)5)
o
o
(fd))
6,112
459
459
5,654
93
lao
t2t
670
323
<(fi,
(3s)
56
6,997
o
o
207
o
o
I
204
'7,2O5
7,31O
1252,
o
(t95)
o
o
(s(r))
6354
a5l
a5l
5,654
93
lao
t2t
66
323((,)
(3s)
3a
6,975
o
o
207
o
o
I
20a
7,t a3
7,354
(269)
o
( 195)
o
o
(555)
6,334
449
449
&st &isting Resources
Frcnt Office T@nsactions
Gs
Solar
Class I DSM
Other
Eist Total Resources
Private eneEtion
kisting Resources:
Intelruptible
Class 2 DSM
New Resources:
Class 2 DSM
E st oHigrtion
Plannins ksewes ( l3ol/o)
o
o
207
o
o
I
204
7,24I
a5l
a5t
&st OHigation + Reserws
&st Position
tut Reserw Nhrgin
7,294
4
13"/o
7,233
4
I 3"/o
7,2OO
3
I 30/o
7,199
36
I 40/o
7,223
20
I 1"/o
7,211
4
I 3"/"
7,264
(0)
I 3"/"
7,271
(() )
| 3./"
7,205
(o)
I 3"/"
7,1 a3
(o)
1 3"/"
Thel:lml
Hydrcelectric
Qualirying Facilities
Class I DSM
Sales
Non-O\med kseryes
Tansfe6
\ryest E(lsting Resourc€s
Frcnt Office TEnsactions
Gs
r'r/ ind
Sohr
Class r DSM
Other
West PlannGd Resources
west Tobl Resources
I-ad
Pdvate CeneEtion
kisting Resources:
Intelruptible
Class 2 DSM
New Resources:
Class 2 DSM
Wcat oHigrtlon
Plannina kserves ( I 3olo)
West Re3eres
west loblagation + Reierws
WGst Pcition
West Re3ere krgin
2,254
861s
la
235
3
(r65)(r)
( (i-l )
3,23 r
3,234
(13)
o
o
o
o(e)
3,161
4l I
4ll
2,254
747
aa
I
220
3
(t65)
(3)
(232)
2,913
2,2*
79.)
95
I
227
3
( 165)
(:l)
( l4-3)
3,06O
2,254
ffi
95
I
203
o(r6r)
(3)
aa
3,122
655o
I
la5
o
(ao)
(-3)
(o)
454
o
o
o
o
o
454
3,526
3,36
(44)
o
o
o
o
(lea)
3,t 20
4M
406
2,254
655
m
I
184
o
( ao)
(f)
(loe)
2,963
570
o
o
o
o
o
57lJ
3,533
3,395
( ss)
o
o
o
o
(214)
3,126
46
406
229
645
59
I
ta2
o
(ao)
(3 )
(s7)
3,OO r
529
o
o
o
o
o
529
3,53()
2,254
654
5a
I
150
o
( ao)
(3)
(40)
2,999
3,436
(71t
o
o
o
o
(f4:)
3,123
46
406
2,254
624
65
I
la7
o(t lO)
(-3 )
70
2,254
547
65
I
t94
o(lro)
(3)
76
530
o
o
o
o
o
53()
3,329
444
o
o
o
o
o
444
419
o
o
o
o
o
419
3,064 3.0a8 3-1172
334
o
o
o
o
o
334
3,569
4%
o
o
o
o
o
490
471
o
o
o
o
o
4at
o
o
o
o
o
I
3,542({)
t30/"
3,554({)
I 3"/o
3,545
(3)
I 30/"
3,539(r)
I 30/o
3,535({)
I 30/o
3,526
o
| 3'/o
3,533
(o)
l3o/o
3,329
o
13"/o
3530
(o)
I 3o/o
3.544
3.279
( le)
o
o
o
o
(<)1)
3,r66
4t2
412
3'57a
(4)
t30/o
3,293
(25)
o
o
o
o
(l2f)
3,1 46
3,541
3,3t2
(31 )
o
o
o
o
(le)
3,137
{a
4()4
3,33 I
(-17)
o
o
o
o
(t63)
3,t32
3,35 I
(41)
o
o
o
o
(rar)
3,129
407
407
3.415
o
o
o
o
(rla)
3,121
46
406
3,551 3,5J5 3,532
ry
409
aa
407
ro,a67
9.594
1,273
lo,a67
o
t 30/"
lo,8l I
9.5'l4
1.26
lo,al I
o
| 30/o
I O,755
9,495
1,260
I o,755
(())
I 30/"
10.747
9,445
t,254
to.74
33
11"/"
to,a79
9,5o2
|,261
1o,762
t7
t30/o
to,777
9,515
t,262
to,777
(o)
130/.
t 0.794
1,2&
to,a93
o
I 3"/o
lo,ag
9,539
t_265
lo,a&
(o)
I 3o/o
1o,735
9,4a8
1,2s7
I 0,735
(o)
130/o
to.7 t2
9,454
1,255
to,7 t2
(())
I 3"/o
OHigation
ReserEs
Obligetion + Reserws
System Position
ReserE M.rgin
109
Sv3tcm
PecIrrCOnr _2011 tRP UPDATE Cuepren 8 - Ponrpolro DeveLopnarut
Table 8.2 (Cont.)
(Megawatts)
2017 IRP Update Summer Capacity Load and Resource Balance
2024 2lt2.'2 0JO 203 1 2033 2031 20J5 2(1362113 2
Thelrul
Hydrcelectdc
Qualifying Facilities
Class I DSM
Sales
Non-tued Reserues
TEnsfere
Fast Erlsttng Resources
Front Office Transactions
Cas
Solar
Class I DSM
Other
&st Planned Re
F-st Totat Faesources
16ad
hvate eneEtion
ExistinS Resources:
Intelmptible
Class 2 DSM
New ksources:
Chss 2 DSM
East obligation
Plann ins Resewes ( I 3olo)
l5l
o
207
o
o
I
359
3la
o
353
177
too
I
1,249
307
o
353
477
l5l
o
r,aa
4,492
93
lao
l2t
662
323
( 6(;)
(15)
670
6,441
4,492
93
lao
t2t
655
323
(66)
(3s)
457
652t
3ra
o
207
o
72
I
s99
4,219
7,5tO
(3O3)
o
(tes)
o
o(as)
6367
453
453
4,535
93
158
l2l
652
32f
(66)
(3s)
437
6,614
3la
o
226
o
72
I
6la
4,236
7,5q
(324)
o
(re5)
o
o
(6eo)
634 I
855
855
4,459
93
126
t2t
644
323
o
(-rs)
466
6,602
3la
o
226
o
72
I
6la
72r9
7,531
(236)
o
( | 9-s)
o
o(731)
6,366
453
a53
4,459
93
t26
t2t
634
323
o
(-15)
917
6,642
3la
o
226
o
-72
I
6ta
7,624
(tr(,1)
o
(le5)
o
o(771'
6,4o2
a5a
a5a
4,102
93
t26
t2l
605
323
o
692
6,O29
4,t02
93
126
t2l
549
323
o(:5)
69t
6,O12
4,O2t
93
t26
t2t
544
323
o
(35)
7o3
5,934
3ta
o
353
4ao
246
o
t .396
1,O2t
93
t26
t2t
532
323
o
453
5,935
3la
o
376
4ao
254
o
r,432
470
470
7371
(4)
l3o/o
a,2oo 7,2 59 7,27 8 7.299 a 333 7 J6a
4,433
(2aa)
o
(l9s)
o
o(602)
6,349
a5l
451
7-7O5
(ra+)
o
( t.r5)
o
o
( ao5)
6,42 |
460
460
7,778
( -loa)
o
(res)
o
o
(a-f5)
6,440
462
462
4,86t
o
(1.)5)
o
o
( a('-l )
6,4'7O
466
466
4,941
( 154)
o
( les)
o
o
(ae2)
6,5O I
&st OHigation + Reserres
Fsst Position
&st Reserw Margin
7,199
o
I 3'/o
7,22O
(ar)
I 3o/o
7,236
(o)
130/o
7,219
o
| 3'/o
7,281
(J)
I 3"/o
7,3O2
(f,)
I 3'/o
7,336
(3)
136/o
7 259
(())
I 30/.
