20170404Volume 1- 2017 IRP.pdf

7OI7 INTEGRATED
RESOURCE PLAN
Volume I
Apri! 4,2017
This 2017 Integrated Resource Plan Report is based upon the best available information at the
time of preparation. The IRP action plan will be implemented as desuibed herein, but is subject
to change os new information becomes available or as circumstances change. It is PacifiCorp's
intention to revisit and refresh the IRP action plan no less frequently than annually. Any refreshed
IW action plan will be submitted to the State Commissions for their information.
For more information, contact:
PacifiCorp
IRP Resource Planning
825 N.E. Multnomah, Suite 600
Portland, Oregon 97232
(s03) 813-s24s
[e-mail]
http ://www.pacifi com.com
This report is printed on recycled paper
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 thermo stat
Paciftc Power wattsmart Business Customer Meeting
Thermal-Gas: Blundell Geothermal Plant
PACIFICORP-2017 IRP TABLE OF CONTENTS
Tagrp op CoNTENTS
TABLE OF CONTENTS
CHAPTER I - EXECUTIVE SUMMARY
PRSFSRREo Ponrrolto Hrcnucsrs ......................
Nnw Rrxzw,qam Rosouncls AND TnqNsutsstoN
WtNo Ropor4/ERING
D nulNo Snn Mtv,qGEMENT.....
WuotostLo P ow m M,qnxsr P u nc HASES ............
Extsrwc C o,qt RosouRC E5........
N.qrun qt Gas RosouacEs............
Rgt'r ow.qa m P o nr ro u o S r,qN o.q nos
C,qnnoy Dtoxtoa E utsstoxs ..
Loeo auo RlsouRcp BeleNcB
C*ecry B,qLANCE
ENoncv BaLANCE.......
2017IRP ApveNceuENTS AND SupplevpNral Sruprcs
IkP AoutNcnuours...............
Supprouoyr,qt Sruorcs
AcrroN Pr-aN
CHAPTER 2 _ INTRODUCTION
2017 INTScRATED RssouRcp PleN CovpoNpNTS ...........
Tup Ror-s op PecrrrCoRp's INrBcRatpo RssouRcp PLauNmc.
Puet.rc INpur Pnocpss
CHAPTER 3 _ THE PLANNING ENVIRONMENT
INrRooucrroN ...........
WsolrselB Er.ecrnrcrrv MaRxrrs
Ntrunet G,qs Uuc nnrArNTy...........
Tus Furunp on Fepenar- EUvIRoNMENTAL Rscur-auoN AND Lpcrs1arroN.....................
F rosan C u u,qrs C neuc o L oc tstlrtoN ...........
F oo ont t Rot't ow,s n rc P o arr o u o Sr,q t t o,q nos
FeoBRAr- Por.rcy Upolrs
Nsw Sounco P snroru,tltco Sr.qNo,tnos ron C,qnnou EutssroNs - CmaN An Acr $ I I I (a)
C,qnsott EutsstoN Gutoottttas ron Extsrn'tc Souncrs - Crc,qlt AR Acr $ I I I (o)
Crc, N AtnAcr Cruroru.q Pouur.sNrs - NlrtoNtt Auarcur Am Qu,utrr Sr,qNo.sRDs
Rnctot't,qr H,qzo
Moncunr tyo H,qz,ARDous Atn PorturtNrs
I
2t
22
23
23
25
.. 28
.. )z
.. 32
25
26
33
JJ
33
33
34
35
J/
I
PACIFICORP_20I7IRP TABLE oF CoNTENTS
C o,qt C oua usrtot'r Rzsto IALS.....
W,qrnn Qu.turr Sr,INDARDS.........
2015 T,qx ExroNoon Loctstqrtoy
Srerp Polrcy Upoare....
C,uFonNLs..
OancoN.......
W.qsnwcroN
Ur.qu.........
G ar sN u o u s o G..4s E ut ss t o r'r P o nr o nu.qN c s S r.q N o.4 RD s
ReNewRsr.p PoRrrolto SreNoeRps
C,quropwlq
Onzcou....
Urta.........
Wsatucrou
TReNspoRTATroN ELncrRIrtcATroN.....
HvpRoelecrRrc Rpr.rcpNsmc ....
P orr,Nrt.u lur,qcr......
Tnntruour m rrud IW
P tc m tC o np' s A p p nolc n ro Hro no ot ECT Rrc Rr uc nx st'to
Uren Rarr DnsrcN INroRveuoN ............
Rrsnzt'trt.tt Rera D nsrcN...............
Couuenct.qt,qNo lNousralqt RArr D gstcu
Inruc.artoN Rqre DostcN
ENencv INaelr-aNcp Mnnxrr ......
ReceNr ResouRcB PRocunerrarNr Acrrvnrcs
DSMAN> Stot M,qtt.qGEMENT (DSM) Rosouncss
2 0 I 7 Tn qvsr rn F atguot tcy Rnsp oNss Ragursr ro a P nor oset^s .............
N,qruRAL G.ts Assnr M,qNAGEMENT,qNo Supptr Reguasr ron Paoros, ts
RoNrruaLo Rosouace,qlo REC RaeuEST FoR Pnopos,us.
2015 Mdaxtr Resouaco Roguesr ronPnopos,qn
RzN eweo rc Euoncy C nrotrs (Saro) Roguosr ro n P nop os.qts.................
Suonr-Tmu M,qaxnr Powon Rtgursr ron PnorosALS.........
CHAPTER 4 - TRANSMISSION PLANNING
INrRooucrroN ...........
Recur-aronv RequneMENTS...
Opatt Acctss TnqttsutsstoN T,sRtrr ......
Rou,q a t ury Sr,qN o,q nos
Roquesr roR AcTNowLEDGEMENT oF Wallule ro McNeny...
FICTONS S UP P O RTING AC TI'IOWTOOG EMENT .....
Pr-aN ro CoNrnrus - WaLLULA To McNany
RequEsr roR AcTNowLEDGEMENT or Apor.us ro BRrncen/ANrrcr-ne
F.qcro RS Su p p IRTTNG Ac xNowtooGEMENT.....
GarewRy Wpsr - CoNrtNuep PeRvrrrrNc...............
Wwosr,qaro Poputus (Socunt'n D)
PopuLus ro Hzurucwu (SocunNr E)......
Garnwey Souru - CoNrrNuso PpRvrrrrnNc
37
57
57
58
58
59
59
60
....6r
6t
62
63
63
64
64
t1
PACIFICORP-2OI7IRP TABLE oF CoNTENTS
PleN ro CoNrNup PrRvrrrrNc - Garpwav Wpsr euo Garewav Sour9........
Exencv GerBwev TReNsvtt s sloN Expe.Ns toN P r,aN
INrnooucrtoN
Blcrcnouuo
P tlt'tN t wc IN u t,qrtv ns
Et'rzncr Glr ew,qv C ot t nc u RAT I o N .....
Et'rz,ncy Glr EWAr' s C ot tr m u go Etto tur t ox
EnEoRrs ro Mexuzs ExIsrn{c Svsrnu CepesrLlrv
TnqusutsstoN Sysrau lupnornurNrs Pnqcao lt'r-Sanrtco StNct rno 2015 IRP
P t qt tNoo Tn lNsutsstol Svsrnu lup novEMENTs..
CHAPTER 5 - LOAD AND RESOURCE BALANCE
INrRooucuoN ...........
Svsrru CorNcrpnNr Penr Loeo Fonncasr..
ExrsrrNc RssouRces....
Tnnwr.qt P L.qt'rrs .......
Rrt'tr,weam Rosouncos
Wind.
Solar.
Biomass/Biogas...........
Hvononrccrruc Gzt tr,n trloN ...........
Hydroelectric Relicensing Impacts on Generation.
DoutNo Stoo Metrr.qGEMENT (DSM)
Prurlqrg Gnt'ronqrtou
P ownn P unc n,qso C ot trmcrs
Loao eNo R-EsouRcs Ber.eNCE .............
C,qpectry tNo Eynncr B,qnquco Ottr,nrryqw....
Loeo,qvo Rasounco B.qLANC E C oup olot'ns .
Existing Resources
Obligation
64
65
65
65
65
68
72
72
7i
67
75
75
75
76
76
77
.77
.79
.80
.80
.80
80
Renewables Net Metering
8l
82
84
85
86
86
87
Planning Reserves
87
88
90
90Position
C lp,sc ry 8,4 L,q ttrc o D zrnnut w.tr t ot't
Methodology
Exoncy B,qL,sNcg DErgRMtulTIoN...........
Methodology
Euzncy Btt lt'tcz Rssuus.
CHAPTER 6 _ RESOURCE OPTIONS
INrnooucuoN ........
90
.90
.90
95
.95
95
97
Supplv-srop ResouRcES .............
Drruv,srrcN or Rtsounc E ATTRIBUTES
H,qt t o tt Nc o F T EC HN o Locv I up aovEMENT T ntx os .qN o C osr Uuc o nrA rNTr ES
Raso unc r O prtous .sN p Arr nt gurgs
.97
.97
.98
.99
101
Rxouaco OprtoNs DtscapruoNs......... .......... 119
lll
PACIFICORP - 20I7 IRP TABLE OF CONTENTS
ll9
120
t2l
122
t23
123
t25
129
r30
Supply and Location ofRenewable Resources
Natural Gas
Energy Storage
Nuclear
DeNrnNp-sIDE RESoURCES ..
Rosouncr Oprtovs tNo Arrptaurns
Source of Demand-side Management Resource Data
Demand-side Management Supply Curves
Class I DSM Capacity Supply Curves
Class 2 DSM, Energy Supply Curves .
Distribution Effi ciency
TReNsurssroN RESoURCES .........
Merrpr Puncuesns................
CHAPTER 7 _ MODELING AND PORTFOLIO EVALUATION APPROACH
INrRooucrroN ...........
MooeI.nlc AND EvALUATIoN Srnps
Rpsoun cr PoRrrolro Dpvpr.opl,rpNr
Srsrou O prrMrzER (SO) ..........
Transmission System
New Resource Options
Capital Costs and End-Effects
General Assumptions
Environmental Policy and Price Scenarios
Cosr eNo Rrsr ANer-YSrs...
P nqt'tt'ttuc, ND R1s.K (P eR)
Cost and Risk Analysis
Monte Carlo Simulation
Stochastic Portfolio Performance Measures.
... 133
... 133
t33
133
134
135
139
... 140
... t4r
143
r43
t44
145
145
146
147
150
150
l5l
.. 156
.. 156
156
Stochastic Model Parameter Estimation.... ...................157
Other PaR Modeling Methods and Assumptions
Orrurn Cosr,qt to Rtsx C ot'rsDrn qrloNy .....,
Fuel Source Diversity..
Customer Rate Impacts
PoRrrolro SBI-pcrloN
Fnrel ScRepNrNc Srece AND PREFERRED PoRTFoLro SplpcrroN
CasB DerrNrrroNs.......
Roctot rn H,qzn C,qso Dzrwtrtor'rs......
Coaa C,qss DnrwtrroNs .........
Case l: Optimized Portfolio (OP-1)..........
Case2:. Flexible Resources (FR-l)
Case 3: Flexible Resources (FR-2)
Case 4: Renewable Energy (RE-l)
Case 5: Renewable Energy (RE-2)
Forward Price Curve Scenarios.....
Case 6: Direct Load Control (DLC-l).......
.166
.166
.168
,168
169
.169
.169
169
t69
t70
170
172
.172
.172
.172
.173
.173
.173
1V
PACIFICORP - 2OI7 IRP TABLE oF CoNTENTS
S sus trtwrr C,qs r D o rw tr I oN s
Regional Haze Sensitivities.
Load Sensitivities
CPP Mass Cap C
CPP Mass Cap D
Limited Availability of FOTs........
Business Plan Sensitivity
Energy Gateway Sensitivities
Energy Storage
East/West Split
WCA Assumptions
CHAPTER 8 _ MODELING AND PORTFOLIO SELECTION RESULTS
IurnopucrroN ...........
RBcroNel Hxzy Ponrrolro ScnrpNrNrc
Rssounc n P o RTFoLro D aroLop uaur..
Rnctouet H,qzn Cosr,qt to Rtsx Au,qiysts
Risk-Adjusted PVRR
Average Energy Not Served (ENS)
Upper-tail Average ENS
Shadow Prices
RrctoN,qL H,qzz Ctso Poarrotro SELECTTzN
Initial Results and Conclusions
tusk-Adjusted PVRR.......
Average Energy Not Served (ENS)
Upper-tail Average Energy Not Served (ENS)
Private Generation Sensitivities
173
.174
.174
.17 5
.176
.176
.176
.176
.177
.177
.177
.178
.178
.178
179
PaR Configuration and Metrics.........
Final Regional Haze Portfolio Selection
ELICIBLE PoRTFoLIo SCREENTNG
E ucrc m P oRTFoLro D EVELq P MENT....
Coad C.qso PoarroLro DEVELqPMENT
Cumulative Additional Resource Capacity
Situs-Assigned Renewable Resources
E ucrc rc S evs trn/rrv P oRTFoLro D EVELz p MENT .........
Resource Capacity Impacts and PVRR Results
Eucnm P oRTFoLro Cosr,qNo Rtsx At utvsts.
Regional Haze Case 5 Enhancement..................
PaR Configuration and Metrics.........
E ucrc rc P o RT FoLro S ELECTT oN
FNAL PORTFoLIo SCREENTNG
F t't,u P o nr po u o D ntr nLo p u nur
Wind Repower (FS-REP) Portfolio.......
Energy Gateway 4 (FS-GW4) Portfolio
Renewable Energy (FS-Rlc and FS-R2) Portfohos
Cumulative Additional Resource Capacity
SO System Costs
V
PACIFICoRP-20I7 IRP TABLE oF CoNTENTS
Fnrlu Poarrouo Cosr.quo RrsxANttysts ...225
PaR Conflrguration and Metrics 225
227
228
229
230
231
232
233
234
Average Energy Not Served (ENS)
Upper-tail Average Energy Not Served (ENS)..
Fw,u Pnzronnoo PonrpoLto SrmcrtoN 231
Customer Rate Impacts
Preferred Portfolio Selection.
Now Rouow,qBLE RESzURCES AND Tnqusutsstoy
Wtwo RopowERrNG
D outN o S n a M.tN.qc ouour
Wu o Lrs.qLn P o w m M.q nxor P u ac HAS ES ............
Extsrtxc Co,qt ResouRC E5........
N.qrunet Ges RosouncEs............
C.qp.4cffv,4ND ENERGY
Rtw ow,qn L n P o nr ro u o Sr.l uoe nos
C.qnnox Dtoxtoo EutsstoNs
DorttLoo P rc,ronazo P onrrouo
ADDITIONAL SENSITIVITY ANALYSIS
I-ru-20 LoeD GRowH Sor'rsrcrwry (CASE LD-1).......
Low Lo,qo Gnowra Stusrrrwrr (C,asn LD-2)............
Hrcn Loto Gnowu Sovyrltrrr (Ctsn LD-3) ..........
L ow P p.tv.tr n G aN o ntrt o tt S t ws rtwrr (C as e P G- I ) .
Hrcu P rur.qr E G EN E RAT r oN S ous tr tvtry (C,eso P G - 2)
CPP M.qss Clr C Sousrrrvrry (C,tst CPP-C)
CPP M,sss Cer D Sotrsrrrwrr (Ctso CPP-D)............
Lrurrno FOT Srusrrrvrry (C,aso FOT-1) ........ . .... . .
CO2 Pruco SoNsrrvrcy (C,nso CO2-1)......
No CO2 Porrcy Sousrrrvrry (CasnNO-CO2) ...........
Bustt'tass Pt.qu Sst'tstrtwrr (Cso BP)
Eu n ncy Sro alc a S ot'ts r t rtrrcs.
E tsr/Wosr Srrrr Sarsrr r vrry (Cts o WCA)
E,qsr/W asr S p ur RP S S susrrrwrr (C,ts o WCA- RP S)
2015 IRP WCA SeNsrrrwry DrscussloN.......
CHAPTER9_ACTIONPLAN
INrRooucrroN
Tar, 2OT7 IRP AcrroN PIaN
PRocRBss oN PRBvrous AcrroN Pr,aN Irevs...
AcqursrrroN Peru ANelvsrs
Ros o u nc o,st'r o C o up u,qNc o S ra.qr ocr E5..................
AcAutsrctoN P.qrn D sctstot t Macrurtsu.
PRocuRpl,tsNr DBlays..
IRP AcuoN Pr.eN LrNrecp ro Busnress PlelNn{c ..
RrsouRcs PRocuReveNr SrRerEGy...........
Rouzw.qaLo Rosouncns
THE2OIT IRP PREFERRED PoRTFoLIo
234
235
235
236
237
238
239
240
242
243
247
247
248
249
250
250
251
252
252
253
254
255
255
258
259
260
263
263
26s
270
276
276
276
278
279
283
283
vl
PACIFICORP-20I7IRP TABLEoF CoNTENTS
RaNrrunLo Euoncv C n-sotrs.
D au,qNo- sn r M,qN.qc n urur
AsspsswNr on OwNrNc Assers vERSUS Puncnesntc Powen....,
MeNlcnic ClnsoN fusr roR ExrsrrNc Pr.eNrs
Punposs or HepcNc
fusx Met'lqceutt tr P oucr,lNo Htoctyc P aocn qu .....
Cosr MtututzuTroN ....... -..
Ponrrouo
E p p scr t v or,r ESs M z.qs u nr...
INsrnuuz,Nrs
TnBerNaeNr or CusroMER AND INvpstoR Rtsrs.............
Srocntsrtc Rtsx
Cepff.sr Cosr fusrs
Sc nN,q p,to Rts r Ass ossuovr
283
283
283
284
285
285
287
287
288
288
288
288
289
289
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PACIFICoRP-20I7 IRP TABLE OF CONTENTS
INopx OF TABLES
Teet.e l.l -2017 IRP PnnrBnnrp PoRrrolro SuuuaRv (Nauerlare MW). ... . .. . .. 2
Tnst-e 1.2-PecmrConp lO-YpanSuuuenCRpRcrrvPosnroNFoREcesr(M\y)..................11
Test.p 1.3 - PecmrConr l0-Ynen WrNrpn Cepecrrv PosnroN FoRscasr (MW)......................11
Test.e 1.4 -2017 IRP AcuoN Pr-nN......... .............16
Tasls 2.1-2017 IRP Pust.rc INpur MpprrNcs ......................23
Taels 3.1- Srers RPS RequrREMENrs .42
Taslp 3.2-C*rroRNrA Col,rplnNcr PeRroo ReeurneuENTS ..43
Teer,B 3.3 - CurroRNrA Ber.eNceo PoRrrolro RBeunBuENTS.......... .....................44
Teslp 3.4 - PecrrrCoRp's Rreuesr roR PRoposx. AcuvrrrEs .......... ......................53
TesI-n 5.1- FonecAsrED Sysrru Suuuen CorNcDsNr Pper Loao rN MBcewarrs, BnroRe
Er.tBRcv ErplclBNcv aNo PRrverp GeNeRRTroN.......... .....................76
TRsr.p 5.2-2017 CepRcrry CoNrRraurIoN AT Sysreu SuuueR Pner ron ExsrrNlc ResouRcps
TReLp 5.3 - Cou-Fupleo Pr.RNrs..
Tasr.e 5.4 - Nerunel-Ges-FUELED PleNrs
TesI.e 5.5 - OwNno WrNp RnsouRcps.....
Tesle 5.6 -NoN-OwNBo Wnro RpsouRcps
Tesls 5.7 -NoN-OwNro Solan Rnsouncps...
Test.p 5.8 -NBr MBrsRrNrc CusrouBRS AND Cepecrrrcs
Taet.s 5.9-HvonoELECTRrc CourRecrs - Loep ewo RrsouRce BeleNcE CapacruEs.....
Teet-e 5.10 - PecrrrConp Owrveo HvoRoelBCTRrc GBNsneuoN Facu-nrcs - Loeo axo
ResouRce BeleNcn Cepecrurss ...................81
Tlsr-p 5.11 - Esrrvarno Iuplcr or FERC LrcBNse ReilBwRr.s e.No RSLTcENSTNG SprrlerreNr
ColaurrureNTs oN HvoRoelecrRrc GeNnRArroN 82
Teet.e 5.12 - ExrsuNc DSM ResouRcp Sutrrrraanv ...............84
TeeI,p 5.13 SuuueR PpA,r Cepecrrv CoNrRrsurroN Velues FoR Wrxro eNo So1,q.R................88
Teet-n 5.14 - Suuupn Ppnr - Svsrev Cepecrrv Loeos eNo RrsouRCES wrrHour RnsounceAooruoNs ..................91
Teet.e 5.15 - WnqrER Psar - SvsreN4 Cepncrrv Lonos eNo ResouRCES wrrHour ResouncsAooruoNs ..................92
Tnslp 6.1-2017 Suppr.y SluB ResouRcp Tasls (2016$)r02
Tnsle 6.2-Torpl- ResouRce Cosr roR Suppr.v-Spp Rpsouncp Opuor.rs.... ........104
TesI-s 6.3 -Torel Rnsounce Cosr, FoR vARrous Capacrrv FRcroRs (Mrlls/rWH,2016$).114
Teslp 6.4 - GlossARy oF TeRMs FRoM Suppt v Spe RrsouRcp Tesr,B.. ...............1 14
Taet.e 6.5 - GlossARy oF AcRoNvus Useo rN THE Supplv Stoe ResouncEs ..........................115
Taslp 6.6 - CuvruLATrvE Mexuuu ReNpwaeLB Ser-BcrtoN LIurrs... ..................I23
Tnet.p 6.7 - CuuuLATrvE Maxruuvr ReNpwest.e Ser.ecrroN Lnarrs... ..................123
Teelp 6.8 -UpperEp BerrBnv TBcnNoLoGrES RNo DarR ...................126
Tnet.e 6.9 - BnrrpRy SronecB Srupy SuvueRy Cosr aNo Cepacrry Rrsulrs (2016$) ......I27
T,q.er-B 6.10 - BerrsRy ENBncv SroRece Spectar. Esce.leuoN RerBs.... ..............128
TesI.p 6.1I - Class 1 DSM PRocRev ArrRrsurps Wesr CoNrnol Anne........ .....135
Test.e 6.12-Cless I DSMPRocReuArrRteuresEnsrCoNrnoLAnse........ ......135
Tler.r 6.13 - Class 2 DSM MWn PorpNuel ev Cosr Burrple.... .......138
Test.e 6.14 - Class 2 DSM Aorusreo Pnrces sv Cosr BrNpLn.... .......139
vl11
76
77
77
78
78
79
80
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PACIFICORP_20IT IRP TABLE OF CONTENTS
TeeI-e 6.15 - ExevrplB op TRRNsMrssroN INrpcReuoN Cosrs sv Srzp op RpsouRce
AooruoNs ...........140
TasLe 6.16 - Mexuuu Avert-eer-e FnoNr Orrrcr TReNsecrroN QueNTrry By Memer
Hue .........................r42
TesLe
TesLe
TeeLp
TeeLp
TneLp
TaeLp
TeeLp
TasLe
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
- Pzuce-Er\4ISSIoNS SceNRRtos
- SHonr Tpnv Loeo Srocuasnc PaRaUETERS ......
- Suonr Tenu Gas Pntce PeRevprpRs....................
- Ssonr TBrur ElpcrRrcrrv PRtcp PeRevprrRs......
- Wnqrpn SBasoN Pnrcn CoRner-euoN............
- SpnrNc SEesoN Pruce CoRReLeuoN............
- Suuusn SeasoN Pnrce ConRrr-erloN ...................
- Fall SsasoN Pnrce ConnelauoN ...........
.t52
.157
.158
.158
.158
.158
.159
.ts9
Tesls 7.9 - Hvono SsoRr Tpnv Srocuesrtc............... .......159
Tegle 7.10 - RecroNer. Hrzr, Cese AssuMpnoNs.... ...........171
TaeLe 7.ll - Cone Cess DepNIuoNS....... ..........172
Taet.e 7.12 - SsNsrrrvrrv DprrN{rrroNs ............. ....................174
Tesle 7.13 - ENpRcv Garswev SeNsrrtvruEs ....
TeeLe 8.1 -- RIsr-ADJUSTED PVRRAMoNG Top PpnroRMrNG PoRrpouos, PHase ONn
Teet.e 8.2 - PVRR Cosr/(BENErtr) or RH-24 vs. RH-2
Taer.e 8.3 - PVRR Cosr/(BnNerrr) or RH-5e vs. RH-5
Teer-p 8.4 - Cone CasBs
Taer-E 8.5 - SeNsrrrvrrrEs CoNspBnrD FoR rHe PREpTRREo PoRrro1ro.............. ....................204
178
193
t94
t95
196
Teet-p 8.6 - PVRR Cosr/(BrNnnrr) or OP-REP vs. OP-NT3 ...
Tegr-E 8.7-PVRRCosr/(BeNerrr) or GWl vs. OP-NT3 .......
TesLe 8.8 - PVRR Cosr/(BrNertr) or GW2 vs. OP-NT3
TaeLe
TesLp
TaeLe
TeeLp
8.9-PVRRCosr/(Beuerrr) or GW3 vs. OP-NT3
8.10 - PVRRCoST/(BeNerrr) on GW4 vs. OP-NT3
8.1 I - PVRR Cosr/(BeNerrr) or OP-GW4 vs. OP-NT3................
8.12 - Rrsr-aorusrno PVRR AMoNG Top PenroRMrNG PoRrrolros, PHasE Two
206
206
...............207
.208
.209
.209
.2r8
Tngr-B 8.13 -Frxel ScRseNnrc Ponrnolros.
Taer,B 8.14 - Gerpwav 4 QueNrrrrABLE BeNeprrs
Tesls 8.15 - Rrsr-Rolusrpo PVRRAMoNG Top PpnroRMrNG PoRrrolros..
Teet.e 8.16 - 2017 IRP PRsnenRno PoRtrolro SuuveRv Q.IevEu-,rre MW)
Teslp 8.17 - PecrrrCoRp's 20l7IRP Pnerennso PoRrrolro ..............
Tasle 8.18 - PRSFpRREo PoRrrolro SurraNasR Clpacrrv Loao aNp RnsouRcp Be.r.eNce
Tnsle 8.19 - PnsrpRRro PoRrrolto WINTpR Cepecrry Loeo euo RpsouRcp BaLRucp
Teet.s 8.20 - Suvruanv or AoorrtoNal SeNsruvttv Cesps
Teet-p 8.21 - PVRR Cosr/(BeNerrr) on LD-l vs. OP-l
Teet-e 8.22-PVRRCosr/(BeNerrr) or LD-2 vs. OP-1
Tasle 8.23 - PVRR Cosr/(BnNerrr) or LD-3 vs. OP-1
Tesle 8.24 -PVRR Cosr/(BrNrrrr) or PG-1 vs. OP-1
Tast.r 8.25 -PVRR Cosr/(BENenrr) or PG-2 vs. OP-1 ..
TesLe 8.26- PVRR Cosr/(BeNerrr) or CPP-C vs. OP-1
Te.sLp 8.27 - PVRR Cosr/(BnNorrr) or CPP-D vs. OP-1
Tesr-B 8.28 - PVRR Cosr/(BENenrr) or FOT-1 vs. OP-1
Test.e 8.29 - PVRR Cosr/(BeNEur) on CO2-l vs. OP-1
TaeLe 8.30 - PVRR Cosr/(BeNerrr) or NO-CO2 vs. OP-NT3..
Tesle 8.31 - PVRR Cosr/(BENenrr) on BP vs. OP-NT3
TesLp 8.32- PVRR Cosr/(BeNnrtr) or BarreRv vs. FS-GW4
....219
....221
....23r
....234
....244
....245
....246
....247
....248
....248
....249
....250
....250
....25t
......252
......253
.253
..............2s4
..............255
..........._..256
lx
PACIFICORP_20I7IRP TABLEOF CoNTENTS
Tesr.B 8.33 - PVRR Cosr/(BeNnrrr) or CAES vs. FS-GW4 .................257
Tesls 8.34 - PVRR Cosr/(Beuenrr) or WCA vs. FS-REP ...................258
TaeLe 8.35 - FOTs as e PnRceNTAGE oF Ner Prnr Lono ....................259
TesLe 8.36 - PVRR Cosr/(BeNeur) or WCA-RPS vs. FS-REP ...........260
Taet.e 9.1 -2017 IRP AcrroN Pr.aN...... ..............265
Tenrn 9.2 -2015IRP AcuoN PleN Srerus Upoern ..........270
Teue 9.3 -NeA.n-TERM exp LoNc-TERM Rrsouncn AcqursruoN ParHs .............277
Taer.B 9.4 - Corr,cARrsoN oF THE 20l7IRP PRerpRRro PoRrnolro wrrH rHE 2015 IRP Upoern
PoRrpolro ..................280
Teslr 9.5 -CoupARISoN oF THE 20l7IRP PRnrBRRno PoRrrolro wrrHTHE Fer,l2016 Busrxress
Pr.eN PoRrrolro ..............282
x
PACIFICORP-2OI7IRP TABLE oF CoNTENTS
INnpx or FTCURES
Frcuns 1.1 - Kev ElpupNrs or PecmrCoRp's IRP Pnocsss .............. .........................1
FIcuns 1.2 -Loto Fonrcesr CoupezusoN BETwEEN REceNr IRPs (BeroRE INcRr\4ENTAL
ENpRcy ErrrcrcNcv SevrNcs) ........................3
FIcuRe 1.3 - CorvpARISoN or TorLl ENpRcy EnrtcrBNcy SevNcs BETwEEN rne 2017 IRP
PRmeRRro PoRrrolro AND THE 2015 IRP PRerpnREo Ponrnolro ......................4
Frcuns I .4 - CorvpARrsoN op Torel Dnrcr Loao CoNrRor- Capecny BETwEEN rHe 2017 IRP
PRsneRRpp PoRrnolro AND THE 2015 IRP PRerpRREo PoRrrolro ......................4
FIcune 1.5 - CoupARrsoN on Powpn Pprces eNo NeruRal Gls PRrcps nr REcpNr IRPs ...........5
FIcunn 1.6 - Corr,rpARrsoN op SuuueR Menxrr PuRcueses rNr REcrNr IRPs ............6
Frcunr 1.7 -2017IRP Pnerenneo PoRrrolro Coel UNrr RSTREMENTS ...................6
Frcune 1 .8 - CorrapARrsoN on Torel Nnw Narunel Ges Rpsouncps BETwEEN rnp 2017 IRP
PnprpRRso PoRrnolIo AND THE 2015 IRP PReneRReo PoRrrolro ......................7
Ftcunr 1.9 - Alwual Srerp RPS CovtpLIANCE Fonrcesr. .......................9
Ftcunr 1 . I 0 - CorweRrsoN or CO2 EvrssroN FoRrcesrs BETWEEN rHe 2017 IRP Pnrpennpo
PoRrror.ro AND THE 2015 IRP PRsppRREo PoRrrolro ........10
Frcunr 1.1 1 - EcoNovrc Svsrnu DrspercH or Exsrnsc RrsouRcrs rNr REr-erroN To
MoNtrlv Loep........
Frcunr 3.1 - Heunv Hus Dav-Heep Ges Prucp HrsroRv..
FrcuRn 3.2 - U.S. Dny Nerunal Ges PRopucuoN ............
12
.......29
.......29
Frcunp 3.3 - Lownn 48 Srerns SHele Plevs.30
FIcunr 3.4 - Pr.eys AccouNuNG FoR At l Naruner. Ges PRooucuoN GRowrn 20ll -2014...30
Frcunp 3.5 - HeNnv Hus NYMEX Furunes...
FrcuRB 3.6 - ENpncv INasRr,RNcp MRRrsr ExpaNsroN
Frcune 4.1 - SecueNr D
Frcuns 4.2 - SEcurNr E.
FrcuRs 4.3 - SecN,ENr F............. .........64
Frcunn 4.4 - ENency G.q.rpwev TReNsvrrssroN ExpaNsroN PleN ..........71
Flcunp 5.1 - Pruvere GeNenenoN Mampr PeNErReuoN (MWAC),2017-2036 .....................85
Frcunp 5.2 - CoNrnacr Cepacrry rN THE 2017 SumapR Loao aNo RnsouRce Be1eNcp.........86
Frcuns 5.3 - DSM rN Cepacruv Loep aNo Rnsounce Ber-RNce (nroucrroN To r.oeo)............89
FrcuRs 5.4 - SuvnvrsR SvsrsN{ Cepecrrv PosruoN TnrNo.......
Frcunp 5.5 - WrNreR Svsrpu Cepecrrv PosruoN TnrNo.......
Frcunr 5.6 - Easr SuvuER Cepecrrv PostttoN TnpNo
FrcunB 5.7 - Wssr SuvrveR Cepecrrv PosrrroN TnpNo
Frcune 5.8 - Svsrpv AvrRace MoNrrrr-v ENeRcv PosrrroNs..
Frcune 6.1 - Wonro CaRsoN Srppl PrucrNc sv Tvpn
FrcuRe 6.2 - HrsroRrc CensoN SrBBr. Pnrcnrc
Frcuru 7.1 -PonrFolro EvaluerroN Srnps wrrHrN rnp IRP Pnocpss.
Ftcunp 7.2 - TnqrsMISSIoN Svsrerra Moopl Topor-ocv
Frcune 7.3 - PecrrConp Svsrsv Mess Cap A & Mess Cep B Assuuprrous........
Frcunp 7.4 - Pnrcs ScpNeruo Mopplnvc...
Frcunp 7.5 -Nolanrer. WHoLBser.p Er,BcrRICrry eNo Ne.ruRel Gas PnrcB SceNeruos ...
FrcuRr 7.6 - U.S.WECC CO2 EvrssroNs, Besp Narunal Ges PRrcns.......
Frcuns 7.7 - U.S.WECC CO2 EvrsstoNs, Low Nerunel Gas PRrcps
.32
.52
.63
.64
93
93
94
94
96
100
100
r44
t47
151
t52
t54
154
155
155FrcuRs 7.8 - U.S. WECC CO2 EvrssroNs, Hrcu NaruRer, Ges Pnrces......
xl
PACIFICORP-20I7 IRP TABLE oF CoNTENTS
Frcunr 7.9 - Sruulerep Axxu* Mn-C Er-scrRlcrry Mamer PRrces .................160
Frcunr 7.10 - Sruur,erpo ANNuer. Pelo Venop EI.ecrRrcrry MeRrer PRrces 160
FrcunB 7.lI - SnauLereo Amrrual WSSTSRNNATURAL Ges Manrrr Prucps.... ....161
FlcunB 7.I2 - Suraulerpo ANuuel EesreRNNeruRer, Ges Mnnrer PRrcBs.... .....161
Frcuns 7.13 - Slvrur.Rreo AxNulr- Ionso (GosueN) Loep ...................162
FrcunB 7.14 - SnauLerpo ANNuer. Uren Loeo
FIcune 7.15 - Snraur-arpo Axlruel
Ftcunp 7.16 - Stvur.Rreo AxNual
Frcune 7.17 - SruuLerep ANNuel
Frcuns 7.18 - Sruur-arep ANn{ueL
WvoNarNc Loeo........
OnpcoN/CALTFoRNTA Loep .
WnsHnicroN Loao
Svsrpv Loao........
r63
r63
164
164
165
Frcunn 7.19 - SrMur.arso ANNuel Hyono GeNeReuoN .....165
FrcuRn 7.20 - Loeo SpNsruvrry AssuupuoNs.......... ..........175
FtcuRn 7.21 - PRrvRrp GBNpRluoN SBNsruvlry AssuuprroNs 176
FIcURB 7.22 -NovrrNer- CO2 Prucp AssuupuoNs FoR rur CO2 SeNsnryrry.....
C uuuleuvp Cepec rry rHRouG g 203 6, RpcroNal H tzp. RsrpReNcp Cesp
Ftcune 8.2 - CUUuLATIVE Cepecrry rHRouGH 2036, RecroNer- Htzp, Cese 1 ...
FtcuRB 8.3 - CuvruLATrvE Capacrry rHRouGH 2036, RrcroNel Hlzz Cnse 2...
Ftcunp 8.4 - CuvuLATrvE Cepecrry rHRouGH 2036, RncroNal HezB CnsB 3...
Frcunn 8.5 - CuvuLATrvE Cap.q.crry rHRouGH 2036, RscloNer. Htzp. Cese 4...
177Ftcune 8.1-
.................... 1 8 1
.................... I 8l
.................... I 82
.................... I 82
.................... I 83
183
184
184
185
186
t87
Frcunp 8.6 - CuuuLATrvE Cepecrry rHRouGH 2036,RpcroNal Hrzp. Casp 5
8.7 - CuvuLATrvE Caplcrrv rHRouGH 2036,RscroNer. Htzp. Cesp 6.....
8.8 - Sysrpv OprurarzpnPVRR Cosrs nonRscloNer- Heze Cesns
8.9 - INcneASE rN Sysrpu OprnrarzeR PVRR Cosrs vs. RsrpRENcp Casp
8. 1 0 - RpcroNer. Hl.zB ScRrrBn Plors, Mass Cap B
8.1 1 - RporoNar. Htzn ScerrnR PLors, Mess Cep A.......
Ftcune 8.12- Rrsr-Aplusrep PVRRRelerrvE To rHE Lowssr Cosr RpcroNAL Hrze CesB 188
FrcuRe 8.13 - Srocuesrrc MBaN AvBRecp AxNuel ENS RrurrvE To run Besr PnRroRurNcCas8......... ................189
FrcuRp 8.14 - UpppR-rlu- AvBnacp ANuuar- ENS RuarrvE To rHe Besr PeRroRvrNc
CasB.190
Ftcune
FrcuRe
Frcuns
Frcunp
Frcunp
FrcuRp
FrcuRp
Frcune
Frcune
FrcuRE
FrcuRl
FrcuRp
8.15
8.16
8.t7
8.18
8.r9
8.20
8.2t
- CO2 EurssroNs RsI-errve ro rHE Besr PBToRMTNG RpcroNar- Hlzo Case
- Reuce ru CO2 Suepow PRrcES, Mass Cap B.......
- RaNce rN CO2 Sueoow PRrces, Mess Cep A.......
- Curr,ruleuve INcReesr/(DEcneese) tN RH-2e R-esouRcps vs. RH-2
- Cul,rulerrve INcReese/(Decnrnse) rN RH-5n RpsouRcps vs. RH-5
- Cuvulerrve Cepecrry rHRouGu2036, Cone Casp OP-NT3.............
- Cuuur-auvB CRpacrry rHRoucu2036, Conr Cese FR-1
...191
...t92
...t92
...t94
...195
...197
...198
...198
FrcuRe 8.23 - Cuvulerrvp Capacrry rHRouGg2036, Cone Case RE-1A........................r99
Ftcuns 8.24 - Cuvularrve Cepecrry rHRouGg2036, Cons Cese RE-1B........199
Frcunp 8.22- Cuvulerrvn Cepacrry rHRouGu2036, Conp Cesp FR-2
FrcuRE 8.25 - CurvrulRrrve Cepecny rHRouGH 2036, Cone Casp RE-1c.................
FrcuRp 8.26- CuuularrvB Clpncrry rHRoucg2036, Conr Cese RE-2
......200
......200
FIcuRe 8.27 - Cuvtur-Ruve Cepecrry rHRouGH 2036, Conp Cese DLC-1 .........201
FIcunr 8.28 - Cuuuleuvn Srrus RrNEwesLr Cepecrry, CoRE Cnsp RE-le (OnrcoN RPS)202
FrcuRr 8.29 - Cuvur-Rrrve Srrus ReNewnst.p C,qplcrrv, CoRr Cesp RE-ln (WasunrcToN
RPS)......... ................202
FrcuRp 8.30 - Cuuularvp Snus RpNewasLB Capacrrv, CoRE Ce.sp RE-1c (OR+WA
CotvtsNeo)....................202
xll
PACIFICORP - 2OI7 IRP TABLE OF CONTENTS
FrcuRB
FrcuRe
FrcuRp
FrcuRp
FrcuRn
FrcuRp
8.31 - Curvruleuvp Snus RrNpwesr-s Ceplctrv, CoRe Cesp RE-2 (OnecoN)
8.32- Sysrnu OprruzeR PVRR Cosrs ron Cons Ceses.......
8.33 - ENeRcv Garewev TRaNsulssIoN ExpnNsloN Mep
8.34 - INcnease/(Decneesr) rNI REsouncps, OP-REP vs. OP-NT3 ...................,
8.35 - INcneesei(Decneese) rNI REsounces, GWl vs. OP-NT3 ...............
8.36 - INcneese/(Decneese) nr REsouRcBs, GW2 vs. OP-NT3 ...............
203
203
204
206
207
207
208
209
2t0
FrcuRE 8.37 - INcnrese/(Drcnnasr) nr REsouRcEs, GW3 vs. OP-NT3
FrcuRe 8.38 - INcnease/(Decnnnse) rN RssouRcps, GW4 vs. OP-NT3 ...............
FrcuRe 8.39 - INcnrese/(Dncnrlse) nr REsouRcps, OP-GW4 vs. OP-NT3....
FrcuRs 8.40 - Svsrpu OprnatzeR PVRR Cosrs roR Er.tcrsr.e Cone CRsns eNo
SeNstrrvltres.
FrcuRp 8.41 - Svsrev OprrvrzpR PVRR CruNcp FRoM OP-REP....
FrcuRp 8.42- EI,rcrsLe PoRrrolto Sclrren PLots, Mass Cap B
Frcune 8.43 - Er.rcrst-e PoRrrolto ScarrpR PLots, Mnss Cnp A ........213
FrcuRs 8.44 - Rrsr-Aorusrso PVRR RpI.errvs ro rHE Besr PpnroRMrNG Cese ......... ...........214
FrcuRe 8.45 - Srocuesuc MraN AvpRacp AwNuer, ENS Rpr.auvE To rHe Besr PpnroRvnqc
Cese......... ................215
Flcunp 8.46 - UpppR-rau- AvsRAcs Ar.trrueI. ENS Rrr.errvE To rse BEsr PeRnoRMnrcCesE......... ................216
FlcuRp 8.47 - CO2 EvrssroNs Rer.euvE To run Besr PeRronvmc Casr...... ........2I7
FrcuRe 8.48 - Cuuuleuvr Capactry rHRouGg2036, FrNIar- ScRseNrNc Cese FS-REP..... ....222
FlcuRp 8.49 - Cuuulauvp CRpecrry rHRoucg2036, Fn{eL ScReeNmc Case FS-GW4 .......223
FrcuRe 8.50 - Cuuur.errvs Caplcttv rHRouGH 2036, Fnqal ScRppNrNIc Cesp FS-RIc .........223
FrcuRe 8.51 - Cuvrulerrvp Cepacrrv rHRoucH 2036, FNIL ScRreNrNrc Cnse FS-R2 ...........224
FrcuRe 8.52 - Sysrpu Oprwrznn PVRR Cosrs roR Fnrat- Cases....... ...................224
Frcune 8.53 - SysrEv OprrvrzpR PVRR CsaNcB FRoM FS-REP roR Fmar- CasBs....... .....-....225
FrcuRp 8.54 - FNaL PoRrrolto ScerrpR PLots, Mess Cep B .............226
FrcunB 8.55 - Fn{aL Ponrpolro ScerrER PLors, Mess Cap A .............226
FlcuRp 8.56 - fusr-Aorusrep PVRR RBlarrvs ro rHE BEsr PpnroRMrNG Cesp......... ...........227
Frcunp 8.57 - SrocHesrrc MBaN AvpRecp AxNuel ENS RslarrvE To rne Bpsr PpnronvrNcCnsp......... ..........-.....228
FrcuRe 8.58 - UppeR-rarl AvpRecB Alwual ENS Rsr-arrvE To rHn BBsr PpRpoRvnvcCes8......... ................229
FrcuRe 8.59 - CO2 EvrssroNs RSLaTIVE To Bpsr PenToRMING Cess ........ ............230
Frcuns 8.60 - 2020 Fonlc,q.sr CO2 EMrssroNS vERSUS 1990 Esrruerpo EvrssroN Lpvpr.s.....231
FrcuRe 8.61 - CovrpeRrsoN or ResouRCES rN rHp Er-rcrelp RpsouRcp PoRrrolros ...............232
FrcuRp 8.62- CneNce IN THE Culaur-arrvp PVRRRELATIvE ro FS-GW4 ...............................233
Frcune 8.63 -2017IRP PRepBRRro PoRrror-ro - Cuuulerrve RsNewnsle RESoURCES ........235
Frcune 8.64 - ColapeRrsoN or TotaL ENpRcv ErprcrpNcv SavrNcs BETwEEN rHp 2017 IRP
PRerpRReo Ponrpolro AND THE 2015 IRP PRprpRReo Ponrrolro .......-..........236
FrcuRp 8.65 - CoupanrsoN op Torll DrnBcr Loao CoNrnol Cepacrrv BETwEEN rlg.p.20l7
IRP PnrneRReo PoRrFoLro AND rHE 2015IRP PRrreRReo PoRrrolro ...........236
FrcuRe 8.66 - CovpeRrsoN or SuvrrapR Menrpr PuRcHRsps AMoNG RsceNr IRPs ......... ......237
FrcuRs 8.67 - 2017 IRP PRprrRnro PoRrpolto Coal UNtr RerrneMENrs .............237
Frcune 8.68 - CouperusoN or Torer.NpwNeruRel Ges RBsouncps BETwEEN rup 2017 IRP
PRsneRREo PoRrrolto AND rHE 2015IRP PRBnERReo PoRrrolro ..................238
FtcuRe 8.69 - MesrNc PecrrrConp's CnpAcrrv Nppos wnu PnpnpRRso PoRrFoLro
.......239
........2rt
........2t1
........2t2
RrsouRces
xlll
PACIFICoRP - 20I7 IRP TABLE oF CoNrENrs
Frcunr 8.70 -PnoJECTED ENeRcv Mrx wnn PRprpRRro PoRrpor.ro ResouRcss ....................240
Flcuns 8.71 -PnoJECTED Cepecruv Mx wrru PRnreRRep Ponrrolro Rrsouncps .................240
Frcune 8.72- Arwuel Srern RPS CoUpLTANCE Fonecesr. .................242
FrcuRp 8.73 - CouperusoN or CO2 EurssroN FoReclsrs BETwEEN rrrc,20l7IRP PnBrBnnBo
PoRrrolro AND THE 2015 IRP PRereRnBo PoRrror.ro ...................243
Frcune 8.74- INcnrese/(Decnrese) rN Rnsounces, LD-l vs. OP-l ....248
Frcune 8.75 - INcnresr/(Decnrnse) nr REsouRcBs, LD-2 vs. OP-l ....249
Frcunp 8.76- INcnrase/(Decnease) nq Resounces, LD-3 vs. OP-l ....249
Frcune 8.77 - INcnnese/(Decnrese) rN ResouncEs, PG-l vs. OP-l .....250
FrcuRe 8.78 - INcnresr/(Decnresn) rN RBsouRcss, PG-2 vs. OP-l .....251
Frcune 8.79 - INcnresr/(Dncnresn) rN RssouRcBs, CPP-C vs. OP-1.....
FrcuRp 8.80 - INcnnesr/(DEcnen se) nr REsounces, CPP-D vs. OP-l .....
FrcuRs 8.81-INcnresr/(Decneese) ru Rnsounces, FOT-I vs. OP-1
Frcunp 8.82 - INcnrese/(Decneese) n't REsounces, CO2-1 vs. OP-l .....
Frcunp 8.83 -INcnease/(DecnEese) rN Rrsounces,NO-CO2 vs. OP-NT3
Frcune 8.84-INcneese/(Decnresr) rN RBsouRcBs, BP vs. OP-NT3...............
Frcunp 8.85 - INcnease/(Decneese) rNr REsounces, BArreRy vs. FS-GW4
FrcunB 8.86 - INcnrase/(Decneese) nr REsouRces, CAES vs. FS-GW4
Frcunp 8.87 - Cuuuu.uvs Cepecrry rHRouGg2036, Eesr/Wesr Splrr Cesn - WCA.........
Frcune 8.88 - Curvruleuve Cepecrry rHRoucg2036, Eesr/Wrsr Splrr RPS Case - WCA-
RPS..........
.25r
252
253
254
254
255
257
258
259
260
xlv
PecrrConp-20l7IRP CgeprpR 1 - Execurtvs SuN,rMARv
CrmprER I -ExpcurIVE SUMMARY
PacifiCorp's 2017 Integrated Resource Plan (IRP) presents the company's plans to provide
reliable and reasonably priced service to its customers. The analysis supporting this plan helps
PacifiCorp, its customers, and its regulators understand the effect of both near-term and long-
term resource decisions on customer bills, the reliability of electric service PacifiCorp customers
receive, and changes to emissions from the generation sources used to serve customers. In the
2017 IRP, PacifiCorp presents a cost-conscious plan to transition to a cleaner energy future with
near-term investments in both existing and new renewable resources, new transmission
infrastructure, and energy effi ciency programs.
The primary objective of the IRP is to identifu the best mix of resources to serve customers in the
future. The best mix of resources is identified through analysis that measures cost and risk. The
least-cost, least-risk resource portfolio--defined as the "preferred portfolio"-is the portfolio
that can be delivered through specific action items at a reasonable cost and with manageable
risks, while considering customer demand for clean energy and ensuring compliance with state
and federal regulatory obligations.
The full planning process is completed every two years, with a review and update completed in
the off years. Consequently, these plans, particularly the longer-range elements of the plans, can
and do change over time. PacifiCorp's 2017 IRP was developed through an open and public
process, with input from an active and diverse group of stakeholders, including customer
advocacy groups, regulatory staff, and other interested parties. The public input process began
with the first public input meeting in June 2016. Over the subsequent nine months, PacifiCorp
met with stakeholders in five states and hosted seven public input meetings. Through this
process, PacifiCorp received valuable input from its stakeholders and presented findings from a
broad range of studies and technical analyses that shaped and support the 2017 IRP.
As depicted in Figure 1.1, PacifiCorp's 2017 IRP was developed by working through five
fundamental planning steps. This includes preparing a load and resource balance, which
compares a forecast of load relative to existing resources. In the next planning step, PacifiCorp
develops a range of different resource portfolios that meet projected deficiencies in the load and
resource balance, each uniquely characterized by the type, timing, and location of new resources
in PacifiCorp's system. PacifiCorp then analyzes these different resource portfolios to measure
the comparative cost, risk, reliability and emission levels. This resource portfolio analysis
informs selection of a preferred portfolio and the associated resource action plan. Throughout
this process, PacifiCorp considers a wide range of factors to develop key planning assumptions
and to identifr key planning uncertainties, with input from its stakeholder group. Supplemental
studies are also done to produce specific modeling assumptions.
Action
Planl),ril rrllrr.
lii.rrLrtt.I ,,,,1.1
l\! ,' I
ll,, ,r rt
Figure 1.1 - Key Elements of PacifiCorp's IRP Process
I
PacmrCoRp - 2017 IRP Cseprrn 1 -Execuuvp Suvruenv
Preferred Po rtfolio Highlights
The 2017 IRP preferred portfolio reflects a cost-conscious transition to a cleaner energy future.
Table 1.1 shows that PacifiCorp's resource needs will be met with new renewable resources,
demand side management (DSM) resources, and short-term firm market purchases (labeled as
front-office transactions or FOTs) through 2028. Over the 2}-year planning horizon, the
preferred portfolio includes I,959 MW of new wind resources, 905 MW of upgraded
("repowered") wind resources, 1,040 MW of new solar resources, 2,077 MW of incremental
energy efficiency resources, and 365 MW of new direct load control capacity.
Notably, PacifiCorp's analysis demonstrates that-by 2020 and with all-in economic savings for
customers-the company can add 905 MW of repowered wind resources, 1,100 MW of new
wind resources, and a new 140-mile 500 kV transmission line in Wyoming to access the new
wind resources and relieve congestion for existing capacity. The preferred portfolio also assumes
existing owned coal capacity will be reduced by 3,650 MW through the end of 2036 (including
assumed coal retirements at the end of 2036 not shown below). The first new natural gas
resource is added in 2029, one year later when compared to PacifiCorp's 2015 IRP preferred
portfolio, subject to technology and IRP reassessments over the next decade.
Table l.l -2017IRP Preferred Portfolio Summary (Nameplate MW)
x Note: Energy efficiency resource capacity reflects projected maximum annual hourly energy savings, which is
similar to a nameplate rating for a supply-side resource. FOTs are short-term firm market purchases delivered only
in the year shown. Reductions in existing coal and nafural.gas capacity are shown in the year after the assumed year-
end retirement date (909 MW of existing coal capacity is assumed to retire year-end 2036, which would be reflected
beginning 2037). Repowered wind capacity reports the amount of existing wind capacity assumed to be repowered
in the preferred portfolio.
New Renewable Resources and Transmission
The 2017 IRP preferred portfolio advances PacifiCorp's commitment to low-cost clean energy
with plans to add 1,100 MW of new Wyoming wind resources by the end of 2020. These new
zero-emission wind facilities will connect to a new 140-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). This time-sensitive project
requires that the new wind and transmission assets achieve commercial operation by the end of
2020 to fully achieve the benefits of federal wind production tax credits (PTCs). In addition to
providing significant economic benefits for PacifiCorp's customers, the wind and transmission
project will provide extraordinary economic development benefits to the state of Wyoming.
Beyond 2020, the preferred portfolio includes an additional 859 MW of new wind-85 MW of
Wyoming wind coming online in 2031, and 774MW of Idaho wind in 2036. New solar resource
2
New Resouces
S,mmer FOT 500 521 878 807 7E)916 844 885 | _042 978 1.040 r.575 t-5't5 t.566 1.575 1.575 r.575 1.575 r.575 1.539 nla
Winter FCrT 281 112 271 ']0?3tg r08 106 241 .]48 351 )9'7 4t?551 516 4m 451 417 47'7 4',79
DSM - Energ Efficrency 154 128 lI \23 il4 Il8 t12 109 t02 96 95 83 75 65 6l 63 2-01'l
DSM - I-oad Contol 0 0 0 0 0 0 0 0 0 0 0 r9i 110 s l l 3 4 l l?365
0 0 0 0 1.t00 0 0 0 0 0 0 0 0 0 85 0 0 0 0 1.959
Solar 0 0 0 0 0 0 0 0 0 o 0 ll 9'1 0 I t8 )1'7 ))6 48 291 I]I04O
o 0 0 0 0 0 0 0 0 0 0 0 30 0 0 0 0 0 0 0
Natwal Cas 0 0 0 0 0 0 0 0 0 0 0 0 200 416 0 0 677 0 0 0 titl
Existiry Resouces
Reduced Cml Caoaciru 0 0 (280)0 (387)0 0 0 0 r82\0 (162\r354)rt57\r78)0 (i59)0 (42\0 (?741\
Redrrced Ga< Ceneci*0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (358)0 0 0 (358)
Remwered Wind Caoacitu 0 0 194 111 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 g0s
2017 20lE 2019 2020 2O2l 2022 2023 2021 2025 1026 2021 2128 2029 2030 20Jl 2032 2033 2031 2035 2036 Total
PACIFICoRP-20I7IRP CHAPTER I -EXECUTIVE SUNffVIARY
additions totaling 1,040 MW come on-line over the 2028 to 2036 timeframe. Approximately
77 percerf. of the new solar is located in Utah (beginning 2031), and the remaining 23 percent is
located on the west side of PacifiCorp's system (beginning 2028).
Wind Repowering
PacifiCorp executed wind-turbine-generator (WTG) equipment purchases in December 2016 to
preserve the option to repower existing wind generation facilities and obtain PTC benefits for
customers. Analysis performed in the 2017 IRP supports repowering 905 MW of existing wind
resources by the end of 2020 and demonstrates that this exciting project will save customers
hundreds of millions of dollars. The scope of the repowering project involves installing new
nacelles and longer blades. With the installation of modern technology and improved control
systems, the repowered wind facilities will produce more zero-emission energy for a longer
period of time at reduced operating costs. Existing towers and foundations will remain in place,
resulting in minimal environmental impact and permitting requirements.
Demand Side Management
PacifiCorp evaluates new DSM opportunities, which includes both energy efficiency and direct
load control programs, as a resource that competes with traditional new generation and wholesale
power market purchases when developing resource portfolios for the IRP. Consequently, the load
forecast used as an input to the IRP does not reflect any incremental investment in new energy
efficiency programs; rather, the load forecast is reduced by the selected additions of energy
efficiency resoruces in the IRP. Figure 1.2 shows that PacifiCorp's load forecast before
incremental energy efficiency savings has decreased relative to projected loads used in the 2015
IRP and 2015 IRP Update. On average, forecasted system load is down 5.3 percent and
forecasted coincident system peak is down 3.5 percent when compared to the 2015 IRP Update.
Through the planning horizon, the average annual growth rate, before accounting for incremental
energy efficiency improvements, is 0.94 percent for load and 0.86 percent for peak. Changes to
PacifiCorp's load forecast are driven by reduced industrial class loads, due in large part to lower
commodity prices, and continued gains in energy conservation as evidenced by a drop in the
average use per customer.
Figure 1.2 -Load Forecast Comparison between Recent IRPs (Before Incremental Energy
Efficiency Savings)
80,000
70,000
60,000
s0,000
40,000
30,000
20,000
10,000
0
Forecasted Annual System Load
(GWh)
r6oo:d6$h9r@6o-N6shQi:-ddNNNddNNN6666-66ooooooooooooooooooooNddNNNdNNNNNNdNNNNNN
-2017
IRI' *..-2015 IRP Update +2015 IRP
Forecasted Annual System Coincident Peak
(Ir,rw)
-20f
7lRP "t> 2Ol5IRP Update -.+-2015 tRP
14,000
12,000
r0,000
8,000
6,000
4,000
2,000
0 f@OO-No$h€r€6Ord6$69:-:NNNNNNNNNN6OO6-66OOOOOOOOOOOOOOOOOOOONNNNNNNNNddNNNNNdNNN
J
PecrnConp- 20l7IRP CnaprpR I -ExECUTrve SuuuaRy
DSM resources continue to play a key role in PacifiCorp's resource mix. Over the first ten years
of the planning horizon, accumulated acquisition of new incremental energy efficiency resources
meets 88 percent of forecasted load growth from 2017 through 2026 (tp from 86 percent in the
2015 IRP). Figure 1.3 compares total energy efficiency savings by state in the 2017 IRP
preferred portfolio relative to the 2015 IRP preferred portfolio. Decreased selection of energy
efficiency resources relative to the 2015 IRP is driven by reduced loads and reduced costs for
wholesale market power purchases and renewable resource alternatives.
Figure 1.3 - Comparison of Total Enerry Efliciency Savings between the 2017 IRP
Preferred Portfolio and the 2015IRP Preferred Portfolio
In addition to continued investment in energy efficiency programs, the preferred portfolio
identifies an increasing role for direct load control programs with total capacity reaching 365
MW by the end of the planning period. Figure 1.4 compares total incremental capacity of direct
load control program capacity by state in the 2017 IRP preferred portfolio relative to the 2015
IRP prefened portfolio. The significant increase in direct load control capacity and expansion of
state programs is coincident with assumed coal unit retirements, signaling the importance of
these capacity-based programs in PacifiCorp's transitioning resource mix.
Figure 1.4 - Comparison of Total Direct Load Control Capacity between the 2017 IRP
Preferred Portfolio and the 2015 IRP Preferred Portfolio
trCA
6wA
toR
OID
!wY
rUT
400
350
300
250
4 200z
150
100
50
0 r € O\ O i c.l o $ h \O r € O\ O - e{ m $ ni - - (\ c.l a.l C.l N a.l a.l a.l c{ c{ o o 6 o o ooooooooooooooooooooc{ e{ e{ c.l c{ N e.l N e{ c.l c.l c.l N N e{ N N c.l N
r € O\ O i e{ m r+ n € r 6 O\ O - N 6 + h \Or - - N a.l a.l a.l N c.l N (\ N N m o o o m m moooooooooooooooooooocl et ei e{ c.t c{ e{ a.t N N a.l a.l N N a.l N a.t N N c.l
2017 IRP Prefened Portfolio2015 IRP Prefened Portfolio
HffiE
IIIEIITEIIIIIil
-ITTIITIITIII
BCA
BWA
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trID
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1,400
1,200
1,000
800
600
400
200
0
B2d
r 6 O\ O = N m $ h \O r € O\ O i N o $ hr - - c{ c{ N N a{ N c.l N d d o o m o o o
N N e{ N Gl N N a.l N e{ a{ c.l N N a.l N c.l N N
€ o\ o i a.t 6 $ h \o r € o\ o r c{ m <f h \or - c.l N c{ N e{ N N N d N o o m m o 6 6oooooooooooooooooooc.l c.l N N cl e{ 6l a.l c{ e{ a.l N c.l a.l N N a.l N e.l
r
2017 IRP Preferred Portfolio2015 IRP Preferred Portfolio
-aE-rI-rl -II-I
r":
4
P.q,crrrCoRP-20l7IRP CHAPTER I -Exscurrvs SuvnuaRv
Wholesale Power Market Purchases
Figure 1.5 shows that base case forecasted wholesale power prices and natural gas prices used in
the 2017 IRP are significantly lower than the base case market prices used in the 2015 IRP and
are more closely aligned with those used in PacifiCorp's 2015 IRP Update. Over the last couple
of IRP cycles, growth in natural gas supplies, primarily from prolific shale plays in North
America, have continued to outpace expectations. With continued declines in forward natural gas
prices and on-going reductions in regional electric load growth expectations, forward power
prices have also declined significantly since the 2015 IRP.
Figure 1.5 - Comparison of Power Prices and Natural Gas Prices in Recent IRPs
Henry Hub Natural Gas Prices
($/IvIMBtu)
$9
$8
S7
$6
U)
$4
s3
$2
$l
$-r€6
Ndd
OiN-<nENNNNNdNooooooaNNNNdNN
r€6O-No$h€aaatlaara!!!39AQQAAOOOONNNNdNNNNN
o - 20 I 5 IRP Update (Dec 20 I 5)
-2017
rlu (oct 2016)
.+2015 IRP (Sep 2014)
Average of MidC/Palo Verde Flat Power Prices
($/t\{Wh)
$80
$70
S60
ss0
s40
$30
$20
$10
$-f€OO:Not69f€OO*N-$h€**iNNNdNNNNNNOO66O6O
NNNNNNdNNNdNNNNdNNNd
-20l7IRI'
(Oct 2016)
<-zols IRP (Sep 20la)
.. 2015 IRP Update (Dec 2015)
Figure 1.6 compares wholesale market firm purchases from the 2017 IRP preferred portfolio to
the market purchases included in the preferred portfolio of recent IRPs. While market conditions
for firm wholesale power purchases are favorable, reduced loads and continued investment in
energy efficiency programs reduce the need for wholesale power purchases through 2027 relative
to the 2015 IRP Update. Over this period, average annual wholesale power purchases are down
by 27 percent relative to the 2015 IRP Update and are on par with wholesale power purchases
projected in the 2015 IRP. Longer-term wholesale power purchases increase coincident with
assumed coal unit retirements. In this 2017 IRP, PacifiCorp evaluated regional resource
adequacy and determined that its wholesale power purchase limits are reasonable. Pacif,rCorp
will, however, continue to monitor potential shortfalls in regional supply through its on-going
planning process.
5
PACIFICoRP-20I7IRP CHAPTER I -EXECI.-]-TIVE SUMMARY
Figure 1.6 - Comparison of Summer Market Purchases in Recent IRPs
&6lo
o
c
F
B2
2,000
1,500
1,000
500
0
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 203t 2032 2033 2034 203s 2036
l20l7IRP 82015 IRP Update l2015IRP
Existing Coal Resources
Supported by analysis of potential Regional Haze compliance alternatives, the 2017 IRP
preferred portfolio does not include any incremental selective catalytic reduction (SCR)
equipment. Avoiding installation of this equipment will save customers hundreds of millions of
dollars and retain compliance-planning flexibility associated with the Clean Power Plan or other
potential state and federal environmental policies. As in past IRPs, the 2017 IRP studies a range
of Regional Haze compliance scenarios, reflecting potential bookend alternatives that consider
early retirement outcomes as a means to avoid installation of expensive SCR equipment. The
individual unit-specific outcomes assumed in the 2017 IRP preferred portfolio will ultimately be
determined by on-going rulemaking; litigation results; and future negotiations with state and
federal agencies, partner plant owners, and other vested stakeholders. Consequently, individual
unit retirements reflected in the preferred portfolio, while reasonable for planning pu{poses, are
not firm commitments for early unit closures. Figure 1.7 summarizes coal unit retirements
assumed in the preferred portfolio. By the end of the planning horizon, PacifiCorp assumes 3,650
MW of existing coal capacity will be retired.
Figure 1.7 -2017IRP Preferred Portfolio Coal Unit Retirements
2
c
c(J
c,
(J
4,000
3,500
3,000
2,500
2,000
1,s00
1,000
500
0 rI
2017 2018 2019 2020 2021 2022 2023 2024 202s 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037
tNaughton(WY) lCholla(AZ) BCraig(CO) lDaveJohnston(WY) lJimBridger(WY) oHayden(CO) tHuntington(UT)
*Note: Retired capacity is reported in the frst year in which the unit is no longer available to meet summer
coincident peak load.
Reflecting an updated operating permit from the state of Wyoming, PacifiCorp assumes
Naughton Unit 3 retires at the end of 2018-one year later than in the 2015 IRP Update.
6
PecmrConp-2017IRP CHAPTER I -Expcurrvr Sulriuanv
PacifiCorp will continue to review emerging technologies, re-assess traditional gas conversion
technologies and costs, and consider other potential altematives that could be applied to
Naughton Unit 3 to allow continued operation beyond year-end 2018 if proven to be cost
effective for customers. PacifiCorp's analysis also assumes Cholla Unit 4 retires at the end of
2020. This early closure assumption was considered in PacifiCorp's RegionalHaze compliance
analysis to account for changes in market conditions, characteized by reduced loads and
wholesale power prices. As with Naughton Unit 3, PacifiCorp will continue to analyze potential
early-closure scenarios for Cholla Unit 4 as part of its on-going planning process. Longer term,
the preferred portfolio reflects an early retirement of Craig Unit I at the end of 2025, Jim Bridger
Unit 1 at the end of 2028, and Jim Bridger Untt 2 at the end of 2032. Assumed end-of-life
retirements include four units at the Dave Johnston plant at the end of 2027, Naughton Units 1
and 2 at the end of 2029, Hayden at the end of 2030, Craig Unit 2 at the end of 2034, and two
units at the Huntington plant at the end of 2036.
Natural Gas Resources
Figure 1.8 compares total new natural-gas-fired resource capacity in the 2017 IRP preferred
portfolio relative to the 2015 IRP preferred portfolio. The first natural gas resource, a 200 MW
frame simple cycle combustion turbine (SCCT), is added to the portfolio in2029-one year later
than the first natural gas resource in the 2015 IRP. The first combined combustion turbine
(CCCT), a 436 MW G-class 1x1, is added to the system in 2030-two years later than the first
CCCT in the 2015 IRP. In aggregate, t}e 2017 IRP preferred portfolio includes 1,313 MW of
new natural-gas-fired capacity, a reduction of 1,540 MW of natural gas resources relative to the
2015 IRP prefened portfolio. Reduced loads, on-going investment in energy efficiency
programs, and increased renewables reduce the need for new natural gas resources in the 2017
IRP. Recognizing the long time horizon before the first natural gas plant is added, PacifiCorp
will continue to evaluate potential long-term supply alternatives, including the potential
penetration ofenergy storage, through its on-going resource planning over the next decade.
Figure 1.8 - Comparison of Total New Natural Gas Resources between the 2017 IRP
Preferred Portfolio and the 2015IRP Preferred Portfolio
3,000
2,500
2,000
a 1,5002
1,000
500
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Preferred Portfolio
ICCCT EFrame SCCT
2017 IRP Preferred Portfolio
Renewable Portfolio Standards
Figure 1.9 shows PacifiCorp's renewable portfolio standard (RPS) compliance forecast for
California, Oregon, and Washington after accounting for the wind repowering project and new
7
PecrprConp-20l7IRP CTTapTSR I -EXECUTIVE SUMMARY
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 RPS
targets in PacifiCorp's western states.
Oregon RPS compliance is achieved through 2034 wfih the addition of repowered wind, new
renewable resources and transmission in the 2017 IRP preferred portfolio. A small increment of
annual purchases of unbundled renewable energy credits (REC), labeled "Unbundled
Surrendered" in Figure 1.9 below, beginning at under 160 thousand RECs in 2018, is required to
achieve Oregon RPS compliance through 2036. The California RPS compliance position is also
improved by the addition of repowered wind, new renewable resources and transmission in the
2017 IRP preferred portfolio and similarly requires a small amount of unbundled REC purchases
under 150 thousand RECs per year to achieve compliance through the planning horizon.
Washington RPS compliance is achieved with the benefit of the repowered wind assets located in
the west side, Marengo and Leaning Juniper, new renewable resources added to the west side
beginning 2028, and unbundled REC purchases under 200 thousand RECs per year. Under
current allocation mechanisms, Washington customers do not benefit from the repowered wind
and new renewable resources added to the east side of PacifiCorp's system. While not shown in
Figure 1.9, PacifiCorp 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, new renewable resources and transmission in the
2017 IRP preferred portfolio.
8
PacmrConp - 2017 IRP CHeprsn I -ExECUTrvp Surr,rutenv
.r2(J
E]tl.
01
6!o
tr
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
RPS
,d$"-)."d9".r""d|r{Pr$.r$nS""rtr$rs,.ndP.r$tnS"de"d}rs"rdirs,'
ESESSlUnbundled Strrendered IBundled Surrendered
NtUnbundled Bank Surrendered rBundled Bank SurrenderedIShortfall NlYear-end Unbundled Bank Balance
tttt tttttltl
0r)
clo
E
Er
oQ
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California RPS400
300
200
100
0
,**d;Ei"*#'$"sr"-{F"*'S'$ofotl*"t"']"ps"s""si'"s''
N Unbundled Bank SurrenderedIShortfall
I Bundled Bank Surrendered
n<ta Year-end Unbundled Bank Balance
800
600
400
200
N Unbundled Bank Surrendered
rShortfall
RPS
I Bundled Bank Surrendered
ESSN Year-end Unbundled Bank Balance
tE
an
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rrlil 0
"**:d,',*;f,#,s "$,{F
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lrlrllllllllllllllllllllIlll
Figure 1.9 - Annual State RPS Compliance Forecast
Carbon Dioxide Emissions
The 2017 IRP preferred portfolio reflects PacifiCorp's on-going efforts to provide cost-effective
clean-energy solutions for our customers and accordingly reflects a continued trajectory of
declining carbon dioxide (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 (EIM), which reduces customer costs and maximizes use of clean
9
PecrrCorp - 2017IF.P CH.cPTSR I -ExECLrnvs SUI\,flIARY
energy; PacifiCorp's on-going expansion of renewable resources and transmission; and Regional
Haze compliance that capitalizes on flexibility. Figure l.l0 compares projected annual COz
emissions between the20lT IRP and 2015 IRP preferred portfolios. Over the first 10 years of the
planning horizon, average annual COz emissions are down by over 10.5 million tons (21 percent)
relative to the 2015 IRP. By the end of the planning horizon, system COz emissions are projected
to fall from 43.8 million tons in 2017 to 33.1 million tons in2036-a24.5 percentreduction.
Figure 1.10 - Comparison of COz Emission f,'orecasts between the 2017 IRP Preferred
Portfolio and the 2015IRP Preferred Portfolio
60
50
N
8oo0
€rot
Fzo2 lll II0
0
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
I2OIT IRP I2OI5IRP
A key element of PacifiCorp's IRP process is to assess its load and resource balance over the
2O-year planning horizon. The load and resource balance relies on the ability for specific types of
resources to meet our forecasted coincident system peak load while accounting for reserve
requirements, which ensures reliable electric service for PacifiCorp customers. In developing the
resource plan, PacifiCorp applies a 13 percent planning reserve margin to account for near-term
and longer-term planning uncertainties.
Capacity Balance
Table 1.2 shows PacifrCorp's summer capacity position from2017 through 2026, with coal unit
retirement assumptions and incremental energy efficiency savings from the 2017 IRP preferred
portfolio before adding any incremental new generating resources. With continued load growth
and assumed coal unit retirements, summer margins drop over time, but remain higher than the
13 percent target planning margin throughout the first 10 years of the planning horizon.
l0
PACIFICORP _ 2OI7 IRP CHAPTER I -EXECUTIVE SUMMARY
Table 1.2 - PacifiCorp l0-Year Summer Capacity Position Forecast (M!Y)
s)\lttn (suDtfltr)lr)t7 l0lli l0re l0l0 20lt lr)l: l02l l{r2l :r)15 :026
Eristing Resource Capacity C,ontribution
Available FOT Capacily Contribution
10494 10,109 10,194 t0,069
1,670 1,670 1,670 1,670
10493
1,670
9880
1,670
10,062
ts70
10,043
1,670
9,E20
t,670
9,912
1,670
Total kisting Resource + FOTs
SystemPosition with Available FOTs 1,142 1,129
Reserve Margin with Available FOTs 25.tr/o 24.8o/o
12,162 12,163 11,778 11,864 11,738 11,650 11,731 1t,712 11,589 11,581
obligation Net of Incremental DSM 9,730 9,'143 9,743 9,758 9,793 9,U4 9,829 9,850 9,892 9,831
13% Planning Resene Margin 1290 1292 1,292 1294 1,298 1,302 1,303 1,306 1,311 1,303
Obligation+13%PlanningResewes 11,020 11,035 t1,035 11,052 11992 11,126 ll,l32 ll,156 11203 11,135
59s24743812 &7
21.60/o 9.q/.18.6Y. l9.4%o 18.ry/,
556 385 447
17.2y" t'1.80/o20_y/o
In response to stakeholder feedback from the 2015 IRP planning cycle, PacifiCorp developed a
winter load and resource balance for the 2017 IRP. Table 1.3 shows PacifiCorp's annual winter
capacity position from 2017 through 2026, with coal unit retirement assumptions and
incremental energy efficiency savings from the 2017 IRP preferred portfolio before adding any
incremental new generating resources. Accounting for available market purchases, PacifiCorp
substantially exceeds its 13 percent target planning reserve margin over the winter peak though
this period. With continued load growth and assumed coal unit retirements, winter margins drop
over time, but remain significantly higher than the 13 percent target planning margin.
Table 1.3 - PacifiCorp l0-Year Winter Capacity Position Forecast (MlY)
Existing Resource Capacity Contribution
Available FOT Capacity Contribution
1,417
1,670
11,369
ts70
I l,l l2
1,670
l l,1 l0
1,670
10,047
1,670
10,037
1,670
9,978
1,670
9,m8
1,670
9,905
1,670
9,878
1,670
Total kisting Resource + FOTs
Obligation Net oflncremental DSM
13% Plmning Reserve Margin
13,087 13,038 12,781 12,779 1,717 11,707 tt,A1 \,577 1t,574 11,548
8A4r
1,123
8,453
t,\24
8y's3
1,124
8,400
l,l 17
I,M3
1,123
8!',t2
1,127
8,503
I,l3 I
8,487
t,129
8,51 I
1,132
8,467
1,t26
Obligation + l3olo Planning Resewes
System Position with Available FOTs
Reserve Margin with Available FOTs
9,s& 9,578 9,s78 9,518 9,s66 9,599 9534 9,616 9,@3 9,s93
3,523
55.V/.
3,461
54.2v"
3,204
51.2o/o
3261
s2.tv"
2,15\
38.8o/o
2,108
38.2o/o
2,013
37.0o/o 36.4%
1,931
36.V/o
1,954
36.4o/o
l,96l
Energy Balance
The capacity position shows how existing resources and loads balance during the coincident
peak sunmer and winter periods, accounting for assumed coal unit retirements and incremental
energy eff,rciency savings from the 2017 IRP preferred portfolio. Outside of these peak periods,
PacifiCorp economically dispatches its resources to meet changes in load while taking into
consideration prevailing market conditions. In those periods when system resource costs are less
than the prevailing market price for power, PacifiCorp can dispatch resources that, in aggregate,
exceed then-current PacifiCorp customer load obligations, facilitating off-system wholesale
market power sales that reduce costs for PacifiCorp customers. Conversely, at times when
system resource costs are greater than prevailing market prices, system balancing wholesale
market power 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 on behalf of its customers.
Figure 1.11 provides a snapshot of how existing system resources could be used to meet
forecasted load across on-peak and off-peak periods given cuffent planning assumptions and
1l
PacrrrConp - 2017 IRP CsapreR I -Exscuuvr Suuuenv
recent wholesale power and natural gas prices.l The figure shows expected monthly energy
production from system resources during on-peak and off-peak periods in relation to load,
reflecting coal unit retirement assumptions and incremental energy efficiency savings from the
2017 IRP preferred portfolio before adding any new generating resources. At times, system
resources are economically dispatched above load levels facilitating net system balancing sales.
This occurs more often in off-peak periods than in on-peak periods. At other times, economic
conditions result in net syStem balancing purchases, which occur more often during on-peak
periods. Figure 1.1 1 also shows how much system 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 addition of any new
generating resources to the portfolio. During on-peak periods, the first energy shortfall appears in
summer 2022. There are no energy shortfalls during off-peak periods over this timeframe.
Figure 1.ll - Economic System Dispatch of Existing Resources in Relation to Monthly
Load
5,000
4,000
3,000
2,000
1,000
0
On-Peak Energy Balance
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t2
PACIFICoRP - 2017 IRP CHapreR I -Expcurrvr Surr,nra,cRv
IRP Advancements
During each IRP planning cycle, PacifiCorp identifies and implements advancements to
continuously improve the IRP for its customers, other stakeholders, and regulatory commissions.
Some of the key advancements implemented in the 2017 IRP include:
Winter Peak Analysis
In response to stakeholder feedback received during the 2015 IRP, PacifiCorp
incorporated in its 2017 IRP comprehensive analysis of how its resource plan meets
winter peak load obligations. The coincident peak for PacifiCorp's system occurs during
the summer, and prior IRP planning cycles have historically focused on ensuring that
resource plans have sufficient capacity to cover summer coincident peak load. For the
frst time, the 2017 IRP enforces the target planning reserve margin on both the summer
and winter coincident system peak load, allowing PacifiCorp to report a winter load and
resource balance, evaluate direct load control programs targeting the winter peak, and
evaluate and report market purchases used to satisfr winter peak load forecasts.
a
a Resource Portfolio Development Process
PacifiCorp improved its resource portfolio development process to more efficiently
produce alternative combinations of resources that could be used to serve our customers
over time. This was achieved by initially evaluating a comprehensive range of Regional
Haze compliance cases under different market price and environmental policy scenarios,
and then using stochastic risk metrics to evaluate the relative performance of alternative
compliance outcomes. Results from this analysis established coal unit retirement
assumptions for subsequent core case and sensitivity case studies, addressing stakeholder
feedback from the 2015 IRP requesting that portfolios considered for selection as the
preferred portfolio be compared among corlmon Regional Haze compliance assumptions.
Further, PacihCorp implemented a core case modeling framework targeting specific
types of resources having operating characteristics not explicitly valued until the
stochastic risk phase of portfolio analysis. This structure allowed PacifiCorp to evaluate a
more diverse mix of potential resource portfolios among a broader range of market price
and environmental policy scenarios to compare the relative performance of these
portfolios using stochastic risk metrics.
o Stakeholder Requests
Efficiencies gained through improvements to the resource development process better
positioned PacifiCorp to develop additional studies requested by stakeholders during the
public input process. PacifiCorp and stakeholders identified and requested alternative
modeling scenarios that were informed by the initial and intermediate analysis that was
reviewed during the public input process. This is an improvement over past IRP planning
cycles, where a more rigid set of pre-defined core case and sensitivity cases limited the
ability to explore alternative assumptions. This improved process in the 2017 IRP
enabled PacifiCorp to develop additional Regional Haze compliance cases and alternative
environmental policy cases in response to stakeholder requests. Results from some of
these studies led PacifiCorp to consider additional scenarios, which directly influenced
the resource mix in the preferred portfolio.
13
PACIFICORP - 20I7 IRP CH,qprrn I -ExECUTrve SupruaRy
a Clean Power Plan Modeling
In the 2015 IRP, PacifiCorp developed a modeling framework to assess the COz emission
rate targets identified in the Environmental Protection Agency's draft Clean Power Plan
(CPP) rule. Due to modeling limitations, PacifiCorp was not able to explicitly capture the
impact of the emission rate targets in stochastic risk analysis, which is used to compare
the relative cost and risk performance of different resource portfolios. In the 2017 IRP,
PacifiCorp identified different mass cap emission targets outlined in the final CPP,
enabling us to leverage existing modeling capabilities to reflect the impact of CPP
emission limits in stochastic risk analysis.
a Solar Intesration Costs
In previous IRPs, a solar integration study to define incremental operating reserve
requirements and associated costs to manage the variability and uncertainty of solar
resources connected to PacifiCorp's system had not been developed. In the 2017 IRP,
PacifiCorp's flexible reserve study outlines incremental reserve requirements associated
with solar resources and accompanying estimates for solar resource integration costs.
a Public Input Meetings
In response to requests to improve participation in IRP public input meetings, PacifiCorp
coordinated with stakeholders to include video conference connections with locations in
Cheyenne, Wyoming, and Denver, Colorado, to supplement the existing video conference
connection between Portland, Oregon, and Salt Lake City, Utah.
Supplemental Studies
PacifiCorp's 2017 IRP relies on numerous supplemental studies that support the derivation of
specific modeling assumptions critical to its long-term resource plan. A description of these
studies, discussed in more detail in appendices filed with the 2017 IRP, is provided below.
o ConservationPotentialAssessment
An updated conservation potential assessment (CPA), prepared by Applied Energy Group
(commissioned by PacifiCorp) and the Energy Trust of Oregon was prepared to develop
demand side management resource potential and cost assumptions specific to
PacifiCorp's service territory. The CPA supports the cost and DSM savings data used
during the portfolio development process.
o Private Generation Assessment
This supplemental study, prepared by Navigant Consulting, Inc., was refreshed for the
2017 IRP to produce updated private generation penetration forecasts for solar
photovoltaic, small-scale wind, small-scale hydro, combined heat and power
reciprocating engines, and combined heat and power micro-turbines specific to
PacifiCorp's service territory. The private generation penetration forecasts from this
study are applied as a reduction to forecasted load throughout the IRP modeling process.
Western Resource Adequacy Evaluation
PacifiCorp updated its analysis of regional resource adequacy to support its assumptions
for wholesale power market purchase limits adopted for the 2017 IRP. The western
resource adequacy evaluation presents data from the Western Electricity Coordinating
Council's Power Supply Assessment, reviews recent resource adequacy studies
performed for the Pacific Northwest region, and summarizes PacifiCorp's historical peak
t4
a
PecrrConp-20l7IRP CHatrrR I -ExECUTIve SUN,IMARy
period market purchase data. PacifiCorp's review of regional resource adequacy
continues to support the use of wholesale power market purchases as a resource in the
IRP planning process.
Planning Reserve Margin Study
The 2017 IRP was developed targeting a 13 percent planning reserve margin, which
influences the need for new resources and is applied during the portfolio development
process. In the 2017 IRP planning reserve margin study, PacifiCorp analyzes the
relationship between cost and reliability among ten different planning reserve margin
levels, accounting for variability and uncertainty in load and generation resources.
Capacitv Contribution Study
PacifiCorp updated its wind and solar capacity contribution values for the 2017 IRP,
which were developed using the capacity factor approximation method. Capacity
contribution is defined as the availability of wind and solar resources among hours
having the highest loss-of-load probability, and the resulting values are used in the 2017
IRP load and resource balance and in the portfolio development process.
Flexible Reserve Study
PacifiCorp expanded the scope of what has historically been titled as the wind integration
study to include an overall assessment of flexible reserve demands driven by variability
and uncertainty in load, wind, solar, and non-wind and non-solar generation resources.
The updated study was prepared by PacifiCorp in coordination with a technical review
committee and estimates flexible reserve needs and integration costs for wind and solar
resources. Operating reseryes estimated from the study are used in cost and risk analysis
modeling and estimated wind and solar integration costs are applied during the portfolio
development process.
Stochastic Parameter Update
PacifiCorp's preferred portfolio selection process relies, in part, on stochastic risk
analysis using a Monte Carlo random sampling process. Stochastic variables include
natural gas and wholesale electricity prices, load, hydro generation, and unplanned
thermal outages. For its 2017 IRP, PacifiCorp updated its stochastic parameter input
assumptions with more curent historical data.