Thercl
Hydrcelectric
Quarirying Facilities
Class I DSM
Sales
Non-Ormed Reserves
TEns fere
West Btsting Rcsources
Front OfTice Trans action s
Gs
Solar
Class I DSM
Gher
West Plrnned Faesources
West -foat Elesources
laad
Priwate Gneration
Hsthg ksources:
Intemptible
Class 2 DSM
New Resources:
Class 2 DSM
West olrligation
Planning Reseryes ( l3o,/o)
2,2s4
653
5S
I
149
o
(ao)
(3)
(67 t)
2359
l,900
653
53
I
132
o
(74)
(3)
(466)
1.793
1,541
653
53
I
97
o
(7a)
(-l)
(6e2)
1,572
t,54 1
653
53
I
96
o
( 7a)
(3)
<704>
1 ,56()
I,900
653
54
I
l3a
o
(74)
(-3)
(4sa)
2,2O't
1,3s2
o
o
o
o
o
| ,352
3,560
3,503
(46)
o
o
o
o
(264)
3,15()
4to
4ro
I,900
653
54
I
t33
o
<aa)
(-3)
(437)
I ,423
t.352
o
o
3s3
o
o
l.a05
3,524
1,495
(e3)
o
o
o
o
(2ao)
3.r22
406
406
I,900
653
53
I
99
o
(74)
(-3)
<9 l7')
1.7()4
3.532
( a())
o
o
o
o
( -l(,1 )
3,149
4@
4.)9
t,541
653
53
I
97
o
(74)
(3)
(6e3)
I,Sa2
I,541
653
53
I
o
(24)
(3)
(7 51)
1.561
t,t7t
o
o
o
o
o
l,l7t
3,53()
1,352
o
o
414
o
o
1.766
3,559
r,352
o
o49
o
o
I ,A5O
3,559
1,3s2
o
o
613
25
o
I ,949
1,352
o
o
613
25
o
I ,949
3,562
o
39
613
25
o
1,996
1,352
o
39
6r3
25
o
2,O29
3,349
,3 r9
3,562 3,554
3,457
(74)
o
o
o
o
(2ss)
3.124
406
406
3,513
(72)
o
o
o
o
(291)
3,r 50
4aD
409
3,554
(ae)
o
o
o
o
(llr)
3,152
3,575(loo)
o
o
o
o
(322'
3,1 52
4to
4to
3,620(llt)
o
o
o
o
(3-3 2 )
3,t46
413
413
3,612
< 122)
o
o
o
o
( -142 )
3,149
4@
409
4to
4lo
West OHiAetion + Reserws
West Pcition
west Reserw krgin
3,530
o
t 30/o
3,56O
o
I 3o/o
3,524
o
t 36/.
3,559
o
I 30/o
3,562
(o )
130/-
3,549
(0)
136/o
3,554
(l)
I 30/.
3,559
o
I 3'/o
3,562
(I )
130/.
ll0
Totsl Resources
OHigation
Res errs
OHigotion + Reserws
System PGition
Reserw Margin
1o.730
9,473
r,257
1o,729
o
13"/o
1o,779
9,517
1,263
1o.779
(())
| 3o/o
I o,763
9,503
r,26t
to,763
o
I 3'/o
to,77a
9,5 l6
t.262
to,77a
o
130/.
lo,8t8
9,55 l
|,264
IO,8t8
o
I 3o/o
I o,439
9,543
t,2ao
lo,a43
(3)
llo/.
to,a6 I
1,242
ro,864
(-r)
130/.
I 0,922
9.646
1,279
10,923
(+)
l3o/o
I O,925
9,650
l ,2ao
1o.929
(5)
I 3'/o
Calcndar Year
kst
PncmrConr - 2017 IRP UPDATE CHapren 8 - Ponrpolto DEVELopMENT
Table 8.3 - 2017 IRP Update Winter Capacity Load and Resource Balance (Megawatts)
Calendar Year 21121)202t 2022 2023 2024 2025 2o26 2024
Hydroelectdc
Qualiryina Facilities
Class I DSM
Sales
Non-O\^med ReseNes
6,5 l3
72
196
734
691
o
(173)
(35 )
3
a,ool
5,846
72
190
23s
745
o
(173)
(f5)
(14r)
6,734&st E\isiiDg Rcsurrccs
6,233
72
t99
434
442
o
(t7l)
( l5)
7
a,aa9
6,233
a2
197
734
740
o
(t73)
(35)
3l
'7.799
5,U6
190
235
736
o
(l7f)
( l5)
( l{)
6,727
5,aM
72
190
235
82
o
(r7f)
( 146)
6,67O
o
o
207
o
o
I
204
6,.t7'i
5,44
72
t{
t2t
6aa
o
(r4a)
(-15 )
( t_15)
6,549
5,%
72
r90
t2t
643
o
( l4a)
( l5)
(r"6)
6,592
5.763
72
tao
t2l
6a
o
(l16)
6saa
5,763
72
lao
t2t
@
o
(4,6)
(35)
( 143)
6$54
Frcnt OfFrce Tansactions
Cas
Sola.
Class I DSM
Oth er
o
o
o
o
o
I
I
'7,'7AO
o
o
o
o
o
o
o
ot4
o
o
I
145
7,941 6.916 6,935
5,617
(o)
o
( le5)
o
o(ltt)s3r2
o
o
204
o
o
I
204
207
o
o
o
o
I
o
o
207
o
o
I
204
o
o
207
o
o
I
204
6,797
o
o
207
o
o
I
204
o
o
204
o
o
I
204
6,785
2(la
a,()o I 6,8()O 6,765
bad
Pdwate Gneation
kisting tusources:
Intemptible
Class 2 DSM
New ksources:
Class 2 DSM
tut oHig.tion
Plannins kserves ( I3olo)
&3t Reserws
5,590
(o)
o
(t95)
o
o(e)
5'3l I
7t6
716
5,654
(o)
o
(t95)
o
o
(t471s;r6
5,7t 8
o
o
o
5,341
5,774
(o)
o
( 195)
o
o
(2la)
3'36 T
5,81 I
(0)
o
( I.r5 )
o
o
5,363
5,46
(o)
o
( 195)
o
o
(291 )
53aO
5.792
(o)
o
( l<)5)
o
o
( 324)
s269
7to
7to
5,414
(o)
o
(195)
o
o
( 363)
5,255
5,so
(o)
o
( 195)
o
o
( 56)
sSro
at6
716 716
7t6
716
720
720
722
722
723
723
725
725
f(r9
709
&st OUigation + Reserws
&s t Pos ition
&st Reserw krgin
6,O25
I,976
51"/o
6,O26
l,a s3
4"/o
6,O24
1,916
sG/"
6,O32
914
310/o
6,O6O
a7s
3O"/o
6,O43
793
2ao/o
6,O457tt
270/"
6,r 05
695
260/"
5,979
ao6
2q/"
5,964
aor
290/0
Thellrel
Hydrcelectric
Qualiryins Facilities
Class I DSM
Sales
Non-Ol^ned kseryes
Tmnsfe6
west Exlstlng Resources
2,316
w
95
I
220
o
( 154)
(3)
(32)
3343
2,316
7AS
95
I
t95
o(ls4)
(3)
l{
3,375
2,316
9t7
90
I
224
o
(162)
(3)
<4)33ao
3,342
o
o
o
o
o
(ss)
3246
424
427
2,316
943
95
I
2lt
o
(t62)
(3)
(8)
3'395
321
o
o
o
o
o
321
3J t6
3,376
(o)
o
o
o
o
(ao)
3293
2,3 t6
743
a
I
176
o
(al)
(3)
133
33as
3-473
(o)
o
o
o
o
(r93)
3,24O
426
426
2,316
747
59
I
175
o
(al)
(,r )
t25
3;74
2,316
7U
5a
I
t7t
o
(al )
(.r )
125
3,371
349
o
o
o
o
o
349
3,42t
2,316
a%
56
I
t4
o
(al)
(3)
ta
3'36a
3g
o
o
o
o
o
364
3,7 32
3,547
(o)
o
o
o
o(24t
33()3
429
429
336
o
o
o
o
o
336
322
o
o
o
o
o
322
2.316
786
65
I
t77
o
( r r-l)
(l)
t45
3,373
329
o
o
o
o
o
329
3,7O2
2,3t6
744
65
I
la3
o
(lrf)
(3)
t42
3343
o
o
o
o
o
323
3,694
126
426
Frcnt Offce TEnsactions
Gs
Solar
Class I DSM
Other
Wcat Phnned Resourccg
326
o
o
o
o
o
326
3,4o6
314
o
o
o
o
o
314
321
o
o
o
o
o
32t
3,6963,69a 3.a07 3.7 I {
Pfrwate CeneBtion
E*sting Resources:
Intetruptible
Class 2 DSM
New Resources:
Class 2 DSM
Plannins kserves ( l3olo)
West Reserws
424
424
426
126
426
126
3,3U
(o)
o
o
o
o
( l05)
32aa
3,4ss
(o)
o
o
o
o
< 173'
3,282
427
427
3,4')9
(a)
130/.