Smart Grid
PacifiCorp has included in the 2017 IRP appendix an update on its Smart Grid efforts
with a focus on transmission and distribution systems and customer information.
Enerey Storaee Screenine Studies
Two energy storage studies were conducted to support the 2017 IRP. The Battery Energy
Storage Study prepared by DNV-GL catalogues commercially available and emerging
battery energy storage technologies with forecasts and estimates for both perfonnance
and costs. The Bulk Energy Storage Study prepared by Black & Veatch is an update to
the work HDR and Navigant Consulting performed for the 2015 IRP. The Bulk Energy
Storage Study incorporates updated information on three pumped hydro energy storage
projects and a compressed air energy storage project in PacifiCorp's service territory.
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PecmrCoRp - 2017 IRP Cruprpn 2 - INTRoDUCTIoN
CrmprER 2 - INTnoDUCTIoN
Pacif,rCorp files an Integrated Resource Plan (IRP) on a biennial basis with the state utility
commissions of Utah, Oregon, Washington, Wyoming, Idaho, and California. This IRP fulfills
the Company's commitment to develop a long-term resource plan that considers cost, risk,
uncertainty, and the long-run public interest. It was developed through a collaborative public
process with involvement from regulatory staff, advocacy groups, and other interested parties.
As the owner of the IRP and its action plan, all policy judgments and decisions conceming the
IRP are ultimately made by PacifiCorp in light of its obligations to its customers, regulators, and
shareholders.
Compliance associated with Regional Haze requirements continued to be a key area of focus for
the 2017 IRP. PacifiCorp developed resource portfolios among seven potential Regional Haze
scenarios (including a reference case), assessing how different inter-temporal and fleet-tradeoff
compliance outcomes might influence new resource needs and system costs. Regional Haze
scenarios outlining different potential compliance requirements were analyzed concurrent with
other environmental policies, including analysis of EPA's Clean Power PIan. Coal-fired units
subject to near-term Regional Haze requirements were analyzed and included analysis of
compliance alternatives for Hunter 1, Hunter 2, Huntington 1, Huntington 2, Jim Bridger 1, Jim
Bridger 2, Naughton 3, Cholla 4, and Craig 1. In addition, PacifiCorp's 2017 IRP also focused
on analysis of transmission expansion opportunities and renewable resources including a
repowering project to extend the operating life of existing renewable resources while lowering
operating costs through the use of production tax credit benefits.
Other significant studies conducted to support the 2017 IRP include:
An updated demand-side resource potential assessment;
A private generation study for PacifiCorp's service territory;
Energy storage studies examining storage potential;
A planning reserve margin study to determine selection of a planning reserve margin for
the 2017IRP;
A western region regional adequacy assessment;
A wind and solar capacity contribution study;
A flexible reserve study developed in coordination with a technical review committee;
Updated stochastic parameters; and
An updated load and resource balance.
Finally, this IRP reflects continued alignment efforts with the Company's annual ten-year
business planning process. The purpose of the alignment, initiated in 2008, is to:
o Provide corporate benefits in the form of consistent planning assumptions;
o Ensure that business planning is informed by the IRP portfolio analysis, and, likewise,
that the IRP accounts for near-term resource affordability concerns as they relate to
capital budgeting; and
. Improve the overall transparency of PacifiCorp's resource planning processes to public
stakeholders.
o
o
a
a
a
2I
PecmrConp-20l7IRP Csaprsn 2 - INTRoDUCTToN
This chapter outlines the components of the 2017 IRP, summarizes the role of the IRP, and
provides an overview of the public process.
The basic components of PacifiCorp's 2017IRP include
o Set of IRP principles and objectives adopted for the IRP effort (this chapter).
o Assessment of the planning environment, market trends and fundamentals, legislative and
regulatory developments, and current procurement activities (Chapter 3)o Description of PacifiCorp's transmission planning efforts and activities (Chapter 4)o Load and resource balance covering the Company's load forecast, existing resources, and
determination of the load and energy positions for the front ten years of the twenty year
planning horizon (Chapter 5)
o Profile of resource options considered for addressing future capacity and energy needs
(Chapter 6)o Description of the IRP modeling, including a description of the resource portfolio
development process, cost and risk analysis, and preferred portfolio selection process
(Chapter 7)
o Presentation of IRP modeling results, and selection of top-performing resource portfolios
and PacifiCorp's preferred portfolio (Chapter 8)
o Presentation of PacifiCorp's 2017 IRP action plan linking the Company's preferred
portfolio with specific implementation actions, including an accompanying resource
acquisition path analysis and discussion of resource procurement risks (Chapter 9)
The IRP appendices, included as a Volume II, contain the items listed below
o Load Forecast Details (Volume II, Appendix A),
o IRP Regulatory Compliance (Volume II, Appendix B),o Public lnput Process (Volume II, Appendix C),
o Demand Side Management Resources (Volume II, Appendix D),o Smart Grid discussion (Volume II, Appendix E),
o Flexible Reserve Study (Volume II, Appendix F),o Historical plant water consumption data (Volume II, Appendix G),o Stochastic Parameters (Volume II, Appendix H),
o Planning Reserve Margin Study (Volume II, Appendix I),o Assessment of resource adequacy for western power markets (Volume II, Appendix J),o Detailed capacity expansion tables (Volume II, Appendix K),o Stochastic simulation results (Volume II, Appendix L),o Case study fact sheets (Volume II, Appendix M),o Wind and solar capacity contributions (Volume II, Appendix N),
o Private generation study (Volume II, Appendix O), and. Energy storage studies (Volume II, Appendix P)
In an effort to improve transparency PacifiCorp is also providing data discs for the 2017 IRP.
These discs support and provide additional details for the analysis described within the
22
PecnrConp-2017IRP CHAPTER 2 - INTRoDUCTION
document. Discs containing confrdential information are provided separately under non-
disclosure agreements, or specific protective orders in docketed proceedings.
PacifiCorp's IRP mandate is to assure, on a long-term basis, an adequate and reliable electricity
supply at a reasonable cost and in a manner "consistent with the long-run public interest."l The
main role of the IRP is to serve as a roadmap for determining and implementing the Company's
long-term resource strategy according to this IRP mandate. In doing so, it accounts for state
commission IRP requirements, the curent view of the planning environment, corporate business
goals, and uncertainty. As a business planning tool, it supports informed decision-making on
resource procurement by providing an analytical framework for assessing resource investment
tradeoffs, including supporting RFP bid evaluation efforts. As an external communications tool,
the IRP engages numerous stakeholders in the planning process and guides them through the key
decision points leading to PacifiCorp's preferred portfolio of generation, demand-side, and
transmission resources.
While PacifiCorp continues to plan on a system-wide basis, the Company recognizes that new
state resource acquisition mandates and policies add complexity to the planning process and
present challenges to conducting resource planning on this basis.
The IRP standards and guidelines for certain states require PacifiCorp to have a public input
process allowing stakeholder involvement in all phases of plan development. The Company
organized five state meetings and held seven public meetings, some of which spanning two days
to facilitate information sharing, collaboration, and expectations for the 2017 IRP. The topics
covered all facets of the IRP process, ranging from specific input assumptions to the portfolio
modeling and risk analysis strategies employed. Table 2.1 lists the public input
meetings/conferences and highlights major agenda items covered. Volume II, Appendix C
(Public Input Process) provides more details conceming the public input process.
Table 2.1-2017IRP Public Input Meetings
t The Public Utility Commission of Oregon and Public Service Commission of Utah cite "long-run public interest"
as part of their definition of integrated resource planning. Public interest pertains to adequately quantiffing and
capturing for resource evaluation any resource costs extemal to the utility and its ratepayers. For example, the Public
Service Commission of Utah cites the risk of future intemalization of environmental costs as a public interest issue
that should be factored into the resource portfolio decision-making process.
State Meeting 6/6/2016 Washington state stakeholder comments
6/7/2016 Idaho state stakeholder commentsState Meeting
6/10/16 Oregon state stakeholder commentsState Meeting
Utah state stakeholder commentsState Meeting 6/13/2016
State Meeting 6/t412016 Wyoming state stakeholder comments
General Meeting 6l2t/16 2017 IRP kick-off meeting
General Meeting 7/20116 Environmental Policy, Transmission, Regional Integration, Renewable
Portfolio Standards (RPS) / Request for Proposals (RFPs)
23
PACIFICORP_20I7IRP Csaprsn 2 - INrnooucrroN
In addition to the public input meetings, PacifiCorp used other channels to facilitate resource
plaruring-related information sharing and consultation throughout the IRP process. The Company
maintains a public website (https://www.pacificorp.com/es/irp.html), an e-mail o'mailbox"
([e-mail], and a dedicated IRP phone line (503-813-5245) to support stakeholder
communications and address inquiries by public participants. Additionally, a stakeholder
Feedback Form was used to provide opportunities for stakeholders to submit additional input and
ask questions throughout the 2017 IRP public input process. The submitted forms are located on
the PacifiCorp's IRP website: https://www.pacificom.com/es/irp/irpcomments.html in the
comments section.
8125/16 Portfolio Development, Private Generation Study, Supply-Side Resources,
Energy StorageGeneral Meeting (2-Day)
8t26/16 Update on RPS/RFPs, Conservation Potential Assessment, Load Forecast
9122/16
Portfolio Development, Stochastic Modeling, Resource Adequacy and
Front Offrce Transactions, Loss of Load Probability and Planning Reserve
Margin, Capaci8 Contribution StudyGeneral Meeting (2-Day)
9t23/16 Load and Resource Balance, Flexible Capacrty Reserve Study, Smart Grid
General Meeting (phone
conference)tUtT/16 Updated Capacity Contibution Study, Official Forward Price Curve
U26117 Portfolio SummariesGeneral Meeting (2-D ay)U27/17 Sensitivity Studies
3/2tr7 Draft Preferred Portfolio Overview, Market Price Scenarios, PortfoliosGeneral Meeting Q-Day)3/3/17 Sensitivity Studies, Preferred Portfolio Selection Process
24
PacrrConp-2017 IRP CHAPTER 3 -THE PLANNTNG ENVIRONMENT
CuaprER 3 _ TUP PTAUNING ENVINONMENT
Cnaprnn Hrcru-rcrrrs
o North American natural gas markets continue to be driven by high supply. In 2009, the
Marcellus shale play, centered in Pennsylvania and West Virginia, produced almost no
natural gas; by spring 2013, it was producing over 9 BCF/D. Today the Marcellus is
producing 18 BCF/D, and the Utica, much of which underlies the Marcellus, produces
another 4 BCF/D. The Marcellus and Utica plays are expected to account for 40 percent of
the nation's gas supply by 2020, spurred by increased drilling efficiency. Day-ahead 2016
Henry Hub prices averaged $2.494{MBtu, down 64 percent and 69 percent in nominal
and real dollars, respectively, from 2007 prices.
o Federal and state tax credits, declining capital costs, and improved technology
performance have put wind and solar "in the money" in areas of high potential. Wind and
solar will therefore dominate United States capacity additions for the next decade. More
transmission, new storage technologies, and market design changes are needed to better
integrate new wind and solar resources into the grid.
o The U.S. Environmental Protection Agency (EPA) issued a proposed rule under $111(d)
of the Clean Air Act (111(d) or the 1 11(d) rule) to regulate greenhouse gas emissions from
existing sources in June 2014. On August 3,2015, the EPA issued a final rule, referred to
as the Clean Power Plan (CPP), regulating carbon emissions from existing power plants.
On February 9, 2016, the U.S. Supreme Court issued a stay of the CPP, suspending
implementation of the rule pending the outcome of the merits of litigation before the D.C.
Circuit Court of Appeals. The stay remains in effect at this time.
o PacifiCorp and the Califomia Independent System Operator Corporation (CAISO)
launched the voluntary energy imbalance market (EIM) November l, 2014, the first
westem energy market outside of California. The EIM has produced significant monetary
benefits ($142.62 million total footprint-wide benefits as of December 31, 2016).
A significant contributor to EIM benefits are transfers across balancing authority areas,
providing access to lower-cost supply, while factoring in the cost of compliance with
greenhouse gas emissions regulations when energy is transferred into the CAISO
balancing authority area.
o Near-term procurement activities focused on three areas-nafural gas asset management
and supply, the purchase and sale of renewable energy credits, and Oregon solar resources.
Chapter 3 profiles the major extemal influences that affect PacifiCorp's long-term resource
planning and recent procurement activities. External influences include events and trends
affecting the economy, wholesale power and natural gas prices, and public policy and regulatory
initiatives that influence the environment in which PacifiCorp operates.
Major issues in the power industry market include capacity resource adequacy and associated
standards for the Western Electricity Coordinating Council (WECC). As discussed elsewhere in
this IRP, future natural gas prices, the role of gas-fired generation and the falling costs and
increasing efficiencies of renewables are some of the critical factors affecting the selection of the
portfolio that best achieves least-cost, least-risk planning objectives.
25
PACIFICORP _ 20I7 IRP CHAPTER 3 -TTm PLANNTNG ENVm.oNMENT
On the government policy and regulatory front, a significant issue facing PacifiCorp continues to
be planning for an eventual, but highly uncertain, climate change regulatory regime. This chapter
focuses on climate change regulatory initiatives. A high-level summary of the Company's
greenhouse gas emissions mitigation strategy is included as well as a review of significant policy
developments for currently regulated pollutants.
Other topics covered in this chapter include regulatory updates on the EPA, regional and state
climate change regulation, the stafus of renewable portfolio standards, and resource procurement
activities.
PacifiCorp's system does not operate in an isolated market. Operations and costs are tied to a
larger electric system known as the Western Interconnection, which functions on a day-to-day
basis as a geographically dispersed marketplace. Each month, millions of megawatt-hours of
energy are traded in the wholesale electricity market. These transactions yield economic
efficiency by serving demand with resources with the lowest operating cost and by providing
reliability benefits arising from access to larger portfolio of resources.
PacifiCorp actively participates in the wholesale market by making purchases and sales to keep
its supply portfolio in balance with customers' constantly varying needs. This interaction with
the market takes place on time scales ranging from sub-hourly to years in advance. Without the
wholesale market, PacifiCorp or any other load serving-entity would need to construct or own an
unnecessarily large margin of supply that would go unused in all but the most unusual
circumstances and would substantially diminish the ability to cost-effectively match delivery
patterns to the profile of customer demand.
The benefits of access to an integrated wholesale market have grown with the increased
penetration of intermittent generation such as solar and wind. lntermittent generation tends to
come online and go offline abruptly in correlation with changing weather conditions. Federal and
state (where applicable) tax credits, declining capital costs, and improved technology
performance have put wind and solar "in the money" in areas of high potential. Wind and solar
will therefore dominate United States capacity additions for the next decade. More transmission,
new storage technologies, and market design changes are needed to better integrate these
resources into the grid.
There are currently several long-haul renewable-driven transmission projects under
development.l These projects connect areas of high renewable potential and low population
density to areas of high population density with less renewable potential. In the Westem
Interconnection, this includes PacifiCorp's proposed 416-mile, 1,500 MW Gateway South
project, with an online date of 2023, to transport Wyoming wind to central Utah. Similarly,
Gateway West, a 1000-mile project jointly proposed by PacifiCorp and Idaho Power, would
transport Wyoming wind to western Idaho to be picked up for westward delivery In the eastern
interconnection, the Plains & Eastern Clean Line, a 700 mile, 600 KV, 4,000 MW direct-current
line has been announced to go live in2020. This line will transport Oklahoma wind to Tennessee
for distribution by the Tennessee Valley Authority to systems in areas with little native wind
I To date, at least fourteen renewable-driven transmission projects are in some stage of development.
26
PecrrrConp-2017 IRP CHAPTER 3 -THE PLaNNTNIC ENVR.ONMENT
potential. This long-haul, ultra-high-voltage, direct-current line will be the first in the United
States.2
The intermittency of renewable generation also increases the need for fast-responding energy
storage, which is essential for grid stability and resiliency. Pumped storage has been the
traditional energy storage option but expansion is extremely limited due to topography
limitations, with the best resources already harnessed. Of the remaining mechanical, thermal, and
chemical storage options, lithium-ion batteries have shown the most promise in terms of cost and
performance improvement. Battery modules have fallen to under $500/KWh and are expected to
reach $150-$250/KWh by 2020. PJM3 already offers higher payments for fast-responding
storage such as batteries and fly wheels. These energy storage technologies can ramp up
instantaneously - quicker than combustion turbines - but do not last long. State regulatory
commissions are also encouraging development of energy storage options. For example, the
California Public Utility Commission requires investor-owned utilities to procure, intotal,l,325
MW of storageby 2020.4
Increased renewable generation has also contributed to the need for balancing sub-hourly
demand and supply across a broader and more diverse market. For balancing purposes,
PacifiCorp and CAISO formed the EIM, which became operational November I,2014. By
December 2015, Nevada Energy joined, followed by Puget Sound Energy and Arizona Public
Service in 2016. Entities scheduled to join the EIM include PGE (October 2017),Idaho Power
Company (April2018), Seattle City Light (April 2019), and the Balancing Authority of Northern
California (April 2019). The Mexican system operator El Centro Nacional de Control de
Energia has also announced intentions to join the EIM. This larger EIM footprint brings greater
resource and geographical diversity, which allows for increased reliability and cost savings in
balancing generation with demand using l5-minute interchange scheduling and five-minute
dispatch. CAISO's role is limited to the sub-hourly scheduling and dispatching of participating
EIM generators. CAISO does not have any other grid operator responsibilities for PacifiCorp's
balancing authority areas.
As with all markets, electricity markets are faced with a wide range of uncertainties, although
some uncertainties are easier to evaluate than others. Market participants are routinely studying
demand uncertainties driven by weather and overall economic conditions. Similarly, there is a
reasonable amount of data available to gauge resource supply developments. For example,
WECC publishes an annual assessment of power supply and numerous data services track the
status of new resource additions. A review of the WECC power supply assessment is provided in
Volume II, Appendix J (Western Resource Adequacy Evaluation). The latest assessment,
published December 2016, indicates that even when including only existing and under-
construction units, WECC as a whole has ample resources through 2026. WECC's Californian
and Mexican sub-regions, however, fall short starting 2024. The WECC sub-regions in which
PacifiCorp operates (Northwest Power Pool and Rocky Mountain Reserve Group) are both
capacity sufficient through 2026.
2 A Greener Grid,The Economist, January l4n -20fi 2017.
3 PJM is the Pennsylvania-New Jersey-Maryland Interconnection.
4 The California Public Utilities Commission's storage procurement mandate was authorized by California
Assembly Bill2514, as amended by Assembly Bill2227.
27
PacrrConp - 2017 IRP CHAPTER 3 _THE PLANNING ENvR.ONNGNT
There are other uncertainties that greatly influence future prices but are more difficult to analyze.
One such uncertainty is the evolution of natural gas prices over the course of the IRP planning
horizon. Given the increased role of natural-gas-fired generation, gas prices are a critical
determinant of westem electricity prices, and this trend is expected to continue over the term of
this IRP's planning horizon. Another critical uncertainty affecting the 2017 IRP, as in past IRPs,
is the uncertainty surrounding future greenhouse gas policies, both federal and state. PacifiCorp's
official forward price curve incorporates potential impacts of EPA's finalized 111(d) rule, the
Clean Power Plan (CPP). Other price scenarios developed for the IRP consider impacts of
potential future COz emission policies incremental to requirements established in EPA's CPP.
Natural Gas Uncertainty
Over the last decade, North American natural gas markets have undergone a remarkable
paradigm shift. As shown in Figure 3.1, Henry Hub day-ahead gas prices hit a high of
$13.3l/MMBtu on July 2,2008, and a low of $1.49AvIMBtu on March 4,2016. Day-ahead prices
averaged S7.93A4MBtu through 2008, dropped to $3.94lNIMBtu in 2009, and have averaged
$3.474{MBtu since 2010. Day-ahead 2016Herry Hub prices averaged $2.4944MBtu, down 64
percent and 69 percent in nominal and real dollars, respectively, from 2007 pices. The relative
price placidity since 2009, labeled the "Shale Gale," reflects increased supplies (mostly
Appalachian supply).s
1n2009, the Marcellus shale play, centered in Pennsylvania and West Virginia, produced almost
no natural gas; by spring 2013, it was producing over 9 BCF/D. By late 2016, the Marcellus was
producing 18 BCF/D, and the Utica, much of which underlies the Marcellus, was producing
4 BCF/D. In short, supply from the Marcellus and Utica plays continues to grow as volumes and
costs prove to be, respectively, higher and lower than anticipated. The Marcellus and Utica plays
currently account for 30 percent of the nation's gas supply and are expected to account for
40 percent by 2020, spurred by increased drilling efficiency.
s Other significant shale gas plays include Eagle Ford (TX), Haynesville (LAITX), Permian (TX/NM), Niobrara
(CO/WY), and Bakken (ND/MT). The Permian, in particular, is the center of renewed activity.
28
PACIFICoRP-2017IRP CHAPTER 3 _T}fi PLANNTNG ENVIRONNGT.IT
Figure 3.1 - Henry Hub Day-Head Gas Price History
Source: lntercontinental Exchange (ICE), Over the Counter Day-ahead tndex
Historically, depletion of conventional mature resources largely offset unconventional resource
growth. But as shale gas "came into its own," production gains outpaced depletion. Figure 3.2
through Figure 3.4 show United States natural gas production by source and location.
Figure 3.2 - U.S. Dry Natural Gas Production
50
40
30
20
10
History 2o15
o19!n 19srs 20fi) 2005 2o1o 2015 2o.2o 20.25 2()3() 2o,3s 20,40
\7
l: N F e O O O O O d Ft N N fn O tt tf u] ul O OI I ? ? ? ? I t I t I r f .t f .I f .l T'l fE E i E E i 8 E E E E E i T T g E g
'
g
'
\
rDayAhead lndex
s14
su
s
t98
E
Eso{r}
s4
s2
so
a
-finnuxlfiysngg
e e
10 I Trhnolqical
advancements
yield grorthin
shale gas supfly
I Economk
downtum
Source: 2016 Annual Energy Outlook, U.S. Departrnent of Energy, Energy Information Administration
29
')$..1 t'
,--'.+'
I
ii
s--
f,_atela'
Lower 48 states shale plays
8orr-r
tr'i
t
'13-,4r. ,
r.-r-. ,-*
-r-'r-Tr-l. --Ir-N
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:, c ,-rr
-
:: .,.*<r I , -u &r
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PacrprCoRp 20l7lRP CHePTER 3 THe PLANNING ENVIRONMENT
Figure 3.3 - Lower 48 States Shale Plays
Silil" U.S. Department of Energy, Energy Information Administration
Figure 3.4 - Plays Accounting for All Natural Gas Production Growth 20ll -2014
Bakken
Marcellu
Eagle
Source: Drilling ProductiviQ Report, January 2017, U.S. Department of Energy, Energy Information Administration
Figure 3.5 shows Henry Hub NYMEX futures as of January 20,2017. While futures are mildly
in contango, it would appear that price expectations offer little "signal-to-dril1." But as producers
Permian
30
PACIFICORP - 20 I7 IRP CHAPTER 3 -THE PLANNING ENVIRoNMENT
chase production efficiencies the signal-to-drill price becomes lower. Producers have discovered
the economies of scale of deeper wells, longer laterals, clustered well spacing, and repetitive
fracking. One of the deepest and longest wells (8,500 feet deep with 18,544-foot laterals) was
drilled in Ohio. The well was fracked 124 times (compared to the norm of 30-40 times) and used
51 million tons of sand.6 The producer estimated that supersizing the well yielded a cost savings
of 30 percent. Producers have therefore been a victim of their own success. For example, in
2015, Equitable Resources (EQT) drilled a Utica well that produced so much natural gas that it
depressed EQT's stock price due to its deleterious effect on gas prices.T
Moreover, while West Texas Intermediate is only hovering around $53/barrel, it is enough to
spur oil-targeted drilling in "sweet spots" within westem Canada, the Permian, and Bakken.
Slowly recovering oil prices are bringing more price-insensitive gas to market. This is especially
true of Permian Basin oil wells, whose output contains 20-50 percent natural gas. With crude's
price collapse, United States production finally fell to 8.8 million barrels per day (MMbpd) in
2016 from a high of 9.6 MMbpd in 2015. Today, United States production is back to 9 MMbpd,
and Goldman Sachs forecasts another 600,000 bpd by the end of 2017. Even though over a
hundred energy producers have gone bankrupt, they keep pumping. This production resiliency is
a function of (1) declining technology costs, (2) increased production efficiencies, and (3)
variable operating costs (not full cycle costs) being less than $40.00 per barrel. The Energy
Information Administration (EIA) estimated that, as of December 2016, 5,379 wells remain
drilled but uncompleted. These wells can be put into production quickly and represent a
significant source of supply.8 United States production can ramp up quickly.
This resiliency of supply coupled with the flexibility to quickly ramp up production will shorten
the length of asynchronous supply and demand cycles. Unexpected weather-induced demand
spikes or cuts, as well as supply disruptions, will still whipsaw prices for short periods of time.
But LNG startups, outages or dial backs could swing prices for longer periods given the
magnitude of volumes coupled with locational concentration.e lJntll 2024, the global LNG
market is expected to be in oversupply, and the United States LNG tends to be the marginal
supply given its high variable operating costs. Since Europe is a major offtaker for United States
LNG, exports are expected to drop precipitously during surnmer months given little European
surlmer LNG demand. Summer feed gas normally bound for liquefaction would then be diverted
into the market, depressing prices. This dial back will act to also moderate winter prices by
increasing storage and the likelihood of entering winter with an overhang. Thus, seasonal
demand fluctuations for LNG abroad are expected to swing Henry Hub prices given the
magnitude of volumes and proximity to Henry Hub.
Prices finally begin to break out by 2024 as global LNG demand catches up to supply. The key
drivers of demand both before and after 2024 are (1) LNG exports, (2) Mexican exports, and
(3) power generation. Of the three, power generation is by far the largest user, but exports
(especially LNG) are the fastest growing, at least through 2024.10 Afler 2024, the power sector
6 Two Years into Oil Slump, U.S. Shale Firms are Ready to Pump More, Wall Street Journal, September 27,2016.
7 Gas Driller Hits a Gusher-and Sinl<s its Own Stock,Wall Street Journal, November 26,2015.
8 EIA does not distinguish between oil and gas wells since over 50 percent of wells produce both.
e Current and expected facilities are mostly concentrated in the Gulf Coast.
r0 The power sector is expected to maintain pre- and post-2024 annual growth of approximately 2.5 percent. LNG
and Mexican exports average apre-2024 annual rate of24 percent and 7.8 percent, respectively, versus a post-2024
annual growth of2.4 percent and 1.5 percent.
31
PACIFICoRP-20I7IRP CTTAPTER 3 - T}G PLANNTNG ENVIRONMENT
maintains most of it pre-2024 growth, whereas the export sectors' growth rates drop
precipitously and level off.
Figure 3.5 - Henry Hub ll-YMEX Futures
trEailraa
4.00
3.s0
3.00
2.s0
2.00
1.s0
1.00
0.50
0.00 r- 6 o\ o !-t N t') t? t.) \o r- € o\i t-,{ !-l N Ct Gl N al N N N N clVVVVUVUUU9UU9NNNNNN'I616TNN'TN
-Annual
Strip as of Jan 20,2017
The continued build out of Appalachian take-away capacity will keep western regional natural
gas markets well connected to North American supply. Rocky Mountain production slows as
Appalachian volumes push westward and exert downward price pressure on Opal vis-i-vis
Henry Hub. Similarly, West Coast prices are pressured as more Rockies gas, previously destined
for the east, moves west to compete with Canadian gas to serve California. In the Northwest,
where natural gas markets are influenced by production and imports from Canada, prices at
Sumas have traded at a premium relative to AECO. This is likely to continue as AECO loses
market share to the Marcellus in serving AECO's Ontario, Midwest, and even West Coast
markets. In short, the challenge in gauging the uncertainty in natural gas markets will be timing.
The North American natural gas supply curve continues to flatten as production efficiencies
expose an ever-increasing resilient, flexible, and low-cost resource base. In that environment,
managing long-term boom-and-bust cycles is not as crucial as managing shorter-term market
perturbations.
PacifiCorp faces continuously changing electricity plant emission regulations. Although the
exact nature of these changes is uncertain, they are expected to impact the cost of future resource
alternatives and the cost of existing resources in the company's generation portfolio. PacifiCorp
monitors these regulations to determine the potential impact on its generating assets. PacifiCorp
also participates in rulemaking processes by filing comments on various proposals, participating
in scheduled hearings, and providing assessments of proposals.
Federal Climate Change Legislation
To date, no federal legislative climate change proposal has been passed by the U.S. Congress.
The election of Donald Trump as U.S. President reduces the likelihood of federal climate change
legislation in the near term.
)Z
PACIFICORP - 2OI7 IRP CHAPTER 3 _THE PLA}.TNTNG ENVm.ONMENT
Federal Renewable Portfolio Standards
Since 2010, there has been no significant activity in the development of a federal renewable
portfolio standard (RPS). Accordingly, PacifiCorp's 2017 IRP assumes no federal RPS
requirement over the course of the planning horizon.
New Source Performance Standards for Carbon Emissions - Clean Air Act
s 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 August 3,
2015, the EPA issued a final rule limiting carbon emissions from coal-fueled andnatural-gas-
fueled power plants. New natural-gas-fueled power plants can emit no more than 1,000 pounds
of carbon dioxide (CO, per megawatt-hour (MU/h). New coal-fueled power plants can emit no
more than 1,400 pounds of COzlMWh. The final rule largely exempts simple cycle combustion
turbines from meeting the standards.
Carbon Emission Guidelines for Existing Sources - Clean Air Act $ 111(d)
On August 3, 2015, the EPA issued a final rule, referred to as the Clean Power Plan (CPP),
regulating carbon emissions from existing power plants. Under the final rule, states would be
required to submit compliance plans by September 6,2016, but a state may seek an extension to
September 6, 2018, to submit a state plan. On August 3, 3015, EPA also issued a proposed
federal plan and model trading rules for public comment. The public comment period closed
January 21,2016. Under section 111(d) of the Clean Air Act, states are required to develop
standards of performance, which are the degree of emission limitation achievable through the
application of the best system of emission reduction (BSER).
On February 9, 2016, the U.S. Supreme Court issued a stay of the CPP suspending
implementation of the rule pending the outcome of the merits of litigation before the D.C. Circuit
Court of Appeals. If parties petition for a writ of certiorari before the Supreme Court, the stay
will remain in effect until the Supreme Court takes action to either deny the petition or, if the
Supreme Court hears the case, the stay remains in effect until the court enters its judgment. Oral
argument on the CPP litigation was held September 27,2016, before the D.C. Circuit Court of
Appeals.
In the final rule, EPA set forth emission reduction goals for each state based on EPA's
formulation of BSER, which is made up of three building blocks: (1) heat rate improvements at
existing coal-fueled resources; (2) increased use of natural gas resources; and (3) increased
deployment of zero-emitting resources. States would be required to meet the emission reduction
goal by 2030, as well as interim goals, which would be met over three interim compliance
periods: 2022-2024, 2025-2027, and 2028-2029. Using its formulation of BSER, EPA
established uniform national interim and final carbon emission performance standards at 1,305 lb
COzlMWh for coal-fueled power plants and 771 lb COzAvIWh for natural-gas-fueled power
plants, which in turn were used to establish projected mass-based and rate-based compliance
targets for individual states.
JJ
PACIFICoRP-20I7IRP CHAPTER 3 - THE PLANNTNG ENVIRoNMENT
Under the final rule, states have a number of implementation options: states may choose to adopt
the rate-based standard and apply them on a subcategory or state-specific blended rate basis, or
states may choose to adopt the standards as a mass-based state goal. In the final rule, EPA
provided state mass-based goals that it stated are equivalent to the rate-based emissions goals.
Under a mass-based implementation program, compliance would be demonstrated through
reported stack emissions and the retirement of carbon allowances. Under a rate-based
implementation program, compliance would be demonstrated through the use of megawatt-hour
credits referred to as emission rate credits (ERCs) from renewable energy and, potentially,
energy efficiency. States also have the option to trade with other affected resources in other
states implementing similar approaches (e.g., rate state with other rate states or mass state with
other mass states) so long as those states meet certain "trading ready" minimum requirements.
The federal plan proposal also includes model mles for rate-based and mass-based trading
progrirms for potential use by any state in developing its state plan. The mass-based federal plan
proposal includes a proposed allowance allocation methodology and a method for states to
address leakage through allowance set-asides.
On March 28,2017, President Trump issued an Executive Order directing the EPA to review the
Clean Power Plan and, if appropriate, suspend, revise, or rescind the Clean Power Plan, as well
as related rules and agency actions. PacifiCorp will continue to follow activities related to this
Executive Order.
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
"criteria" pollutant in outdoor air. The six pollutants are carbon monoxide, lead, ground-level
ozotre, nitrogen dioxide C{Ox), particulate matter (PM), and sulfur dioxide (SOr. 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 for that area. And that plan must be approved by EPA. The
plan is developed so that once implemented, the NAAQS for the particular pollutant of concern
will be achieved.
In October 2015, EPA issued a final rule modiffing the standards for ground-level ozone from
75 parts per billion (ppb) to 70 ppb. Under the finalrule, EPA will 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. PacifiCorp facilities will
only be affected to the extent they are located in an ozone nonattainment area.
34
PACIFICORP-2017 IRP CHAPTER 3 -THE PLANNNG ENVIRoNMENT
Regional Haze
EPA's regional hazentle,firralized in 1999, 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 identiffing 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 cunent 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
state implementation plans. States are currently required to submit the next periodic update by
July 31,2021.
The regional haze rule is intended to achieve natural visibility conditions by 2064 in specific
National Parks and Wildemess 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 Reeional Haze
In May 2011, the state of Utah issued a regional haze state implementation plan (SIP) requiring
the installation of $Q2, NOx and PM controls on Hunter Units I and 2 and Huntington Units 1
and 2. In Decemb er 2012, the EPA approved the SOz portion of the Utah regional haze 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 approval with an updated BART analysis incorporating
a requirement for PacifiCorp to retire Carbon Units 1 and 2, recogrizing NOx controls
previously installed on Hunter Unit 3, and concluding that no incremental controls (beyond those
included in the May 2011 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 the
Utah's regional haze SIP and propose a federal implementation plan (FIP). The final rule
requires the installation of selective catalytic reduction (SCR) controls at four of PacifiCorp's
units in Utah: Hunter Units 1 and 2, and Huntington Units I and 2. On September 2, 2016,
PacifiCorp filed petitions for administrative and judicial review of EPA's final rule and
requested a stay of the effective date of the final rule. Unless the EPA's FIP is stayed or reversed,
the controls are required to be installed by August 4,2021.
Wyoming Reeional Haze
On January 10, 2014, EPA issued a final action in Wyoming requiring installation of the
following NOx and PM controls at PacifiCorp facilities:
35
PACIFICORP - 20I7 IRP CUAPTPR 3 -TgP PLANNING ENVIRONMENT
o Naughton Unit 3 by December 31, 2014 SCR equipment and a baghouse. Jim Bridger Unit 3 by December 31, 2015: SCR equipmento Jim Bridger Unit 4 by December 31, 2016: SCR equipmento Jim Bridger Unit 2 by December 31, 2021 SCR equipment. Jim Bridger Unit I by December 31, 2022: SCR equipmento Dave Johnston Unit 3: SCR within five years or a commitment to shut down in2027o 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. PacifiCorp successfully requested a stay of
EPA's action as it pertains to Wyodak pending resolution of the appeals. For Naughton Unit 3, in
its final action EPA indicated support for the conversion of the unit to natural gas 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 to gas be delayed one year. As of January 2017, that request is
undergoing public comment. Wyoming has not yet submitted a revised regional haze SIP
incorporating this alternative compliance approach to EPA.
Arizona Reeional Haze
The state of Arizona issued a regional haze SIP requiring, among other things, the installation of
SOz, NOx and PM controls on Cholla Unit 4, which is owned by PacifiCorp but operated by
Aizona Public Service. EPA approved in part and disapproved in part the Arizona SIP and
issued a FIP requiring the installation of SCR equipment on Cholla Unit 4. PacifiCorp filed an
appeal regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of
Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it
relates to their interests. For the Cholla FIP requirements, the court stayed the appeals while
parties attempt to agree on an alternative compliance approach. In July 2016, the EPA issued a
proposed rule to approve an alternative Arizona SIP, which includes converting Cholla 4 to a
natural gas-fired unit in 2025. The comment period on EPA's proposed rule closed September 2,
2016, and PacifiCorp is awaiting EPA's final action.
Colorado Regional Haze
The Colorado regional haze SIP required SCR controls at Craig Unit 2 and Hayden Units I and
2. In addition, the SIP required the installation of selective non-catalytic reduction (SNCR)
technology at Craig Unit I by 2018. Environmental groups appealed EPA's action, and
PacifiCorp intervened in support of EPA. In July 2014, parties to the litigation other than
PacifiCorp entered into a settlement agreement that requires installation of SCR equipment at
Craig Unit 1 in 2021. In February 2015, the State of Colorado submitted a revised SIP to EPA
for approval. As part of a further agreement between the owners of Craig Unit l, state and
federal agencies, and parties to previous settlements, the owners of Craig agreed to retire Unit I
by December 31,2025, or convert the unit to natural gas by August 3I,2023. The terms of this
agreement are currently being considered by the Colorado Air Quality Board; EPA review and
approval will then be required.
36
PACIFICoRP _ 20I7 IRP CFIAPTER 3 -Tm PLANNTNG ENVIRONMENT
Mercury and Hazardous Air Pollutants
The Mercury and Air Toxics Standards (MATS) became effective April 16, 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 for transmission 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. [n December 2015, the D.C. Circuit Court of
Appeals ruled that MATS may be enforced as EPA modifies the rule to comply with the
Supreme Court decision. By April 20t5, 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 and landfills utilized for CCRs may need to close
unless they can meet more stringent regulatory requirements. At the time the rule was published
in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained
CCRs. Before the effective date in October 2015, nine surface impoundments and three landfills
were either closed or repu{posed to no longer receive CCRs and hence are not subject to the final
rule.
The final CCR regulation was set up to be enforced by citizen suits; however, in September
2016, the Senate passed, and in December 2016 President Obama signed, the Coal Combustion
Residuals Regulatory Improvement Act, which sets forth the process and standards for EPA
approval (and withdrawal) of a state's permitting program for coal combustion residual 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.
The legislation:
o Authorizes the EPA to operate permit programs in states that have not been authorized.. Clarifies that a coal ash residual unit is subject to the EPA rule until a permit is issued by
either a state or EPA.
o Provides the EPA with inspection and enforcement authorities. Before EPA can take
enforcement action in an authorized state, EPA must consider any other actions against
the facility and determine if an enforcement action by EPA "is likely to be necessary" to
ensure the facility is operating in accordance with its permit requirements.
o Authorizes EPA to operate a permit program in Indian country.. Provides a permit shield for facilities that are operating in accordance with a state- or
EPA-issued permit.
)t
PACIFICORP _ 20 17 IRP CTTAPTER 3 -TI{E PLANNTNG ENVR.oNNGNT
o Preserves other legal authorities or regulatory determinations in effect before enactment.
Water Quality Standards
Cooline Water Intake Structures
The federal Water Pollution Control Act ("Clean Water Acf') establishes the framework for
maintaining and improving water quality in the United States through a progftlm 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. In May 2014, EPA issued a f,rnal rule,
effective October 2014, under $ 316(b) of the Clean Water Act to regulate cooling water intakes
at existing 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 United States 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 discharge 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 t977
and 1982. On November 3, 2015, EPA finalized revised effluent limit guidelines. The rule does
not allow the discharge of bottom ash or fly ash transport water and directly impacts the
Wyodak, Dave Johnston, and Naughton facilities.
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
Fifty percent bonus depreciation was extended for property acquired and placed in service during
2015,2016, arrd20l7. For property acquired and placed in service during 2018, 40 percent of the
eligible cost of the property qualifies for bonus depreciation. For property acquired and placed in
service during 2019, 30 percent of the eligible cost of the property qualifies for bonus
depreciation. For property placed in service after December 31, 2019, there will be no bonus
depreciation.l l
rr There is an exception for long-production-period property (generally property with a construction period longer
than one year and a cost exceeding $l million). Costs incuned on long-production-period property may qualiff for
bonus depreciation ifphysical construction has begun before the placed-in-service date ofthe bonus phase-out.
38
PACIFICORP_20I7IRP CHApTER 3 -THE PLANNTNG Er.rvrRoNMENT
Production Tax Credit (Wind)
The production tax credit (PTC), currently 2.3 cents per kilowatt-hour (inflation adjusted), has
been extended and phased out for wind property for which construction begins before January 1,
2020, as follows:
o 2015 - 100% retroactivec 2016 - 100% (construction begins before January 1,2017)o 2017 - 80% (construction begins before January 1, 2018)o 2018 - 60% (construction begins before January I,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):
o 2015 - 100% retroactiveo 2016 - 100% (construction begins before January 1,2017)
30% Enerey Investrnent Tax Credit (Wind)
The investment tax credit (ITC) has been extended and phased out for wind property for which
construction begins before January 1,2020, as follows:
o 2015 - 30% retroactiveo 2016 - 30% (construction begins before January l, 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 I,2020)
30% 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:c 2015 -30% retroactiveo 2016 - 30% (construction begins before January I,2017)o 2017 - 30% (construction begins before January 1, 2018)o 2018 - 30% (construction begins before January 1,2019)o 2019 -30% (construction begins before January 1,2020)c 2020 -26% (construction begins before January 1,2021)o 2021-22% (construction begins before January 1,2022)o 2022 - l0% (construction begins on or after January 1,2022)
California
Under the authority of the Global Warming Solutions Act, the California Air Resources Board
(CARB) adopted a greenhouse gas cap-and-trade program in October 201I, with an effective
date of January 1,2012; compliance obligations were imposed on regulated entities beginning in
39
PACIFICoRP - 20 I7 IRP CTTAPTER 3 _ THs PLANNING ENVIRONMENT
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 Califomia 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 2002, California established a renewable portfolio standard (RPS) requiring investor-owned
utilities to increase procruement 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 Califomia Public Utilities Commission is
currently developing rules to implement this new program.
Oregon
In2007, the Oregon Legislature passed House Bill (HB) 3543 - Global Warming Actions, which
establishes greenhouse gas reduction goals for the state that: (1) end the growth of Oregon
greenhouse gas emissions by 2010; (2) reduce greenhouse gas levels to l0 percent below 1990
levels by 2020; 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 1 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 10 percent below 1990 levels by
2020 and 15 percent below 2005 levels by 2020. The OPUC submitted its most recent report
November 1,2014.
On July 3 2013, the Oregon Legislature passed SB 306, which directs the legislative revenue
officer to prepare a report examining the feasibility of imposing a clean air fee or tax as a new
revenue option. The report includes an evaluation of how to treat imported and exported energy
sources. A final report was published December 2014.
In2007, 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, Govemor Kate Brown signed SB 1547-8, the Clean Electricity and Coal
Transition Plan, into law. SB 1547-B 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 percertby 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-tern renewable projects to have unlimited life. The
40
PacmrConp - 2017 IRP CgapruR 3 -TuE PLANNING ENVIRONMENT
bill also includes provisions to create a community solar progftrm 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 I-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: (1) 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, Governor 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. After further stakeholder engagement, the proposed rule was withdrawn on
February 26, 2016, to make updates. The Department of Ecology anticipates releasing a new
proposed ruIe for public review in spring 2016. The only Pacif,rCorp resource that would be
subject to the proposed Clean Air Rule is the Chehalis natural gas plant.
Utah
In March 2008, Utah enacted the Energy Resource and Carbon Emission Reduction lnitiative,
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 115-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
California, 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
4T
PecrrrCoRp - 20 17 IRP CHepTpR 3 -TuE PLANNTNG ENVIRONMENT
that is no higher than the greenhouse gas emission levels of a state-ofthe-art combined cycle
natural gas generation facility. The standards for Oregon and Califomia are currently set at 1,100
lb COzlMWh, which is dehned 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 970Ib COzlMWh.
Renewable Portfolio Standards
An RPS requires a retail seller of electricity to include in its resource portfolio a certain amount
of electricity from renewable energy resources, such as wind, geothermal and solar energy. The
retailer can satisfy this obligation by using renewable energy from its own facilities, purchasing
renewable energy from another supplier's facilities, using Renewable Energy Credits (RECs)
that certify renewable energy has been created, or a combination of all of these.
RPS policies are currently implemented at the state level and vary considerably in their
renewable targets (percentages), target dates, resource/technology eligibility, applicability of
existing plants and contracts, arrangements for enforcement and penalties, and use of REC
trading. By the end of 2016, twenty-nine states, the District of Columbia, and three territories
had adopted a mandatory RPS, and eight states and one territory had adopted RPS goals.12
In PacifiCorp's service territory, California, Oregon, and Washington have each adopted a
mandatory RPS, and Utah has adopted an RPS goal. Each of these states' legislation and
requirements are summarized in Table 3.1, with additional discussion below.
Table 3.1- State RPS Requirements
California
California originally established its RPS program with passage of SB 1078 in 2002. Several bills
that have since been passed into law to amend the program. In the 2011 First Extraordinary
Special Session, the California Legislature passed SB 2 (lX) to increase Califomia's RPS to 33
r2 National Conference of State Legislatures (NCSL) http://www.ncsl.org/research/energy/renewable-portfolio-
standards.aspx
13 Adjustments for generated or purchased from qualifiring zero carbon emissions and carbon capture sequestration
and DSM.
42
California Oregon Washington Utah
Legislation . Senate Bill 1078 (2002)
o Assembly Bill 200 (2005). Senate Bill 107 (2006)
o Senate Bill 2 First
Extraordinary Session (201 1). Senate Bill 350 (2015)
. Senate Bill 838 Oregon
Renewable Energy Act
(2007)
o House Bill 3039 (2009)
o House Bill 1547-B (2016)
o Initiative Measure No.
937 (2006)
. Senate Bill202
(2008)
Requirement
or Goal
. 20oZ by December 31,2013
o 25Vo by Deoember 3 I , 20 I 6. 33olo by December 31, 2020r 40oZ by December 3I,2024
o 4504 by December 31,2027
o 50o% by December 31,2030
and beyond* Based on the retail load for a
three-year compliance period
. 57o by December 3 1, 201 I
o 15% by December 31, 2015
o 2f/oby December 31, 2020
o 21Yoby December 3 l, 2025. 35% by December 31, 2030. 45Yoby December 31, 2035
o 50olo by December 31, 2040* Based on the retail load for
that year
o 3o/oby Januuy 1,2012
o 9o/oby Jantuy 1,2016
o 15%byJanuary 1,
2020 and beyond* Annual targets are
based on the average of
the utility's load for the
previous two years
c Goalof}}o/oby2025
(must be cost
effective. Annual targets are
based on the
adjustedt3 retail sales
for the calendar year
36 months before the
target year
PACIFICoRP - 20I7 IRP CHAPTER 3 -THE PLANNTNG ENVIRoNMENT
percent by 2020.14 SB 2 (1X) also expanded the RPS requirements to all retail sellers of
electricity and publicly owned utilities. ln October 2015, SB 350, the Clean Energy and
Pollution Reduction Act, was signed into law.ls SB 350 established a greenhouse gas reduction
target of40 percent below 1990 levels by 2030 and 80 percent below 1990 levels by 2050. SB
350 also expanded the state's renewables portfolio standard to 50 percent by 2030.
SB 2 (1X) created multi-year RPS compliance periods, which were expanded by SB 350. The
California Public Utilities Commission approved compliance periods and corresponding RPS
procurement requirements, which are shown in Table 3.2.
Table 3.2 - California Compliance Period Requirements
SB 2 (1X) established new "portfolio content categories" for RPS procurement, which delineated
the type of renewable product that may be used for compliance and also set minimum and
maximum limits on certain procurement content categories that can be used for compliance.
Portfolio Content Category I includes eligible renewable energy and RECs that meet either of
the following criteria:
Have a fust point of interconnection with a California balancing authority, have a first
point of interconnection with distribution facilities used to serve end users within a
California balancing authority area, or are scheduled from the eligible renewable energy
resource into a California balancing authority without substituting electricity from
another source;16 or
Have an agreement to dynamically transfer electricity to a California balancing authority.
Portfolio Content Category 2 includes firmed and shaped eligible renewable energy resource
electricity products providing incremental electricity and scheduled into a California balancing
authority.
t4 http://www.leginfo.ca.gov/pub/l l-l2lbilUsenlsb_0001-0050/sbxl 2_bill20ll}4lz_chaptered.pdf
r5 https://leginfo.legislature.ca.gov/faces/billNavClient.xhfinl?bill_id:201 5201 60S8350
16 The use of another source to provide real-time ancillary services required to maintain an hourly or sub-hourly
import schedule into a California balancing authority is permitted, but only the fraction of the schedule actually
generated by the eligible renewable energy resource will count toward this portfolio content category
a
Compliance Period I (201l-2013)(20% * 201 I Retail Sales) + (20o/o * 2012 Retail Sales)
+ (20%* 2013 Retail Sales)
Compliance Period 2 (2014-2016)(21.7% * 2014 Retail Sales) + (23 .3% * 2015 Retail Sales)
+ (25%* 2016 Retail Sales)
Compliance Period 3 (2017-2020)(27% * 20 17 Retail Sales) + (29o/o * 201 8 Retail Sales)
+ (31% * 2019 Retail Sales) + (33% * 2020 Retail Sales)
Compliance Period 4 (2021-2024)(34.8% * 2021 Retail Sales) + (36.5% * 2022 Retail Sales)
+ (38.3%* 2023 Retail Sales) + (40%* 2024 Retail Sales)
Compliance Period 5 (2025-2027)(41.7% * 2025 Retail Sales) + (43 .3% * 2026 Retail Sales)
+ (45%* 2027 Retail Sales)
Compliance Period 6 (2028-2030)(46.7%* 2028 Retail Sales) + (48.3%* 2029 Retail Sales)
+ (50%* 2030 Retail Sales)
43
PACIFICoRP-20I7 IRP CHAPTER 3 _ THE PLANI.ING ENVIRONMENT
Portfolio Content Category 3 includes eligible renewable energy resource electricity products, or
any fraction of the electricity, including unbundled renewable energy credits that do not qualifr
under the criteria of Portfolio Content Category 1 or Portfolio Content Category 2.17
Additionally, the Califomia Public Utilities Commission established the balanced portfolio
requirements for contracts executed after June 1,2010. The balanced portfolio requirements set
minimum and maximum levels for the Procurement Content Category products that may be used
in each compliance period as shown in Table 3.3.
Table 3.3 - California Balanced Portfolio Requirements
In December 2011, the California Public Utilities Commission (CPUC) confirmed that multi-
jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits in the three
portfolio content categories. PacifiCorp is required to file annual compliance reports with the
CPUC and annual procurement reports with the California Energy Commission (CEC). SB 350
did not change the portfolio content categories for eligible renewable energy resources or the
portfolio balancing requirements exemption provided to PacifiCorp. For utilities subject to the
portfolio balancing requirements, the CPUC extended the compliance period 3 requirements
through 2030. The CPUC is in the process of an extensive rulemaking to implement the
remaining requirements under SB 350.
The full California RPS statute is listed under Public Utilities Code Section 399.11-399.32.
Additional information on the California RPS can be found on the CPUC and CEC websites.
Qualifying renewable resources include solar thermal electric, photovoltaic, landfill gas, wind,
biomass, geothermal, municipal solid waste, energy storage, anaerobic digestion, small
hydroelectric, tidal energy, wave energy, ocean thermal, biodiesel, and fuel cells using renewable
fuels. Renewable resources must be certified as eligible for the Califomia RPS by the CEC and
tracked in the Western Renewable Energy Generation Information System (WREGIS).
Oregon
Oregon established the Oregon RPS with passage of SB 838 in 2007. The law, called the Oregon
Renewable Energy Act, was adopted in June 2007 and provides a comprehensive renewable
energy policy for the state.l8 Subject to certain exemptions and cost limitations established in the
Oregon Renewable Energy Act, PacifiCorp and other quali$ing electric utilities must meet a
target of at least 25 percent renewable energy by 2025.In March 2016, the Legislature passed SB
t7 A REC can be sold either "bundled" with the underlying energy or "urbundled" as a separate commodity from the
energy itself into a separate REC trading market.
18 http://www.leg.state,or.us/07reglmeaspdflsb0800.dir/sb0838.en.pdf
Category I -Minimum of 50o/o ofRequirement
Category 3 - Maximum of 25% of RequirementCompliance Period I (2011-2013)
Compliance Period 2 (2014-2016)Category I - Minimum of 65% of Requirement
Category 3 - Maximum of l5Yo of Requirement
Compliance Period 3 (2017-2020)
Compliance Period 4 (2021-2024)
Compliance Period 5 (2025-2027)
Compliance Period 6 (2028-2030\
Category I - Minimum of 75%o of Requirement
Category 3 - Maximum of lloh of Requirement
44
PACIFICoRP - 20I7 IRP CHAPTER 3 -Tue PLANNTNG ENVIRONMENT
I547,te also referred to as Oregon's Clean Electricity and Coal Transition Act. In addition to
requiring Oregon to transition off coal by 2030, the new law doubled Oregon's RPS
requirements, which are to be staged at27 percentby 2025, 35 percent by 2030,45 percent by
2035, and 50 percent by2040 and beyond. Other components of SB 1547 include:
Development of a community solar program with at least l0 percent of the program
capacity reserved for low-income customers.
A requirement that by 2025, at least eight percent of the aggregate electric capacity of the
state's investor-owned utilities must come from small-scale renewable projects under 20
megawatts.
Creates new eligibility for pre-1995 biomass plants and associated thermal co-generation.
Under the previous law, pre-1995 biomass was not eligible until2026.
Direction to the state's investor-owned utilities to propose plans encouraging greater
reliance on electricity in all modes of transportation, in order to reduce carbon emissions.
Removal of the Oregon Solar Initiative mandate.2o
SB 1547 also modified the Oregon REC banking rules as follows
o RECs generated before March 8,2016, have an unlimited life.
o RECs generated during the first five years for long-term projects coming online between
March 8,2016, and December 31, 2022, have an unlimited life.
o RECs generated on or after March 8,2016, from resources that came online before
March 8,2016, expire five years beyond the year the REC was generated.
o RECs generated beyond the first five years for long-term projects coming online between
March 8,2016, and December 31, 2022, expire five years beyond the year the REC is
generated.
o RECs generated from projects coming online after December 31, 2022, expire five years
beyond the year the REC is generated.
o Banked RECs can be surrendered in any compliance year regardless of vintage
(eliminates the "first-in, first-out" provision under SB 838).
To qualiff as eligible, the RECs must be from a resource certified as Oregon RPS eligible by the
Oregon Department of Energy and tracked in WREGIS.
Qualifying renewable energy sources can be located anywhere in the United States portion of the
Westem Electricity Coordinating Council geographic area, and a limited amount of unbundled
renewable energy credits can be used toward the annual compliance obligation. Eligible
renewable resources include electricity generated from wind, solar photovoltaic, solar thermal,
wave, tidal, ocean thermal, geothermal, certain types of biomass and biogas, municipal solid
waste, and hydrogen power stations using anhydrous ammonia.
Electricity generated by a hydroelectric facility is eligible if the facility is not located in any
federally protected areas designated by the Pacific Northwest Electric Power and Conservation
re https://olis.leg.state.or.usllizJ20l6RllDownloads/NleasureDocument/SB 1547lEnrolled
20 ln 2009, Oregon passed House Bill 3039, also called the Oregon Solar Initiative, requiring that on or before
January 7,2020, the total solar photovoltaic generating nameplate capacity must be at least 20 megawatts from all
electric companies in the state. The Public Utility Commission of Oregon determined that PacifiCorp's share of the
Oregon Solar Initiative was 8.7 megawatts.
o
a
o
a
45
PACIFICoRP - 20 I7 IRP CgepTen 3 -TTn PLANNING ENVIRoNMENT
Planning Council as of July 23, 1999, or any area protected under the federal Wild and Scenic
Rivers Act, P.L. 90-542, or the Oregon Scenic Waterways Act, ORS 390.805 to 390.925; or if
the electricity is attributable to efficiency upgrades made to the facility on or after January l,
1995, and up to 50 average megawatts of electricity per year generated by a certified low-impact
hydroelectric facility owned by an electric utility and up to 40 average megawatts of electricity
per year generated by certified low-impact hydroelectric facilities not owned by electric utilities.
PacifiCorp files an annual RPS compliance report by June 1 of every year and a renewable
implementation plan on or before January 1 of even-numbered years, unless otherwise directed
by the Public Utility Commission of Oregon. These compliance reports and implementation
plans are available on PacifiCorp's website.2l
The full Oregon RPS statute is listed in Oregon Revised Statutes (ORS) Chapter 469A and the
solar capacity standard is listed in ORS Chapter 757. The Public Utility Commission of Oregon
rules are in Oregon Administrative Rules (OAR) Chapter 860 Division 083 for the RPS and
OAR Chapter 860 Division 084 for the solar photovoltaic program. The Oregon Department of
Energy rules are under OAR Chapter 330 Division 160.
Utah
In March 2008, Utah's governor signed Utah SB 202,the Energy Resource and Carbon Emission
Reduction tnitiative.22 The Energy Resource and Carbon Emission Reduction Initiative is
codified in Utah Code Title 54 Chapter 17. Among other things, this law provides that, beginning
in the year 2025,20 percent of adjusted retail electric sales of all Utah utilities be supplied by
renewable energy if it is cost effective. Retail electric sales will be adjusted by deducting the
amount of generation from sources that produce zero or reduced carbon emissions and for sales
avoided as a result of energy efficiency and demand side management programs. Qualifying
renewable energy sources can be located anywhere in the Westem Electricity Coordinating
Council areas, and unbundled renewable energy credits can be used for up to 20 percent of the
annual qualifying electricity target.
Eligible renewable resources include electricity from a facility or upgrade that becomes
operational on or after January l, 1995, that derives its energy from wind, solar photovoltaic,
solar thermal electric, wave, tidal or ocean thermal, certain types of biomass and biomass
products, landfill gas or municipal solid waste, geothermal, waste gas and waste heat capture or
recovery, and efficiency upgrades to hydroelectric facilities ifthe upgrade occurred after January
I, 1995. Up to 50 average megawatts from a certified low-impact hydro facility and in-state
geothermal and hydro generation without regard to operational online date may also be used
toward the target. To assist solar development in Utah, solar facilities located in Utah receive
credit for 2.4 kilowatt-hours of qualifying electricity for each kWh of generation.
Under the Carbon Reduction Initiative, PacifiCorp is required to file a progress report by
January 1 of each of the years 2010,2015,2020 afi2024. Following PacifiCorp's December 31,
2009 progress report, the Utah Division of Public Utilities' report to the Legislature stated:
"Given PacifiCorp's projections of its loads and qualifying electricity for 2025, PacifiCorp is
well positioned to meet a target of 20 percent renewable energy by 2025."
2 I www.pacifi cpower.neVORrps
22 http: I lle ttah.gov / -2008 lbills/sbillenr/sb0202.pdf
46
PACIFICoRP-2017 IRP CHAPTER 3 -THE PLANNING ENVIRONMENT
PacifiCorp filed its most recent progress report on December 31, 2014. This report showed that
the Company is positioned to meet its 20 percent target requirement of approximately 5.2 million
megawatt-hours of renewable energy in 2025 from existing company-owned and contracted
renewable energy sources.
In2027, the legislation requires a commission report to the Utah Legislature, which may contain
any recommendation for penalties or other action for failure to meet the 2025 target. The
legislation requires that any recommendation for a penalty must provide that the penalty funds be
used for demand side management programs for the customers of the utility paying the penalty.
Washington
In November 2006, Washington voters approved I-937, a ballot measure establishing the Energy
Independence Act, which is an RPS and energy efficiency requirement applied to qualifying
electric utilities, including PacifiCorp.23 The law requires that qualifuing utilities procure at least
three percent of retail sales from eligible renewable resources or RECs by January I, 2012
through 2015; nine percent of retail sales by January 1,2016 through 2019; and 15 percent of
retail sales by January 1,2020, and every yearthereafter.
Eligible renewable resources include electricity produced from water, wind, solar energy,
geothermal energy, landfill gas, wave, ocean, or tidal power, gas from sewage treatment
facilities, biodiesel fuel with limitation, and biomass energy based on organic byproducts of the
pulp and wood manufacturing process, animal waste, solid organic fuels from wood, forest, or
field residues, or dedicated energy crops. Qualifying renewable energy sources must be located
in the Pacific Northwest or delivered into Washington on a real-time basis without shaping,
storage, or integration services. The only hydroelectric resource eligible for compliance is
electricity associated with efficiency upgrades to hydroelectric facilities. Utilities may use
eligible renewable resources, RECs, or a combination of both to meet the RPS requirement.
PacifiCorp is required to file an annual RPS compliance report by June I of every year with the
Washington Utilities and Transportation Commission demonstrating compliance with the Energy
Independence Act. PacifiCorp's compliance reports are available on PacifiCorp's website.24
The Washington Utilities and Transportation Commission adopted final rules to implement the
initiative; the rules are listed in the Revised Code of Washington (RCW) 19.285 and the
Washington Administrative Code (WAC) 480- I 09.
The electric transportation market remains in an emerging state,2s and plug-in electric vehicles
currently comprise a negligible share of PacifiCorp's load. But this rapidly evolving market
represents a potential driver of future load growth and an opportunity to increase the efficiency
of the electrical system and provide benefits for all PacifiCorp customers. In addition, increased
adoption of electric transportation has the ability to improve air quality, reduce greenhouse gas
23 http://www. secstate.wa. gov/elections/initiatives/text/I93 7.pdf
2a https ://www.pacifi cpower .netl abourtJr:' lwrcr/wrr.html
25 ln20l6,the market share of plug-in elechic vehicles was under lpercent:
https ://www. nada. org/WorkArea./DownloadAsset. asp x? id2 I 47 484 66 I 3
47
PacmrConp-20l7IRP CHeprpR 3 -THe PLA}.rNrNc Ej'TVIRONMENT
emissions, improve public health and safety, and create financial benefits for drivers, which can
be a particular benefit for low and moderate income populations.
Given the negligible share of PacifiCorp's load, a forecast explicitly identifring the load
associated with electric transportation on PacifiCorp's system is currently unavailable. Electric
vehicle load is, however, currently captured and reflected in the Company's load forecast.
PacifiCorp continues to actively engage with local, regional, and national stakeholders and
participate in state regulatory processes that can inform future planning and load forecasting
efforts.
The issues involved in relicensing hydroelectric facilities are multifaceted. They involve
numerous federal and state environmental laws and regulations, and the participation of
numerous stakeholders including agencies, Native American tribes, non-govemmental
organizations, and local communities and governments.
The value of relicensing hydroelectric facilities is continued availability of energy, capacity, and
ancillary services associated with hydroelectric generation. Hydroelectric projects can often
provide unique operational flexibility because they can be called upon to meet peak customer
demands almost instantaneously and back up intermittent renewable resources such as wind. In
addition to operational flexibility, hydroelectric generation does not have the emissions concerns
of thermal generation and can also often provide important ancillary services, such as spinning
reserve and voltage support, to enhance the reliability of the transmission system. With the
exception of the Klamath River, Weber and Prospect No. 3 hydroelectric projects, all of
PacifiCorp's applicable generating facilities now operate under contemporary licenses from the
Federal Energy Regulatory Commission (FERC). Under a2010 settlement agreement, amended
in 2016, the 169 MW Klamath Hydroelectric Project will operate under its existing license
through December 31, 2020. Project operations are then anticipated to end in 2021 with the
decommissioning of the project. The assumed date of Klamath project removal in the IRP is
January 1,2021. The 3.85 MW Weber project and the 7.2}dW Prospect No. 3 project are
currently in the FERC relicensing process.
The FERC hydroelectric relicensing process can be extremely political and often controversial.
The process itself requires that the project's impacts on the surrounding environment and natural
resources, such as fish and wildlife, be scientifically evaluated, followed by development of
proposals and alternatives to mitigate those impacts. Stakeholder consultation is conducted
throughout the process. If resolution of issues cannot be reached in this process, litigation often
ensues, which can be costly and time-consuming. The usual alternative to relicensing is
decommissioning. Both choices, however, can involve significant costs.
FERC has sole jurisdiction under the Federal Power Act to issue new operating licenses for non-
federal hydroelectric projects on navigable waterways, federal lands, and under other criteria.
FERC must find that the project is in the broad public interest. This requires weighing, with
"equal consideration," the impacts of the project on fish and wildlife, cultural resources,
recreation, land use, and aesthetics against the project's energy production benefits. Because
some of the responsible state and federal agencies have the ability to place mandatory conditions
in the license, FERC is not always in a position to balance the energy and environmental
equation. For example, the National Oceanic and Atmospheric Administration Fisheries agency
48
PAcruConp-2017 IRP CHAPTER 3 _THE PLANNITNG ENVIRONMENT
and the U.S. Fish and Wildlife Service have the authority in the relicensing process to require
installation of fish passage facilities (fish ladders and screens) and to specify their design. This is
often the largest single capital investment that will be considered in relicensing and can
significantly impact project economics. Also, because a myriad of other state and federal laws
come into play in relicensing, most notably the Endangered Species Act and the Clean Water
Act, agencies' interests may compete or conflict with each other, leading to potentially contrary
or additive licensing requirements. PacifiCorp has generally taken a proactive approach towards
achieving the best possible relicensing outcome for its customers by engaging in negotiations
with stakeholders to resolve complex relicensing issues through settlement agreements that are
submitted to FERC for incorporation into a new license. FERC welcomes license applications
that reflect broad stakeholder involvement or that incorporate measures agreed upon through
multi-party settlement agreements. History demonstrates that with such support, FERC generally
accepts proposed new license terms and conditions reflected in settlement agreements.
Potential Impact
Relicensing hydroelectric facilities involves significant process costs. The FERC relicensing
process takes a minimum of five years and may take longer, depending on the characteristics of
the project, the number of stakeholders, and issues that arise during the process. As of
December 31, 2016, PacifiCorp had incurred approximately $16 million in costs for license
implementation and ongoing hydroelectric relicensing, which are included in construction work-
in-progress on PacifiCorp's Consolidated Balance Sheet. As current or upcoming relicensing and
settlement efforts continue for the Weber, Prospect No. 3, and other hydroelectric projects,
additional process costs are being or will be incurred that will need to be recovered from
customers. Hydroelectric relicensing costs have and will continue to have a significant impact on
overall hydroelectric generation cost. Such costs include capital investments and related
operations and maintenance costs associated with fish passage facilities, recreational facilities,
wildlife protection, cultural and flood management measures. Project operational and flow-
related changes, such as increased in-stream flow requirements to protect aquatic resources, can
also directly result in lost generation. The majority of these relicensing and settlement costs
relate to PacifiCorp's three largest hydroelectric projects: Lewis River, Klamath River, and
North Umpqua.
Treatment in the IRP
The known or expected operational impacts related to FERC orders and settlement commitments
are incorporated in the projection of existing hydroelectric resources discussed in Chapter 5.
PacifiCorp's Approach to Hydroelectric Relicensing
PacifiCorp continues to manage the hydroelectric relicensing process by pursuing interest-based
resolutions or negotiated settlements as part of relicensing. PacifiCorp believes this proactive
approach, which involves meeting agency and others' interests through creative solutions, is the
best way to achieve environmental improvement while balancing customer costs and risks.
PacifiCorp also has reached agreements with licensing stakeholders to decommission projects
where that has been the most cost-effective outcome for customers.
49
PACIFICoRP_2017IRP CTnpTpn 3 _THE PLANNING ENVIRONMENT
Current rate designs in Utah have evolved over time based on orders and direction from the
Public Service Commission of Utah and settlement agreements between parties during general
rate cases. Most recently, current rates and rate design changes were adopted in Docket No. 13-
035-184. The goals for rate design are (generally) to reflect the cost to serve customers and to
provide price signals to encourage economically efficient usage. This is consistent with resource
planning goals that balance consideration of costs, risk, and long-run public policy goals. The
Company currently has a number of rate design elements that take into consideration these
objectives, in particular, rate designs that reflect cost differences for energy or demand during
different time periods and that support the goals of acquiring cost-effective energy efficiency.
Residential Rate Design
Residential rates in Utah are comprised of a customer charge and energy charges. The customer
charge is a monthly charge that provides limited recovery of customer-related costs incurred to
serve customers regardless of usage. All other remaining costs are recovered through volumetric-
based energy charges. Energy charges for residential customers are designed with an inclining-
tier rate structure so high usage during a billing month is charged a higher rate than low usage.
This gives customers a price signal to encourage reduced consumption. Additionally, energy
charges are differentiated by season with higher rates in the surlmer when the costs to serve are
higher. Residential customers also have an option for time-of-day rates. Time-of-day rates have a
surcharge for usage during the on-peak periods and a credit for usage during the off-peak
periods. This rate structure provides an additional price signal to encourage customers to use less
energy during the daily on-peak periods when energy costs are higher. Currently, less than one
percent of customers have opted to participate in the time-of-day rate option.
Changes in residential rate design that might facilitate IRP objectives include a critical peak
pricing program or an expansion of time-of-use rates. These types of rate designs are discussed
in more detail in Volume I, Chapter 6 (Resource Options). As part of the Sustainable
Transportation and Energy Plan (STEP) legislation enacted in SB I15, the company developed a
pilot time-of-use program to encourage off-peak charging of electric vehicles for residential
customers. The results of this pilot may inform future rate design offerings. Any changes in
standard residential rate design or institution of optional rate options to support energy efficiency
or time-differentiated usage should be balanced with the recovery of fixed costs to ensure price
signals are economically efficient and do not unduly shift costs to other customers.
With the growth in the number of customers adopting private distributed generation, rates will
need to evolve to address the change in usage requirements and ensure appropriate cost recovery
from these customers. Additionally, with net metering, which is currently required to be offered,
the netting process uses the retail rate to compensate customers for energy they put on the grid.
A deeper consideration of the implications of current rates and rate designs is necessary to
address these growing issues and ensure the appropriate price signals are set for the changing
circumstances. To this end, the company proposed a new rate design for residential customer
generators who participate in net metering. The proposed rates are intended to mitigate the shift
of fixed costs from net metering customers to other customers.
50
PACIFICoRP - 20 I7 IRP CHAPTER 3 -THE PLANNING ENVIRONMENT
Commercial and Industrial Rate Design
Commercial and industrial rates in Utah include customer charges, facilities charges, power
charges (for usage over 15 kW) and energy charges. As with residential rates, customer charges
and facilities charges are generally intended to recover costs that do not vary with energy usage.
Power charges are applied to a customer's monthly demand on a kW basis and are intended to
recover the costs associated with demand or capacity needs. Energy charges are applied to the
customer's metered usage on a kWh basis. All commercial and industrial rates employ seasonal
variations in power and/or energy charges with higher rates in the surrmer months to reflect the
higher costs to serve during the summer peak period. Additionally, for customers with load
1,000 kW or more, rates are further differentiated by on-peak and off-peak periods for both
power and energy charges. For commercial and industrial customers with load less than 1,000
kW, the company offers two optional time-of-day rates-one that differentiates energy rates for
on- and off-peak usage, and one that differentiates power charges by on- and off-peak usage.
Currently, about 16 percent of the eligible customers are on the energy time-of-day option and
less than one percent are on the power time-of-day option.
Irrigation Rate Design
Irrigation rates in Utah are comprised of an annual customer charge, a monthly customer charge,
a seasonal power charge, and energy charges. The annual and monthly customer charges provide
some recovery of customer-related costs incurred to serve customers regardless of usage. All
other remaining costs are recovered through a seasonal power charge and energy charges. The
power charge is for the irrigation season only and is designed to recover demand-related costs
and to encourage irrigation customers to control and reduce power consumption. Energy charges
for inigation customers are designed with two options. One is a time-of-day program with higher
rates for on-peak consumption than for off-peak consumption. Irrigation customers also have an
option to participate in a third-party operated Irrigation Load Control Program. Customers are
offered a financial incentive to participate in the program and give the company the right to
intemrpt service to the participating customers when energy costs are higher.
PacifiCorp and the CAISO launched the EIM November I,2014. The EIM is a voluntary market
and the f,rrst western energy market outside of California. The EIM covers eight states-
California, Nevada, Arizona, Idaho, Oregon, Utah, Washington, and Wyoming-and uses
CAISO advanced market systems to dispatch the least-cost resources every five minutes. Since
the launch of the EIM, NV Energy joined the market December 1,2015; Puget Sound Energy
and Arizona Public Service joined October 1,2016. Entities scheduled to join the EIM include
PGE (October 2017),Idaho Power Company (April2018), Seattle City Light (April 2019), and
the Balancing Authority of Northern Califomia (April 2019). PacifiCorp continues to work with
the CAISO, existing and prospective EIM entities, and stakeholders to enhance market
functionality and support market growth.
51
PACIFICORP - 20 I7 IRP CHAPTER 3 - THE PLANNING ENVIRoNMENT
Figure 3.6- Energy Imbalance Market Expansion
Seottle
City t'ts, Puset sound
Portlond
\Generol F
Electric .fa 6
-a
Morket operolor
f Colifornio ISO
EIM €nlity
! &rre porriciponts
! Pbnned EIM entry 2017
! tlonned EIM enrry 20l8
! Plonned EIM enrry 2019
The EIM has produced significant monetary benefits ($142.62 million total footprint-wide
benefits as of December 31, 2016), quantified in the following categories: (1) more efficient
dispatch, both inter- and intra-regional, by automating dispatch every 15 minutes and every five
minutes within and across the EIM footprint; (2) reduced renewable energy curtailment by
allowing balancing authority areas to export or reduce imports of renewable generation that
would otherwise need to be curtailed; and (3) reduced need for flexibility reserves in all EIM
balancing authority areas, also referred to as diversity benefits, which reduces cost by
aggregating load, wind, and solar variability and forecast errors of the EIM footprint.
A significant contributor to EIM benefits are transfers across balancing authority areas,
providing access to lower-cost supply, while factoring in the cost of compliance with greenhouse
gas emissions regulations when energy is transferred into the CAISO balancing authority area to
serve California load. The transfer volumes are therefore a good indicator of a portion of the
52
PacmrConp-2017IRP CHAPTER 3 - THE PLANNING ENVIRONMENT
benefits attributed to the EIM. Transfers can take place in both the five and l5-minute market
dispatch intervals.
The CAISO is exploring expanding into a regional ISO, which requires changes to California
laws that mandate that the governing board of the CAISO be appointed by California's governor.
As of March 2017, a proposal for regional ISO governance has not been submitted to the
California Legislature for consideration. Califomia SB 350 authorized the Califomia Legislature
to consider making changes to current laws that would create an independent governance
structure for a regional ISO up until the conclusion of the 2017 legislative session, which ends
September 15,2017. If legislation is passed, PacifiCorp will coordinate with its state regulatory
authorities on evaluating next steps.
PacifiCorp issued and will issue multiple requests for proposals (RFP) to secure resources or
transact on various energy and environmental attribute products. Table 3.4 summarizes current
RFP activities.
Table 3.4 - PacifiCorp's Request for Proposal Activities
Demand Side Management (DSM) Resources
Ir.2016, through competitive procurement processes, the company selected vendors to continue
and adaptively manage the successful, cost-effective delivery of its two largest Class 2 DSM
programs: Home Energy Savings and wattsmart Business. Home Energy Savings vendor services
include the management of incentives for lighting, appliances, new homes, and other energy
efficiency measures and the delivery of wattsmart starter kits containing efficient light bulbs and
20 I 7 Transfer Frequency
Response RFP
Purchase tansferred
frequency response Closed lanuary 2017 February 20 I 7
2016 Natural Gas Asset
Management and Supply RFP
Canadian natural gas
transportation and
supply
Closed April20l6 June 20 I 6
Pwchase renewable
energy resources and
credits
2016 Renewable RFP Closed April20l6 September 2016
2015 Market Resource RFP
Purchase firm power
for PacifiCorp's
westem balancing
authority
Closed November 20 l5 November 2015
Renewable energy credits (Sale)Excess system RECs Ongoing Based on
specific need
Ongoing
Oregon compliance
needs
Ongoing Based on
soecific need
Renewable energy credits
(Purchase)
Ongoing
Renewable energy credits
(Purchase)
Washington
compliance needs
Ongoing Based on
specific need
Ongoing
Renewable energy credits
(Purchase)
California
compliance needs
Ongoing Based on
specific need
Ongoing
System balancing Ongoing Based on
specific need
OngoingShort-term Market (Sales)
53
PACIFICoRP_20I7IRP CHAPTER 3 _THE PLANNING ENVIRONMENT
water-saving measures. Wattsmart Business vendor services include management of trade ally
networks to deliver energy efficiency options to commercial, industrial, and irrigation customers;
targeted offerings for small business customers; point-of-purchase incentives for efficient
lighting; efficiency options for oil and gas customers; and engineering services for large custom
projects. ln20l7, PacifiCorp will evaluate and re-procure, as appropriate, the delivery contract(s)
for residential behavior program(s).
2017 Transfer Frequency Response Request for Proposals
As a member of the Northwest Power Pool Frequency Response Sharing Group, the company
must demonstrate annually that it used reasonable commercial efforts to secure transferred
frequency response for our own units as a balancing authority area operator under BAL-003.01.
PacifiCorp submitted an RFP to market to demonstrate reasonable commercial efforts.
PacifiCorp evaluated the bids received and found all bids uneconomic relative to available
alternatives. No new transactions were completed based on the RFP.
Natural Gas Asset Management and Supply Request for Proposals
PacifiCorp issued a Natural Gas Asset Management and Supply RFP in April 2016 seeking
natural gas supply offers at the Kingsgate point of delivery. In purchasing natural gas under the
RFP. PacifiCorp proposed temporarily assigning a portion of its existing transportation capacity
to the awarded bidder. No viable transactions were completed as a result of the RFP.
Renewable Resource and REC Request for Proposals
In April 2016, PacifiCorp issued RFPs to market seeking cost-effective renewables and RECs
that could be used to meet the state RPS requirements in California, Oregon, and Washington.
With the extension and phasing out of federal tax incentives for renewables, the company
initiated a timely RFP to evaluate the potential customer benefits from acquiring renewable
resources or RECs in the near term. The issuance of the RFP was also driven by policy changes
to the Oregon and California RPS, which increased the compliance requirements for both states.
After careful evaluation of both the resource and REC bids received, the company opted to
pursue a REC purchase strategy, which proved to be the least-cost, least-risk procurement option.
2Ol5 Market Resource Request for Proposals
PacifiCorp issued a2015 Market Resource RFP in November 2015 seeking firm physical power
delivered to PacifiCorp's westem balancing authority area for term 2016 through 2018. No
viable transactions were completed as a result of the RFP.
Renewable Energy Credits (Sale) Request for Proposals
On an ongoing basis, and based on availability, PacifiCorp issues short-term RFPs to sell RECs
that are not required to be held and or retired for meeting regulatory requirements, such as state
RPS compliance obligations.
54
PecrrConp -2017IBP CHAPTER 3 -THE PLANNI.TG ENVIRONMENT
Short-Term Market Power Request for Proposals
PacifiCorp issued a short-term market power RFP in October 2015. PacifiCorp will continue to
evaluate the need to issue short-term market power RFPs on an as-needed basis for system
balancing purposes.
55
PACIFICoRP_2OI7IRP CHApTER 3 - Tr{E PLAr{NrNc ENvRoNTvg'NT
56
PACIFICoRP-20I7IRP CHAPTER 4 - TRANSMISSION
Cuaprpn 4 _ TnANSMISSION
Crr,lprrn Hrcrrr,rcrrr s
o PacifiCorp is obligated to plan for and meet its customers' future needs, despite
uncertainties sulrounding environmental and emissions regulations and potential new
renewable resource requirements. Regardless of future policy direction, PacifiCorp's
planned transmission projects are well aligned to respond to a change in policy direction
and comply with increasing reliability requirements, while providing sufficient flexibility
to ensure resources can cost-effectively and reliably meet customer demand.
. Given the long periods of time necessary to site, permit and construct major new
transmission lines, these projects need to be planned in advance.
o PacifiCorp's transmission planning and benefits evaluation efforts adhere to regulatory
and compliance requirements and respond to commission and stakeholder requests for a
robust evaluation process and clear criteria for evaluating transmission additions.
o PacifiCorp requests acknowledgment of its plan to construct the Wallula to McNary
portion of the Walla Walla to McNary transmission project (Energy Gateway Segment A)
based on customer need and associated regulatory requirements. PacifiCorp requests
acknowledgement of its plan to construct the Aeolus to BridgeriAnticline portion of
Gateway West (Energy Gateway Sub-Segment D2) based on customer benefits and the
inclusion of this segment in the 2017 PacifrCorp IRP preferred portfolio.
o While construction of the balance of future Energy Gateway segments (i.e., Gateway
West, Gateway South, and Boardman to Hemingway) is beyond the scope of
acknowledgement for this IRP, these segments continue to offer benefits under multiple
future resource scenarios. Thus, continued permitting of these segments is warranted to
ensure the Company is well positioned to advance these projects as required.
PacifiCorp's bulk transmission network is designed to reliably transport electric energy from
generation resources (owned generation or market purchases) to various load centers. There are
numerous benefits associated with a robust transmission network:
1. Reliable delivery of energy to continuously changing customer demands under a wide
variety of system operating conditions.
2. Ability to meet aggregate electrical demand and customers' energy requirements at all
times, taking into account scheduled outages and the ability to maintain reliability during
unscheduled outages.
3. Economic exchange of electric power between PacifiCorp and third-party systems and
electric utility industry participants.
4. Development of economically feasible generation resources in areas where it is best
suited.
5. Access to diverse energy resource areas to support customer needs.
6. Protection against extreme market conditions where limited transmission constrains
energy supply.
7. Ability to meet obligations and requirements of PacifiCorp's Open Access Transmission
Tariff (OATT).
8. Increased capability and capacity to access energy supply markets.
57
PecmrConp - 2017 IRP CuaprgR 4 - TRANSMISSION
PacifiCorp's transmission network is a critical component of the IRP process and is highly
integrated with other transmission providers in the western United States. It has a long history of
reliable service in meeting the bulk transmission needs of the region. Its purpose will become
more critical in the future as energy resources become more dynamic and customer demand
continues to grow.
Open Access Transmission Tariff
Consistent with the requirements of its OATT, approved by the Federal Energy Regulatory
Commission (FERC), PacifiCorp plans and builds its transmission system based on two
customer-type agreements-network customer or point-to-point transmission service. For the
network customers, PacifiCorp uses customer ten-year load and resource (L&R) forecasts, as
well as network transmission service requests. Each year, the Company solicits L&R data from
each of its network customers to determine future load and resource requirements for all
transmission network customers. These customers include PacifiCorp Energy Supply
Management (ESM) (which serves PacifiCorp's retail customers and comprises the bulk of the
Company's transmission network customer needs), Utah Associated Municipal Power Systems,
Utah Municipal Power Agency, Deseret Power Electric Cooperative (including Moon Lake
Electric Association), Bonneville Power Administration, Basin Electric Power Cooperative,
Black Hills Power, Tri-State Generation & Transmission, the United States Department of the
Interior Bureau of Reclamation, and the Western Area Power Administration.
The Company uses its customers' L&R forecasts and best available information, including
transmission service requests, to determine project need and investment timing. If customer L&R
forecasts change significantly, PacifiCorp may consider alternative deployment scenarios or
schedules for its project investment, as appropriate. In accordance with FERC guidelines, the
Company is able to reserve transmission network capacity based on these data. PacifiCorp's
experience, however, is that the lengthy planning, permitting and construction timeline required
for significant transmission investments, as well as the typical useful life of these facilities, is
well beyond the lO-year timeframe of L&R forecasts.r A2}-year planning horizon and ability to
reserve transmission capacity to meet existing and forecasted need over that timeframe is more
consistent with the time required to plan for and build large-scale transmission projects, and
PacifiCorp supports clear regulatory acknowledgement of this reality and corresponding policy
guidance.
For point-to-point transmission service, the OATT requires the Company to accommodate the
service on existing transmission infrastructure using existing capacity or build transmission
system infrastructure as required to provide the service. The required action is determined with
each point-to-point transmission service request through FERC-approved study processes that
identify the transmission need.
I For example, PacifiCorp's application to begin the Environmental Impact Statement (EIS) process for the Gateway
West segment of its Energy Gateway Transmission Expansion Project was filed with the Bureau of Land
Management (BLM) in2007. A partial Record of Decision was received in late April 2013, and a supplemental
Record of Decision was received in January 2017.