3,494
(o)
o
o
o
o
(2r l)
3,287
427
424
3.521
(o)
o
o
o
o
(22A)
3,293
424
424
West Total Rcaources
West oUigltion
3_44
(o)
o
o
o
o
(l30)
3,274
3,431
(o)
o
o
o
o
(152)
3279
west Ouigation + Reserws
West Pcition
West Reserw krgin
3,413
(a>
r3o/o
3,7 23
(1t
I 3"/"
3,705
(7\
t 30/o
3,7O1
(a)
I 3'/o
3,7O5
<at
l3o/o
3,707
o
t30/a
3,711
o
I 30/o
3,72t
(o)
I 3'/o
3,732
o
| 3"/o
OHigation
Reserws
OHigation + Reserres
Sys tem Pos ition
Res€rw Margin
I r,704
4,596
I,143
9.739
r,964
360/"
ll,4%
4,66
t,l4
9,750
t,746
340/"
I I,gt
a,5s
1,142
9,732t,w
36"/o
tqa2
a,5q
t,143
9,736
96
24"/o
10.633
4,619
I,t46
9,765
467
230/"
I O,5aO
a.a3
t.149
9,792
7aa
lo,s&
a,a3
l,149
7t I
I O,5 l4
4,667
1,1 52
9.4t9
695
10.497
4,554
I,l3a
9,6%
aol
23"/o
lo,so6
4,561
I,138
9,7N
ao6
23./o
lll
20ta
&st
Table 8.3 (Cont.)
ly,"::::"::")
2017 IRP Update Winter Capacity Load and Resource Balance
PACIFICORP 2017 IRP Upoare Cueprpn 8 -Ponrpolto DEVELoPMENT
2024 2lt2.t 2 0JO 203 I
5,OO l
72
lao
t2l
657
o
(6)
(,ls)
(r46)
s.744
5,OO I
72
ta
t2t
653
o
(15)
(97',)
5,41 4
o
o
207
o
o
I
204
6,O22
5,93 I
(())
o
( 195)
o
o
(42())
53()4
7t5
7ls
4,564
72
126
t2l
635
o
o
(-r5)
367
5,454
4,212
72
126
r2r
590
o
o(rs)
202
s,2aa
4,212
72
126
t2t
547
o
o
(3s)
247
5,33O
4,130
72
t26
t2t
s70
o
o
(fs)
70
s,os4
318
o
3s3
4ao
o
o
I,15()
6,2O4
6257(o)
o
( I <)5)
o
o
( -s94)
5,468
736
'736
2
6,227
4,130
72
126
t2l
t75
o
o
(15)
&
5,O54
3ra
o
376
4ao
o
ol,ta4
2032
Thel:l:ml
Hy d ro e le ctric
QuaIirying Facilities
Class I DSM
Sales
Non-Omed Reseres
Tmnsfere
kt Edsting Flesources
4,&
72
126
t2t
650
o
(l-s)
291
5,4o3
4.564
72
126
t2t
a6
o
o
(js)
331
5,429
Front office Transactions
CEs
Solar
Class I DSM
Other
o
o
207
o
o
I
204
5,992
o
o
226
o
o
I
227
o
o
226
o
o
I
227
o
o
226
o
o
I
o
o
3s3
177
o
I
a3l
6,O57
o
o
353
477
o
.o430
6,160
6_197
(o)
o
(res)
o
o
(571)
5,429
731
731
6,2O4
(0)
130/o
6,160
o
I 3'/o
6,Oa I
o
I 3o/o
kisting Resources:
Intelruptible
Class 2 DSM
New ksources:
Class 2 DSM
tut oHigafion
Plannins Resewes ( I 3olo)
Fsst ReserEs
&st OHigation + Faeseres
&st Posidon
Fssa R.eserw VLrgin
5,872
(o)
o
( | 9-s)
o
o
(397)
s2ao
7t2
712
6,O81
6,O79
(())
o(les)
o
o
(52s)
s'3s9
6,1 l9
6, l3a
(o)
o
(res)
o
o(ssl)
s392
kt Totat Gaesources
Private Gene€tion
6,O3O
5-972
(o)
o
(r9s)
o
o
(46-l)
s ,3t4
-716
716
6,O29
(o)
o
(r9s)
o
o
(497
'3334
6,29
(o)
o
( te5)
o
o
(6r5)
5,444
739
739719
422
722
726
426
5,992
(o)
I 30/.
6,O23
(())
| 3o/o
6,O3O
(())
l3'/o
6,O56
o
I 3'/o
6,1 l8
o
| 3./.
6,224
o
I 3o/o
Theml
Hydroelectric
Qualit/ing Facilities
Class t DSM
Sales
Non-Omed ReseNes
r,962
7a8
34
I
133
o
(74)
(3)
(292)
2,s6s
|,962
7aa
53
I
to2
o
(74)
(3)
(332)
2.494
t,@2
7aa
53
I
ll
o
(74)
(3)
(46s)
I ,91O
2,316
7aa
55
I
143
o
(al )(3)
145
3364
431
43t
1,962
78a
34
I
t34
o
(74)
(-l )
96
2,9 53
I,962
748
53
I
9a
o
( 7a)
( -1)
(367 t2,434
t,@2
aaa
53
I
97
o
(74)
(3)
(203)
2,259
920
o
o
613
o
o
I ,533
3,791
3,684
(o)
o
o
o
o
(329)
3Jss
436
436
t.602
7aa
53
I
96
o
(74)
(3)
(244)
2,212
9AO
o
o
6t3
o
o
1,s92
3,4O5
3,704
(o)
o
o
o
o
(-34 r )3364
434
434
1,602
7aa
53
I
95
o
(74)
(3)
(70)
2,3a9
775
o
39
613
o
o
I A2a
3€r 7
3,73r
(o)
o
o
o
o
(_l5,1)
3377
439
439
3,817
o
130/o
Front Office Transactions
Cas
Sotar
Class 1 DSM
Gher
West Pl.nned Re
349
o
o
o
o
o
379
3,7 43
West &isting Resources
West'lirtrl Resources
423
o
o
o
o
I .322
| _257
o
39
613
o
o
I ,9O9
3,41 9
a03
o
o
o
o
o
a()3
3,asa
841
o
o
353
o
o
1.t94
4f2
132
132
432
3,657
(o)
o
o
o
o
(3 r6)
3'34t
4fl
433
434
434
a5a
o
o
414
o
o
| ,272
bad
Private GneEtion
&isting Resouroes:
Intelruptible
Class 2 DSM
New Resources:
Class 2 DSM
West oHigafion
Planning Reserues ( I 3olo)
west Fleseres
3.572
(())
o
o
o
o
( l(n))
3J l2
3,59
(o)
o
o
o
o
<274)3325
3,4s9
3,615
(o)
o
o
o
o
(2aa)
3324
3,467
3,636
(o)
o
o
o
o
(3O2 )3333
3,776
3.746
(o)
o
o
o
o
(-36s)
33AO
439
439
West OHigation + ReserEs
West Posidon
West Reserw M.rgin
3.743
(o)
13./"
3,asa
(0)
I 3d/o
3,759
o
| 30/o
3,766
o
I 3'/o
3,74 5
o
t 30/o
3,79r
(o)
l3'/o
3,4o5
(o)
l3'/o
3,420(o)
l3o/o
Toaal Resources
OHig.tion
Reserws
OHigation + Reserws
System PGition
Reserw Margin
9,735
8,593
1,142
9,735
(o)
l3'/o
9,779
8,632
| ,147
9.779
(())
130/o
9.749
a.&l
1,149
9.789
( ())
I 30/o
9.423
4,670
1,t52
9.423
o
I 30/o
9.457
a,7m
I, 156
9,457
o
I 3o/o
9,91O
4.447
1,163
9,91O
( ())
I 3'/o
9,94
8,796
t,t 69
9.965
(())
136/o
l o,o2 l
4,445
t,175
I O,O2 I
o
I 30/-
to,M7
4,469
l,l7a
to_Ma
(())
I 3'/o
n2
&st
ca
6l
a..t
oo
-o
o
oo
bo
d
o
-oCO
o
oo
o
o
a0
xo
o\
bo
o
B
o.o
O
,o
oo-
o
,oo
o
CB
o.f
&r
(\
o
F
e
?
n
i
Pr
,l
!;
9
I
E
9
!
E
I
It
I
)
o
t
0)
lr.()
q)
o
G
o
-l)
r-
6l
a
U
(J
CE
I$€q)
ctF
-zE]
oJE]
ElIJ
J
F
o.
I
@
rl.]F
U
lrl
fo.
t--
a-n
I
o(-)
Ir.