58
PACIFICoRP-20I7IRP Crnprpn 4 -TRANSMSSION
Reliability Standards
PacifiCorp is required to meet mandatory FERC, North American Electric Reliability
Corporation (NERC), and Westem Electricity Coordinating Council (WECC) reliability
standards and planning requirements. PacifiCorp's transmission system operations also responds
to requests issued by Peak Reliability as the NERC Reliability Coordinator. The Company
conducts annual system assessments to confirm minimum levels of system performance during a
wide range of operating conditions, from serving loads with all system elements in service to
extreme conditions where portions of the system are out of service. Factored into these
assessments are load growth forecasts, operating history, seasonal performance, resource
additions or removals, new transmission asset additions, and the largest transmission and
generation contingencies. Based on these analyses, PacifiCorp identifies any potential system
deficiencies and determines the ffiastructure improvements needed to reliably meet customer
loads. NERC planning standards define reliability of the interconnected bulk electric system in
terms of adequacy and security. Adequacy is the electric system's ability to meet aggregate
electrical demand for customers at all times. Security is the electric system's ability to withstand
sudden disturbances or unanticipated loss of system elements. Increasing transmission capacity
often requires redundant facilities in order to meet NERC reliability criteria.
This chapter provides:
o Justification supporting acknowledgement of the Company's plan to construct the
Wallula to McNary and Aeolus to Bridger/Anticline transmission projects.
o Support for the Company's plan to continue permitting Gateway South and the balance of
Gateway West;
. Key background information on the evolution of the Energy Gateway Transmission
Expansion Plan; ando An overview of the Company's investments in recent short-term system improvements
that have improved reliability, helped to maximize efficient use of the existing system,
and enabled the Company to defer the need for larger scale infrastructure investment.
The Wallula to McNary transmission project is required to satisfy PacifiCorp's federal regulatory
obligations to its transmission customers under its OATT. Specifically obligations include an
active transmission service agreement with a transmission customer where service is contingent
upon completion of the project. The project consists of a 30-mile,230 kilovolt (kV) transmission
line between Wallula, Washington, and McNary, Oregon, and represents a portion of the Walla
Walla, Washington, to McNary Energy Gateway transmission project (Segment A). Since 2008,
the Company has worked with stakeholders to permit the transmission project. In 2009, the
Company decided to move forward with building the Wallula-to-McNary portion of the
transmission line and delay development of the Wallula-to-Walla-Walla portion based on
continuing evaluation of evolving regional transmission and resource plans. ln 2011, PacifiCorp
obtained a certificate of public convenience and necessity from the Public Utility Commission of
Oregon. In 2014, transmission customers determined a continued need for the Wallula to
McNary transmission line, which prompted the Company to restart permitting and rights-of-way
acquisition activities. In addition, federal, county and local public outreach activities were
reinitiated in 2015. The project is estimated to be placed into servicein2017-2018, subjectto
completion of permitting, rights-of-way acquisition, and interconnection to the McNary
substation. To meet its obligation to transmission customers under the OATT, the Company
requests acknowledgement of the Wallula to McNary transmission project in the 2017 IRP.
59
PACIFICoRP _ 20 I7 IRP CHAPTER 4 _ TRANSMISSION
Factors Supporting Acknowledgement
The key driver supporting PacifiCorp's request for acknowledgement of the Wallula to McNary
transmission project is meeting its obligations to its transmission customers consistent with its
OATT. Without the transmission line, there is no available capacity to serve transmission
customers on the existing Wallula to McNary transmission line. This new line will enable the
Company to meet its obligation to serve transmission customers under the OATT and an
executed transmission service agreement, and improve reliability in the area by providing a
second connection between Wallula and McNary and a possible future connection between
Walla Walla and Wallula (see "Plan to Continue - Wallula to McNary" section below). The
transmission line will support future resource growth, including access to renewable energy, and
transmission needs.
Currently there are only two megawatts posted for available transfer capacity on the existing line
between Wallula and McNary, which is insufficient to satisff the request for service that drives
the need for the project. By contrast, there was sufficient capacity associated with the new line
that was already in the permitting stage between Wallula and McNary that could be used for the
requested transmission service. Based on this information, it was determined that no new studies
were required to grant the transmission service request. The maximum transfer capability of the
upgraded Wallula to McNary path will be determined by completion of studies in concurrence
with the Western Electricity Coordination Commission Project Coordination, Path Rating and
Progress Report Processes guideline.
The rate offered by PacifiCorp to the transmission customer was a rolled-in or embedded rate.
Under FERC precedent, transmission rates are designed using an embedded cost approach,
which is the rolled-in embedded cost for the system as expanded. Embedded cost rates are
justified for transmission facilities that are part of the transmission network, such as the facilities
that will be installed as part of the Wallula to McNary project. Under FERC transmission pricing
policy and precedent, network transmission facilities enjoy a presumption of rolled-in rate
treatment so long as any degree of network integration or benefit is shown, and that benefit need
not be large to be significant. PacifiCorp's OATT contains additional guidance on cost
assignment. In section 1.27, "Network Upgrades" are defined as "Modifications or additions to
transmission-related facilities that are integrated with and support the Transmission Provider's
overall Transmission System for the general benefit of all users of such Transmission System."
Network Upgrade costs are typically shared by all network customers. The network concept is
supported by projected use of the new line by area network customers in an outage condition of
the existing line.
Reliability benefits correspond to the fact that with only a single line between Wallula and
McNary, line outages, either planned or unplanned, cause disruption of service to customers.
This disruption can result in loss of service under existing contracts or reduced reliability for
customers served from the Wallula substation. The second line provides service reliability in a
single line outage condition. Additionally, the new line will provide lightning protection,
allowing continued operation of the line if there is a lightning strike, whereas the existing line is
not protected. In the past, customer service has been disrupted due to line outages caused by
lightning strikes on the existing line. Constructing a second 230 kV line between the Wallula and
McNary substations will provide additional flexibility and added reliability to customers served
in the area and is required to comply with PacifiCorp's OATT and Federal Power Act
obligations. With the new line in place, outages on either the new or existing line can occur
60
PACIFICoRP - 20 I7 IRP Cuapren 4 - TRANSMrssroN
without intemrption of customer service, thus providing added reliability of service. The Walla
Walla to McNary transmission project alleviates a constrained transmission path used to move
resources into and out of the Walla Walla and Wallula areas. At this time, only the Wallula to
McNary transmission line segment is being constructed to meet a customer request for point-to-
point service under PacifiCorp's OATT. The segment between Walla Walla and Wallula will be
completed when there is a transmission customer need.
The below sections of the OATT outline the FERC requirements associated with providing
transmission service as requested. These requirements mandate completion of the project.
a OATT section 28.2: As a Transmission Provider, Pacif,rCorp is obligated to "plan,
construct, operate and maintain its Transmission System in accordance with Good Utility
Practice and its planning obligations in Attachment K in order to provide the Network
Customer with Network Integration Transmission Service over the Transmission
Provider's Transmission System. "
OATT section 15.4: 'olf the Transmission Provider determines that it cannot
accommodate a Completed Application for Firm Point-To-Point Transmission Service
because of insufficient capability on its Transmission System, the Transmission Provider
will use due diligence to expand or modifu its Transmission System to provide the
requested Firm Transmission Service consistent with its planning obligations in
Attachment K...."
These sections of the OATT require the transmission provided to perform transmission system
upgrades as required to serve customer need driven either from network or point-to-point
transmission service requests. The network needs are generated from the outcome of the yearly
network L&R planning study that shows projected load growth and required system changes to
meet this growth. The point-to-point needs are driven by specific point-to- point requests where
system changes are required to meet the requested service.
The Wallula to McNary transmission project will offer benefits under multiple, future resource
scenarios. In addition, as part of its asset exchange agreement with Idaho Power Company, there
is an option for Idaho Power to partner with PacihCorp to construct the remaining Walla Walla
to Wallula portion of the transmission line.2 To ensure the Company is well positioned to
advance the projects as required to meet customer need, PacifiCorp believes it is prudent to
finalize permitting, acquire rights-of-way, and construct the Wallula to McNary segment of the
Walla Walla to McNary transmission project.
The 2017 PacifiCorp IRP preferred portfolio includes the Aeolus to Bridger/Anticline
transmission segment (Energy Gateway West, Sub-Segment D2). This segment is included in the
preferred portfolio as a component of the least-cost, least-risk strategy for existing and future
capacity delivery. The Aeolus to Bridger/Anticline transmission line relieves existing congestion
2 FERC Docket Nos. EC15-54 and ERl5-680
6l
PACIFICoRP - 20I7 IRP Crmprrn 4 - TRANsMrssroN
and facilitates the addition of new wind resources in Wyoming that can take full advantage of the
federal production tax credits (PTCs) and maximize customer benefits.
The 500 kV transmission segment extends 140 miles between the planned Aeolus substation near
Medicine Bow, Wyoming, and the new annex substation (Bridger/Anticline) that is located near
the existing Bridger substation in westem Wyoming. This transmission segment represents a
portion of the Windstar to Populus transmission project (Segment D), which is part of Energy
Gateway West. The Company, with stakeholder involvement, has pursued permitting of the
Energy Gateway West transmission project since 2008. On April 26,2013 the BLM released its
final Environmental Impact Statement (EIS). The Record of Decision was released on November
14, 2013, which provided a right-of-way grant for the federal properties. This transmission
segment was part of four Energy Gateway scenarios analyzed in the IRP and was ultimately
chosen to be included in the 2017 IRP preferred portfolio. Based on the IRP analysis, the Aeolus
to Bridger/Anticline transmission segment would be placed into service by the end of 2020,
subject to completion of local permitting and private rights-of-way acquisitions. To align
development of the Aeolus to Bridger/Anticline transmission segment with additional wind
projects that will further decarbonize PacifiCorp's portfolio and qualiff for the full value of
PTCs by year-end 2020, thereby maximizing customer benefits, the Company requests
acknowledgment in this IRP of the Aeolus to Bridger/Anticline transmission segment.
Factors Supporting Acknowledgement
Acknowledgment of the Aeolus to Bridger/Anticline transmission segment is supported by the
extensive analysis and demonstrated customer benefits that led to the inclusion of the
transmission line in the 2017 IRP preferred portfolio. This transmission segment will allow
PacifiCorp to implement system improvements, relieve existing congestion, and add incremental
Wyoming wind resources to support customer needs and deliver benefits to customers in the
most cost-effective way. Timing of construction is driven by the phase-out schedule of federal
PTCs, particularly the 2020 in-service requirements for 100 percent PTC eligibility. In addition
to supporting renewable resource additions in PacifiCorp's generation portfolio; quali$ing them
for full value of the PTCs, the new transmission segment will increase transfer capability out of
eastern Wyoming and alleviate voltage issues.
PacifiCorp's transmission system in eastern Wyoming is operating at capacity, specifically the
known WECC path#37 TOT 44, which limits transfer of resources from eastern Wyoming. The
TOT 4A cut plane is a WECC-defined path in southeastern Wyoming consisting of three 230 kV
transmission lines. The Aeolus to Bridger/Anticline transmission segment increases the transfer
capability from east to west across Wyoming by 750 MW. The WECC-rated path #37 TOT 4A
from the rating path catalog has a non-simultaneous rating of 1,025 MW. However, the
interaction with WECC path #38, TOT 48, limits the transfer capability of TOT 4,A. in real-time
operations. TOT 4.A. is currently identified as a constrained path in the mainly 230 kV
transmission system in eastem Wyoming. To relieve existing congestion and add resources in
eastern Wyoming, new transmission is required to increase transfer capability out of eastern
Wyoming.
Completion of the new transmission segment will allow the addition of up to 1,270 MWs of
additional wind resources (depending on re-dispatch) added to the system east of the TOT 4,A. cut
plane. PacifiCorp's preferred portfolio includes 1,100 MW of new wind resources, which reflects
a least-cost, least risk mix when the anticipated economic re-dispatch of resources in the area is
considered. Importantly, the transmission project includes critical voltage support, which is the
62
PACIFICoRP-20I7IRP CHAPTER 4 - TRANSMISSIoN
system limitation in the area. The new transmission capacity, voltage support, generation re-
dispatch, and a generator tripping scheme will allow for a disproportionate amount of wind
generation to be integrated into the system. The 230 kV transmission system today east of the
TOT 4A cut plane is operating at the limits of the system and has fully exhausted the ability to
interconnect additional resources behind the cut plane. The addition of this new transmission
segment has the potential to provide a path for projects sited east of the TOT 4A interconnected
at or near Aeolus Substation.
Voltage control issues under certain operating conditions have been identified on the
transmission system in southeastern Wyoming, with additions of wind resources in the area
exacerbating the issue. An identified solution to the voltage control issues is the addition of
transmission lines in the area. The transmission system in the area will benefit with the addition
of the new transmission segment by reducing voltage issues behind the TOT 4A cut plane that
currently restrict the addition of new resources interconnected behind the cut plane.
Other customer benefits of the new transmission segment include increased reliability of the
transmission system, congestion relief, reduction of capacity and energy losses on the
transmission system, and greater flexibility managing existing generation resources. Reliability
will be augmented with the addition of the new transmission segment, which will provide
support to the underlying 230 kV system during outages. Most of these outages result in a
deration of TOT 4A transfer capacity and some outage scenarios require significant generation
curtailment. The new 500 kV transmission segment will significantly reduce, if not eliminate,
many of the impacts caused by the 230 kV outages. Increased energy imbalance market (EIM)
and transmission wheeling opportunities under the OATT will also result from the additional
system capacity. Capacity and energy losses on the transmission system are reduced with the
new transmission segment, which has the potential to provide significant monetary savings over
time.
ln addition to the Windstar to Populus line (Energy Gateway Segment D), the Gateway West
transmission project also includes the Populus to Hemingway transmission segment (Energy
Gateway Segment E). In a future IRP, the Company will support a request for acknowledgement
to construct the balance of Gateway West with a cost-benefit analysis for the project. While the
Company is not requesting acknowledgement in this IRP of a plan to construct these segments at
this time, the Company will continue to permit the projects.
Windstar to Populus (Segment D)
The Windstar to Populus transmission project consists of three key sections:
a Dl-A single-circuit 230 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;
re 4.1 -ent D
o D2-A single-circuit 500 kV line
approximately 140 miles from the
runmng
planned
MING
63
PACIFICoRP-2OI7IRP Cnaprsn 4 - TRANsMrssroN
Aeolus substation to a new annex substation (Anticline) near the existing Bridger
substation in western Wyoming; and
D3-A single-circuit 500 kV line running approximately 200 miles between the new
annex substation (Anticline) and the recently constructed Populus substation in southeast
Idaho.
Populus to Hemingway (Segment E)
4.2 -The Populus to Hemingway transmission project consists
of two single-circuit 500 kV lines that run approximately
500 miles between the Populus substation in eastern
Idaho to the Hemingway substation in westem Idaho.
The Gateway West project would enable the Company to
more efficiently dispatch system resources, improve
performance of the transmission system (i.e., reduce line
losses), improve reliability, and enable access to a diverse range of new resource altematives
over the long term.
Under the National Environmental Policy Act, the BLM has completed the EIS for the Gateway
West project. The BLM released its final EIS on April 26, 2013, followed by the Record of
Decision on November 14,2013, providing a right-of-way grant for all of Segment D and most
of Segment E of the project. The Agency chose to defer its decision on the western-most portion
of Segment E of the project located in Idaho in order to perform additional review of the Morley
Nelson Snake River Birds of Prey Conservation Area. Specifically, the sections of Gateway
West that were deferred for a later Record of Decision include the sections of Segment E from
Midpoint to Hemingway and Cedar Hill to Hemingway. A Record of Decision for these final
sections of Segment E was issued on January 19,2017 .
As part of PacifiCorp's Energy Gateway Transmission
Expansion, the Company is planning to build a high-
voltage transmission line, known as Gateway South
(Segment F), which extends approximately 400 miles
from the planned Aeolus substation in southeastern
Wyoming into the Clover substation near Mona, Utah.
Figure 4.3 - Segment F
The BLM published its Notice of Intent in the Federal
Register in April 2011, 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 final EIS was released May 2016 and the Record of Decision was signed
December 13,2016.
The Gateway West and Gateway South transmission projects continue to offer benefits under
multiple, future resource scenarios. To ensure the Company is well positioned to advance the
o
E
IDAHON
C.tu
64
PACIFICoRP_20I7 IRP CHapren 4 - TRANSMrssroN
projects, it is prudent for PacifiCorp to continue to permit the balance of Gateway West and
Gateway South transmission projects. The Records of Decision and rights-of-way grants contain
many conditions and stipulations that must be met and accepted before a project can move to
construction. PacifiCorp will continue the work necessary to meet these requirements and will
continue to meet regularly with the Bureau of Land Management to review progress.
Introduction
Given the long periods of time necessary to successfully site, permit and construct major new
transmission lines, these projects need to be planned well in advance. The Energy Gateway
Transmission Expansion Plan is the result of several robust local and regional transmission
planning efforts that are ongoing and have been conducted multiple times over a period of
several years. The purpose of this section is to provide important background information on the
transmission planning efforts that led to PacifiCorp's proposal of the Energy Gateway
Transmission Expansion Plan.
Background
Until PacifiCorp's announcement of Energy Gateway in2007, its transmission planning efforts
traditionally centered on the generation additions identified in the IRP. With timelines of seven
to ten years or more required to site, permit, and build transmission, this traditional planning
approach was proven problematic, leading to a perpetual state of transmission planning and new
transmission capacity not being available in time to be viable transmission resource options for
meeting customer need. The existing transmission system has been at capacity for several years,
and new capability is necessary to enable new resource development.
The Energy Gateway Transmission Expansion Plan, formally announced in May 2007, has
origins in numerous local and regional transmission planning efforts discussed further below.
Energy Gateway was designed to ensure a reliable, adequate system capable of meeting current
and future customer needs. Importantly, given the changing resource picture, its design supports
multiple future resource scenarios by connecting resource-rich areas and major load centers
across PacifiCorp's multi-state service area. In addition, the ability to use these resource-rich
areas helps position PacifiCorp to meet current state renewable portfolio requirements. Please
refer to the regional maps of wind, solar, biomass, and geothermal potential available on
PacifiCorp's Energy Gateway project website to see an overlay of the Energy Gateway project
and renewable resource potential.3 Energy Gateway has since been included in all relevant local,
regional and interconnection-wide transmission studies.
Planning Initiatives
Energy Gateway is the result of robust local and regional transmission planning efforts.
PacifiCorp has participated in mrmerous transmission planning initiatives, both leading up to and
since Energy Gateway's announcement. Stakeholder involvement has played an important role in
each of these initiatives, including participation from state and federal regulators, government
http ://www. pac i fi corp. com/tran/tp/eg. htm I
65
PacrnConp - 2017 IRP CHAPTER 4 - TRANSMISSIoN
agencies, private and public energy providers, independent developers, consumer advocates,
renewable energy groups, policy think tanks, environmental groups, and elected officials. These
studies have shown a critical need to alleviate transmission congestion and move constrained
energy resources to regional load centers throughout the west, and include:
o Northwest Transmission Assessment Committee NTAC)
The NTAC was the sub-regional transmission planning group representing the Northwest
region, preceding Northern Tier Transmission Group and ColumbiaGrid. The NTAC
developed long term transmission options for resources located within the provinces of
British Columbia and Alberta, and the states of Montana, Washington and Oregon to
serve Pacific Northwest loads and northern California.
a Rocky Mountain Area Transmission Study
Recommended transmission expansions
overlap significantly with Energy Gateway
configuration, including:o Bridger system expansion similar to
Gateway Westo Southeast Idaho to southwest Utah
expansion akin to Gateway Central
and Sigurd to Red Butteo Improved east-west connectivity
similar to Energy Gateway Segment
H altematives
o Western Governors' Ass ociation Trans miss io n Tas k Fo rce Report
Examined the transmission needed to
deliver the largely remote generation
resources contemplated by the Clean and
Diversified Energy Advisory Committee.
This effort built upon the transmission
previously modeled by the Seams Steering
Group-Western Interconnection, and
included transmission necessary to support a
range of resource scenarios, including high
efficiency, high renewables and high coal
scenarios. Again, for PacifiCorp's system,
the transmission expansion that supported
these scenarios closely resembled Energy Gateway's configuration.
l{estern Regional Transmission Expansion Partners hip (ZRTEP)
The WRTEP was a group of six utilities working with four western governors' offices to
evaluate the proposed Frontier Transmission Line. The Frontier Line was proposed to
connect Califomia and Nevada to Wyoming's Powder River Basin through Utah. The
utilities involved were PacifiCorp, Nevada Power, Pacific Gas & Electric, San Diego Gas
& Electric, Southern Califomia Edison, and Sierra Pacific Power.
a
o Northern Tier Transmission Group NTfq Transmission Planning Reports
"The analyses presented in this
Report suggest that well-
considered transmission
upgrades, capable of giving LSEs
greater access to lower cost
generation and enhancing fuel
diversity, are cost-effective for
consumers under a variety of
reasonable assum ptions about
natural gas prices."
"The Tasl< Force observes that
tra nsrnission investrnents
typically continue to provide
value even as networl<
conditions change. For example,
transmission originally built to
the site of a now obsolete
power plant continues to be
usecl since a new power plant is
often constructed at the same
location."
66
PACIFICoRP - 20I7 IRP CHAPTER 4 _ TRANSMISSION
a
In the 2016-2017 NTTG Draft Regional
Transmission Plan, Energy Gateway (both
Gateway West and Gateway South and
Gateway West) were listed as necessary for
acceptable system performance. The study
also established that the amount of new
Wyoming wind that is added over time
impacts the transmission system reliability
west of Wyoming. Additionally three
interregional projects were included in the
study (SWP North, Cross Tie and TransWest Express), which showed that all three
projects relied on Energy Gateway to attain their full transfer capability rating.
WECClTransmission Expansion Policy and Planning Committee (TEPPC) Annual
Reports and Western Interconnection
Transmission Path afinzafion Studies
These analyses measure the historical use of
transmission paths in the west to provide
insight into where congestion is occurring and
assess the cost of that congestion. The Energy
Gateway segments have been included in the
analyses that support these studies, alleviating
several points of significant congestion on the system,
including Path 19 (Bridger West) and Path 20
(Path C).
Energy Gateway Configuration
To address constraints identified on PacifiCorp's system, as well as meeting system reliability
requirements discussed further below, the recommended bulk electric transmission additions
took on a consistent footprint, which is now known as Energy Gateway. This expansion plan
establishes a triangle of reliability that spans Utah, Idaho and Wyoming with paths extending
into Oregon and Washington, and contemplates logical resource locations for the long term
based on environmental constraints, economic generation resources, and federal and state energy
policies.
Since Energy Gateway's announcement, this series of projects has continued to be vetted through
multiple public transmission planning forums at the local, regional and interconnection-wide
levels. In accordance with the local planning requirements in PacifiCorp's OATT, Attachment K,
the Company has conducted numerous public meetings on Energy Gateway and transmission
planning in general. Meeting notices and materials are posted publicly on PacifiCorp's
Attachment K Open Access Same-time Information System (OASIS) site. PacifiCorp is also a
member ofNTTG and WECC's TEPPC.
These groups continually evaluate PacifiCorp's transmission plan in their efforts to develop and
refine the optimal regional and interconnection-wide plans. Please refer to PacifiCorp's OASIS
site for information and materials related to these public processes.4
'',nf t er :i rr ;i l
,',r i i n:l t lre :1 e:.r d ir -:t ;rt e
[JEIf r:r l-fr'r,i fr r: E r:rt ::t fE:: :]E rl
r: r:r ftr:l tt I r:rrr Er:l r: il :: Ei,,1 f I if r:r t'r:r r-t:;
r::r:r llt i Ii rlE Ilr::\r :1 ft ;: I i,' !i :i
r::r:rrrt trr Enr::Er:l,,. t l-rr rr, [',,]TTrI;':;
TE r::hl-l i r:: ;i I r.-.r:rl r"t l1"l itt EE
ilete rrn i rre rl ;i r:ti it i r: rr ;r I f ;: r:il it ie::
r,ir:rLrlLl [-rr rrepr]ed tr: rireet tl-re
reliat:r lrt i rriteri:-r,,,,"
"Path 19 [Bridger] is the most
heavily loaded WECC path in the
study.... Usage on this path is
currently of interest due to the
high number of requests for
transmission service to move
renewable power to the West
from the Wyoming area."
a http ://www.oatioasis.com/ppdindex.html
67
PecmrConp-2017 IRP CHAPTER 4 - TRANSMISSIoN
Additionally, * extensive l8-month stakeholder process on Gateway West and Gateway South
was conducted. This stakeholder process was conducted in accordance with WECC Regional
Planning Project Review guidelines and FERC OATT planning principles, and was used to
establish need, assess benefits to the region, vet alternatives and eliminate duplication of
projects. Meeting materials and related reports can be found on PacifiCorp's Energy Gateway
OASIS site.
Energy Gateway's Continued Evolution
The Energy Gateway Transmission Expansion Plan is the result of years of ongoing local and
regional transmission planning efforts with significant customer and stakeholder involvement.
Since its announcement in May 2007, Energy Gateway's scope and scale have continued to
evolve to meet the future needs of PacifiCorp customers and the requirements of mandatory
transmission planning standards and criteria. Additionally, PacifiCorp has improved its ability to
meet near-term customer needs through a limited number of smaller-scale investments that
maximize efficient use of the current system and help defer, to some degree, the need for larger
capital investments like Energy Gateway (see the following section on Efforts to Maximize
Existing System Capability). The IRP process, as compared to transmission planning, is a
frequently changing resource planning process that does not always support the longer-term
development needs of transmission, or the ability to implement transmission in time to meet
customer need. Together, however, the IRP and transmission planning processes complement
each other by helping PacifiCorp optimize the timing of its transmission and resource
investments for meeting customer needs.
While the core principles for Energy Gateway's design have not changed, the project
configuration and timing continue to be reviewed and modified to coincide with the latest
mandatory transmission system reliability standards and performance requirements, annual
system reliability assessments, input from several years of federal and state permiuing processes,
and changes in generation resource planning and our customers' forecasted demand for energy.
As originally announced in May 2007, Energy Gateway consisted of a combination of single-
and double-circuit 230 kV, 345 kV and 500 kV lines connecting Wyoming, Idaho, Utah, Oregon
and Nevada. In response to regulatory and industry input regarding potential regional benefits of
"upsizing" the project capacity (for example, maximized use of energy corridors, reduced
environmental impacts and improved economies of scale), the Company included in its original
plan the potential for doubling the project's capacity to accommodate third-party and equity
partnership interests. During late 2007 and early 2008, PacifiCorp received in excess of 6,000
MW of requests for incremental transmission service across the Energy Gateway footprint,
which supported the upsized configuration. The Company identified the costs required for this
upsized system and offered transmission service contracts to queue customers. These customers,
however, were unable to commit due to the upfront costs and lack of firm contracts with
customers to take delivery of future generation, and withdrew their requests. In parallel,
Pacif,rCorp pursued several potential partnerships with other transmission developers and entities
with transmission proposals in the Intermountain Region. Due to the significant upfront costs
inherent in transmission investments, firm partnership commitments also failed to materialize,
leading PacifiCorp to pursue the current configuration with the intent of only developing system
capacity sufficient to meet the long-term needs of its customers.
68
PACIFICoRP-2017 IRP CHAPTER 4 - TRANSMISSIoN
In 2010, the Company entered into memorandums of understanding to explore potential joint-
development opportunities with Idaho Power Company on its Boardman to Hemingway project
and with Portland General Electric Company (PGE) on its Cascade Crossing project. One of the
key purposes of Energy Gateway is to better integrate PacifiCorp's east and west balancing
authority areas, and Gateway Segment H from western Idaho into southern Oregon was
originally proposed to satisfu this need. However, recognizing the potential mutual benefits and
value for customers of jointly developing transmission, PacifiCorp has pursued these potential
partnership opportunities as a potential lower-cost alternative.
In 2011, the Company announced the indefinite postponement of the 500 kV Gateway South
segment between the Mona substation in central Utah and Crystal substation in Nevada. This
extension of Gateway South, like the double-circuit configuration discussed above, was a
component of the upsized system to address regional needs if supported by queue customers or
partnerships. However, despite significant third-party interest in the Gateway South segment to
Nevada, there was a lack of financial commitment needed to support the upsized configuration.
In 2012, the Company determined that one new 230 kV line between the Windstar and Aeolus
substations and a rebuild of the existing 230 kV line were feasible, and that the second new
proposed 230 kV line and proposed 500 kV line planned between Windstar and Aeolus would be
eliminated. This decision resulted from the Company's ongoing focus on meeting customer
needs, taking stakeholder feedback and land-use limitations into consideration, and finding the
best balance between cost and risk for customers. In January 2012, the Company signed the
Boardman to Hemingway Permitting Agreement with Idaho Power Company and the Bonneville
Power Administration (BPA) that provides for the Company's participation through the
permitting phase of the project. The Boardman to Hemingway project was pursued as an
alternative to PacifiCorp's originally proposed transmission segment from eastern Idaho into
southern Oregon (Hemingway to Captain Jack). Idaho Power leads the permitting efforts on the
Boardman to Hemingway project, and PacifiCorp continues to support these activities under the
conditions of the Boardman to Hemingway Transmission Project Joint Permit Funding
Agreement. The proposed line provides additional connectivity between PacifiCorp's west and
east balancing authority areas and supports the full projected line rating for the Gateway projects
at full build out. PacifiCorp plans to continue forward in support of the project under the Permit
Funding agreement and will assess next steps post-permitting based on customer need and
possible benefits.
In January 2013, PacifiCorp began discussions with PGE regarding changes to its Cascade
Crossing transmission project and potential opportunities for joint development or firm capacity
rights on PacifiCorp's Oregon system. The Company further notes that it had a memorandum of
understanding with PGE for the development of Cascade Crossing that terminated by its own
terms. PacifiCorp had continued to evaluate potential partnership opportunities with PGE once it
announced its intention to pursue Cascade Crossing with BPA. However, because PGE decided
to end discussions with BPA and instead pursue other options, PacifiCorp is not actively
pursuing this opportunity. PacifiCorp continues to look to partner with third parties on
transmission development as opportunities arise.
In May 2013, PacifiCorp completed the Mona to Oquirrh project. In November 2013, the Bureau
of Land Management issued a partial Record of Decision providing a right-of-way grant for all
of Segment D and most of Segment E of Energy Gateway. The agency chose to defer its decision
on the westem-most portion of Segment E of the project located in Idaho in order to perform
additional review of the Morley Nelson Snake River Birds of Prey Conservation Area.
69
PACIFICORP - 20 I7 IRP CHAPTER 4 - TRANSMISSION
Specifically, the sections of Gateway West that were deferred for a later Record of Decision
include the sections of Segment E from Midpoint to Hemingway and Cedar Hill to Hemingway.
In May 2015, the Sigurd to Red Butte project was completed and placed in-service
In December 2016, the Bureau of Land Management issued its Record of Decision and right-of-
way grant for the Gateway South project.
In January 2017, the Bureau of Land Management issued its Record of Decision and right-of-
way grant, previously deferred as part of the November 2013 partial Record of Decision, for the
sections of Segment E from Midpoint to Hemingway and Cedar Hill to Hemingway.
PacifiCorp evaluated four Energy Gateway scenarios in this 2017 IRP
Energy Gateway l: Segment D Windstar to Aeolus 230 kV (one new line and one re-built
line) and Aeolus to Bridger/Anticline 500 kV line;
Energy Gateway 2: Segment F Windstar to Aeolus 230 kV (one new line and one re-built
line) and Aeolus to Mona/Clover 500 kV line;
Energy Gateway 3: Segments D & F Windstar to Aeolus 230 kV (one new line and one
re-built line) and Aeolus to Bridger/Anticline, Bridger/Anticline to Populus and Aeolus to
Mona/Clover 500 kV lines; and
Energy Gateway 4: Segment D2 Aeolus to Bridger/Anticline 500 kV line.
This analysis demonstrates that Energy Gateway 4 (Aeolus to Bridger/Anticline) showed
potential to align development of this new transmission line with new PTC-eligible wind
resources and provide value for PacifiCorp customers. PacifiCorp refined its analysis during the
IRP process, to understand how the most current assumptions would influence potential
customer benefits associated with this new transmission line. The refined analysis shows that the
Energy Gateway 4 scenario, Aeolus to Bridger/Anticline, in conjunction with new wind
additions and PTCs, is the most cost-effective Energy Gateway transmission segment, providing
the most benefit to customers. Energy Gateway 4 is therefore a component of the 2017 IRP
preferred portfolio.
Finally, the timing of segments is regularly assessed and adjusted. While permitting delays have
played a significant role in the adjusted timing of some segments (e.g., Gateway West, Gateway
South, and Boardman to Hemingway), PacifiCorp has been proactive in deferring in-service
dates as needed due to permitting schedules, moderated load growth, changing customer needs,
and system reliability improvements.
PacifiCorp will continue to adjust the timing and configuration of its proposed transmission
investments based on its ongoing assessment of the system's ability to meet customer needs and
its compliance with mandatory reliability standards.
a
a
o
70
PecrnConp-2017IRP CHAPTER 4 _ TRANSMISSION
4.4 -Transmission Plan
This map is for general reference only and reflects current plans.
It may not reflect the final routes, construction sequence or exact line configuration.
WIsHINGToN :
r MONTANA
it"ON IDAHO
MING
CALIFO RN IA t o
NEVADA
COLORADO
U
ARIZONA , NEW MEXICO
I Raci0Corp mtall scrvkc arra
Ncw transmlsslon lhcs:
- 500 kVmlnlmum rolagc
- 3{5 kV mlnhnum volago
- 230 kV mlnknum rolergr
O Exlrthg rtbratbn
O Ncw subscbn
Segment & Name Description
Approximate
Mileage Status and Scheduled In-Service
(A)
Wallula-McNary 230 kV, single circuit 30 mi o Status: local permitting completed
o Scheduled in-service: 2018 is sponsor driven
(B)
Populus-Terminal 345 kV, double circuit 135 mi o Status: completed
o Placed in-service: November 2010
(c)
Mona-Oquirrh
500 kV single circuit
345 kV double circuit 100 mi o Status: completed
o Placed in-service: May 2013
Oquirrh-Terminal 345 kV double circuit 14 mi o Status: rights-of-way acquisition underway
o Scheduled in-service: 2021
(Dl)
Windstar-Aeolus
New 230 kV single circuit
Re-built 230 kV single
circuit
75 mi r Status: permiuing underway
o Scheduled in-service: 2019-2024
(D2)
Aeolus-
Bridger/Anticline
500 kV single circuit 140 mi o Status: permitting underwayr Scheduled in-service: 2020
(D3)
Bridger/Anticline-
Populus
500 kV single circuit 200 mi o Status: permitting underway
o Scheduled in-service: 2020-2024
(E)
Populus-Hemingway 500 kV single circuit 500 mi o Status: permitting underway
o Scheduled in-service: 2020-2024
(F)500 kV single circuit 400 mi o Status: permiuing underway
71
PecmrConp - 2017 IRP Csapren 4 - TRANSMISSToN
Segment & Name Description
Approximate
Mileage Status and Scheduled In-Service
Aeolus-Mona o Scheduled in-service: 2020-2024
(c)
Sigurd-Red Butte 345 kV single circuit 170 mi o Status: construction began May 2013
o Placed in-service: May 2015
(H)
Boardman-
Hemingway
500 kV single circuit 500 mi
o Status: pursuing joint-development and/or firm
capacrty opportunities with project sponsors
o Scheduled in-service: sponsor driven
In addition to investing in the Energy Gateway transmission projects, PacifiCorp continues to
make other system improvements that have helped maximize efficient use of the existing
transmission system and defer the need for larger-scale, longer-tenn ffiastructure investment.
Despite limited new transmission capacity being added to the system over the last 20 to 30 years,
PacifiCorp has maintained system reliability and maximized system efficiency through other
smaller-scale, incremental proj ects.
System-wide, the Company has instituted more than 155 grid operating procedures and 17
special protection schemes to maximize the existing system capability while managing system
risk. In addition, PacifiCorp has been an active participant in the EIM since November 2014.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 currently includes
the PacifiCorp east and west balancing authority areas, the NV Energy, Puget Sound Energy,
Arizona Public Service balancing authority areas, and the CAISO balancing authority area
(collectively, EIM Area) for use as short-term balancing resources to ensure energy supply
matches demand. Entities scheduled to join the EIM include PGE (October 2017),Idaho Power
Company (April20l8), Seattle City Light (April 2019), and the Balancing Authority of Northern
California (April 2019). By broadening the pool of lower-cost resources that can be accessed to
balance systems, reliability is enhanced and system costs are reduced across the entire EIM Area.
In addition, the automated system is able to identiff and use available transmission capacity to
transfer the dispatched resources, enabling more efficient use of the available transmission
system.
Transmission System Improvements Placed In-Service Since the 2015 IRP
o Constructed the new Standpipe substation and installed a synchronous condenser located
in Wyoming.
o Installed an additional230lll5 kV 250 MVA transformer at Casper substation located in
Wyoming.
o Installed shunt capacitors at Fry substation located in Oregon.
o Installed a load-shedding scheme at Grass Creek and Thermopolis substations located in
Wyoming.o Installed a phase-shifting transformer and series reactor at Upalco substation located in
Utah.
o Installed an additional230lll5 kV 250 MVA transformer and 230 kV ring bus at Union
Gap substation located in Washington.o Expanded the 230 kV ring bus at Pomona Heights substation located in Washington.
o Installed new relays on the Rigby to Sugarmill 161 kV line located in Idaho.
72
PACIFICoRP - 20I7 IRP CHAPTER 4 -TRANSMSSION
o Installed new relays on the Rigby to Jefferson 161 kV line located in Idaho.o Installed a phase-shifting transformer at Pinto substation located in Utah.o Constructed the new Whetstone substation located in Oregon.o Constructed a 1O-mile,46 kV line from the Holden substation tap to the Flowell-Robison
line located in Utah.o Converted the Highland substation to 138 kV located in Utah.o Installed a 138/46kV transformer at Snyderville substation located in Utah.
Planned Transmission System Improvements
o Replace the existing 115169 kV transformer at Weed substation with a 50 MVA LTC unit
located in California.o Replace 500 kV line relays at several500 kV substations located in Oregon.
o Energize one circuit of the 230kV Ben Lomond to Parrish line as a three-terminal 138kV
line from Ben Lomond to Syracuse and Parrish located in Utah.
o Install a new remedial action scheme (RAS) in the Goshen/Rigby area located in Idaho.
o Reconstruct the Goshen-Jefferson 161kV line located in Idaho.
. Energize Red Butte-St. George 345 kV line at 138 kV located in Utah.
o Install a new bay with a breaker and half scheme at Spanish Fork substation located in
Utah.o Install a second 700 MVA 3451138 kV transformer at Syracuse substation located in
Utah.
o Install backup bus differential relays at various substations located in Utah and
Wyoming.o Replace breakers identified as over-dutied with higher-capability breakers in various
substations located in Utah, Wyoming, and ldaho.
o Replace an existing oil breaker at the Treasureton 138 kV substation with a SF6 breaker
and add a circuit switcher in series with the breaker located in Utah.
o Replace conductor on the Moxee- Hopland section of the Moxee- Union Gap 115 kV line
located in Washington.o Construct two new 500-230 kV substations, Snow Goose and Sams Valley, located in
Oregon.
o Rebuild the 230 kV portion of the Troutdale substation, located in Oregon, into a six
breaker ring bus configuration.
o Rebuild the I 15 kV main and transfer bus into a breaker and half scheme at the Union
Gap substation in Washington.
o Construct a 138 kV line from Croydon substation to Silver Creek substation located in
Utah.
o Replace conductor between Hazelwood and BPA Albany and construct a new 115 kV
ring bus at Hazelwood substation located in Oregon.
o Replace the 25 MVA 115 kV-69 kV transformer at Dry Gulch with a 50 MVA
transformer located in Washington.
o Convert portions of Portland, Oregon area transmission network to 115 kV from 57 kV
and 69 kV.
o Install an additional 115 kV-69 kV transformer at Yreka substation located in California.o Install a new 230 kv-l15 kV transformer at Ponderosa substation and a new seven-mile
115 kV transmission line between Ponderosa and Baldwin substations located in Oregon.
73
PACIFICORP - 20I7 IRP CHAPTER 4 -TRANSMSSIoN
These investments help maximize the existing system's capability, improve the Company's
ability to serve growing customer loads, improve reliability, increase transfer capacrty across
WECC Paths, reduce the risk of voltage collapse and maintain compliance with NERC and
WECC reliability standards.
74
PACIFICoRP - 20I7 IRP CTTepTgn 5 - LOAD AND RESoURCE BALANCE
CHaprER 5 _ LOAD AND RpSOURCE BaraNcp
Cnaprrn Hrcru,rcnrs
o On both a capacity and energy basis, PacifiCorp calculates load and resource balances
from existing resources, forecasted loads and sales, and reserve requirements. The
capacity balance compares existing resource capability at the time of the coincident
system summer and winter peak periods.
o For capacity expansion planning, the Company uses a 13 percent target planning reserve
margin applied to PacifiCorp's obligation, which is calculated as projected load less
private generation, less Class 2 demand side management (DSM) energy efficiency
savings, and less intemrptible load.
o A 2016 Private Generation Long-Term Resource Assessment (2017-2036) study prepared
by Navigant Consulting, Inc. produced estimates on private generation penetration levels
specific to PacifiCorp's six-state territory. The study provided expected penetration levels
by resource type, along with high and low penetration sensitivities. PacifiCorp's 2017 IRP
resource needs assessment treats base case private generation penetration levels as a
reduction in load.
o PacifiCorp's system coincident peak load is forecasted to grow at a compounded average
annual growth rate of 0.85 percent over the period 2017 through2026. On an energy basis,
PacifiCorp expects system-wide average load growth of 0.91 percent per year from 2017
through 2026. Loads growth rates are before the impact of new energy efficiency savings.
o After accounting for load growth, coal unit retirement assumptions, and front-office
transaction (FOT) availability, and after incorporating future energy efficiency savings,
PacifiCorp's system planning reserve margin in surlmer and winter exceeds the
13 percent target planning reserve margin for the period ended 2025.
This chapter presents PacifiCorp's assessment of its load and resource balance, focusing on the
flrst ten years of the IRP's Z0-year study period,2017 through 2026. The Company's long-term
load forecasts (both energy and coincident peak load) for each state and the system as a whole
are summarized in Volume II, Appendix A (Load Forecast Details). The summary-level system
coincident peak is presented first, followed by a profile of PacifiCorp's existing resources.
Finally, load and resource balances for capacity and energy are presented. These balances are
composed of a year-by-year comparison of projected loads against the existing resource base,
including available FOTs, assumed coal unit retirements and incremental new energy efficiency
savings from the 2017 IRP preferred portfolio, before adding new generating resources. In
response to stakeholder feedback in the previous IRP cycle, this 2017 IRP includes the modeling
of the winter coincident peak as an improvement over previous IRPs.
The system coincident peak load is the annual maximum hourly load on the system. The
Company's long-term load forecasts (both energy and coincident peak) for each state and the
system are sufirma.rizedinVolume II, Appendix A (Load Forecast Details).
75
PecmrCoRp-2017IRP Cgap,rpn 5 _LOADAND RESOTJRCE BALA].{CE
The 2017 IRP relies on PacifiCorp's December 2016 load forecast. Table 5.1 shows the annual
summer coincident peak load stated in megawatts as reported in the capacity load and resource
balance, before any load reductions from Class 2 DSM and private generation. The system
summer peak load grows at a compounded average annual growth rate (CAAGR) of 0.85 percent
over the period 2017 through2026.
Table 5.1 - Forecasted System Summer Coincident Peak Load in Megawatts, Before
Enerry Elliciency and Private Generation
On a system coincident basis, PacifiCorp is a summer-peaking utility. For the forecasted 2017
swnmer coincident peak, PacifiCorp owns or has interests in resources with an expected system
summer peak capacity of 11,645 MW. Table 5.2 provides anticipated system summer peak
capacrty ratings by resource category as reflected in the IRP load and resource balance for 2017.
Note that capacrty ratings in the following tables provide resource capacrty value at the time of
system coincident peak, rounded to the nearest megawatt.
Table 5.2 -2017 Capacity Contribution at System Summer Peak for Existing Resources
Sales and Non-Owned Reserves are not included.z Represents the capacity available at the time of system summer peak used for preparation of the capacity load
and resource balance. For specific definitions by resource type see the section entitled "Load and Resource
Balance Components" later in this chapter.
3/ DSM includes existing Class I (direct load contol) and Class 2 (energy efficiency) programs.
a/ Purchases constitute contracts that do not fall into other categories such as hydroelectric, renewables, and
natural gas.
Thermal Plants
Table 5.3 lists PacifiCorp's existing coal-fueled thermal plants and Table 5.4 lists existing
natural-gas-fueled plants. The assumed end-of-life dates are used for the 2017 IRP modeling of
existing coal resources.
10,164 10,277 10,384 10,486 10,608 10,718 10,804 10,907 11,028 11,049
Pulverized Coal 5,919 50.8o/o
Gas-CCCT 2,377 20.4o/o
Gas-Other 357 3.1%
Hydroelectric 9s8 8.2%
DSM,,426 3.7%
Renewables 294 2.5Yo
Quali&ine Facilities-Renewables 70s 6.l%o
Purchase*'267 2.3%
Oualifuins Facilities t46 1.3%
Intemrptible Contracts 195 1.7%
Total 11.645 l00o/o
76
PACIFICORP _ 2OI7 IRP CHAPTER 5 -LOADAND RESOURCE BALANCE
Cholla 4 100 AZ 2042 387
Colstrip 3 l0 MT 2046 74
Colstrip 4 l0 MT 2046 74
Craie I t9 CO 2034 82
CO 2034 82Craig2t9
Dave Johnston 1 100 WY 2027 106
WY 2027 106Dave Johnston 2 100
Dave Johnston 3 100 WY 2027 220
Dave Johnston 4 100 WY 2027 330
Hayden I 24 CO 2030 45
Hayden 2 l3 CO 2030 ).5
94 UT 2042 418Hunter I
Hunter 2 60 UT 2042 269
t00 UT 2042 471Hunter 3
Huntineton 1 100 UT 2036 4s9
UT 2036 450Huntington 2 100
Jim Brideer I 67 WY 2037 354
WYJim Brideer 2 67 2037 359
Jim Bridser 3 67 WY 2037 345
WYJim Brideer 4 67 2037 350
Nauehton I 100 WY 2029 156
WYNaughton 2 100 2029 201
Naushton 3"100 WY 2029 280
WYWyodak80 2039 268
TOTAL - Coal 5.919
Table 5.3 - Coal-Fueled Plants
Naughton Unit 3 may be retired at the end of 2018
Table 5.4 - Natural-Gas-Fueled Plants
Renewable Resources
Wind
PacifiCorp either owns or purchases under contract 2,333 MW of wind resources. Since the 2015
IRP Update, the Company has entered into power purchase agreements totaling 40 MW.
Chehalis 100 WA 2043 464
UTCurrant Creek 100 2045 533
Gadsby I 100 UT 2032 64
100 UT 2032 69Gadsby 2
Gadsby 3 100 UT 2032 105
100 UT 2032 40Gadsby 4
Gadsby 5 100 UT 2032 40
Gadsby 6 100 UT 2032 40
OR 2036 227Hermiston (owned)50
Lake Side 100 UT 2047 530
Lake Side 2 100 UT 2054 623
TOTAL- Gas and Combined Heat & Power 2,734
77
PacrnConp-2017IRP CHAPTER 5 _LOADAND RESOURCE BALANCE
Table 5.5 shows existing wind facilities owned by PacifiCorp, while Table 5.6 shows existing
wind power purchase agreements.
Table 5.5 - Owned Wind Resources
PacifiCorp's share is 32 MW of the 40 MW project.
Table 5.6 - Non-Owned Wind Resources
New since 2015 IRP Update
Foote Creek I"WY 32 6
Leanine Juniper OR 101 t2
Goodnoe Hills Wind WA 94 ll
Marenso WA 140 l7
Marengo II WA 70 8
WY 99 l6Glenrock Wind I
Glenrock Wind III WY 39 6
l6Rolline Hills Wind WY 99
Seven Mile Hill Wind WY 99 l6
Seven Mile Hill Wind II WY 20 3
Hish Plains WY 99 l6
McFadden Ridee I WY 29 4
Dunlap I WY 111 18
TOTAL-Owned Wind 1.032 r48
Combine Hills OR PPA 4t 5
Foote Creek IV WY PPA l7 J
8Rock River I WY PPA 50
Stateline Wind OR/WA PPA 175 2t
WY PPA 99 l6Three Buttes Wind Power (Duke)
Top ofthe World WY PPA 200 32
Wolverine Creek ID PPA 65 l0
Casper Wind (Chewon)WY OF t7 J
Chopin WA OF l0 I
0Foote Creek II WY QF 2
Foote Creek III WY OF 25 4
UT OF 60 9Latieo Wind
Maxiah rWind OR OF l0 I
Meadow Creek Proiect - Five Pine ID OF 40 6
Meadow Creek Proiect - North Point ID QF 80 l3
Mountain Wind Power I WY OF 6l l0
l3Mountain Wind Power II WY QF 80
Orchard r$y'ind"WA OF 40 5
8Oreson Wind Farns I & II OR QT 65
OremFamilv Wind OR OF l0 I
13Pioneer Wind Park I WY QF 80
Power CounW Wind ParkNorth ID OF 23 4
4Power CounW Wind Park South ID QF 23
Spanish Fork Wind Park 2 UT OF t9 3
IThree Mile Canyon Iil/A QF l0
Small OF WY OF 0.2 0
TOTAL-Purchased Wind 1301 191
78
PacmrCoRp - 2017 IRP CHAPTER 5 - LoAD AND RESOURCE BALANCE
Solar
PacifiCorp has a total of 54 solar projects under contract representing 1,164 MW of nameplate
capacity. Of these, two projects totaling 100 MW are new since the 2015 IRP Update.
Table 5.7 - Non-Owned Solar Resources
Black Cao PPA OR 2 I
Utah Solar PV Proeram PPA UT 2 I
PPAoldMill OR 5 .,
Oreson Solar lncentive Proiects PPA OR 10 5
Small Solar QF UT 0.5 0
Adams Solar Center QF OR l0 6
OF ORBear Creek Solar Center l0 6
OF OR 5 JBeatty Solar
Bervl Solar OF UT J I
Black Cap Solar II QF OR 8 5
Bly Solar Center QF OR 9 6
Buckhorn Solar OF UT 3 I
Cedar Vallev Solar OF UT 3 I
Chiloquin Solar QF OR l0 5
OF ORCollier Solar l0 6
OF OR l0 6Elbe Solar Center
Entemrise Solar QF UT 80 47
Escalante Solar I QF UT 80 47
OF UT 80Escalante Solar II 47
Escalante Solar III OF UT 80 47
Ewauna Solar QF OR I I
OF OREwauna Solar 2 3 2
Fiddler's Canvon Solar 1-3 OF UT 9 5
Granite Mountain - East QF UT 80 47
Granite Mountain - West QF UT 50 30
OF UT 3 IGranite Peak Solar
Greenville Solar OF UT 2 I
kon Sorinss QF UT 80 47
OF OR l0 6Ivory Pine Solar
Laho Solar OF UT 3 I
Merrill Solar QF OR IO 6
OF UT 3 2Milford Flat Solar
Milford Solar 2 OF UT J I
Norwest Enersv 2 (Nef0 QF OR l0 6
Norwest Enersv 4 (Bonanza)OF OR 6 4
Norwest Enerev 7 (Eaele Point)OF OR l0 6
Norwest Enercy 9 Pendleton QF OR 6 J
OR Solar 2. LLC (Asate Bav)OF OR l0 6
OR Solar 3. LLC (Turkev Hill)QF OR l0 6
OFOR Solar 5. LLC (Merrill)OR 8 5
OR Solar 6. LLC (Lakeview)OF OR l0 6
OR Solar 7. LLC (Jacksonville)QF OR l0 6
OR Solar 8- LLC (Dairv)OF OR t0 6
Pavant Solar OF UT 50 29
Pavant Solar II LLC QF UT 50 30
Pavant Solar III LLC"OF UT 20 12
Ouichaoa Solar l-3 QF UT 9 5
OF uTSouth Milford Solar 3 2
SoraEue River Solar OF OR 7 5
Sweetwater Solar"QF WY 80 48
OFThree Peaks Solar UT 80 47
OF OR l0 5Tumbleweed Solar
Utah Red Hills Renewable Park OF UT 80 47
Woodline Solar QF OR 8 5
t.164 690TOTAL - Purchased Solar
.:: '
New since 2015 IRP Update
79
PacrrConp-2017IRP Csaprrn 5 -LoADAND RESoURCE BALANcE
Geothermal
PacifiCorp owns and operates the Blundell geothermal plant in Utah, which uses naturally
created steam to generate electricity. The plant has a net generation capacity of 34 MW. Blundell
is a fully renewable, zero-discharge facility. The bottoming cycle, which increased the output by
I I MW, was completed at the end of 2007. The Oregon Institute of Technology added a new
small qualifring facility (QF) using geothermal technologies to produce renewable power for the
campus that is rated at 0.28 MW. PacifiCorp has a six-year power purchase agreement with a
3.65 MW QF geothermal project near Lakeview, Oregon, which became operational September
2016.
BiomasslBiogas
PacifiCorp has biomass/biogas agreements with 19 projects totaling approximately 100 MW of
nameplate capacity. At least one project is located in each state in PacifiCorp's service territory.
Renewables Net Metering
Installation rates for net metering facilities have been relatively consistent for the last few years
over most of PacifiCorp's service territory. Utah, however, has seen tremendous growth-an
approximate 180 percent increase year over year-in the amount of residential solar being
interconnected. Table 5.8 provides a breakdown of net metered capacity and customer counts
from data collected on November 30, 2016.
Table 5.8 - Net Metering Customers and Capacities
Gas includes: biofuel, waste gas, and fuel cellsz Mixed includes projects with multiple technologies, one project is solar and biogas and the others are solar and
wind
Hydroelectric Generation
PacifiCorp owns 1,135 MW of hydroelectric generation capacity and purchases the output from
127 MW of other hydroelectric resources.t These resources provide operational benefits such as
flexible generation, spinning reserves and voltage control. PacifiCorp-owned hydroelectric plants
are located in Califomia,Idaho, Montana, Oregon, Washington, Wyoming, and Utah.
The amount of electricity PacifiCorp is able to generate or purchase from hydroelectric plants is
dependent upon a number of factors, including the water content of snow pack accumulations in
the mountains upstream of its hydroelectric facilities and the amount of precipitation that falls in
I PacifiCorp's 2016 l0-K shows 1,135 MW of Net Facility Capacrty
Nameplate
(kw)184,548.20 793.66 884 658.40 I 130.1 I
Capacity
(percentage)98.160/o 0.420/,0.47%0.3s%0.60%
Number of
customers 22,355 198 4 t4 60
Customer
(nercentase)98.78%0.87%0.02o/o 0.06Yo 0.27o/o
80
PACFICoRP_2OI7IRP CHAPTER 5 -LOADAND RESOIIRCE BALANCE
its watershed. Operationat limitations of the hydroelectric facilities are affected by varying water
levels, licensing requirements for fish and aquatic habitat, and flood control, which lead to load
and resource balance capacrty values that are different from net facility capacrty ratings.
Hydroelectric purchases are categorized into two groups, as shown in Table 5.9, which shows
2017 capacity included in the load and resource balance.
Table 5.9 - Hydroelectric Contracts - Load and Resource Balance Capacities
Table 5.10 provides the operational capacrty for each of PacifiCorp's owned hydroelectric
generation facilities at system summer peak (2017).
Table 5.10 - PacifiCorp Owned Hydroelectric Generation Facilities - Load and Resource
Balance Capacities
Cowlitz County PUD ov,rns Swift No. 2, and is operated in coordination with the other projects by PacifiCorpz Includes Bend, Fall Creeh and Wallowa Falls
3/ Includes Ashton, Paris, Pioneer, Weber, Stairs, Granite, Snake Creek, Olmstead, Fountain Green, Veyo, Sand
Cove, Viva Naughton, and Gunlock
Hydroelectric Relicensing Impacts on Generation
Table 5.1I lists the estimated impacts to average annual hydro generation from expected Federal
Energy Regulatory Commission (FERC) orders and relicensing settlement commitnents.
PacifiCorp assumes that the Klamath hydroelectric facilities will be decommissioned in
accordance with the Klarnath Hydroelecric Settlement Agreement in the year 2020 and that
other projects currently in relicensing will receive new operating licenses, but that additional
Hydroelectric 89
38Quali&ine Facilities-Hydroelectric
Total Contracted Hydroelectric Resources 127
MT 4Bie Fork
Klamath - Disoatch CA 56
CA llKlamath- Flat
Klamath - Shape OR 86
WA 390Lewis - Dispatch
Lewis - Shape"WA 94
OR 3lRozue
Small West Hvdro"CA/OR/WA 2
OR 24Umpqua - Flat
Bem River - Dispatch
OR
IDruT
89
53
IDruT l6Bear River - Shape
IDruTAilY t4Small East Hydro"
TOTAL - Hvdroelectric before Contracts 869
127PIus Hvdroelectric Contracts
TOTAL - Hvdroelectric with Contracts 996
81
PACIFICoRP-20I7IRP CHEPTER 5 -LOADAND RESOURCE BALANCE
operating restrictions will be imposed in new licenses, such as higher bypass flow requirements,
that will reduce generation available from these facilities.
Table 5.11 - Estimated Impact of FERC License Renewals and Relicensing Settlement
Commitments on Hydroelectric Generation
Demand Side Management (DSM)
DSM resources/products vary in their dispatchability, reliability, term of load reduction and
persistence over time. Each has its value and place in effectively managing utility investments,
resource costs and system operations. Those that have greater persistence and firmness can be
reasonably relied upon as a base resource for planning purposes; those that do not are more
suited as system reliability resource options. The reliability resource options are used to avoid
outages or high resource costs as a result of weather conditions, plant outages, market prices, and
unanticipated system failures. PacifiCorp categorizes DSM resources into four general classes
based on their relative characteristics:
Class I DsM-Resources from fully dispatchable or scheduled firm capacity
product offerings/programs-Class 1 DSM programs are those for which capacity
savings occur as a result of active Company control or advanced scheduling. Once
customers agree to participate in a Class I DSM program, the timing and persistence of
the load reduction is involuntary on their part within the agreed upon limits and
parameters of the program. Program examples include residential and small commercial
central air conditioner load control programs that are dispatchable, and irrigation load
management and intemrptible or curtailment programs (which may be dispatchable or
scheduled firm, depending on the particular program design or event noticing
requirements).
a
a Class 2 DsM-Resources from non-dispatchable, firm enerry and capacity product
offerings/programs-Class 2 DSM programs are those for which sustainable energy and
related capacity savings are achieved through facilitation of technological advancements
in equipment, appliances, lighting and structures, or repeatable and predictable voluntary
actions on a customer's part to manage the energy use at their facility or home. Class 2
DSM programs generally provide financial or service incentives to customers to improve
the efficiency of existing or new customer-owned facilities through: (1) the installation of
more efficient equipment, such as lighting, motors, air conditioners, or appliances;
(2) upgrading building efficiency through improved insulation levels, windows, etc.; or
(3) behavioral modifications, such as strategic energy management efforts at business
facilities and home energy reports for residential customers. The savings endure (are
considered firm) over the life of the improvement or customer action. Program examples
include comprehensive commercial and industrial new and retrofit energy efficiency
programs, comprehensive home improvement retrofit programs, strategic energy
management and home energy reports.
2017-2018 1,631 1,631
2019-2020 9,485 I l,l 16
2021-2036 628,000 639,116
82
PncrrConp - 2017 IRP CHAPTER 5 -LOADAND RESOURCE BALANCE
o Class 3 DsM-Resources from price responsive energy and capacity product
offerings/programs-Class 3 DSM programs seek to achieve short-duration (hour by
hour) energy and capacity savings from actions taken by customers voluntarily, based on
a financial incentive or signal. As a result of their voluntary nature, participation tends to
be low and savings are less predictable, making Class 3 DSM resources less suitable to
incorporate into resource planning, at least until their size and customer behavior profile
provide sufficient information for a reliable diversity result (predictable impact) for
modeling and planning purposes. Savings typically only endure for the duration of the
incentive offering and, in many cases, loads tend to be shifted rather than being avoided.
The impacts of Class 3 DSM resources may not be explicitly considered in the resource
planning process; however, they are captured naturally in long-term load growth patterns
and forecasts. Program examples include time-of-use pricing plans, critical peak pricing
plans, and inverted block tariff designs.
Class 4 DsM-Non-incented behavioral-based savings achieved through broad
energy education and communication efforts-Class 4 DSM programs promote
reductions in energy or capacity usage through broad-based energy education and
communication efforts. The program objectives are to help customers better understand
how to manage their energy usage through no-cost actions such as conservative
thermostat settings and turning off appliances, equipment and lights when not in use. The
programs are also used to increase customer awareness of additional actions they might
take to save energy and the service and financial tools available to assist them. Class 4
DSM programs help foster an understanding and appreciation of why utilities seek
customer participation in Classes 1,2 and 3 DSM programs. Similar to Class 3 DSM
resources, the impacts of Class 4 DSM programs may not be explicitly considered in the
resource planning process; however, they are captured naturally in long-term load growth
patterns and forecasts. Program examples include Company brochures with energy
savings tips, customer newsletters focusing on energy efficiency, case studies of
customer energy efficiency projects, and public education and awareness programs.
PacifiCorp has been operating successful DSM programs since the late 1970s. While the
Company's DSM focus has remained strong over this time, since the 2001 western energy crisis,
the Company's DSM pursuits have expanded to new heights in terms of investment level, state
presence, breadth of DSM resources pursued (Classes I through 4) and resource plaruring
considerations. Work continues on the expansion of cost-effective program portfolios and
savings opportunities in all states while at the same time adapting programs and measure
baselines to reflect the impacts of advancing state and federal energy codes and standards. In
Oregon, the Company continues to work closely with the Energy Trust of Oregon to help
identifu additional resource opportunities, improve delivery and communication coordination,
and ensure adequate funding and Company support in pursuit of DSM resource targets.
For a summary of current DSM program offerings in each state, refer to Volume II, Appendix D
(Demand-Side Management Resources).
Table 5.12 below summarizes the Company's existing DSM programs, their assumed impact,
and how they are treated for purposes of incremental resource planning. Note that since
incremental Class 2 DSM is determined as an outcome of resource portfolio modeling and is
83
characterized as a new resource in the preferred portfolio, existing Class 2 DSM in Table 5.12 is
shown as having zero MW.'
Table 5.12 - Existing DSM Resource Summary
PACIFICoRP - 2OI7 IRP CHAPTER 5 -Loao eNo RESoURCE BALANCE
Assumes sx percent for planning reserves in addition to realized irrigation load curtailment in Idaho and Utah of 170
MW and 20 MW, respectively, with an additional 3 MW from the Oregon pilot through 2020.
' Due to the timing of the 2017 IRP load forecast, there is a small amount (tOO fr4W) of existing Class 2 DSM in Table
5.14 (System Capacity Loads and Resources without Resource Additions).
Private Generation
For the 2017 IRP, PacifiCorp contracted with Navigant Consulting Inc. (Navigant) to update the
assessment of private generation penetration performed for the 2015 IRP with new market and
incentive developments. Deliverables included: (1) technical potential; (2) market potential; and
(3) levelized cost ofenergy for each private generation resource in each ofthe six states served
by the Company. Specific technologies studied included solar photovoltaic, small-scale wind,
small-scale hydro, and combined heat and power (CHP) for both reciprocating engines and
micro-turbines.
Navigant estimates approximately 1.4 GW of cumulative private generation capacity will be
installed in PacifiCorp's territory ftom2017-2036 inthe base case scenario.'As shown in Figure
5.1, the low and high scenarios project a cumulative installed capacity of 1.00 GW and 2.10 GW
by 2036, respectively. The main drivers between the different scenarios include variation in
'The historical effects of previous Class 2 DSM savings are backed out of the load forecast before the modeling for
new Class 2 DSM.
3 The complete Navigant Study is available in Volume II, Appendix O (Private Generation Study).
ResidentiaVsmall
commercial air conditioner
load control
l22MW sunmer peak Yes.
trrigation load
management 204 MW summer peakr/Yes.I
Intemrptible contracts 195 MW
Year-round availabilitv Yes.
2 PacifiCorp and Energy
Trust of Oregon programs 0 Mw'?/
No. Class 2 DSM programs are
modeled as resource options in the
portfolio development process and
included in the preferred portfolio.
Time-based pricing 98 MW summerpeak
No. Historical savings from
customer responses to pricing
signals are reflected in the load
forecast.3
Inverted rate pricing
55-149 GWh (capacity impacts
are unavailable due to lack of
information on end use loads
being saved
No. Historical savings from
customer response to pricing
structure is reflected in load
forecast.
4 Energy education Energy and capacity impacts
are not available/measured
No. Historical savings from
customer participation are reflected
in the load forecast.
84
PACIFICoRP-20I7IRP CHAPTER 5 - LOAD AND RESOURCE BALANCE
technology costs, system performance, and electricity rate assumptions. As in the 2015 IRP, the
Navigant study identifies expected levels of customer-sited private generation, which is applied
as a reduction to PacifiCorp's forecasted load for IRP modeling purposes.
5.1 - Private Generation Market Penetration 2017-2036
Power Purchase Contracts
PacifiCorp obtains the remainder of its capacity and energy requirements through long-term firm
contracts, short-term firm contracts, and spot market purchases. Figure 5.2 presents the contract
capacity in place for 2017 through 2036. As shown, major capacity reductions in purchases and
hydro contracts occur. For planning purposes, PacifiCorp assumes that current purchases from
small qualifying facility and intemrptible load contracts are extended through the end of the IRP
study period. Note that renewable wind contracts are shown at their capacity contribution levels.
3
=!
C)
ruo_$O
0).2H
CU
frE
=O
,r$rdu,r$","pt,"rdf rdp"dP,r$"r$,r&"C*"r$,r$,r$..ns++o+",S6g"
:500
2000
1 500
1 000
r High r Base Case r Loiv
500
0
85
PACIFICoRP - 2OI7 IRP CHAPTER 5 - Loeo eNo RESOI.JRCE BALANCE
5.2 - Contract in the 2017 Summer Load and Resource Balance
Capacity and Energy Balance Overview
The purpose of the load and resource balance is to compare annual obligations with the annual
capability of PacifiCorp's existing resources, without new generating resource additions. This is
done with two views of the system, the capacity balance and energy balance.
The capacity balance compares generating capability to expected peak load at time of system
suflrmer peak load hours. It is a key part of the load and resource balance because it helps guide
the timing and severity of potential future resource need. It is developed by frst reducing the
hourly system load by hourly private generation projections to determine the net system
coincident peak load for each of the fust ten years (2017-2026) of the planning horizon.
Intemrptible load programs, existing load reduction DSM programs, and new load reduction
DSM programs from the preferred portfolio at the time of the net system coincident peak are
further netted from the peak load forecast to compute the annual peak-hour obligation. Then the
annual firm capacity availability of the existing resources, reflecting assumed coal unit
retirements from the preferred portfolio, is determined. The annual resource deficit or surplus is
then computed by multiplying the obligation by the target planning reserve margin (PRM) and
then subtracting the result from existing resources, accounting for available FOTs.
The energy balance shows the average monthly on-peak and off-peak surplus or deficit of energy
over the first ten years of the planning horizon (2017-2026). The average obligation (load less
existing DSM programs, new DSM programs from the preferred portfolio, and projected private
generation) is computed and subtracted from the average existing resource availability for each
month and time-of-day period. The usefulness of the energy balance is limited because it does
not address the cost of the available energy. The economics of adding resources to the system to
meet both capacity and energy needs are addressed during the resource portfolio development
process described in Chapter 8 (Modeling and Portfolio Selection Results).
IWind I
I
2,000
1,500
1,000
500
Bz0
-500
-1,000
,{$
"$'."s9 "srt"$r{Pr{F "s}r{F"$rt"{S r$r.r{P "srt"sft"{Pr{i r$"r{f "$'
86
PACIFICoRP-2017IRP CHAPTER 5 _ LoAD AND RESoURCE BALANCE
Load and Resource Balance Components
The 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,
reserves, position, and available FOTs.
Under the calculations, there are negative values in the table in both the resource and obligation
sections. This is consistent with how resource categories are represented in portfolio modeling.
The resource categories include resources by type-thermal, hydroelectric, renewable, QFs,
purchases, existing Class I DSM, sales, and non-owned reserves. Categories in the obligation
section include load (net of private generation), intemrptible contracts, existing Class 2 DSM,
and new Class 2 DSM from the preferred portfolio.
Existing Resources
A description of each of the resource categories follows:
Thermal
This category includes all thermal plants that are wholly owned or partially owned by
PacifiCorp. The capacity balance counts them at maximum dependable capability at time of
system surlmer 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, six natural-gas-fueled plants, and one cogeneration unit. These
thermal resources account for roughly two-thirds of the firm capacity available in the PacifiCorp
system.
Hvdroelectric
This category includes all hydroelectric generation resources operated in the PacifiCorp 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 Westem 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 ilre 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.
Renewable
This category comprises geothermal and variable (wind and solar) renewable energy capacity.
The capacity balance counts the geothermal plant by 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. For purposes of the 2017 IRP,
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 by resource type and balancing
authority area, which is presented in Volume II, Appendix N (Wind and Solar Capacity
Contribution Study). The resulting capacity contribution values are shown in Table 5.13 below.
87
PACIFICORP _ 2OI7 IRP CHAPTER 5 _ LOAD AND RESOURCE BALANCE
Table 5.13 Summer Peak Contribution Values for Wind and Solar
Purchase
This includes all major purchases contracts for firm capacity and energy in the PacifiCorp
system.a The capacity balance counts these by the maximum contract availability at time of
system sufllmer peak. The energy balance counts contracts at optimal economic model dispatch.
Purchases are considered firm and thus planning reserves are not held for them.
Oualifrine Facilities (Qn
A11 QFs that provide capacity and energy are included in this category. Like other power
purchases, the capacity balance counts them at maximum system summer peak availability and
the energy balance counts them at optimal economic model dispatch.
Dispatchable Load Control (Class I DSM)
Existing dispatchable load control program capacrty 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.
Sales
This includes all contracts for the sale of firm capacrty and energy. The capacity balance counts
these contracts by the maximum obligation at time of system sunmer peak and the energy
balance counts them by expected model dispatch. All sales contracts are firm and thus planning
reserves are held for them in the capacity view.
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 are authority for load and generation that are
in PacifiCorp's balancing authority area (BAA) but not owned by PacifiCo{p's. There are a
number of counterparties that operate in the 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 the
requirement is for capacity only.
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. The following are descriptions of each of these
components:
a PacifiCorp has curtailrnent contracts for approximately 172 MW on peak capacity that are fieated as firm
purchases. PacifiCorp has the right to curtail the customer's load as needed for economic purposes. The customer in
turn may or may not pay market-based rates for energy used during a curtailment period.
59.7%tt.8%53.9%64.8%
Capacrty
Contribution
Percentage
ts.8%37.9o/o
88
PACIFICoRP _ 2017 IRP CHapTgn 5 _LoADAND RESoURCE BALANCE
Load Net of Private Generation
The largest component of the obligation is retail load. In the 2017 IRP, the hourly retail load at a
location is frst 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 balancing
authority areas thus reflect loads at the time of PacifiCorp's coincident system summer peak. The
energy balance counts the load on monthly basis by on-peak and off-peak hours. The net load is
simply referred to as load in the context of load and resources balances and portfolio selection
and evaluation.
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 is a level of 2016 Class 2
DSM that is not incorporated in the forecast. The 2016 Class 2 DSM forecast (100 MW) has
been accounted for by adding an existing Class 2 DSM resource in the load and resource
balance. The DSM line also includes the selected Class 2 DSM from the 2017 IRP preferred
portfolio.
5.3 - DSM in C Load and Resource Balance reduction to
Intemrptible Contracts
PacifiCorp has intemrptible contracts for approximately 195 MW of load intem.rption capability
beginning in2017. 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 on the executed hours. 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.
0
(100)
(200)
(300)
(400)
(s00)
(600)
(700)
(800)
(e00)200 '% '.% '.% % % '.% "r, t% '%
I East r West
89
PACIFICORP - 20I7 IRP CHAPTER 5 _ LOAD AND RESOURCE BALANCE
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) and known requirements (i.e., operating reserves).
Position
The position is the resource surplus or deficit after subtracting obligation plus required reserves
from total resources. While similar, the position calculation is slightly different for the capacity
and energy views of the load and resource balance. Thus, the position calculation for each of the
views will be presented in their respective sections.
Capacity Balance Determination
Methodolory
The capacity balance is developed by first determining the system coincident peak load for each
of the first ten years of the planning horizon. Then the annual firm-capacity availability of the
existing resoruces is determined for each of these annual system summer and winter peak
periods, as applicable, and summed as follows:
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 surlmer 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 13 percent target planning reserve
margin (PRM) adopted for the 2017 IRP. The formula for this calculation is:
Planning Reserves: Obligation x PRM
Finally, the annual capacity position is derived by adding the computed reserves to the
obligation, and then subtracting this amount from existing resources, including available FOTs,
as shown in the following formula:
Capacity Position: (Existing Resources + Available FOTs) - (Obligation * Reserves)
Capacity Balance Results
Table 5.14 and Table 5.15 show the annual capacity balances and component line items for the
surlmer peak and winter peak, respectively, using a target planning reserve margin of 13 percent
to calculate the planning reserve amount. Balances for PacifiCorp's system as well as east and
west BAAs are shown. While west and east BAA balances are broken out separately, the
PacifiCorp system is planned for and dispatched on a system basis. Also note that new QF wind
and solar projects listed earlier in the chapter are reported under the QF line item rather than the
renewables line item.
90
PACIFICoRP - 20I7 IRP CHAPTER 5 - LOeo aNo RESOURCE BALANCE
Table 5.14 - Summer Peak - System Capacity Loads and Resources without Resource
Additionsr/
Calendar Year 2017 2018 2019 2020 2021 2022 2023 2024 202s 2026
last
Theml
Hydroelectric
Renewable
Purchase
Qualifying Facilities
Class I DSM
Sale
Non-Owned Reserves
fast kisting Resources
toad
hivate Generation
Intemrptible
DSM
Rlst oUigation
Planning Reserves (13%)
East OHigation + Reserrts
Frst Position
ArailaHe Front 0ffrce Transactions
6,4M
103
20r
249
656
323
(6s2)
(37)
7249
7,008
(33)
( les)
(138)
6,643
889
7,532
(283)
318
6,M
106
201
249
&6
)z)
(6s2\
137)
7 241
7,@3
(51)
( re5)
(le0)
6,6s7
891
7547
(306)
318
6,126
l13
201
249
689
323
16s2)
(37)
1,O12
7,141
(72)
( r9s)
(246)
6,629
887
6,126
il3
201
249
681
)z)
(652)
(37)
7,004
7231
(80)
( 195)
(2e8)
6,6s7
891
7 54E
(s.r4)
318
5,739
l13
199
221
672
323
(r72)
(37)
7,058
7,331
(86)
1 te5)
6,695
8%
5,739
ll3
l9l
221
661
323
1172\
(37)
7p38
7,420
1et)
(le5)
(4 r0)
6,725
900
5,739
ll3
l9l
221
657
323
1172\
(37)
7,O34
7,485
(94)
( le5)
(468)
6,728
900
7,628
(se4)
318
5,739
E2
l9l
221
603
323
( r.16)
(37)
6,987
7s&
198)
( re5)
(527\
6,744
902
5 715
E2
191
121
s98
323
( 146)
(37)
6,a78
7,61
(104)
(t95)
(s84)
6,779
907
5,U5
m
l8l
tzl
594
)L)
(63)
(37)
6,856
7,63
(lt2)
(te5)
(641)
6,714
898
7,612
(7s6)
318
7,516
(s01)
3lE
7Sgt
(sJ3)
318
7 $24
(s86)
3r8
7,646
(6se)
3r8
7,685
(807)
318
West
Thermal
Hydroelectnc
Renewable
Purchase
Qua}fymg Facilrties
Class l DSM
Sale
Non-Owned Reserves
West kisting Resources
toad
Private Generation
Intemrptible
DSM
West oHigstion
Plannmg Reserves (13%)
West OHigation + Reserrts
West Position
Arailable Front Ollice Transactions
3,488 3,487 3,s19(24s) (23s) (4231
r,3s2 lJs2 t3s2
2,247
855
93
18
195
3
( 165)
(2)
3244
3,155
(l)
0
(67)
3,087
401
2,247
859
93
l8
2N
3
( l6s)
(2)
32s3
3,tu
(2)
0
(97\
3,086
401
) )t7
717
93
I
2A
3
( l6s)
(2)
3,O97
3,243
(2)
0
( r26)
3,1t 5
zto5
2,247
806
%
I
207
3
( 165)
(2)
3,191
3,255
(3)
0
(152)
3,101
403
2,247
635
93
I
198
0
( r6l)
(2)
3,01l
3,276
(3)
0
(r7s)
3,098
403
2,247 2,247 2,247 2,247 2,247
549 644 g8 634 651
62 62 57 57 56
lllll
195 186 t85 184 tA
00000
(l r0) (l r0) (80) (80) (80)
(2) (2) (2) (2) (2)
2,942 3,028 3056 3,042 3,056
3,298 3,319 3,343 3,367 3,386
(3) (4) (4) (s) (6)
00000
( l%) (214) (232) (248) (263)
3,099 3,101 3,106 3,114 3,117
q3 403 M 40s 40s
3,504
(313)
t3s2
3,501
(48e)
t3s2
3,s02
(s60)
1,352
3,505
(477')
rJs2
3,510
(4s1)
t3s2
35r8
(476)
1352
3,523
(1671
r3s2
System
Total Resources
OHigation
Reserrts
OHigation + Reserrcs
Slstem Position
ArailaHe FYont Oflice Transactions
10,493
9,730
t,2qJ
I 1,020
(s27)
1,670
10,494
9,743
1,292
I 1,035
(541)
1,670
10,109
9,743
\2n
t I,035
(927\
t,670
l0,t%
9,758
1,294
1,0s2
(858)
1,670
10,069
9,793
1,298
t,092
( r,023)
1,670
9,980
9,824
t3a
1,126
( t,l.16)
1,670
10,M2
9,49
1,303
I 1,132
( 1,070)
1,670
10,043
9,8s0
1,306
I I,156
(r,rB)
t,670
q qro
9,92
1,311
11,203
( r,284)
1,670
9.912
9,831
r,303
I 1,135
(1,223\
1,670
'/ The DSM line includes selected Class 2 DSM from the 2Ol7 IRP preferred portfolio.
9l
PecmrCoRp-2017IRP Cgaprpn 5 - Loeo axo RESOURCE BALANCE
Table 5.15 - Winter Peak - System Capacity Loads and Resources without Resource
Additionsr/
CalendarYear 2Ol7 2018 2Ol9 2020 2OZl 2022 2023 2024 2025 2026
Thernal
Hydroelectric
Renewable
Purchase
Qualifying Facilities
Class I DSM
Sale
Non-Owned Reserves
&st kisting Resources
load
Pnvate Creneration
Interruptible
Existing Class2 DSM
f,.st oUigation
Plannmg Reserves (13%)
East OHigation + Reserres
&st Position
ArailaHe Front OIfice Transactions
6,s14
1t
201
734
il7
2t
( 170)
(37t
7,9E1
72
201
734
688
21
( 170)
(37)
E,023
5,617
( l7)
( r9s)
(132)
s274
711
6234
72
201
734
680
2t
( 170)
(37)
7,735
s.6f36
(24)
( le5)
1r73)
s,294
714
6234
72
199
734
676
2l
(170)
(37)
1,729
5,597
(28)
( 195)
(213)
5,161
696
5,U7
72
191
23s
68
21
(170)
i37)
6,826
5,770
(31)
( 195)
(2s6)
s288
'713
6,001
826
31E
s,u7
72
l9l
23s
6s8
2t
(170)
(37)
6,816
s,u7
72
l9l
235ffi
21
(170)
(37)
6,762
5,923
(13)
(re5)
(340)
5,355
721
5,U7n
l9l
121
600
2l
( tz[5)
(17)
6,670
5,956
(3s)
( les)
(383)
sr43
720
5,U3
72
l9l
121
595
2l
( 146)
(37)
6,661
5,919
(37)
( les)
(42s)
s262
7@
s97t
689
31E
5,753
72
l8l
t2t
591
2t
(63)
(37)
6,640
s,n4
(40)
( l9s)
(46e)
5?,20
7M
s,924
716
318
6,s14
5,550
(ll)
( les)
1e2)
s2s2
708
s,961
2,020
3r8
5,9E5
2,039
318
6,007
1,728
3r8
5,E57
1,872
31E
5,U7
(32)
( les)
(v7)
s323
717
6,040
776
3lE
6,076
686
31E
6,063
607
318
\!est
Thenral
Hydroelectric
Renewable
Purchase
Qualifying Facilities
Class I DSM
Sale
Non0wned Resewes
West kisting Resources
lnad
Pnvate Generation
Intenuptible
DSM
West oHigation
Planning Reserves (13%)
West OHigation + Reserws
West Pmition
AmilaHe trtont OIIice Transactions
2,308
91
93
6
200
0
( 162)
(2)
3J36
3,2U
(l)
0
(74)
3,188
414
2,308
915
93
I
192
0
( r62)
(2)
334s
3,2n
(2)
0
( 109)
3,r80
413
2,308
943
93
I
195
0
( 162)
(2)
3377
3,305
(2)
0
( 143)
3,r60
411
2,308
937
93
I
197
0
( 154)
(2)
3J81
3,4t6
(3)
0
(171)
3239
421
3,66r
(280)
t3s2
2,308
7U
93
I
190
0
(154)
(2)
3221
3,359
(3)
0
(201)
3,155
4r0
3,565
(344)
tes2
2,308
782
62
I
183
0
(lt3)
(2)
322r
3,378
(3)
0
(2?5)
3,149
N
35s9
(338)
rJs2
2,308
783
62
I
177
0
(ll3)
(2)
32ts
3,399
(4)
0
(246\
3,149
40
35s8
(343)
t3s2
2,308
Tt9
57
I
176
0
(81)
(2)
3238
3,416
(4)
0
(267)
3,144
4@
35s3
(3l s)
I,352
2,308
7t36
56
I
175
0
(81 )
(2)
3244
3,540
(5)
0
(286)
3249
422
2,308
7t36
55
I
t7t
0
(81)
(2)
3238
3,557
(6)
0
(lo4)
3247
422
3,670
(431)
1,352
3,603
(t67',t
l3s2
3,593
(24E1
1352
3,571
(r e1)
1,352
3,671
(428)
t3s2
Total Resources
OHigation
Reserrcs
OHigation + Reserres
System Position
Arailable Front Oflice Transactions
1,417
8,44t
1,123
9,5U
1,854
1,67O
I 1,369
8,453
t,124
9,578
1,791
1,670
I I,t l0
8,400
l,l r7
9,518
Lsq2
1,670
11,112
8,4s3
1,124
9,578
1,534
1,670
10,047
8,443
1,t23
956
481
1,670
10,037
8,472
1,127
9,s99
438
1,67O
9,n8
8,503
r,l3l
9,634
344
1,670
9,908
8,487
t,129
9,616
2q2
1,670
s sos
8,511
1,132
9,&3
2A
1,670
9,878
8A67
1,t26
9,s93
28s
1,670
'/ The DSM line includes selected Class 2 DSM from the20lT IRP preferred portfolio.
Figure 5.4 through Figure 5.7 are graphic representations of the above tables for annual capacity
position for the sunmer system, winter system, east BAA, and west BAA. Also shown in the
system capacity position graph are available FOTs, which can be used to meet capacity needs.
The market availability assumptions used for portfolio modeling are discussed further in Chapter
6 (Resource Options) and Volume II, Appendix J (Western Resource Adequacy Evaluation).
92
PacmrCoRp-2017 IRP CHAPTER 5 - LOAD AND RESOURCE BALANCE
5.4 - Summer C
5.5 - Winter
Position Trend
Position Trend
f'rctrtOlnce
Obligetion
,"t1 Pristing Resources
.Wcst
14,000
12,000
10,000
201920172018 2021
8,000
!