U
E
tI xI
PACIFICoRP - 20 I 7 IRP Uponrr CHAPTER 8 PoRTFoLIO DEVELOPENT
Figure 8.1 shows PacifiCorp's RPS compliance forecast for Califomia, Oregon, and Washington
after accounting for Energy Vision 2020 projects and new renewable resources in the preferred
portfolio. While these resources are included in the preferred portfolio as cost-effective system
resources, they also contribute to meeting state-RPS.
Oregon RPS compliance is achieved through 2036 with the addition of repowered wind and new
renewable resources in the 2017 IRP Update preferred portfolio. As shown in Figure 8.1, no
additional REC purchases are required to achieve Oregon RPS compliance through2036.
The Califomia RPS compliance position is also improved by the addition of repowered wind and
new renewable resources in the 2017 IRP Update preferred portfolio. As RPS targets increase,
California requires some level of unbundled REC purchases (under 167,000 RECs per year) to
achieve compliance through the planning horizon. In the 2017 IRP, California RPS Requirement
targets were developed around three-year compliance periods. For the 2017 IRP Update, annual
compliance targets are used, producing consistent incremental changes from year-to-year.
Washington RPS compliance is achieved with the benefit of the repowered wind assets located in
the west side-Marengo I and II, Goodnoe Hills, and Leaning Juniper-as well as new renewable
resources added to the west side beginning 2030, and unbundled REC purchases (under 290,000
RECs per year). Under the current allocation mechanisms, Washington customers do not benefit
from the remainder of the repowered wind or new renewable resources added to the east side of
PacifiCorp's system. Under an alternative allocation mechanism, in which Washington would
receive its system-allocated share of repowered wind and new wind located in Wyoming, the
state's RPS targets could be met without the need for any incremental unbundled REC purchases
throughout the 20-year planning period.
While not shown in Figure 8.1, Pacif,rCorp meets the Utah 2025 state target to supply 20 percent
of adjusted retail sales with eligible renewable resources with existing owned and contracted
resources before considering the addition of repowered wind and new renewable resources in the
2017 IRP Update preferred portfolio.
tt4
Renewable Portfolio Standards (RPS)
PncrprConr - 20 l7 IRP Upoarp Cnapren 8 - PoRTFoLIo DeveloprrasNt
8.1 - Annual State RPS C ,liance Forecast
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
"$.ti"dit"d,,""$"{P"{F"$"{F"s,t"$"{F"{F"s""F}"p"N}"e""{i"&"
I
-rIIIIIIIIII
0
O
F
OIr-]
RPS
-Bundled
SurrenderedI Bundled Bank SurrenderedIYear-end Bundled Bank Balance*Requirement
rs Unbundled Surrendered
t=rs.r Unbundled Bank Surrendered
Iir'-Tn Year-end Unbundled Bank BalanceIShortfall
California RPS
o
O
F
OQri
0
"$ "dF""t.1p""9"{P"F'} "$"$ "$,""$ "s,""{F "$""$"d}"$"$""dt "s"nqlsq Unbundled Surrendered
Fs.!s Unbundled Bank Surrendered
r'r-:Fr Year-end Unbundled Bank BalanceIShortfall
I Bundled Surrenderedr Bundled Bank SurrenderedI Year-end Bundled Bank Balance*Requirement
RPS2,500
000
500
000
s00
3t
=l
F,
oQf-l
0
"$ "$""$"t "{,,""$"{r'"dP"s}"{F ",pt"$ "{.r,""P "F,""$"N}"$ "$""S "e"rls [-[nSundled Surrendered
r;5=;r Unbundled Bank Surrendered
F---r=l Year-end Unbundled Bank BalanceIShortfall
I Bundled SurrenderedI Bundled Bank SurrenderedI Year-end Bundled Bank Balance*Requirement
I l5
)
500
400
300
200
100
PA.CmICOnp -2011 IRP UPDATE cHAPTER 8 - Ponrpouo DevelopeNr
The 2017 IRP Update preferred portfolio continues to reflect PacifiCorp's on-going efforts to
provide cost-effective clean energy solutions for our customers and accordingly reflects a
continued trajectory of declining COz emissions. PacifiCorp's emissions have been declining and
continue to decline as a result of a number of factors including, PacifiCorp's participation in the
energy imbalance market, which reduces customer costs and maximizes use of clean energy,
PacifiCorp's on-going expansion of renewable resources, and regionalhaze compliance strategies
that leverage flexibility. Figure 8.2 compares projected annual COz emissions between the 2017
IRP Update preferred portfolio and the 2017 IRP preferred portfolios (as reported by PaR). Over
the first l0 years of the planning horizon, average annual COz emissions are down by over 4.6
million tons (11 percent) relative to the 2017 IRP. By the end of the planning horizon, system COz
emissions are projected to fall from 39.5 million tons in 2017 to 30.8 million tons in 2036-a
reduction of 22 percent.
Figure 8.2 - Comparison of COz Emission Forecasts between the2017 IRP Update Preferred
Portfolio and the 2017IRP Preferred Portfolio
50
45
A40(.)J)
"308,'ts
e20
ErsEro
5
0
"$.,o.r$nSr$n$n$n$.t'"uet$ro"r"n)"uoorslnsl"uof "s,""srrs,'.2011 tRP Update r2017lRP
Figure 8.3 shows how PacifiCorp's system energy mix is projected to change over time. In
developing this figure, purchased power is reported in identifiable resource categories where
possible. Figure 8.3 is based upon base price curve assumptions. Renewable generation reflects
categorization by technology type and not disposition of renewable energy attributes for regulatory
compliance requirements.2 On an energy basis, coal generation drops below 45 percent by 2025,
2The projected PacifiCorp 20l7lRP Update preferred portfolio'renergy mix" is based on energy production and not
resource capability, capacity or delivered energy. All or some of the renewable energy attributes associated with wind,
biomass, geothermal and qualifying hydro facilities in PacifiCorp's energy mix may be: (a) used in future years to
comply with renewable portfolio standards or other regulatory requirements; (b) sold to third parties in the fbrm of
renewable energy credits or other environmental commodities; or (c) excluded fiom energy purchased. PacifiCorp's
2017 IRP Update portfolio energy mix includes owned resources and purchases from third parties.
ll6
Carbon Dioxide Emissions
Proiected Enersy Mix
J I J IT r _t _l I _.1 J
PacmrConp - 20 I 7 tRP UpoRre CITnpTER 8 PonrroIIo DEVELOPMENT
drops below 40 percent by 2030, and declines to 32 percent by the end of the planning period. This
result reflects relatively low natural gas natural gas prices prior to 2025 and coal retirements
thereafter. Reduced energy from coal is offset primarily by increased energy from renewable
resources and DSM resources. No new natural gas generating units are included in the 20l7IRP
Update preferred portfolio through the entire Z)-year planning period.
8.3 -Mix with 2017 IRP Preferred Portfolio Resources
Business Plan Sensitivity
Figure 8.4 shows a comparison of the resource portfolio from the business plan sensitivity with
the 2017 IRP Update preferred portfolio. This sensitivity complies with requirements to perform
a business plan sensitivity in accordance with the Public Service Commission of Utah's order in
Docket No. l5-035-04, which is summarized as follows:
a Over the first three years, resources align with those assumed in PacifiCorp's fall2017
business plan.
Beyond the first three years of the study period, unit retirement assumptions are aligned
with the preferred portfolio.
All other resources are optimized.
a
a
100%
90%
80%
70%
60%
50%
40%
30%
20%
t0%
0%
2018 2019 2020 2021 2022 2023 2024 202s 2026 2027 2028 2029 2030 2031 2032 2033 2034 203s 2036
rCoal tGas rHydroelectric rRenerable rClasslDSM+lntenuptibles rNewClas2DSM zExistingPurchases aFrontOfficeTransactions
tt7
Sensitivitv Studies
'10/o 80A 9t/o 9%l0%l0o/o llo/o llo/o taot t2%l2Yo t3%l3oio
I6-0r I 60,i,t8
7%
110 l i0t0t59rtl 0 ]J 230i )10110
)g'fl9qo 'li)9.;..i09t,
l8%
5Yo
r8%1896
10/
300k
2lo/o
3096
22Yo30%250h 230/o 730h 1 10,210210/o 28%
I 99;200/o 1996
4AYo 36%10?i,1l%3l1o 350/o 34o/o 35%389;45%44%40Vo 36%360/o 33Yo 33Yo 32Yo 320k
t.a
(J6lg
ctlQ
q)
U
400
300
200
100
(l 00)
(200)
,$r**r*ero"uord|rdProrlnof ,Sr&br$r&*rsreorslnelrof nCrof ,e6
r DSM r FOTs I Gas { Renewable r Gas Conversion Other I Early Retirement ! Retirement
PACIFICORP - 20 I7 IRP UPDATE CHAPTER 8 - PoRTFoLIo DEVELOPENT
Figure 8.4 - Cumulative Increase/(Decrease) in 2017 Business Plan and 2017 IRP Update
Preferred Portfolio
Key differences between the Business Plan sensitivity and the 2017 IRP Update preferred portfolio
include timing and assumptions around Energy Vision 2020 projects, wind repowering, and Class
2 DSM, as described below:
The Energy Vision 2020 new wind and transmission projects that are included in the fall
201 7 business plan reflect proxy wind resources totalin g 1,182 MW, which includes a
320 MW proxy PPA. These proxy assumptions were developed before the 2017R
Request for Proposals (RFP) was finalized. The 2017 IRP Update preferred portfolio
includes Energy Vision 2020 new wind totaling l,3l I MW, consistent with the final
shortlist from the 2017R RFP (see Chapter 7).