2
6,O00
4,000
2,000
o
2020 2022 2023 2024 2025 2026
Obligation + 13olo Plrnning Reserves
Avdhblc Off,e
Obligrti,on
Eest Eristing Resources
lVest
14,000
10,000
2017 20l8 2019
12,000
8,000
Bo
z
6,000
4,OO0
2,000
0
2020 2021 2022 2023 2024 2025 2026
93
PACIFICoRP-20I7IRP CHAPTER 5 _LOADAND RESOURCE BALANCE
5.6 - East Summer Capacity Position Trend
14,000
r2,000
1o,000
8,000
=-a2 6,000
4,O00
2,000
0
2017 20t 8 20t9 2020 2021 2022 2023 2024 20.25 2026
7 - West Summer Capacity Ppqtion Trend
l4,oo0
12,000
10,000
8,000
B
6,000
4,000
2,OOO
0
M
MI
M
EF,'M
94
2017 2018 20t9 2020 2021 2022 2023 2024 2025 2026
PACIFICORP - 2OI7 IRP CHAPTER 5 -LOADAND RESOURCE BALANCE
Energy Balance Determination
Methodolory
The energy balance shows the monthly on-peak and off-peak surplus (deficit) of energy. The on-
peak hours are weekdays and Saturdays from hour-endingT:00 am to 10:00 pm; off-peak hours
are all other hours. This is calculated using the formulas that follow. Please refer to the section
on load and resource balance components for details on how energy for each component is
counted.
Existing Resources : Thermal + Hydro + Existing Class 1 DSM + Renewable + Firm
Purchases + QF + Intemrptible Contracts - Sales
The average obligation is computed using the following formula:
Obligation: Load + Firm Sales
The energy position by month and time block is then computed as follows:
Enerry Position : Existing Resources - Obligation - Operating Reserve Requirements
Energy Balance Results
The capacity position shows how existing resources and loads, accounting for coal unit
retirements and incremental energy efficiency savings from the preferred portfolio, balance
during the coincident peak sunmer and winter. 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 the 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 5.8 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. 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 5.8 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, the first energy shortfall appears
in summer 2022, and continuers in the subsequent years. During off-peak periods, there are no
energy shortfalls through the2026 timeframe.
95
5,000
4,000
3,000
2,000
1,000
0
.lr"$*i*+r"*C.st*p".9'J.,"s../"sJ.J./."$.Jod."P".9"-r Enerly at or Below Load ' iNet Balancing Sal6 ' rNet Balancing Purchase
-Energy
Shortfall Energy Available
-Load
On-Peak Energy Balance
5,000
4,000
3,000
2,000
1,000
0
Off-Peak Energy Balance
-Energy
Shortfall
-Load
BI
Energy Available
PACIFICORP - 20I7 IRP CHAPTER 5 -LoADAND RESoURCE BALANCE
5.8 -Positions
96
PlcrrrConp - 2017 IRP CHAPTER 6 - Rrsouncs OprroNs
CHeprER 6 - RpsouRCE OprtoNs
Cnaprnn HrcHr,rcnrs
o PacifiCorp developed resource attributes and costs for expansion resources that reflect
updated information from project experience, public input meeting comments and thfud
party studies.
o Generally, resource costs have remained stable since the 2015 IRP and any cost increases
have been modest. Renewable resource costs in particular, have continued to fall.
o As with the 2015 IRP both large utility scale solar photovoltaic options and geothermal
purchase power agreements (PPAs) have been included as supply-side options inthe 2017
IRP and updated to reflect current conditions.
o The number of combustion turbine types and configurations has been slightly modified to
reflect different siting locations and are identified in the Supply Side Resource options
table.
o Energy storage systems continue to be of interest to PacifiCorp stakeholders. Options for
advanced large batteries (one megawatt), pumped hydro and compressed air energy
storage are included in the 2017 IRP.
o A Demand-Side Resource Potential Assessment for 2017-2036, conducted by Applied
Energy Group, served as the basis for updated resource characterizations covering
demand-side management (DSM) resources. The demand-side resource information was
converted into supply curves by resource type and competes against other resource
alternatives in IRP modeling.
o PacifiCorp applied cost reduction credits for energy efficiency, reflecting risk mitigation
benefits, transmission & distribution investment deferral benefits, and a 10 percent market
price credit for Washington and Oregon as allowed by the Northwest Power Act.
o Transmission integration costs and transmission reinforcement costs are based on the
timing and location of resource selection.
This chapter provides background information on the various resources considered in the IRP for
meeting future capacity and energy needs. Organized by major category, these resources consist
of utility-scale supply-side generation, DSM programs, transmission resources and market
purchases. For each resource category, the chapter discusses the criteria for resource selection,
presents the options and associated attributes, and describes the various technologies. In addition,
for supply-side resources, the chapter describes how PacifiCorp addressed long-term cost trends
and uncertainty in deriving cost figures.
The list of supply-side resource options has been updated to reflect the realities evidenced
through permitting, internally-generated studies and externally-commissioned studies undertaken
to better understand the details of available generation resources. Renewable resources,
particularly solar and wind resource options, have been reviewed and updated to capture recent
trends in cost and performance. Solar resource options include utility-size photovoltaic systems
(PV) with both fixed and single axis tracking. A variety of gas-fueled generating resources were
97
PacmrConp - 2017IRP Cnayren 6 - RESoURCE OPrroNs
selected after consultation with major suppliers and large engineering-consulting firms.
Stakeholder feedback and industry journals also influenced the selection of resources. The
capital and operating costs of simple and combined-cycle gas turbine plants have remained
relatively low in recent years, with a flat to slightly decreasing cost trend. Energy storage options
of at least one megawatt continue to be of interest among the stakeholders, with options analyzed
for large pumped hydro projects, as well as advanced battery and compressed air energy storage
projects. Additionally, in response to stakeholder requests, multiple different battery energy
storage configurations were also evaluated. New coal-fueled resources received minimal focus
during this cycle due to ongoing environmental, economic, permitting and sociopolitical
obstacles for siting new coal-fueled generation.
Derivation of Resource Attributes
The supply-side resource options were developed from a combination of resources. The process
began with the list of major generating resources from the 2015 IRP. This resource list was
reviewed and modified to reflect stakeholder input, new technology developments,
environmental factors, cost dynamics and anticipated permitting requirements. Once the basic
list of resources was determined, the cost and performance attributes for each resource were
estimated. The information sources used are listed below, followed by a brief description on how
they were used in the development of the Supply Side Resource table:
o Recent (2016) third-party, cost and performance estimates;o Prior third-party, cost and performance studies or updated earlier estimates;o Publicly available cost and performance estimates;o Actual PacifiCorp or electric utility industry installations, providing current
construction/maintenance costs and performance data with similar resource attributes;o Projected PacifiCorp or electric utility industry installations, providing projected
construction/maintenance costs and performance data of similar or identical resource
options; and
o Recent Requests for Proposals and Requests for Information.
Recent third-party engineering information from original equipment manufacturers were used to
develop capital, operating and maintenance costs, performance and operating characteristics and
planned outage cycle estimates. Engineering-consultants or govemment agencies have access to
this data based on prior research studies, academia, actual installations, and direct information
exchanges with original equipment manufacturers. Examples of this type of effort include the
2016 Black & Veatch estimates prepared for simple cycle and combined cycle options. For this
IRP cycle, the energy storage effon was performed by two different consultants. The bulk energy
storage portion of the 2014 HDR Engineering (HDR) that focused on pumped storage and
compressed air energy storage was updated by Black & Veatch. The battery energy storage part
of the 2014 HDR study was updated by DNV-GL.
Prior studies include studies prepared by others but not specifically for the Integrated Resource
Plan process, and include similar types of cost and performance data provided in the Supply-
Side Resource table. This information includes publicly available engineering and government
agency reports. Examples of this type of study include the United States Department of Energy's
2015 Wind Technologies Market Report.
98
PacrrCoRp-2017IRP CHAPTER 6 - REsouncp OprroNs
PacifiCorp or industry installations provide a solid basis for capitaVmaintenance costs and
operating histories. Performance characteristics were adjusted to site-specific conditions
identified in the Supply Side Resource Table. For instance, the capacity of combustion turbine
based resources varies with elevation and ambient temperature and, to a lesser extent, relative
humidity. Adjustments were made for site-specific elevations of actual plants to more generic,
regional elevations for future resources. Examples of actual PacifiCorp installations used to
develop the cost and performance information provided in the Supply Side Resource table
include O&M costs for the Company's Gadsby GE LM6000PC peaking units and the Lake Side
2 combined cycle plant.
Requests for Information (RFI) and Requests for Proposals (RFP) also provide a useful source of
cost and performance data. In these cases, original equipment manufacturers provided
technology specific information. Examples of RFIs informing the Supply Side Resource Table
include obtaining updated equipment pricing for wind turbine equipment from original
equipment suppliers and reviews of capital costs prepared by engineering firms by engineer-
procure-construct fi rms.
Handling of Technology Improvement Trends and Cost Uncertainties
The capital cost uncertainty for some generation technologies is relatively high. Various factors
contribute to this uncertainty, including the relatively small number of facilities that have been
built, especially for new and emerging technologies, as well as prolonged economic uncertainty.
Despite this uncertainty, the cost profile between the 2015 IRP and the 2017 IRP has not
changed significantly. For example, Figure 6.1 shows the trend in North American carbon steel
sheet prices over the period from October 2015 through September 2016. Similar information
was presented in the 2015 IRP and is shown in Figure 6.2. These figures illustrate near term
changes in capital costs ofgeneration resources.
99
PecmrConp - 2017IRP CHAPTER 6 - RrsouRce OprroNs
Figure 6.1 - World Carbon Steel Pricing by Typ"
World Carbon Steel Pricing Averate Transaction Price
(www.worldsteel prices.com )
+Hot Rolled Coal .+Structural Sections & 8€ails -r-Rebar
S0.35
90.3o
s0.2s
So.2o
So.1s
50.10
6.2 - Historic Carbon Steel
World Hot Rolled Coi! Steel Prices
(stelonthcnct.oml
d +oo eo" ,oc to$ .,"t tsQt {".\ r"" to*J rb
go{
so.so
50.45
so.40
so.3s
so.30
f, so.rs
so.20
so.r5
So.to
so.o5
90.0o2q)l 2@2 2003 2@a 2(D5 2(x)6 2@7 2(xlE 2(xX' 20lO 2011 201' 2013 201.
Prices for solar photovoltaic (PV) panels as well as balance of plant costs have fallen since the
2015 IRP. Real prices are projected to flatten out for the next several years given large demand
100
PACIFICORP - 20I7 IRP CHarrpn 6 - Rrsouncr OprroNs
to meet the 30 percent federal ITC deadline at the end of 2016 and recently announced panel
tariffs on certain Chinese imports, but uncertainty in the solar market makes it difficult to
accurately predict future prices. Other technologies, such as gas turbines and wind turbines have
seen more stable prices since the 2015 IRP. Long-term (10+ years) pricing for this equipment
remains challenging to forecast.
Some generation technologies, such as integrated gasification combined cycle (IGCC), have
shown significant cost uncertainty because only a few units have been built and operated. Recent
experience with the significant cost ovem;ns on IGCC projects such as Southern Company's
Kemper County IGCC plant illustrate the difficulty in accurately estimating capital costs of these
emerging resource options. As these technologies mature and more plants are constructed, the
costs of such new technologies may decrease relative to more mature options such as pulverized
coal and natural gas-fueled plants.
The supply-side resource option tables do not include the potential for such capital cost
reductions since the benefits are not expected to be realized until the next generation of new
plants are built and operated. For example, construction and operating "experience curve"
benefits for IGCC plants are not expected to be available until after their commercial operation
dates. As such, future IRPs will be better able to incorporate the potential benefits of future cost
reductions. Given the current emphasis on construction and operating experience associated with
renewable generation, PacifiCorp anticipates the cost benefits for these technologies to be
available sooner. The estimated capital costs are displayed in the supply-side resource tables
along with expected availability of each technology for commercial utilization.
Resource Options and Attributes
Table 6.1 lists the cost and performance attributes for supply-side resource options designated by
generic, elevation-specific regions where resources could potentially be located:
o ISO conditions (sea level and 59 degrees F); this is used as a reference for certain
modeling purposes.o 1,500 feet elevation: eastern OregorVWashington.
o 3,000 feet elevation: southern/central Oregono 4,500 feet elevation: northern Utah, specifically Salt LakeAjtah/Tooele/Box Elder
counties
o 5,050 feet elevation: central Utah, southern Idaho, central Wyoming.o 6,500 feet elevation: southwestern Wyoming
Tables 6.2 and 6.3 present the total resource cost attributes for supply-side resource options, and
are based on estimates of the first-year, real-levelized costs for resources, stated in June 2016
dollars. Similar to the approach taken for the 2015 IRP, it is not currently envisioned that new
combined cycle resources could be economically permitted in northern Utah, specifically Salt
Lakefutah/Davis/Box Elder counties due to state implementation plans for these counties
regarding particulate matter of 2.5 microns and less (PMz.s).
A Glossary of Terms and a Glossary of Acronyms from the Supply Side Resource table is
summarized in Table 6.4 and Table 6.5.
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PncmrConr- 2017IRP Cnaprsn 6 - RESoURCE OPTroNs
Additionally, total resource costs were prepared for three natural gas-fired combined cycle
combustion turbine resource options at an elevation of 5,050 feet at varying capacity factors to
show how these costs are affected by dispatch. Table 6.3 shows the total resource cost results for
this analysis.
Table 6.3 - Total Resource for various Factors 201
Capaci8 Factor CCCT 400h 78o/o 94Vo
Capaci8 FactorDuct Fire lto/o 12o/"22o/"
CCCT Drv'G/fI", lxl $66.06 $44. l8 940.26
CCCT Drv "GAI". DF. lxl s8s.99 $76. l9 $s3.92
CCCT Drv "GAI".2xl $54.s7 s38.22 $3s.29
CCCT Drv "Giy'H". DF.2xl $76.91 $68.61 $49.7s
CCCT Drv'T/HA.02"" lxl s60.33 $41.14 s37.70
CCCT Drv'T1HA.02". DF. lxl s80.21 $71.40 $51.37
CCCTDrv. "J/HA.022Xl $s0.4s s36.01 $33.42
CCCT Dry "J /H4.02", DF, 2Xl $72.70 $6s. l l v7.87
Table 6.4 -of Terms from Side Resource Table
Fuel Primary fuel used for electricity seneration or storase.
Resource Primary technology used for electriciW generation or storage.
Elevation (afsl)Average feet above sea level for the proxy site for the given resource
Net Capacify (MW)
For nafural gas-fired generation resowces, the Net Capacity is the net
dependable capacrty (net electrical output) for a given technology, at the
given elevation, at the annual average ambient temperature in a "new
and clean" condition.
Commercial
Operation Year
The resource availability year is the earliest year the technology
associated with the given generating resource is commercially available
for procurement and installation. The total implementation time is the
number of years necessary to implement all phases of resource
development and construction: site selection, permitting, maintenance
contracts, IRP approval, Rf'P process, owner's engineering,
construction, commissioning and erid interconnection.
Design Life (years)
Average number of years the resource is expected to be "used and
useful," based on various factors such as manufacturer's guarantees,
fuel availabilitv and environmental regulations.
Base Capital ($/kW)
Total capital expenditure in $lkW for the development and constructionof a resource including: direct costs (equipment, buildings,
installation/overnight construction, commissioning, contractor
fees/profit and contingency), owner's costs (land, water rights,
permitting, rights-of-way, design engineering, spare parts, project
management, legal/financial support, grid interconnection costs,
owner's contingency), and financial costs (AFUDC, capital surcharge,
property taxes and escalation during construction, if applicable).
tt4
PACIFICoRP_20IT IRP CH.qsren 6 - Rrsouncr OPTIoNS
Includes real levelized variable operating costs such as combustion
turbine maintenance, water costs, boiler water/circulating water
treatment chemicals, pollution control reagents, equipment maintenance
and fired hour fees.
Var o&M ($Adwh)
Fixed O&M ($/kW-
year)
Includes labor costs, combustion turbine fixed maintenance fees,
contracted services fees, office equipment and training.
Full Load Heat Rate
HHV (Bfu/KWh)
Net efficiency of the resource to generate electricity for a given heat
input in a "new and clean" condition on a higher heating value basis.
Estimated Equivalent Forced Outage Rate, which includes forced
outages and derates for a given resource at the given site.EFOR (%)
POR (%)Estimated Planned Outage Rate for a given resource at the given site
Water Consumed
(galllvlWh)
Average amount of water consumed by a resource for make-up, cooling
water make-up, inlet conditioning and pollution control.
SOz (lbs/TvlMBtu)Expected permitted level of sulfru dioxide emissions in pounds of sulfur
dioxide per million Btu of heat input.
Expected permitted level of nitrogen oxides (expressed as NOz) in
pounds ofNOx per million Btu of heat input.NOx (lbslN4MBtu)
Hg (lbs/TBtu)Expected permitted level of mercury emissions in pounds per trillion
Btu of heat input.
COz (lbs/IvlMBtu)Pounds of carbon dioxide emitted per million Btu of heat input.
Table 6.5 - G of Used in the Side Resources
AFSL Average Feet (Above) Sea Level
Compressed Air Energy StorageCAES
Combined Cycle Combustion TurbineCCCT
Carbon Capture and SequestrationCCS
Capaciry FactorCF
CSP Concentrated Solar Power
DF Duct Firing
IC Intemal Combustion
IGCC Integrated Gasifi cation Combined Cycle
ISO InternationalOrganrzation for Standardization (Temp : 59 Fll5 C,
Pressure :14.7 psia/l.013 bar)
PPA Power Purchase Agreement
PC CCS Pulverized Coal equipped with Carbon Capture and Sequestration
PV Poly-Si Photovoltaic modules constructed from poly-crystalline silicon
semiconductor wafers
Recip Reciprocating Engine
SCCT Simple Cycle Combustion Turbine
Super-Critical Pulverized CoalSCPC
115
PAcrnConp-20l7IRP CHepren 6 - RESoURCE OprroNs
Resource Descriptions
The following are brief descriptions of each of the resources listed in Table 6.1
Itind
Wind. 2.0 MW turbine 38% NCF WA/OR/ID - a wind resource based on 2.0 MW wind turbines
located in Washington, Oregon or Idaho with an estimated annual net capacity factor of 38%.
The scope would include developing, permitting, engineering, procuring equipment and
constructing a wind farm.
Wind. 2.0 MW turbine 31% NCF UT - a wind resource based on 2.0 MW wind turbines located
in Utah with an estimated annual net capacity factor of 3lYo. The scope would include
developing, permitting, engineering, procuring equipment and constructing a wind farm.
Wind. 3.3 MW turbine 43% NCF WY - a wind resource based on 3.3 MW wind turbines located
in Wyoming with an estimated annual net capacity factor of 43o/o. The scope would include
developing, permitting, engineering, procuring equipment and constructing a wind farm.
Solar
Solar. PV Fixed Tilt 26.8% NCF UT (1.35 MWdc/MWac) - a large utility scale (50 MW) solar
photovoltaic resource using crystalline silica panels in a fixed tilt configuration located in
southwestem Utah. A similar resource with the same DC/AC ratio built in southeastern Oregon
would have a 24.9% net capacity factor.
Solar. PV Single Axis Tracking 31.1% NCF UT (1.25 MWdc/N{Wac) - a large utility scale (50
MW) solar photovoltaic resource using crystalline silica solar panels in a single axis tracking
system located in southwestern Utah. A similar resource with the same DC/AC ratio built in
southeastern Oregon is estimated to have a28.8%;o net capacity factor.
Solar. CSP Troueh w Natural Gas - a concentrated solar resource using parabolic trough
technology. The system would be equipped with natural gas fueled boiler to supply steam during
cloudy or evening hours.
Solar. CSP Tower 24% CF - a concentrated solar resource using a power tower technology
feeding a boiler based system for power production. The boiler based system could use natural
gas as a backup fuel for the boiler during cloudy or evening hours in which case the capacity
factor would be variable.
Solar. CSP Tower Molten Salt 30% CF - a concentrated solar resource using a power tower
technology. The boiler based system would use molten salt as the heat transfer medium with
natural gas as a backup fuel for the boiler during cloudy or evening hours. A four to six hour
storage system would allow a capacity factor increase of about six percent.
116
PACIFICORP - 20I7 IRP Cserrpn 6 - REsouRCp OpuoNs
Biomsss
Biomass. Forestry Byproduct - a resource fueled by forestry byproducts. Resources tend to be
smaller and constrained by the economically available fuel. It is expected that these types of
resources would not be developed by the Company but would be secured through power
purchase agreements.
Geothermal
Geothermal. Blundell Dual Flash 90% CF - a dual flash geothermal resource located at the
Roosevelt Hot Springs in southern Utah.
Geothermal. Greenfield Binarv 90o/o CF - a geothermal resource based on binary technology
assuming development of a new geothermal resource.
Geothermal. Generic Geothermal PPA 90% CF - power and electric energy provided through a
power purchase agreement.
Natural Gas
Natural Gas. SCCT Aero x3 - a resource based on tlree General Electric LM6000PF-Sprint
simple cycle aero-derivative combustion turbines fueled on natural gas. The scope would include
selective catalytic reduction systems and oxidation catalysts to reduce NOx and carbon
monoxide/volatile organic compounds (VOC) emissions.
Natural Gas- I SCCT Aero x 2 - a resource based on two General Electric
LMS1O0PA+ simple cycle aero-derivative intercooled combustion turbine fueled on natural gas.
Scope would include selective catalytic reduction systems and oxidation catalysts to reduce NOx
and carbon monoxide/VOC emissions. An air-cooled intercooler is assumed.
Natural Gas. SCCT Frame "F" xl - a resource based on one General Electric 7FA.05 simple
cycle frame type combustion turbine fueled on natural gas. Scope would include selective
catalytic reduction systems and oxidation catalysts to reduce NOx and carbon monoxide/VOC
emissions.
Natural Gas. IC Recips x6 - a resource based on six Wartsila I8V50SG reciprocating engines
fueled on natural gas. Scope would include selective catalytic reduction systems and oxidation
catalysts to reduce NOx and carbon monoxide/VOC emissions.
Natural Gas. CCCT Dry "G/FI". lxl - a combined cycle resource based on one frame-type
General Electric 7HA.01 combustion turbine, one 3-pressure heat recovery steam generator and
one steam turbine. Scope would include selective catalytic reduction systems and oxidation
catalysts to reduce NOx and carbon monoxide/VOC emissions. Steam from the steam turbine is
condensed in an air cooled condenser.
Natural Gas. CCCT Dry "G/FI". DF. lxl - an option that can be added to a combined cycle plant
to increase its capacity by the addition of duct burners in the heat recovery steam generator. This
increases the amount of steam generated in the heat recovery steam generator. The amount of
tt7
PACIFICoRP-20I7IRP CHAPTER 6 - RESoURCE OprroNs
duct firing is up to the owner. Depending on the amount of duct firing added, the size of the
steam turbine, steam turbine generator and associated feedwater, steam condensing and cooling
systems may need to be increased. This description also applies to the following technologies
that are listed on Table 6.1: CCCT Dry "G/fI", DF, 2x1; CCCT Dry "J/FIA.O2", DF, lxl; CCCT
Dry "J/[IA.02",DF,2xl.
Natural Gas" CCCT Drv "G/[I". 2x1 - a combined cycle resource based on two frame-type
General Electric 7HA.01 combustion turbines, two 3-pressure heat recovery steam generators
and one steam turbine. Scope would include selective catalytic reduction systems and oxidation
catalysts to reduce NOx and carbon monoxide/VOC emissions. Steam from the steam turbine is
condensed in an air cooled condenser.
Natural Gas. CCCT Dry "J/HA.02". lxl - a combined cycle resource based on one frame-type
General Electric 7HA.02 combustion turbine (air-cooled), one 3-pressure heat recovery steam
generator and one steam turbine. Scope would include selective catalytic reduction systems and
oxidation catalysts to reduce NOx and carbon monoxide/VOC emissions. Steam from the steam
turbine is condensed in an air cooled condenser.
Natural Gas. CCCT Dry "J/[IA.02". 2x1 - a combined cycle resource based on two frame-type
Mitsubishi M50IGAC combustion turbines (air-cooled), two 3-pressure heat recovery steam
generators and one steam turbine. Scope would include selective catalytic reduction systems and
oxidation catalysts to reduce NOx and carbon monoxideA/OC emissions. Steam from the steam
turbine is condensed in an air cooled condenser.
Storage
Storage. Pumped Storage - a moderately sized (600 MW) pumped storage system using a
combination of natural and constructed water storage combined with elevation difference to
enable a system capable of discharging the rated capacity for eight hours combined with
recharging that capacity over 16 hours. Total development time is estimated at l0 years for
permitting.
Storage. Lithium Ion Battery - a battery technology of lithium ion batteries located close to the
load center. Based on current commercial options such a system is modeled with an acquisition
and implementation schedule of one year.
Storage, Sodium-Sulfur Battery - a battery technology of sodium-sulfur batteries. Based on
current commercial options such a system is modeled with an acquisition and implementation
schedule ofone year.
Storage" Vanadium RedOx Battery - abattery technology based vanadium ReDOx flow battery.
Based on current commercial options such a system is modeled with an acquisition and
implementation schedule of one year.
Storage. CAES - A compressed air energy storage (CAES) system consists of air storage
reservoir replacing the compressor on a conventional gas turbine. The gas turbine exhaust
powers a power turbine providing a simple cycle gas turbine energy at lower costs than a
conventional gas turbine. Off-peak energy is used to compress air into the storage reservoir. A
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PACIFICoRP-20I7IRP Cueprpn 6 - RESoURCE OPTToNS
system size of 320 MW is assumed. The air storage reservoir is assumed to be solution mined to
size. Natural gas is required to generate power.
Nuclear
Nuclear. Advanced Fission - a large 2,234 MW nuclear resource reflects the current state-of-the-
art advanced nuclear plant and is modeled after the Westinghouse AP1000 technology currently
being installed by Southern Company at the Vogtle Generating Station in Georgia. The assumed
location for this resource is the proposed Blue Castle site near Green River, Utah which is in
development. It is expected that the resource would be available no earlier than2025.
Nuclear. Small Modular Reactor - such systems hold the promise of being built off-site and
transported to a location at lower cost than traditional nuclear facilities. A nominal 570 MW
concept is included. It is recognized that this concept is still in the design and licensing stage
and is not commercially available, requiring at least 10 years for nuclear availability.
Coal
Coal" SCPC with CCS - conventional coal-fired generation resource including a supercritical
boiler (up to 4000 psig) using pulverized coal with all emission controls including scrubber,
fabric filters (baghouse), mercury control, selective catalytic reduction (SCR) and carbon capture
and sequestration (CCS) to reduce carbon dioxide emissions by 90%.
Coal. PC CCS retrofit @ 500 MW - a retrofit of an existing conventional coal-fired boiler and
steam turbine resource. Costs include the reduction in plant output due to higher auxiliary power
requirements and reduced steam turbine output and would remove carbon dioxide by 90Yo and
provide a marginal improvement in other emissions.
Coal, IGCC with CCS - an advanced Integrated Gasification Combined Cycle (IGCC) resource
to facilitate lower cost carbon capture and sequestration costs. An IGCC plant produces a
synthetic fuel gas from coal using an advanced oxygen blown gasifier and burning the synthetic
fuel gas in a conventional combustion turbine combined cycle power facility. The IGCC would
utilize the latest advanced combustion turbine technology and provide fuel gas cleanup to
achieve ultra-low emissions of sulfur dioxide, nitrogen oxides using selective catalytic reduction
systems, mercury and particulate. Carbon dioxide would be removed from the synthetic fuel gas
before combustion thereby reducing carbon dioxide emissions by more than 90o/o.
Resource Options Descriptions
Wind
PacifiCorp commissioned a study of utility scale wind generation by Black & Veatch in20l6 to
get market based estimates of the capital cost to build new wind projects, the ongoing operation
and maintenance costs, and energy production for projects of a nominal 100 MW size.
PacifiCorp reviewed operation and maintenance costs for existing Company owned projects and
communicated with wind equipment manufacturers and construction companies for
supplemental cost information that was used to inform the 2017 IRP. The wind turbine generator
(WTG) selection and net capacity factors are based upon the analysis performed by Black &
Veatch to design projects that delivered the lowest cost of energy to customers. Black & Veatch
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PecrplConp-2017IRP Cseprsn 6 - RESoURCE OptroNs
chose Vestas 2.0 MW WTGs for their sample layouts in Washington, Oregon, Idaho and Utah,
and chose Vestas 3.3 MW WTGs for their sample layouts in Wyoming. While Vestas WTGs are
sited in the IRP, WTGs from all manufacturers that meet PacifiCorp's quality standards would
be acceptable for new wind farm construction.
Federal Production Tax Credits (PTCs) were extended in December 2015 and included a
graduated phase out structure that reduces the value of the credits between 2017 and 2020. The
PTC extension led to increasing demand for WTGs in the United States during 2016 and is
expected to stimulate demand through 2018 at a minimum. The phase out period has impacted
the timing of WTG purchases as developers have purchased WTGs earlier in the development
and construction process to secure more PTC benefits. Black & Veatch estimates the cost of
WTGs and wind projects will increase through 2018 because of increased market demand,
followed by five years of declining prices as the market adjusts to the expiration of the PTCs.
Wind Capital Costs
Capital cost estimates for wind resources in the IRP are based upon a combination of the Black
& Veatch study and communications with wind equipment and construction companies. All
wind resources are specified in 100 MW blocks, but the model can choose a fractional amount of
a block.
Wind Resource Capacity Factors and Energy Shapes
Resource options in the topology bubbles are assigned capacity factors based upon historic or
expected project performance. Assigned capacity factor values for wind resources are 43 percent
in Wyoming,3SYo in Washington, Oregon and Idaho, and 3l percent in Utah. Capacity factor is
a separate modeled parameter from the capital cost, and is used to scale wind energy shapes used
by both the System Optimizer and Planning and Risk models. The hourly generation shape
reflects average hourly wind variability. The hourly generation shape is repeated for each year of
the simulation.
Wind Intesration Costs
To capture the costs of integrating wind into the system, PacihCorp applied a value of
$0.573l\4wh (in 2016 dollars) for resource selection. To capture the costs of integrating solar
into the system, PacifiCorp applied a value of $0.603AvIWh (in 2016 dollars). Additional detailed
information can be found in the Company's 2017 flexible reserve study (Volume II, Appendix
F). Integration costs were incorporated into wind capital costs based on a 30-year project life
expectancy and generation performance.
Solar
Three solar technologies are included in the supply side resource table: single axis tracking
(SAT) photovoltaic (PV), fixed tilt PV and concentrated solar. Based upon current technology
and market conditions, PV resources have lower capital intensity and are better suited to
PacifiCorp's service territory than concentrated solar systems. PacifiCorp evaluates projects
based upon the cost of the energy produced over the life of the project. Among large utility scale
solar projects, SAT projects often have lower energy costs than fixed tilt projects because the
additional generation produced by the tracking system more than offsets the higher capital cost
over the life of the resource. The choice of which mounting system to use is site and project
specific.
t20
PacmrConp-20l7IRP CHAPTER 6 - RESoURCE OPTIoNS
PacifiCorp commissioned a study of utility scale solar PV generation by Black & Veatch in2016
to get market based estimates of the capital cost to build new solar projects, the ongoing
operation and maintenance costs, and energy production for projects of a nominal 50 MW size in
Utah and Oregon. To estimate costs and generation for fixed tilt and SAT 50 MW projects, Black
& Veatch created a project design that included: solar resource information, selection of
components, layout, DC to AC ratio and loss factors. PacifiCorp applied various owner's costs to
the Black & Veatch estimate to create the capital costs reported in Table 6.1.
In December 2015, the 30%o investment tax credit (ITC) for solar generation was extended
through 2019, phase out values of 26%o and 22oh were put in place for 2020 and 2021
respectively, and a l|oh permanent value for commercial projects will begin in 2022. The
extension of the ITC combined with the falling cost of PV modules has fueled the continued
growth of the solar market across the United States. Increases in inverter sizes and mounting
systems that are more easily assembled in the field are lowering capital costs as well.
PacifiCorp's estimated capital costs for PV in the 2017 IRP are based upon Black & Veatch's
study results and PacifiCorp's estimated owner's costs. The IRP estimates new 50 MW SAT PV
projects in Utah and Oregon will cost less than $1,900 per kW and new 50 MW fixed tilt PV
projects will cost less than $1,800 per kW. Black & Veatch estimates the capital cost of new PV
projects will decrease by about 25%o over the next ten years.
There was significant solar development activity in PacifiCorp's service territory between 2012
and 2016. Over the course of those five years, 199 solar projects with nameplates of 10 MW or
greater have initiated generation interconnection requests with PacifiCorp. The total nameplate
capacity of those 199 projects is over 12,500 MW. There were 95 new generation projects
greater than 10 MW that entered PacifiCorp's generation interconnection queue during 2016; of
these 95 new projects, 86 are solar, 8 are wind and 1 is energy storage. The nameplate capacity
of the 86 solar projects added in 2016 alone is over 8,300 MW. While many projects that have
initiated generation interconnection studies over the past 15 years have not been built, the
number and size of the 2016 interconnection solar projects is testament to the tremendous solar
development activity that is underway within PacifiCorp's service territory.
Biomass
Cost and performance data for biomass based resources were obtained from third-party studies.
The Pacific Northwest and Atlantic Southeast are generally considered good regions for siting
biomass generation plants because the climate supports the abundant growth of fuel resources. In
general, large-scale (greater than 50 MW) plants are rare, which is why the resource is
represented as a 5 MW plant in the supply side resource table. Many biomass products have
multiple potential uses including industrial manufacturing, agriculture and energy generation.
Because these other uses increase the demand and cost of the source material, biomass electric
generation facilities often operate in areas that pay high prices for electricity production or have
significant regulatory or incentive structures in place to support biomass based electric
generation. Select coal plants in the United States and other parts of the world have been
converted from burning coal to burning various types of biomass, including wood chips,
cellulosic switch grass, municipal solid waste, or, in rare cases, an engineered fuel which adds
processing and sorbents to the aforementioned base fuels. The greatest challenge to building
large biomass generation plants or retrofitting existing coal units is the cost and the availability,
reliability, and homogeneity of a long-term fuel supply. The cost and logistical challenges of
acquiring, transporting, processing and handling large quantities of biomass fuel pose significant
t2r
PecrrrConp-20l7lRP Csepren 6 - RESoURCE OprroNs
challenges. While PacifiCorp currently does not own any biomass plants, the Company does
purchase power from a number of biomass resources in Oregon through power purchase
agreements.
Geothermal
Geothermal resources are a desirable renewable generation resource given their base-load
operating profile combined with high reliability and availability. However, geothermal resources
have significantly higher development costs and exploration risks than other renewable
technologies such as wind and solar. PacifiCorp has commissioned several studies of geothermal
options during the past ten years to determine if additional sources of production can be added to
the Company's generation portfolio in a cost effective manner. A 2010 study commissioned by
PacifiCorp and completed by Black & Veatch focused on geothermal projects near to
PacifiCorp's service territory that were in advanced phases of development and could
demonstrate commercial viability. PacifiCorp commissioned Black & Veatch to perform
additional analysis of geothermal projects in the early stages of development and a report was
issued n20I2. An evaluation of the Company's Roosevelt Hot Springs geothermal resource was
commissioned in 2013. The geothermal capital costs in the 2017 supply side resource option are
built on the understanding gained from these earlier reports, publically available capital costs
from the Geothermal Resources Council and publicly available prices for energy supplied under
power purchase agreements.
The cost recovery mechanisms currently available to PacifiCorp as a regulated electric utility are
not compatible with the inherent risks associated with the development of geothermal resources
for power generation. The primary risks of geothermal development are dry holes, well integrity
and insufficient resource adequacy (flow, temperature and pressure). These risks cannot be fully
quantified until wells are drilled and completed. The cost to validate total production capability
of a geothermal resource can be as high as 35 percent of total project costs. Exploration test wells
typically cost between $500,000 and $1.5 million per well. Full production and injection wells
cost between $4-5 million per well. Variations in the permeability of subsurface materials can
determine whether wells in close proximity are commercially viable, lacking in pressure or
temperature, or completely dry with no interconnectivity to a geothermal resource. As a
regulated utility subject to the public utility commissions of six states, PacifiCorp is not
compensated nor incentivized to engage in these inherently risky development efforts.
To mitigate the financial risks of geothermal development, PacifiCorp would use a Request for
Proposals (RFP) process to obtain market proposals for geothermal power purchase agreements
or build-own-transfer project agreement structures. Geothermal developers, external to
PacihCorp, have the flexibility to structure project pricing to include all development risks.
Through an RFP process, PacifiCorp could choose the geothermal project with the lowest cost
offered by the market and avoid considerable risk for the Company and its customers. Several
geothermal projects submitted proposals in response to the 2016 Oregon Renewables RFP, but
none of the geothermal projects were selected as a new PacifiCorp generation source. In the
event PacifiCorp identifies a geothermal asset that appears to be economically attractive but also
determines that there is a significant possibility of development risk that the market will not
economically absorb, PacifiCorp may approach state regulators with estimates of resource
development costs and risks associated to obtain approval for a mechanism to address risks such
as dry holes. Because public utility commissions typically do not allow recovery of expenditures
122
PecmrConp-2017IRP CHAPTER 6 _ RESoURCE OPTIoNS
which do not result in a direct benefit to customers, and at least one state has a statute that
precludes cost recovery of any asset that is not considered to be "used and useful," obtaining a
mechanism to recover geothermal development costs may be difficult.
Supply and Location of Renewable Resources
In the 2017 IRP, the availability of certain renewable resources is contingent upon transmission
availability. Table 6.6 shows the total cumulative selection limits for solar and geothermal
resources. Table 6.7 shows the total cumulative selection limits for wind resources, varying
depending on whether a case includes an Energy Gateway project assumption.
Table 6.6 - Cumulative Maximum Renewable Selection Limits
Solar: FL€d Tilt / Single Tracking
Table 6.7 - Cumulative Maximum Renewable Selection Limits
Natural Gas
Natural gas-fueled generating resources offer several important services that support the safe and
reliable operation of the energy grid in an economic manner. They include technologies that are
capable of providing peaking, intermediate and base generation.
A variety of natural gas-fueled generating resources that are and will continue to be available for
a several years are included in the Supply Side Resource Table (Table 6.1). The variety of
natural gas resources were selected to provide for generating performance and services essential
to safe and reliable operation of the energy grid. Natural gas resources generate cost competitive
power while producing low air emissions. Natural gas-fueled resources have proven to be highly
Oregon Wind (Arlington/ Medford)38o/o 400 40,0
Washington Wind (Walla Walla)38o/o o o
IJtah Wind (South)3lo/o soo 500W-ind
Idaho Wind (Coshen)38o/o lso 800
Oregon So lar (Lakeview)25/29/o 405 405
Washington Solar CYakima)25/29/o 655 655Solar
I-Itah Solar (South)27/3lo/o 80s 805
9ff/o 35 30(Jtah Geothermal @lundell)
Utah Geothermal (Milfiord)9Oo/o 30 30Geothermal
Oregon Geothermal (Neal Hot Springs)X)o/o 30 30
43o/o 300 0 300 440 300 440 300 r200 r200 0 1,100 0WindWyoming
Wird (Aeolirs)
t23
PecruConp-20l7IRP CHaprrn 6 - RESoURCE OPTIoNS
reliable and safe. Performance, cost and operating characteristics for each resource were
provided at elevations of 1,500, 3,000, 5,050 and 6,500 feet above mean sea level, representative
of geographic areas in which the resource could be located. Performance, cost and operating
characteristics were also provided at ISO conditions (zero feet above mean sea level and 59 "F)
as a reference. The essential services provided by the resource are peaking, intermediate and base
generation.
Three simple cycle combustion turbine options and one reciprocating engine option were offered
to provide peaking generating services. Peaking generating services require the ability to start
and reach near full output in less than ten minutes. Peaking generating services also require the
ability in increase (ramp up) and decrease (rarnp down) very quickly in response to sudden
changes in power demand as well as increases and decreases in production from intermittent
power sources. Peaking generation provides the ability to meet peak power demand that exceeds
the capacity of intermediate and base generation. Peak generation also provides reseryes to meet
system upsets.
Options for peaking resources included in the supply side resources are: 1) three each General
Electric (GE) LM6000 PF aero-derivative simple cycle combustion turbines, 2) two each GE
LMS 100PA* aero-derivative simple cycle combustion turbines, 3) one each GE 7F frame
simple cycle combustion turbine, and 4) six each Wasilla 18V50SG reciprocating internal
combustion engines. All of these options are highly flexible and efficient. Higher heating value
heat rates for the resource ranged from 9,204 Bflrikw-hr for the LM6000 PF to 8,279 Btu/kW-hr
for the 18V50SG engines. Installation of high temperature oxidation catalysts for carbon
monoxide (CO) control and an SCR system for nitrogen oxides (NOx) control would be
available for these resources.
Eight combined cycle combustion turbine options were provided for intermediate and base
generating service. Intermediate generating service requires resources that are able to efficiently
operate at production rates well below full production in compliance with air emissions
regulations for long periods of time. Intermediate generating service also requires the ability to
change production rates quickly. Intermediate generation services provide cost effective means
of providing power demand that is greater than base load and lower than peak demands. Base
generating service requires a highly cost effective turbine that is capable of operating at full
production for long periods of time. Base generation provides for the minimum level of power
demand over a day or longer period of time at a very low cost.
Options for intermediate and base generation were based on two size classes of engines. Thet'Gfll)) size was represented by a GE HA.0l. The "J/HA.02" was represented by the GE HA.02.
Each engine was arranged in a one combustion turbine to one steam turbine (lxl) and a two
combustion turbine to one steam turbine (2x1) conf,rguration to obtain four resource options. The
combined cycle resources offered high heating value heat rates from 6,317 to 6,374 Btu/kW-hr.
Installation of oxidation catalysts for carbon monoxide (CO) control and SCR systems for
nitrogen oxides CIOx) control is expected. All of the combined cycle options included dry
cooling allowing them to be located in areas with water resource concerns.