The fall 2017 business plan includes repowering existing wind resources at a slightly
different capacity than what is assumed in the 2017 IRP Update. This difference in
capacity is driven by interconnection limits. The business plan also reflected an earlier
version of repowering equipment at certain facilities that had assumed lower incremental
energy output relative to the 2017 IRP Update.
With less new wind and less incremental energy from wind repowering, DSM resources
in the fall2017 business plan are slightly higher relative to the 2017 IRP Update
preferred portfolio.
FOT resources are higher in the fall20l7 business plan beginning 2020. There is a
reduction in FOTs in2036 with the addition of incremental renewable resources.
a
a
a
Table 8.5 shows the impact of the business plan sensitivity with the initial estimate of 1,182 MW
of new wind versus the 2017 IRP Update preferred portfolio with 1,3 I I MW of Energy Vision
2020 new wind.
ll8
'-'r tt!I lttt lltt
a
PACIFICoRP - 20 I 7 IRP UPOATE CHapTgn 8 - PoRTFoLIo DEVELoPMENT
Table 8.5 - PVRR Cost/(Benefit) of the Business Plan Relative to the 2017 IRP Update
Preferred Portfolio
The SO model PVRR(d) is a reflection of higher QF wind project costs, higher fuel costs from
lower renewables, higher fixed costs, higher DSM costs, and higher system balancing purchase
costs.
The PaR PVRR(d) is a reflection of higher QF wind project costs, higher fuel costs from lower
renewables, higher fixed costs, and higher DSM costs, offset by system balancing sales.
Foote Creek I Sensitivity
Preliminary assessment of Foote Creek I shows potential for customer benefits by acquiring the
remaining portion of Foote Creek I, which is co-owned with the Eugene Water & Electric Board,
and repowering this wind facility. Foote Creek I is the oldest wind facility in PacifiCorp's wind
fleet, having been brought online in 1999. PacifiCorp will explore this opportunity further in the
20l9IRP.
Change from
l7 IRP Update Pref-Port s422 $233
ll9
Medium Gas - Medium COz
System Optimizer PaR Stochastic Mean
Pa,crptConp - 2017 IRP Upoa'rp crrAprER 8 - Ponrpolro Dsver-opp,Nr
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120
PACIFICoRP 20I7 IRPUPOATE CHeprsn 9 - TneNsurssroN Sruores
CuaprER 9 - TnaNSMrssroN SruorE,s
The 2017 Integrated Resource Plan (IRP) action plan identifies specific resource actions
PacifiCorp will take over the next two to four years to deliver resources included in the 2017 IRP
preferred portfolio. Action items are based on the type and timing of resources in the preferred
portfolio, which is selected based on analysis completed during the development of the 2017 IRP.
This chapter discusses transmission studies completed in response to the following action item
(please refer to the 2017 IRP, Volume I, Table 1.4):
o Complete planning studies that include proposed coal unit retirement assumptions
from the 2017 IRP preferred portfolio and two other scenarios.o Summarize studies in the 2017 IRP Update.
In the 2017 IRP proceeding, PacifiCorp was required by the Public Utility Commission of Oregon
to provide Dave Johnston early retirement transmission analysis to the commission and panies in
that proceeding.l The information provided in scenarios two and three of this chapter are in
response to that directive.
In recognition of the transmission planning process and the planning tools available for such an
analysis, various coal retirement scenarios were assessed to provide a response to this action item
based on prior studies, system knowledge and new study efforts. These coal units are synchronous
machines with large spinning shafts that provide higher inertia and help to provide stable and
reliable operation, particularly during system disturbances. Proposed retirement of those plants in
the 2017 IRP preferred portfolio that are directly interconnected to PacifiCorp's transmission
system were considered. Cholla Unit 4 and Hayden Units I and2,located in Arizona and Colorado,
respectively, are not directly connected to PacifiCorp's transmission system and hence, their
retirement does not directly impact transmission-system operations. It is noted that additional
detailed studies will accompany any final coal retirement decision(s) and results may be different
than those identified herein.
Table 9.1 lists the assumed coal-unit retirements in the 2017 IRP preferred portfolio that inform
the transmission system assessment summarized in this chapter. Four scenarios are considered:
1. Scenario I reflects the following coal-unit retirement and Energy Vision 2020
assumptions:
o Jim Bridger Unit I at the end of 2028
. Jim Bridger Unit2 at the end of 2032
o Naughton Unit 3 at the end of 2018
. Cholla Unit 4 at the end of 2020
I See the Public Utility Commission of Oregon's 2017 IRP acknowledgement order issued April 27,2018, Docket LC
61.
t2t
Introduction
Transmission Studies
Energy Vision 2020 projects, including the Aeolus-to-Bridger/Anticline
transmission line (sub-segmentD.2), are online by the end of 2020.
2. Scenario 2 reflects the following coal-unit retirement and Energy Vision 2020
assumptions:
o Dave Johnston Unit I at the end of 2021
o Dave Johnston Unit 2 at the end of 2027
o Dave Johnston Unit 3 at the end of 2027
o Dave Johnston Unit 4 at the end of 2027
. Energy Vision 2020 projects, without sub-segmentD.2, are online by the end of
2020, and
3. Scenario 3 reflects the following coal-unit retirement and Energy Vision 2020
assumptions:
o Dave Johnston Unit I at the end of 2027
o Dave Johnston Unit 2 at the end of 2027
o Dave Johnston Unit 3 at the end of 2027
o Dave Johnston Unit 4 at the end of 2027
o No Energy Vision 2020 project
4. Scenario 4 reflects the following coal-unit retirement and Energy Vision 2020
assumptions:
. Naughton Unit 1 at the endof 2029
. Naughton Unit 2 atthe end of 2029
o Energy Vision 2020 projects, including sub-segmentD.2, are online by the end of
2020.
Table 9.1 - Assumed Coal-Unit Retirements in the 2017 IRP Preferred Portfolio
a
Coa! Unit
PacifiCorp
Percentage
Ownership Share
l%l State
Assumed Retirement
Year
Summer Load and
Resource Balance
Capacity
(MW)
Naughton 3 100 2018 280
Cholla 4 100 AZ 2020 387
Craig 1 19 CO 2025 82
DJ1 100 2027 (end-of-life)105
DJ2 100 WY 2027 (end-of-life)106
DJ3 100 2027 (end-of-life)220
DJ4 100 WY 2027 (end-of-life)330
Bridger 1 67 WY 2028 354
Naughton 1 100 2029 (end-of-life)201
Naughton 2 100 2029 (end-of-life)280
Hayden 1 24 CO 2030 (end-of-life)45
Hayden 2 13 CO 2030 (end-of-life)33
Bridger 2 67 WY 2032 3s9
PacrprConr - 20 I 7 IRP Upoere Cr rAprER 9 - TnaNsvrssroN SrLlt)uis
122
PACTFTCoRP -2017 IRP Uppere Cnaprpn 9 - TRANSMrssroN Sruoms
Transmission Impact Assessment - Scenario 1
The Aeolus West Transfer Capability Assessment (February 2018) was relied upon to identify the
system impacts for Scenario l. This assessment includes the retirement of Jim Bridger Units I and
2.The Jim Bridger generation units are among the largest synchronous machines on the PacifiCorp
system and play an integral role in voltage support and dynamic stability for the transmission
system. Energy Vision 2020 projects were considered in service and include significant new wind
generation, a new 140-mile 500-kV transmission line from the proposed Aeolus substation near
Medicine Bow, Wyoming, to the Jim Bridger power plant, and subsystem facilities.
The impact of retiring Jim Bridger Unit t had limited impact on voltage due to the support provided
by the three remaining Bridger units as well as the presence of existing capacitor banks at the
Bridger facility, which can be switched on to provide voltage support during outage conditions
(typical line and major equipment outages aligned with NERC standards criteria). Retirement of
both Jim Bridger Unit I and Unit 2 resulted in the remaining Jim Bridger units using close to their
maximum reactive capability when near full output, with the existing capacitors online. Therefore,
new reactive support to control voltage under outage conditions likely would be required if both
units were retired. A dynamic voltage device, such as a static var compensator or synchronous
condenser, at the Jim Bridger 345-kV bus is probable under this scenario. Due to the potential for
sub-synchronous resonance at Jim Bridger, this analysis will be required for all unit retirements
and proposed facility additions.
With an assumed retirement of any of the Jim Bridger units, the Bridger remedial action scheme
(RAS) would need to be modified accordingly. Currently, up to two Jim Bridger generation units
are armed to trip under certain 345-kV transmission line outage conditions.
Importantly, the study demonstrated that the Energy Vision 2020 transmission improvements and
the new wind generation provide increased transmission capacity and power flow to support the
existing 2,400 MW Bridger West transmission path rating, even if the two Jim Bridger units are
retired.
Retirement of Naughton Unit 3 did not have a significant impact on system performance. It is
noted that this unit also is part of a tRAS and if the unit were retired, the Naughton RAS would
need to be modified to reflect this change.
Anticipated high-level system improvements for Scenario 1 include the following with a non-
binding estimate of $45-S70 million:
l. Install a new dynamic voltage device at or near Bridger
2. Modification of Bridger and Naughton RASs
j
This transmission system assessment was performed to assess the impacts of the full retirement of
all four Dave Johnston coal units with a total capacity of 762 MW and determine if the end-of-life
retirement (end of 2027) of Dave Johnston will require transmission system improvements. The
Energy Gateway west D.2 transmission project was not considered; however, the new and
repowered wind generation was assumed based on preliminary 2017 RFP shortlist resources.
123
PecnConr - 2017 IRP Upoere Cuaprr,n 9 - TRANsMrssroN Sruoms
Study results indicated that under this scenario, various 230-kV transmission line segments
between the Point of Rocks substation in central Wyoming and the Dave Johnston substation in
eastern Wyoming, overload above their continuous ratings under normal conditions, and above
emergency ratings under system outage conditions. Voltage levels outside of approved limits were
also observed at multiple locations in eastem and central Wyoming under outage conditions. The
new wind turbine technology provides improved reactive response, but cannot provide all of the
required voltage support.
To mitigate these issues the following system improvements were identified, with a high-level
non-binding estimate of $810 million:
1. Build a new 140-mile 23O-kV line between Bridger-Latham-Freezeout.
2. Build a new 230-kV line between Freezeout-Shirley Basin-Windstar.
3. Rebuild the existing 230-kV lines from Point of Rocks to Freezeout substations (Point of
Rocks-Bitter Creek-Bar X-Echo Springs-Latham-Platte-Standpipe-Freezeout).
4. Rebuild the following substations: Point of Rocks, Bitter Creek, Bar X, Echo Springs,
Latham, Platte, Standpipe, Freezeout, Shirley Basin and Windstar to support higher
transmission line capacity.
5. Install a +3501-125 MVAr Static Var Compensator (SVC) at Latham substation
6. Install five, 40 MVAr each switched shunt capacitors at Latham substation
Replace the three existing 3451230-kV 200-MVA auto transforners at Jim Bridger
substation with at least two 3451230 700-MVA auto transforrners.
This scenario analyzed the impacts of the full retirement of all four Dave Johnston coal units in
2027 with no Energy Vision 2020 wind or transmission facilities. Study results indicate that
retiring Dave Johnston with no generation additions, significantly changes the directional power
flow in eastern Wyoming, which can result in west-to-east flows to meet load requirements versus
the currently predominant east-to-west flows for this area. As more power from the Jim Bridger
generation facility and other western Wyoming and Utah resources are needed to serve Wyoming
loads, the three Jim Bridger 3451230-kV auto transformers overload under normal and outage
conditions (typical line and major equipment outages aligned with NERC standards criteria). This
change in power flow also results in decreased flows to the PacifiCorp-west system.
The Dave Johnston plant retirement also impacts the ability to control voltages in the area; high
voltages were observed during light load, no wind conditions and low voltages were observed
during heavy load conditions. As such, reactive support in the form of capacitors and reactors
would be required. A preliminary assessment of required facilities under this scenario is as follows
with a high-level estimate of $23-$33 million:
l. Replace the three existing 3451230 kV 200 MVA auto transforrners with at least two 700 MVA
transformers. Note that replacement of one of the transformers is proposedby 2020 to resolve
identified North American Electric Corporation (NERC) Planning Standard TPL-001-4
thermal overload issues.
2. Install a 3O-MVAr shunt capacitor and 5O-MVAr shunt reactor.
124
PacmrConp - 20 17 IRP Upnare Csaprgn 9 - TnaNsHarsstoN STUDTES
Without the D.2 projects, the study noted that installation of a dispatchable replacement resource
at Dave Johnston of approximately 650 MW dispatchable resource would mitigate the
aforementioned impacts of the Jim Bridger transformer overload and would provide necessary
voltage support. A high level non-binding cost estimate to replace Dave Johnston generation with
a 650 MW dispatchable resource is $1,257lkilowatt for an approximate total of $817 million (this
is based on a Combined Cycle Combustion Turbine in the 650 MW range, per Table 6.1 in the
20l7 rRP).
This transmission system assessment considers the impact of an end-of-life retirement of Naughton
Units I and 2 with a total capacity of 357 MW.
Historically, the Naughton units have provided transmission operators the capability to control
voltage on the Naughton 230-kV bus and the surrounding system under normal operation and
outage conditions (typical line and major equipment outages aligned with NERC standards
criteria). Area shunt capacitors are used to support post disturbance voltages. Naughton units being
off line under normal conditions leads to the conclusion that additional shunt capacitors will be
required in the area with the assumed retirement of Units I and2.
Anticipated high-level system improvements for Scenario 4 include the following with a non-
binding estimate of $6-$15 million:
1. Install two new 3O-MVAr capacitor banks near Naughton
The system review shows that additional infrastructure will be required to maintain a safe reliably
operating transmission system with the retirement of coal resources per the four scenarios
reviewed. The addition of the D.2 transmission line provides needed transmission system support
with and without the resource retirements and the addition of new wind resources per the 2017
IRP preferred portfolio. The addition of new wind from Energy Vision 2020 using new turbine
technology does provide needed voltage support but cannot provide all of the system requirements
absent the coal facilities.
t25
Transmission Assessment - Scenario 4
Conclusions
PacrprConp - 2017 IRP UPDATE Cgepren 9 Tna.NsvrssroN Sruores
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PRcrplConp - 2017 IRP Upoerp APPENDIx - ADDITIoNAL LOAD FORECAST DETAILS
ApppNDIX _ AopITIONAL LOAD FORECAST DPTEU-S
The load forecast presented in Chapter 4 represents the data used for capacity expansion
modeling, and excludes load reductions from incremental energy efficiency resources (Class 2
DSM).The load forecast used in the 2017 IRP Update was produced in August 2017 . The average
annual energy growth rate for the lO-year period (2018 through 2027) is 0.55 percent. Relative to
the load forecast prepared for the 2017 IRP, PacifiCorp's 2027 forecasted energy requirement
decreased in all jurisdictions other than Oregon and Idaho, while PacifiCorp system energy
requirement decreased approximately 4.2 percent. Table A.1 and Table A.2 illustrate the annual
load and coincident peak load forecast when not reducing load projections to account for new
energy efficiency measures (Class 2 DSM).'
Table A.1 - Forecasted Annual Load Growth, 2018 through 2027 (Megawatt-hours), at
re-DSM
201 8 59,876,340 14,828,080 4,568,290 903,060 25,660,060 10,023,590 3,893,260
1 5,148,080 4,602,t70 899.340 25.87 r,850 10,006,200 3,920,890201960,448,530
2020 60,684,390 l 5,171,700 4,622,620 89 r,670 26,029,s00 rc,029,430 3,939,470
15,218,700 4,620,810 883,870 26,210,610 10,063,780 3,954,870202160,952,&0
2022 6 r,451,780 15,316,170 4,634,340 880,000 26,499,690 I 0,140, l 00 3,98 r,480
61,983,M0 15,423,000 4,652,580 876,680 26,802,770 10,216,900 4,011,1102023
4.045.980202462,662,000 15,570,800 4,689,t20 87s,620 27,16/',620 10,3 I 5,860
2025 63,004,770 b,629340 4,701,470 868,930 27,378,200 10,360,020 4,066,810
4.728.450 864.610 26.741.980 r0.429.410 4.092.430202662,578,260 t5,721,380
2018 -2027
2027
0.s5%
62.922,460
0.72',/,
15,817,000
Average Ar
4,75,1,180
nual Growtl
0.440h -0.53o/"
860,700
r Rate for 2l
16.u74,580
tt8-2027
0.52o/o 0.520h
r0,498,300 4,I 17,500
0.620h
I Class 2 DSM load reductions are included as resources in the System Optimizer model
137
Year Total OR WA CA UT WY ID
PACIFICORP - 20I 7 IRP UpoeTg AppENDrx - ADDIrroNAI- Lono FoRECAST DETAILS
Table A.2 - Forecasted Annual Coincident Peak Load (Megawatts) at Generation, pre-
DSM
Year Total OR WA CA UT WY ID
2018 9,971 2,326 752 r48 4,687 1,283 775
2019 10,005 ,'l5s 757 t47 4,685 1,280 780
2020 10,038 2,359 763 146 4,7M 1,284 782
2021 10,109 2.368 768 t45 4.750 1,289 789
2022 10,190 2,377 772 145 4,803 1,298 795
2023 10,266 2.386 778 146 4,850 1,306 800
2024 10,344 2,391 783 144 4,902 1,317 806
2025 10,419 2,406 791 t43 4,961 1.324 794
2026 10,422 2,414 797 142 4,922 1,332 8t6
2027 10.462 2.42t 803 t42 4,933 1,340 823
Avemge Annual Growth Rate for 2018-2027
2018 -2027 0.540h 0.450h 0.730h -0.490h 0.57"/"0.49o/o 0.67o/"
Table A.3 and Table A.4 show the forecast changes relative to the 2017 IRP load forecast for loads
and coincident system peak, respectively. The 2017 IRP Update incorporates a methodological
update for the treatment of private generation and how it affects the coincident peak. In previous
IRPs, the load forecast summed the hourly kW for seven different private generation sources to
produce the hourly private generation shape within each state. For the 20l7IRP Update, since a
high percentage of forecasted private generation is solar (>90yo), a more appropriate methodology
was adopted where the seven individual private generation sources were weighted by annual
MW. The result was that the aggregated hourly shapes for each state better reflect the individual
contribution for each ofthese private generation sources.
As such, the improved methodology results in the coincident peak being lower than it would have
been using the unweighted approach. For example, when holding all else constant, the improved
methodology results in the coincident peak for 2018 to be 49 MW (0.5%) lower, while the
coincident peak for 2027 is 149 MW (l-4%) lower when compared to the unweighted private
generation methodology used in the 2017 IRP.
Table A.3 - Annual Load Growth Change: 2017IRP Forecast less 2017IRP Update
Forecast watt-hours at Generation re-DSM
Year Total OR WA CA UT WY ID
201 8 (794.1 10)9l,380 70.860 (1,160)(977.630)(27.330)49,770
2019 (8s2,840)266,4s0 6s,360 (2,550)( r,084,6s0)(144,390)46,940
2020 ( l. r78.910)219,920 59,380 (6, r60)( r.230.920)(263.410)42,280
2021 ( r,344,560)198,830 35,300 (8,270)( r,336,400)(270,360)36,340
2022 ( l.ss5.250)171,360 19.2s0 (e.e00)i.462.450)(304.960)3 1,450
2023 ( 1,816,690)146,830 5,680 ( l 1,240)( 1,s9s,700)(390,030)27,770
2024 ( 1.948.360)t22,770 (3.360)02.390)0.731.800)(347.940)24,360
2025 (2,t66,790)94,580 (re,Mo)( 13,880)( 1,846,430)(403,s40)2t,520
2026 (2,604,720)86,460 (24,730)(14,670)(2,1s2,220)(5 r8,4s0)
2027 (2,761,t90)77,190 (3 r,860)(ls,1s0)(2,283,320)(s2s,070)r7,020
138
18,890
Appguotx - ADDTTToNAL Loao FoRncasr DETAILS
Table A.4 - Annual Coincident Peak Growth Change: 2017 IRP Forecast less 2017 IRP
U te Forecast M at Generation,re-DSM
Table A.5 and Table ,{.6 provide total system and state-level forecasted retail sales summaries
measured at the customer meter by customer class including retail load reduction projections from
new energy efficiency measures from the 2017 IRP Update preferred portfolio.
Table A.5 - System Annual Retail Sales Forecast 2018 through 2027 (Megawatt-hours),
ost-DSM
Year Total OR WA CA UT WY ID
l8201 8 (2s4)28 (3)(383)36 5l
20t9 (30s)6 l8 (5)(412)35 53
2020 (365)(0r 2t (6)(448)l6 52
2021 (40e)(6)20 (6)(466)10 39
2022 (434)( 14)20 (7)(478)6 39
2023 (440)(21)20 (5)(491)4 53
2021 (46r)(34)20 (7)(s07)l3 54
2025 (s00)(37)23 (8)(s21)6 37
(44)2026 (50e)24 (8)(524)(11)54
2027 (5se)(51)25 (8)(s46)( l8)40
System Retail Sales - Megawatt-hours (M.Wh)
Year Residential Commercial Industrial Irrigation Lighting Total
2018 r5,842,460 17,655,267 18,840,636 1,472,t63 139.346 53,949,872
2019 15,666,962 t],776,306 18,904,216 I,468,159 138,470 53,954,173
2020 15.3t7,343 t7,799,587 18,95t,777 1,463,425 137,705 53,669,838
2021 15,139,3 t 9 17,776,502 18,979,641 t.459,882 136,290 53,491,634
2022 15,103,151 17,824,771 19,029,805 1,456,569 135,254 53,549,550
15.101,463 17.887.3892023 19,o76,640 1,453,4r4 t34,294 53,653,199
2024 15.17 I,r 17 r 7,991,108 19.151.692 t.449.714 133,771 53,897,4O2
2025 15,109,350 17,980,093 19,152,679 1"445.707 \32,3s5 53,820.183
t8.oo7.4692026l5,l 14,358 18,331,019 1.442,171 13t,322 53,O26,339
2027 t5,139,947 18,026,O99 18.378.406 1,438,641 130,355 53,113,447
Average Annual Grorvth Rate
2018-27 -O.5"/"O.2"/"-O-3"/n -O.3o/o -O.7"/o -O.2o/o
139
PACIFICoRP - 20 I7 IRP UPDA.|E
Year Res idential Commercial Industrial Irrigation Liehtine Total
(t40.147)2018 177,449 273,632 (666,108)79,206 (3,727)
2019 13t.349 330.248 (738.992)86.81l (4.72r)(l9s.3o4)
2020 (4s.432)284.O28 (843.91r)94,O82 (s.946')(s17,179)
2021 (7 t.403)233,291 (866.246')t02,o42 (6,983)(609,300)
(8.033)(754.199)2022 ( r r 3,880)196,864 (938,71s)r08,965
2023 (r21.4s3)r60.865 0.084.944)1t6"707 (8.999)(937.824')
2024 04r.892)130,274 (l.101.119)127,O23 (e,e30)(99s,@.5)
2025 (96.134)53,616 (1.269,773)154,074 ( 10,943)( 1,169,160)
/L1.976)(l.540.876)2026 (98,987)( 15,380)(1,612,8s4)198,321
2027 ( 101.065)(85.816)(r.682.937)244.120 /r2.943)(1.638.91)
PACIFICORP - 20I 7 IRP UpoRrs APPENDIX - ADDITIONAL LOeo FORECeST DETAILS
Table 4.6 - Annual Load Growth Change: 2017IRP Forecast less 2017 IRP Update Forecast
(Megawatt-hours) at Retail, Post-DSM
Residential
Over the 2018-2027 timeframe, the average annual growth of the residential class sales forecast
declined from -0.3 percent in the 2017 IRP to -0.5 percent in the 2017 IRP Update. The number of
residential customers across PacifiCorp's system is expected to grow at an annual average rate of
1.0 percent, reaching approximately 1.8 million customers in2027, with Rocky Mountain Power
states adding 1.4 percent per year and Pacific Power states adding 0.4 percent per year. It is
expected that residential customers are likely to use more efficient appliances, which is having an
adverse impact on the residential forecast, relative to the 2017 IRP load forecast.
Commercial
Average annual growth of the commercial class sales forecast declined from 0.5 percent annual
average growth in the 2017 IRP to 0.2 percent expected average annual growth in the 2017 IRP
Update. The number of commercial customers across PacifiCorp's system is expected to grow at
an annual average rate of I .0 percent, reaching approximat ely 229 ,000 customers in 2027 , wrth
Rocky Mountain Power states adding 1.3 percent per year and Pacific Power states adding 0.5
percent per year. Relative to the 2017 IRP, the Company increased its commercial forecast in the
earlier years of the 20l7IRP Update load forecast, but lowered its commercial load expectations
in the later years of the forecast. This is attributable to a more optimistic outlook for the
commercial sector in Oregon and Washington, and a relatively less favorable outlook for the
sector over the long-term in Utah.
Industrial
Average annual growth of the industrial class sales forecast declined from 0.3 percent annual
average growth in the 2017 IRP to -0.3 percent expected annual groMh in the 2017 IRP Update.
A portion of the Company's industrial load is in the extractive industry in Utah and Wyoming.
The Company has seen several large industrial customers lower their expectations for load growth
given less favorable conditions within their particular sectors. Table A.7 through Table A.12
provide additional detail for the class level forecast within each jurisdiction.
140
Svstem Retail Sales - Megawatt-hours (M\Vh)
PacrprCoRr -2017 IRP Upoarr,APPENDIX - ADDITIONAL LOAD FoRECAST DETAILS
Table A.7 - Forecasted Retail Sales Growth in
Table A.8 - Forecasted Retail Sales Growth in Washi
ost-DSM
t-DSM
Oregon Retail Sales - Megawatt-hours (MWh)
Year Res idential Cornrnercial Industrial Irrigation Liehtine Total
201 8 5.583,761 s,243,692 1.707.309 328, r 53 36,758 12,899,673
2019 5,563,312 5,301,661 1,786,249 327.434 36,67s t3,o21337
2020 5,4&,674 5,2&,941 1,784,727 326,@4 36.627 12.877.613
2021 5,397,546 5,248,tO7 1,789,182 326,267 36,467 12,797,570
5.252.99620225,375,546 1,789,987 326,187 36,460 12,781,177
2023 5,367,170 5,259.993 1.793.616 326,273 36,483 12,783,535
2024 5,385,442 5,219,OO2 1,797,358 326,26s 36.634 12.424.700
2025 5,360,638 5,273,844 1,800,475 326,259 36,6r I 12,797,826
5.283.11420265,355,60s t,803,726 326,317 36,722 12,806,095
2027 5,354,934 5,292.903 1,806,948 326,362 36.843 12,817,991
Average Annual Growth Rate
20ta-27 -O.460/o O.l0o/o O.630/o -O.O60/o O.O3o/o -O.O7"/"
Washington Retail Sales - Megawatt-hours (MWh)
Year Res idential Commercial Industrial Irrigation Liehtine Total
2018 I,583,963 1,53 1,076 754.506 t59,634 r0,095 4,O39,274
2019 1.s18.843 l,538,986 745,572 t59.279 to,o27 4,O32,706
2020 1,561,096 I ,55 l,553 736.309 159,035 10,005 4,O17,998
2021 1,s46,875 1,551,753 719,218 I 58,91 8 9.947 3,986,7r r
2022 1,543,783 1,558,459 700,585 158,885 9,933 3,971,644
2023 154L4M 1,566,41I 683.400 158,920 9,934 3,961,069
2024 1,548,222 t,579,063 61t,923 158,925 9,974 3.968.107
2025 1,54t,570 1,581,426 660,230 158,8 r 6 9,949 3,951,991
2026 1,541,584 1,589,087 652.O50 158,777 9,971 3,951,47O
2027 1,543,786 r,598,326 642.O80 158,835 l0.ol9 3.953.04s
Average Annual Grorvth Rate
2018-27 -O.29o/o O-48"/n -1.78o/"-O.O60/o -O.O8"/"-O.24"/o
t4l
California Retail Sales - Meqawatt-hours (M\ilh)
Year Residential Commercial lndustrial Irrigation Lighting Total
758.9452018316,905 226,895 57,71O 95,411 2,Ot9
2019 373.803 222.688 57 ?q5 95,533 2,OO3 751,420
2020 366,846 218,992 57.238 95,370 I,989 740,435
2021 361,570 2t4.662 56,850 95,O97 1,968 730,146
2022 722,812358,@6 21o,869 56,590 94,761 1,946
2023 3s6.306 207.O51 56.384 94.432 I,930 7l6,lo2
2024 355,551 203,762 56,276 94.O45 1,922 711,555
2025 35 1,8 l8 199,186 55,797 93.628 1.901 702,331
2026 349,659 r95,r59 55,472 93,254 1,888 695,432
2027 348.47 190.977 55.144 92.867 I,870 688,884
Average Annual Growth Rate
20ta-27 -O.887o -l.9Oo/o -O.5O"/"-O.3O"/"-0.850 -1.O7"/"
PacmICoRp 20lT IRP UPDATE AppeNox - ADDITIONAL Loao FonECnST DETAILS
Table A.9 - Forecasted Retail Sales Growth in California,t-DSM
Table A.10 - Forecasted Retail Sales Growth in Uta DSM
Utah Retail Sales - Mesawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Liehtine Total
20r8 6,s80,32s 8.150.826 1,726,3t8 220,942 76,102 23354,513
2019 6,449,969 8,797,719 7,770,7t6 220.356 75.601 23314360
2020 6.251.O58 8,841,81O 7.836.627 2t9.757 75.t19 23.230372
2021 6,186,442 8,834,148 7.873.530 219,125 74.180 23,188,025
2022 6.186.852 8.8&.904 7.919.273 218.567 73.441 23,263,O37
2023 6,202,O50 8,904.636 7,962,165 2t8,tt7 72,750 23359,718
2024 6,246,505 8,9&,872 8,O12,795 217,650 72,281 23,514,103
23.50637320256,233,228 8,962,794 8,O22,O97 216,990 71,2&
2026 6,251,555 8,979.066 7,188,909 2t6,3ss 70,443 22.706328
2027 6,280,581 8,983,885 7,224,382 215,778 69,658 22,774,284
Averaqe Annual Growth Rate
2018-27 4.52o/o O.29o/o -O.74o/o -O.260/o -O.98o/o -O.28"/"
142
PACIFICoRP -2017 IRP UPDATE APPENDIX - ADDITIONAL LOe.o FOn-eCaST DETAILS
Table A.11 - Forecasted Retail Sales Growth in ldaho, post-DSM
Table A.l2 - Forecasted Retail Sales Growth in Wyoming, post-DSM
Idaho Retail Sales - Megawatt-hours (MWh)
Year Res idential Commercial Industrial Irrigation Liehtine Total
2018 700,o24 5 19,58 I 1"713,474 &3,556 2.604 3,579,24O
2019 697,720 533,400 1.713,216 (At.t79 2,580 3,5gg,og4
2020 686.874 546,324 1,713.424 638.320 ? 55?3,597,495
2021 681,434 556.258 t,712,508 636,273 2,s2t 3,588,994
2022 681,551 568,547 t,712,418 634,07s 2,488 3,599,O79
2023 683,O92 58 1,261 1,712,128 631,689 2,449 3,610,619
2024 687,631 594.84t 1,712.500 628.961 2,416 3,626355
2025 685,857 604,016 t,7tt,o73 626.284 2.367 3.629.598
2026 687,235 614,O79 t,7to,4t6 623,895 2,327 3,637,953
2027 689,253 623.959 1,709,822 62t.396 2,288 3,646,719
Average Annual Grorvth Rate
20ta-27 -O.l7o/o 2.O5o/o -O.O2"/o -O.39"/"-1.42o/o O.2lo/o
Wyoming Retail Sales - Megawatt-hours (MWh)
Year Residential Commercial Industrial Irrigation Liehtine Total
2018 t,ot],483 1,383,t97 6,881,318 24.460 11,768 9.318,226
2019 1,003,316 1,375,846 6,83 1,130 24,379 r r.585 9,246,256
2020 980,796 1.375.968 6.823.453 24,298 I t,412 9,215,926
2021 965,4s3 1.370.915 6,828,353 24,20t 11,208 9,200,189
2022 956,174 1,368,994 6,850,953 24,O94 t0,986 9,21 I ,80O
2023 950,441 1,368,037 6,868,947 23,983 to,t46 9,222,155
2024 947.765 1.369,569 6,900,840 23.863 1o.544 9.252.582
2025 936,239 1,358,827 6,903,006 23,730 to.262 9,232,064
2026 928,719 1,346,363 6,920,445 23,573 9.971 g,22g,o7l
2027 923,366 1.336.049 6,940.030 23,403 9,617 9,232,524
Average Annual Grorrth Rate
2018-27 -l.O7o/o -O.38"/"O.O9o/o -O.49o/o -2.15"/o -O.lO"/o
143
PACII,TCoRP 2017 IRP UPDnrE,APPENDIx ADDITIONAL LOAD FORECAST. DI.I.,I.II,s
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