Duct Firing (DF) of the combined cycle is shown in the Supply Side Resource table. Duct firing
is not a stand-alone resource option, but is considered to be an available option for any combined
cycle configuration and represents a low cost option to add peaking capability at relatively high
efficiency and also a mechanism to recover lost power generation capability at high ambient
t24
PACIFICoRP _20I7 IRP CHaprrn 6 - RESoURcE OPTIoNS
temperatures. Duct firing is shown in the Supply Side Resource table as a fixed value for each
combined cycle combination. In practice the amount of duct firing is a design consideration
which is selected during the development of combined cycle generating facilities.
While equipment provided by specific manufacturers is used for cost and performance
information in the supply side resource table, more than one manufacturer produces these type of
equipment. The costs and performance used here is representative of the cost and performance
that would be expected from any of the manufacturers. Final selection of a manufacturer's
equipment would be made based on a bid process.
New natural gas resources were assumed to be installed at greenfield sites on either the east or
west side of PacifiCorp's system. Greenfield development includes the costs of high pressure
nafural gas laterals, electrical power transmission lines, ambient air monitoring, permitting, real
estate, rights of way and water rights. Resources additions at a brownfield site, such as an
existing coal-fueled generating facility, costs are reduced to reflect infrastructure at the site.
Energy Storage
For the 2017 IRP, two energy storage studies were conducted to update the studies performed for
previous IRP's. 1) The battery Energy Storage Study focuses only on battery technologies. 2)
The Bulk Energy Storage Study focuses on pumped hydro and compressed air energy storage
(CAES). The estimates and information in the studies was used to inform the 2017 IRP and may
be used to develop alternative applications to traditional utility transmission and distribution
issues. The energy storage studies are available at www.pacificom.com/es/irp.html.
A Battery Energy Storage Summary Supply-Side Resource Table (available at
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy Sources/Inteerated_Resource Pl
anl2017 IRP/2016-IRP_Update_for_Battery_Storage.pdfl was created to provide information
not included in the traditional Supply-Side Resource Table (SSR Table). This table provides
inputs for five size scenarios: four different durations (I,2, 4 and 8 hours) at a power capacity of
I MW and a single larger scale 8 MW system with a duration of 4 hours for a total usable energy
capacity of 32 MWhs. Information for sodium sulfrr batteries is only available for systems of
approximately 8 MWhs; therefore data for the other sodium sulfir system sizes are listed as N/A.
The data for all technologies is standardized at a 20 year system life meaning that degradation
was taken into account such that each system would last 20 years. Thus the maximum annual
generation is limited due to expected degradation. Bulk energy storage systems are included in
Table 6.1.
t25
PecmrConp-2017IRP CHaprsn 6 -REsouRCE OrnoNs
Battery Energ.v Storage Study
The Battery Energy Storage Study (available at http://www.pacificorp.com/content/dam/
Ercificorp/doc/Enerev_Sources/Inteerated_Resource_Plan/2017 IRP/I0018304-R-01-D
PacifiCorp_BattervJnergv_Storase_Studv.pdfl was provided by DNV-GL to update
engineering estimates for the cost and performance of utility scale battery energy storage
technologies, maintain a current catalog of commercially available and emerging battery energy
storage technologies with forecasts and estimates of performance and costs, and provide a
probabilistic cost forecast for each ofthe technologies, broken out by technology costs, energy
conversion system costs and O&M costs.
Table 6.8 identifies the battery technologies and data updated for the 2017 IRP cycle. Note that
for the 2017 IRP, lithium ion batteries were split into the three most common sub-chemistries
and two emerging zinc technologies were added.
Table 6.8 - Updated Battery Technologies and Data
Littrium ion batteries (Li-Ion)
Lithium Nickel Manganese Cobah Oxlle
(LiNiN4nCoO2 or NCM)
Lithium Iron Phosphate (LFePO4)
Lithium Titanate (LATtsOlz or LTO)
Flow batteries:
Vanadium Redox (VRB)
Emerging technologbs
Zinc Bromine (ZnBr) Redox
Znc Hybrd Cathode (Znc - ak)
Sodium sulfur htterbs (NaS)
Stage of Commerchl Devehpment
Typical project size (kW & kwh)
Largest project size installed (kW & kwh)
Current total power capacity (MUD installed
Current total enerry storage capacity (MWh) installed
P erformance Characterbtic s
Power Capacity
Energy Capacity
Recharge Rates
Roundhip Effrciency
Availability
Degradation
Expected Life
Environmental Impact upon disposal
t26
PacrrConp-2017IRP CHapren 6 -Rssouncs OpuoNs
Table 6.9 - Battery Storage Study Sumnary Cost and Capacity Results (2016$)
Average BatteryData
CapitalCost
AmualO&M ($/yr)
System Effcbrrcy (AC or.il/AC in)
TechnicalLiE (years)
Maxinnrn Arrnral Generation (MW}/yr)
EFOR(%o)
POR(7o)
SpirmingReserves (MW)
Ranp Rate (MWsec)
Assurpd C-Rate
Capital Cost ($)
ArmualO&M($.r)
System Effcierrcy (AC ot"il/AC in)
TechnbalLifr (yean)
Maxinnrn Anntal Generation (Mwt/yr)
EFOR(7o)
POR(7o)
Spirning Reserves (MW)
Rarp Rate (MWsec)
Assunpd C-Rate
CapitalCost ($)
AmualO&M($/yr)
SystemEfficierrcy (AC ouf/AC in)
TechnbalLiE (years)
Maximm Anmral Generation (MW}/yr)
EFOR(%o)
POR(7o)
Spiruring Reserves (MW)
Rarp Rate (MWsec)
AssunBd C-Rate
I MW Power Capacity 8MW
I hor.r
1,657,492
2 horrs
2,549,054
4 hours
4,332,178
8 horrs
7,898,425
4 hous
31,t36,475
13,485 18,470 28,440 48,380 227,520
8lo/o 8lo/o 8t%8lo/o 8t%
20 20 20 20 20
184 368 736 1.472 5,888
3o/o 3o/o 3o/o 3o/o 3%
t%lYo t%t%t%
I I I I 8
50 50 50 50 400
IIN/A
IIN/A
IIN/A
I
7.504.817
I
N/A
N/A N/A N/A 53,415 N/A
N/A N/A N/A 80%N/A
N/A N/A N/A 20 N/A
N/A N/A N/A 1,448 N/A
5%5o/o 5%5%5%
lo/o lYo lYo lYo t%
I I I 1 8
0 0 0 0 I
I
-
2.434.917
II
3.003.617
I
-
4.867.017
I
8.593.817
I
37.201.242
15,500 21,500 33,500 57,500 460,000
72o/o 7zYo 72%'720/o 72Yo
20 20 20 20 20
500 1,000 2,000 4.000 16.000
sYo sYo 5Yo 5o/o 5o/o
2%2%2%z%o 2o/o
I I I I 8
25 25 25 25 200
1 I I I I
In addition to updating the cost estimates, cost trend forecasts for the next ten years were
developed. Capital cost forecasts were broken out by storage equipment, power conversion
system equipment, power control system and balance of system. No forecast was provided for
fixed O&M costs. There are a wide variety of O&M agreements and capacity maintenance
agreements which are sometimes rolled into upfront capital costs or combined as a single O&M
agreement. There is not currently a uniform or industry acceptable methodology for quantifring
variable O&M.
Based on the information provided in the study, the Company selected Li-Ion and Flow batteries
to use in the PaR model and developed the following special escalation rates for battery energy
storage. Li-Ion escalation rates are based on an average of the technologies presented in the
study. The data indicates that Li-Ion batteries with higher power-to-energy ratios (also known as
high power batteries) have lower de-escalation rates than high energy Li-Ion batteries. However,
high energy flow batteries have higher de-escalation rates than high energy flow batteries. Larger
scale battery energy storage systems are expected to have the same escalation rates as smaller
systems with the same power-to-energy ratio.
127
PecmConp - 2017IRP Cserren 6 - RssouRcs OPTToNS
The battery storage special escalation rates are provided and reported in Table 6.10.
Table 6.10 -Escalation Rates
Another new subject covered in this study is Utility Applications and Value Stream. The
applicability of each technology and the relative potential for generating economic value were
studied for the following benefit cases within the Company's service territory during the next 20
years. Potential uses include:o Electric Energy Time Shifto Electric Supply Capacity
o Regulationo Spinning, Non-Spinning and Supplemental Reserveso Voltage Supporto Load Following/Ramping Support for Renewableso Frequency Response. Transmission and Distribution Congestion Relief
Bulk Enere.v Storage Study
The Bulk Energy Storage Study (available at http://www.pacificom.com/content/dam/
pacificom/doc/Energy Sources/Intesrated_Resource Plar/2O17_IRP/Black_Veatch_PacifiCom
Bulk-Storaee IRP_Study_Report-final20160819.pdfl provides an update to engineering
estimates for the cost and performance of utility scale bulk energy storage technologies.
The bulk energy storage technologies identified for updates include the technologies identified
below. PacifiCorp has no affiliation or partnership with any of these projects. They are
considered to be in a medium stage of development and are representative of what is available to
PacifiCorp for these types of energy storage systems. Other projects may become available such
as the Banks Lake project. The study provides an updated project status, description and
schedule. Various levels of detail were provided for each project:
o Pumped Hydro (PH)
o Swan Lake North
MW I I 8 I I 8
MWh I 4 32 I 4 32
20t7 -7.77%-9.79%-9.79%-s.98%-5.4t%-5.4t%
2018 -7.00%-9.t5%-9.15%-537%-459%-4.59%
20t9 -6.05%-7.80%-7.80%-4.48%-3.8t%-3.81%
2020 -5.21%-7.05%-7.05%-4.03%-3.5t%-3.51%
202t -435%-6.03%-6.03%-2.98%-2.59Yo -259%
2022 -3.63%-4.84%-4.84%-2.11%-r.7t%-t.71%
2023 -3.04%-4.37%-4.37%-1.80%-r.2r%-1.21%
2024 -2.43%-3.47%-3.47o/o -1.36%-r.03%-t.03%
2025 -1.85%-2.4s%-2.45%-0.84%-0.72%-0.72%
2026 -1.31%-1.48%-1.48%-0.5t%-0.19%-0.19%
t28
PecmrConp - 20l7IRP Csaprsn 6 - Rrsouncp OprroNs
o JD Pool
. Seminoe (previously Black Canyon). Compressed Air Energy Storage (CAES)
o Western Energy Hub
o Norton Energy Storageo PG&E Kern County CAES
o Adele CAES
o APEX Bethel Energy Center
Case-by-Case Analysis of Energy Storage Solutions
In 2015, PacifiCorp hired B&V to develop a cost estimating model for BESS's. The modeled
was vetted against information in the DOE Energy Storage Database and will be updated using
the information provided in this year's battery energy storage study. Estimating the value cases
of ESS's is still under development. PNNL recently developed the Battery Storage Evaluation
Tool (BSET) which models up to four stacked use cases in using actual load data. PacifiCorp is
also participating in EPRI's Energy Storage Integration Council (ESIC) on the development of a
new model called StorageVET which recently underwent alpha and beta testing. StorageVET
appears to combine aspects of earlier models.
While these models are being evaluated, more work is needed to accurately model the value of
potential energy storage projects. Each project needs to have different values applied to the
applicable use cases. Additionally, in a dynamic market those values may change over time,
especially as more of the service is introduced to the market. The Company will continue to
work with organizations like ESIC to further develop storage valuation modeling.
Nuclear
PacifiCorp revisited two of the nuclear options presented in the 2015 IRP: 1) the AP 1000 plant
being developed by Blue Castle Holdings in Green River, Utah rated at 2,234 MW and 2) the
570 MW NuScale Small Modular Reactor (SMR) being developed for construction at the Idaho
National Lab site. PacifiCorp participated in in-depth discussions with Blue Castle Holdings
(BCH) and NuScale regarding the expected levelized cost of energy (LCOE) of each plant. The
data used from BCH and NuScale in this IRP is publicly available.
BCH provided a detailed cost analysis of the Vogtle plant construction and eliminated
unexpected costs which would not apply to the Green River site such as geotechnical problems
encountered at the Vogtle site. The Vogtle plant was a first of a kind (FOAK) plant but the Green
River plant will be an Nth of a kind (NOAK) plant based on the Vogtle plant AP 1000 design.
PacifiCorp added a 3.7o/o delay cost to BCH's capital cost estimate for potential unforeseen
problems not encountered on the Vogtle project. Details of the BCH project can be found at
www. b luecastleproj ect. com/.
NuScale is developed an advanced reactor design in the small modular reactor (SMR) category.
Although it is an FOAK technology, the design has inherent safety features which support
reduced capital costs and operating cost estimates. PacifiCorp has a seat on the NuScale advisory
board, however PacifiCorp has no monetary interest in NuScale or the SMR project being
developed for the Idaho National Lab site. PacifiCorp added 5% contingency and 10Yo delay
r29
PacrnConp- 20l7IRP Cneprun 6 - RESoURCE OPrroNs
costs due to the project being FOAK. Details of NuScale's SMR can be found at
http ://www.nuscalepower.com/.
PacifiCorp's capital cost estimates include a 10.36% owner's cost for the BCH and NuScale
projects. Despite the cost improvements due to the leaming curve associated with the AP-1000'
previous installations or the NuScale SMR's simplified design attributes, nuclear generation is
still expected to have a high LCOE relative to other generation options.
Coal
Potential coal resources are shown in the supply-side resource options table (Table 6.1) as
supercritical pulverized coal boilers (PC) and integrated gasification combined cycle (IGCC),
located in both Utah and Wyoming. Both resource types include carbon dioxide capture and
compression needed for sequestration.
Supercritical technology is considered the standard design technology compared to subcritical
technology for pulverized coal. Increasing coal costs make the added efficiency of the
supercritical technology more cost-effective. Additionally, there is a greater competitive
marketplace for large supercritical boilers than for large subcritical boilers. Increasingly, large
boiler manufacturers only offer supercritical boilers in the 500-plus MW sizes. Due to the
increased effrciency of supercritical boilers, overall emission intensity rates are smaller than for
similarly sized subcritical units. Compared to subcritical boilers, supercritical boilers also have
better load following capability, faster ramp rates, use less water and require less steel for
construction. The costs shown in Table 6.1 for a supercritical PC facility reflect the cost of
adding a new unit at an existing site.
The requirement for COz capture and sequestration (CCS) represents a significant cost for both
new and existing coal resources. In order for a coal-fueled generating facility to meet the Federal
New Source Performance Standards for Greenhouse Gases (NSPS-GHG) carbon dioxide
emissions limit of 1,100 lbs per megawatt-hour would require COz capture and permanent
sequestration. Based on this requirement, only coal resource options that include carbon capture
are included in the Supply Side Resource Table.
Two major utility-scale CCS retrofit projects have been recently constructed and have entered
commercial operation on pulverized coal plants in North America. SaskPower's 115 MW (net)
$1.24 billion Boundary Dam project entered commercial operation in October 2014.In July,
2016, the plant reached a major milestone when it had demonstrated that over 1,100,000 tons of
COz had been captured. In January,2017, NRG's Petra Nova project went into commercial
operation. Both of these projects have COz capture rates in excess of 90o/o; sequestration is
accomplished through enhanced oil recovery (EOR). Both of these projects utilize amine-based
systems for carbon dioxide capture.
The Petra Nova project is especially meaningful in that the project entailed a retrofit of an
existing coal-fueled plant using an amine based system and captures approximately 5,000 tons
per day from the 240 MWe equivalent flue gas slipstream from NRG's W.A. Parish unit 8.
Captured COz is transported through an Sl-mile pipeline and used for EOR at the West Ranch
Oilfield, located on the Gulf Coast of Texas. It is the largest retrofit of a carbon capture
technology of a pulverized coal plant in the world. The project was constructed and
130
PRCITICoRp-20I7 IRP CHeprER 6 - RESoURCS OprroNs
commissioned on schedule. No major cost increases have been reported; material cost increases
and schedule delays have been the prevailing characteristic of a number of recent clean coal
projects. Petra Nova is a 50-50 joint venture by NRG and JX Nippon. The United States
Department of Energy (DOE) is providing up to $190 million in grants as part of the Clean Coal
Power Initiative progftlm (CCPD, a cost-shared collaboration between the federal government
and private industry. Managed and executed in the U.S., the capture system is based on
Mitsubishi's proprietary KM CDR Process@ and uses its KS-1rM amine solvent.
MHIA formed a consortium with TIC (The Industrial Company) to construct the project on a full
turnkey basis. The consortium began construction in September 2014 and completed the
performance tests in December 2016.
PacifiCorp continues to monitor these COz capture technologies for possible retrofit application
on its existing coal-fired resources, as well as their applicability for future coal plants that could
serve as cost-effective alternatives to IGCC plants. An option to capture COz at an existing coal-
fired unit has been included in the supply side resource tables. Currently there are only a limited
number of large-scale sequestration projects in operation around the world; most of these have
been installed in conjunction with enhanced oil recovery. Given the high capital cost of
implementing CCS on coal fired generation (either on a retrofit basis or for new resources) CCS
is not considered a viable option before 2025. Factors contributing to this position include capital
cost risk uncertainty, the availability of commercial sequestration (non-EOR) sites, and the
uncertainty regarding long term liabilities for underground sequestration.
To address the availability of commercial sequestration, three PacifiCorp power plants are
participating in new federally funded research into carbon capture and storage. A grant from the
U.S. Department of Energy to the University of Wyoming will be used to assess the storage of
carbon dioxide in the Rock Springs Uplift, a geologic formation located adjacent to the Jim
Bridger Plant in southwest Wyoming. Similar funding will allow the University of Utah to study
the feasibility of long-term carbon dioxide storage in the San Rafael Swell near the Hunter and
Huntington plants in central Utah. Both of these projects were selected based on the proximity to
the geologic formations and the plants, which are major sources of carbon dioxide.
An alternative to supercritical pulverized-coal technology for coal-based generation is the
application of IGCC technology. A significant advantage for IGCC when compared to
pulverized coal with amine-based carbon capture, is the reduced cost of capturing COz from the
process. Only a limited number of IGCC plants have been built and operated around the world.
In the United States, these facilities have been demonstration projects, resulting in capital and
operating costs that are significantly greater than those costs for conventional coal plants. These
projects have been constructed with significant federal funding. One large, utility-scale IGCC
plant with carbon capture capability recently went into service. Southem Company's 582 MWnet
$6.8 billion Kemper County project includes carbon capture (65Yo capture) and sequestration (for
EOR). The plant is expected to enter commercial operation on coal-fuel based syn-gas in the first
quarter of2017.
The Texas Clean Energy Project is a second IGCC project which also includes carbon dioxide
capture and is currently in an advanced stage of development. This project anticipates using
Siemens gasification technology with COz capture being used for both EOR purposes and urea
l3l
PacmrConp - 2017 IRP Cuaprrn 6 - RESoURCE OprroNs
production. However, it is uncertain at this stage if this project will progress to construction
given recent de-funding announcements by the US DOE.
The costs presented in the supply-side resource option tables for new IGCC resources are based
on 2007 studies of IGCC costs associated with efforts to partner PacifiCorp with the Wyoming
Infrastructure Authority $IIA) to investigate the acquisition of federal grant money to
demonstrate western IGCC proj ects.
Other than the Texas Clean Power Project, which is the only current coal-fueled IGCC project in
development in the United States, a consortium of Japanese firms received orders on December
1,20L6 for two 540 MW IGCC plants to be constructed in Japan based on Mitsubishi's IGCC
technology that was tested at the Nakoso Power Station from2007 through 2013. A number of
countries, including Dubai, India, Kenya, Philippines and Malaysia have recently announced
plans to construct new conventional coal-fueled electric generating resources.
No new cost studies were performed for coal-fueled generation options in2016. Updated capital
and O&M costs for coal-fuel generation options were based on escalating costs used in the 2015
IRP.
Coal Plant Efficiency Improvements
Fuel efficiency gains for existing coal plants, which manifest as lower plant heat rates, are
realized by: (1) continuous operations improvement, (2) monitoring the quality of the fuel
supply, and (3) upgrading components if economically justified. Efficiency improvements can
result in a smaller emissions footprint for a given level of plant capacity, or the same footprint
when plant capacity is increased.
The effrciency of generating units, primarily measured by the heat rate (the ratio of heat input to
energy output) degrades gradually as components wear over time. During operation, controllable
process parameters are adjusted to optimize the unit's power output compared to its heat input.
Typical overhaul work that contributes to improved efficiency includes (1) major equipment
overhauls of the steam generating equipment and combustion/steam turbine generators, (2)
overhauls of the cooling systems and (3) overhauls of the pollution control equipment.
When economically justified, efficiency improvements are obtained through major component
upgrades of the electricity generating equipment. The most notable examples of upgrades
resulting in greater generating capacity are steam turbine upgrades. Turbine upgrades can consist
of adding additional rows of blades to the rearward section of the turbine shaft (generically
known as a "dense pack" configuration), but can also include replacing existing blades, replacing
end seals, and enhancing seal packing media. Currently the Company has no plans to make any
major steam turbine or generator upgrades over the next 10 years.
t32
PacrnConp - 2017 IRP CHAPTER 6 - RESoURCE OpTToNs
Resource Options and Attributes
Source of Demand-side Management Resource Data
Demand-side management (DSM) resource opportunity estimates used in the development of the
2017 IRP were derived from the Demand-side Resource Potential Assessment for 2017-2036
(DSM Potential Study) conducted by Applied Energy Group (AEG). This study provided a
broad estimate of the size, type, location and cost of demand-side resources.l For the purpose of
integrated resource planning, the demand-side resource information from the DSM Potential
Study was converted into supply curves by type of DSM (i.e. capacity-focused Classes 1 and 3
DSM and energy-based Class 2 DSM) for modeling against competing supply-side alternatives.
Demand-side Management Supply Curves
Resource supply curves are a compilation of point estimates showing the relationship between
the cumulative quantity and cost of resources, providing a representative look at how much of a
particular resource can be acquired at a particular price point. Resource modeling utilizing
supply curves allows the selection of least-cost resources (products and quantities) based on each
resource's competitiveness against altemative resource options. At the time of preparation for
the 2017 IRP, the Company had established DSM acquisition targets and funding levels and had
begun acquiring savings for calendar year 2017. To ensure that the 2017 IRP analysis is
consistent with those planned Class 2 DSM acquisition levels, expected DSM savings in each
state were fixed for calendar year 2017. Beyond 2017, the model optimized DSM selections.
As with supply-side resources, the development of demand-side resource supply curves requires
specification of quantity, availability, and cost attributes. Attributes specific to demand-side
supply curves include:
o Resource quantities available in each year-either in terms of megawatts or megawatt-
hours- recognizing that some resources may come from stock additions not yet built,
and that elective resources cannot all be acquired in the first year of the planning period;
o Persistence of resource savings; for example, Class 2 DSM (energy-focused) resource
measure lives;
o Seasonal availability and hours available (Class 1 DSM capacity resources);
o The hourly shape of the resource (load shape of the Class 2 DSM energy resource); and
. Levelized resource costs (dollars per kilowatt per year for Class 1 DSM capacity
resources, or dollars per megawatt-hour over the resource's life for Class 2 DSM energy
resources).
Once developed, DSM supply curves are treated like discrete supply-side resources in the IRP
modeling environment.
I The 2017 DSM potential study is available on PacifiCorp's demand-side management web page
hffp ://www.pac ifi corp.com/es/dsm.htm I
133
PACIFTCoRP-20l7IRP CHavren 6 - RESoURCE OprroNs
Class I DSM Capacity Supply Curves
The potentials and costs for Class I DSM products were provided at the state level, with impacts
specified separately for summer and winter peak periods. Resource price differences between
states for similar resources reflect differences in each market, such as inigation pump size and
hours of operation, as well as product performance differences. For instance, residential air
conditioning load control in Oregon is more expensive than Utah on a unitized or dollar-per-
kilowatt-year basis due to climatic differences that result in a lower load impact per installed
switch
Table 6.11 and Table 6.12 show the summary level Class 1 DSM resource supply curve
information, by control area. For additional detail on Class I DSM resource assumptions used to
develop these supply curves, see Volume 3 of the 2017 DSM Potential Study.2 Potential shown
is incremental to the existing Class 1 DSM resources identified in Table 5.12. For existing
program offerings, it is assumed that the Company could begin acquiring incremental potential in
2017. For resources representing new product offerings, it is assumed the Company could begin
acquiring potential in 2019, accounting for the time required for program design, regulatory
approval, vendor selection, etc.
2 http://www.pacifi corp.com/es/dsm.html
t34
PACIFICoRP_20I7IRP Csarren 6 - Rpsounce OPTroNs
Table 6.11 - Class 1 DSM Attributes West Control Area
I For consistency in modeling, water heating potential for both searions is included with the central air conditioning
product.
Table 6.12 - Class l DSM Attributes East Control Area
I For consistency in modeling, water heating potential for both seasons is included with the central air conditioning
product.
Class 2 DSM, Enerry Supply Curves
T\e2017 DSM potential study provided the information to fully assess the potential contribution
from Class 2 DSM resources over the IRP planning horizon accounting for known changes in
building codes, advancing equipment efficiency standards, market transformation, resource cost
changes, changes in building characteristics and state-specific resource evaluation considerations
(e.g., cost-effectiveness criteria).
58 $71 - $104 251 $198 - $248Resitential ard Snull Cornrprcbl
Air Conditbnine ard WaterHeating
Resiterfhl and Snrall C ormrBrcial
Space Heating nla nla tt7 $40 - $sl
Resilerf hl Room Air C ondiliorBrs J $238 - S404 nla rla
2t $65 - $100 5l $34 - $3eResilential Srmrt Thermostats
5 $2s6 - $263 5 $256 - $263Resllential Snnrt Appliarpes
Resllerthl Electic Vehicb Chargirs ll $236 - S24t ll $236 - $241
27 $80 - s8l nla n/aLrisatbn Direct load Cor{rol
49 $85 - S89 44 $96 - Sl23C orrrrprcbVlrdustial Curtaftrprt
Ice Errcrpy Storase 7 $199 - $204 n/a n/a
Resllertial ard Small Cormrercial
Air Conditioning and Water Heating 108 s43 - $r02 2ol $302 - $661
Resilenthl and Srnall Connnercial
Space Heating n/a n/a 82 $34 - $43
Resllerfr hl Room Air Conditiorprs 5 $18s - $264 rla nla
46 $4s - $93 2t $39 - $l2sResilential Snrart Thermostats
Resllerfiial Srnart Appliarrces 9 $266 - $278 9 s266 - 5278
Resilerthl Ehctb Vehicle CtrargtC l0 s244 - $250 l0 $244 - g2s0
Irrimtbn Dire ct l-oad Cortrrol 3l $58 - $82 n/a nla
134 $90 - sl08 108 s92 - $l2lConrnerch/Indutrhl Curtaikrprl
Ice Enerpl,r Storage 8 $206 - $217 rla nla
135
PecrrrConp - 2017 IRP Cseprrn 6 - RESoTTRCE OPTroNs
Class 2 DSM resource potential was assessed by state down to the individual measure and
facility levels; e.g., specific appliances, motors, lighting configurations for residential buildings,
small offices, etc. The DSM potential study provided Class 2 DSM resource information at the
following granularity :
State: Washington, California, Idaho, Utah, Wyoming3
Measure:
83 residential measures
109 commercial measures
99 industrial measures
22 irligation measures
1l street lighting measures
Facility typea:
Six residential facility types
28 commercial facility types
30 industrial facility types
Two irrigation facility type
Four street lighting types
The 2017 DSM potential study levelized total resource costs (including measure costs and a 20
percent adder for program administrative costs) over the study period at PacifiCorp's cost of
capital, consistent with the treatment of supply-side resources. Consistent with regulatory
mandates, Utah Class 2 DSM resource costs were levelized using utility costs (incentive and
non-incentive program costs) instead oftotal resource costs.
The technical potential for all Class 2 DSM resources across five states over the twenty-year
DSM potential study horizon totaled I1.2 million MWh.s The technical potential represents the
total universe of possible savings before adjustments for what is likely to be rcalized
(achievable). When the achievable assumptions described below are considered the technical
potential is reduced to an achievable technical potential for modeling consideration of 9.5 million
MWh. The achievable technical potential, representing available potential at all costs, is
provided to the IRP model for economic screening relative to supply-side alternatives.
Despite the granularity of Class 2 DSM resource information available, it was impractical to
model the Class 2 DSM resource supply curves at this level of detail. The combination of
measures by facility type and state generated over 33,000 separate permutations or distinct
measures that could be modeled using the supply curve methodology. To reduce the resource
options for consideration without losing the overall resource quantity available or its relative
cost, resources were consolidated into bundles, using ranges of levelized costs to reduce the
number of combinations to a more manageable number. The range of measure costs in each of
3 Oregon's Class 2 DSM potential was assessed in a separate study commissioned by the Energy Trust of Oregon.
a Facility type includes such attributes as existing or new construction, single or multi-family, etc. Facility types are
more fully described in Chapter 4 of Volume 2 of the 2015 DSM potential study; pages 4-3 for residential, pages 4-5
for commercial, and pages 4-8 for industrial.
5 The identified technical potential represents the cumulative impact of Class 2 DSM measure installations in the
20ft year of the study period. This may differ from the sum of individual years' incremental impacts due to the
introduction of improved codes and standards over the study period.
136
a
a
a
PacrrrConp - 2017 IRP CHAPTER 6 - RESoURCE OprIoNs
the 27 bundles used in the development of the Class 2 DSM supply curves for the 2017 IRP are
the same as those developed for the 2015 IRP.
Bundle development began with the Class 2 DSM technical potential identified by the 2017
DSM potential study. To account for the practical limits associated with acquiring all available
resources in any given year, the technical potential by measure was adjusted to reflect the
amount that is realistically achievable over the 2}-year planning horizon. Consistent with the
Northwest Power and Conservation Council's aggressive6 regional planning assumptions, it was
assumed that 85 percent of the technical potential for discretionary (retrofit) resources arrd 73
percent of lost-opportunity (new construction or equipment upgrade on failure) could be
achievable over the Z}-year planning period. Over the planning period, the aggregate (both
discretionary and lost opporfimity) achievable technical potential is 79 percent of the technical
potential.
The 2015 DSM potential study applied market ramp rates on top of measure ramp rates to reflect
state-specific considerations affecting acquisition rates, such as age of programs, small and rural
markets, and current delivery infrastructure. This mechanism was used solely in the Wyoming
industrial sector to reflect that program momentum is still building. The current assessment
utilizes the same "Emerging" market ramp rate used in the 2017 assessment for Wyoming's
industrial sector. T
The Energy Trust of Oregon (ETO) applies achievability assumptions and ramp rates in a similar
manner in its resource assessment. For a more detailed description of the methods used in
PacifiCorp's 2017 DSM Potential study and the ETO's resource assessment, see Appendix E in
Volume 4 of the 2015 DSM potential study report. Neither PacifiCorp nor the ETO performed an
economic screening of measures in the development of the Class 2 DSM supply curves used in
the development of the 2017 IRP, allowing resource opportunities to be economically screened
against supply-side altematives in a consistent manner across PacifiCorp's six states.
Twenty-seven cost bundles were available across six states (including Oregon), which equates to
189 Class 2 DSM supply curves. Table 6.13 shows the2}-year MWh potential for Class 2 DSM
cost bundles, designated by ranges of $AvIWh. Table 6.14 shows the associated bundle price after
applying cost credits afforded to Class 2 DSM resources within the model. These cost credits
include the following:
o A transmission and distribution investment deferral credit of $13.56lkW-yearo Stochastic risk reduction credit of $5.03/MWh8o Northwest Power Act lO-percent credit (Oregon and Washington resources only)e
6 The Northwest's achievability assumptions include savings realized through improved codes and standards and
market transformation, and thus, applying them to identified technical potential represents an aggressive view of
what could be achieved through utility DSM programs.
7 The Wyoming industrial market ramp rate is provided in Table E-l of Volume 4 of the 2017 DSM potential study
report.
8 PacifiCorp developed this credit from two sets of production dispatch simulations of a given resource portfolio,
and each set has two runs with and without DSM. One simulation is on deterministic basis and another on stochastic
basis. Differences in production costs between the two sets of simulations determine the dollar per MWh stochastic
risk reduction credit.
r37
PacrrCoRp-2017IRP Cuavren6 - Rpsouncp OruoNs
The bundle price is the average levelized cost for the group of measures in the cost range,
weighted by the potential of the measures. In specifuing the bundle cost breakpoints, narrow cost
ranges were defined for the lower-cost resources to ensure cost accuracy for the bundles
considered more likely to be selected during the resource selection phase of the IRP.
Table 6.13 - Class 2 DSM MWh Potential Cost Bundle
e The formula for calculating the $A{Wh credit is: (Bundle price - ((First year MWh savings x market value x l0%)
+ (First year MWh savings x T&D deferral x l0%)/First year MWh savings. The levelized fonvard electricity price
for the Mid-Columbia market is used as the proxy market value.
<= l0 27,146 91,695 610,445 972,850 118,725 211,694
10-20 8,772 37,868 186,280 869,625 43,968 91,745
20-30 10,126 45,728 688,346 588,821 79,553 131,056
30-40 14,956 38,417 334,064 4l1,008 52,584 342,3t0
40-50 9,775 52,426 229,316 483,287 65,569 193,275
s0-60 4,341 36,941 77,508 530,396 87,588 151,994
60 -70 17,388 15,456 5,469 455,609 61,885 64,025
70-80 9,417 25,123 134,301 220,392 42,658 107,615
80-90 5,1 54 10,915 t00,947 108,222 26,837 49,829
90 - 100 10,254 16,337 326,823 73,579 34,445 23,983
100-110 I1,845 15,402 123,499 73,895 40,142 83,812
110-120 5,672 5,813 84,733 81,351 25,457 20,135
120 - 130 2,185 1,895 3l,830 135,61I 13,624 8,299
130 - 140 1,180 2,936 243 96,048 12,904 7,132
140 - 150 3,650 9,583 8,074 102,483 20,565 19,236
150 - 160 5,327 r 3,075 5,370 171,330 1.751 12,537
160 - 170 2,948 2,079 11,767 79,327 lt,433 31,246
170 - 180 1,553 21,250 t23,068 20,376 27,385 13,435
180 - 190 2,420 4,429 21,219 72,989 24,746 2,655
190 - 200 1,461 t,4t2 8,995 28,040 7,011
200 -250 20,293 20,386 13,612 51,139 28,980 33,316
250 - 300 1,173 4,187 24,169 30,894 11,539 7,536
300 - 400 3,750 6,470 30,240 174,195 16,937 12,491
400 - 500 r,627 3,338 57,170 154,893 13,614 10,608
500 - 750 7,154 9,940 4,520 87,716 16,628 20,803
750 - 1,000 1,954 4,1l8 4,553 36,122 7,967 4,789
> 1,000 2,418 7,107 124,020 55,743 11,637 19,268
138
PacrrrConp - 2017 IRP CHAPTER 6 - Rrsor,rncp OprroNs
<: l0
r0-20 1.04 4.42 4_56 3.70 5.97
20-30 15.07 t3.79 15.89 14.08 10.80 14.82
30-40 25.06 23.38 24.11 22.54 t9.79 26.55
40-s0 3s.33 35.92 34.35 32.63 28.52 34.14
50-60 44.s6 43.51 43.79 43.37 39.65 43.t3
60-70 53.97 53.08 53.99 53.38 48.50 53.14
66.1 5 62.16 66.1670-80 62.65 59.46 63.16
74.24 75.t6 75.4980-90 73.77 70.66 73.55
90 - 100 83.35 84.80 87.00 82.02 79.51 84.48
100-110 93.40 9s.42 95.49 93.16 89.22 92.62
110-120 10s.98 103.19 107.87 106.22 97.34 t02.72
120 - 130 115.81 I15.56 112.39 tt2.t7 108.30 tt4.16
130 - 140 122.24 t21.79 t25.21 12t.67 121.26 t23.0t
140 - 150 131.05 131.36 t31.26 134.06 133.12 130.60
147.08150 - 160 146.61 141.70 140.69 t35.46 144.93
160- r70 157.27 152.80 152.24 152.46 149.59 1s7.21
170- 180 t63.12 160.40 164.32 162.74 160.37 163.00
180 - 190 176.04 175.68 168. l9 175.32 171.99 176.t4
190 - 200 183.28 I 8l .78 183.84 179.57 1 81 .80
200 - 250 209.42 210.12 210.55 210.61 204.00 2r2.39
2s6.32 247.66250 - 300 270.22 258.92 263.51 26t.tt
300 - 400 342.64 334.27 338.9s 321.47 329.59 337.62
400 - 500 430.66 423.50 451.01 441.33 458.62 422.80
500 - 750 660.71 664.18 677.89 s99.s6 662.0s 642.42
877.28750 - 1,000 880.s0 947.88 868.86 840.77 848.36
> 1,000 31,152.34 22,647.63 1,315.61 43,789.06 43,421.09 24,325.48
Table 6.14 - Class 2 DSM usted Prices Cost Bundle
To capture the time-varying impacts of Class 2 DSM resources, each bundle has an annual 8,760
hourly load shape speciffing the portion of the maximum capacity available in any hour of the
year. These shapes are created by spreading measure-level annual energy savings over 8,760
load shapes, differentiated by state, sector, market segment, and end use accounting for the
hourly variance of Class 2 DSM impacts by measure. These hourly impacts are then aggregated
for all measures in a given bundle to create a single weighted average load shape for that bundle.
Distribution Efficiency
The Company continues to evaluate distribution energy efficiency. The Company's recent efforts
in distribution efficiency are expected to show tangible results in three areas. The first is
streetlight efficiency. In 2017, the Company is endeavoring to replace approximately I,420
company owned streetlights system-wide, equal to ten percent of existing inventory. Older
mercury vapor, metal halide and incandescent streetlights will be replaced with more efficient
lights (high pressure sodium or LED).
t39
PacmrConp-20l7IRP CHaprEn 6 - Rssouncs OprroNs
The second area is software focused. The Company recently transitioned its power flow
application from ABB FeederAll@ to CYME CYMDIST@. The new CYME power flow
application allows the evaluation of many complex real world scenarios, and will help ensure
that future planning efforts and project definitions are as accurate as possible. As application
proficiency and model accuracy evolve, CYME will further enhance the Company's ability to
develop renewable resources and private generation.
The third area touches the key areas of efficiency, capital deferral and customer service. The
Company evaluated a VAR (Volt Ampere Reactive) optimization project as a possible solution
to respond efficiently to a proposed system change while maintaining reliability and safe
operation of the system. ln 2016, efforts in the Yakima, Washington area addressed conductor
thermal capacity and low voltage risks associated with a customer load addition. The strategy
implemented a complex voltage and reactive power control scheme utilizing voltage regulators,
fixed capacitor banks and switched capacitor banks. Additional monitoring will be performed to
ensure proper off-peak operation and to identifr any power quality issues or increased
maintenance costs.
The distribution energy efficiency efforts described above have not been modeled as potential
resources in this IRP, as the savings associated with these measures is difficult to determine and
expected to be very small.
For the 2017 IRP, the Company selects generation resource portfolios with a pre-determined
transmission topology based on transmission rights that are owned by the Company and
contracted with third parties. Potential transmission resource additions are examined prior to
generation resource selection. Sensitivities are also developed to test various transmission build-
out scenarios. Additionally, in order to determine the appropriate placement and timing of
generation resources, generic assumptions on transmission integration costs are included in the
costs of potential resources. These costs are associated with improvements needed to transfer the
generation to load centers and/or markets and maintain the reliability and stability of the
transmission system.
Costs of transmission integration vary discretely based on size of the resources added. Table
6.15 provides an illustrative example how the transmission integration costs at a location may be
structured based on the size of the resource additions.
Table 6.15 -of Transmission Costs Size of ource Additions
For any initial resource additions up to 500 MW there would not be incremental transmission
costs as there is capacity currently available. However, if a resource added is in any size between
500 MW and 1,500 MW, the transmission integration costs would be $350 million. If a second
Up to 500 MW $0 million
500 MW to 1,500 MW $350 million
1,500 MW to 2,500 MW $700 million
2,500 MW to 3,000 MW $1,000 million
t40
PecmrCoRp-2017IRP CHAPTER 6 - RESoURCp OprroNs
resource added subsequently at the same location and total capacity between the two resources
does not exceed 1,500 MW, there would not be transmission integration costs for this second
resource.
In addition, if a comparable resource is selected immediately after a unit retires, there may not
need to be costs to reinforce the existing transmission resource in the area; otherwise, additional
costs would be incurred to maintain reliability of the transmission system. To accurately reflect
the impact of transmission costs of the resource portfolios, the generic assumptions are later
revised based on specific size, timing, location, md sequence of resources added in each
portfolio.
PacifiCorp and other utilities engage in purchases and sales of electricity on an ongoing basis to
balance the system and maximize the economic effrciency of power system operations. In
addition to reflecting spot market purchase activity and existing long-term purchase contracts in
the IRP portfolio analysis, PacifiCorp modeled front office transactions (FOT). FOTs are proxy
resources, assumed to be firm, that represent procurement activity made on an on-going forward
basis to help the Company cover short positions.
As proxy resources, FOTs represent a range of purchase transaction types. They are usually
standard products, such as heavy load hour (HLH), light load hour (LLH), and super peak (hours
ending 13 through 20) and typically rely on standard enabling agreements as a contracting
vehicle. FOT prices are determined at the time of the transaction, usually via an exchange or
third party broker, and are based on the then-current forward market price for power. An optimal
mix of these purchases would include a range of volumes and terms for these transactions.
Solicitations for FOTs can be made years, quarters or months in advance, however, most
transactions made to balance PacifiCorp's system are made on a balance of month, day-ahead,
hour-ahead, or intra-hour basis. Annual transactions can be available three or more years in
advance. Seasonal transactions are typically delivered during quarters and can be available from
one to three years or more in advance. The terms, points of delivery, and products will all vary
by individual market point.
Three FOT types were included for portfolio analysis in the 2017 IRP: an annual flat product, a
HLH July for summer, and a HLH December for 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 6.16 shows the FOT resources included in the IRP models, identifuing the
market hub, product type, annual megawatt capacity limit, and availability. 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 (see Volume II, Appendix J for an assessment of western resource
adequacy). 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. Additional discussion of how FOTs are modeled during the resource portfolio
development process of the IRP is included in Chapter 7 (Modeling and Portfolio Evaluation
Approach).
t4t
PACIFICORP_2017 tRP Csarrrn 6 - REsor,JRcE OmoNs
Table 6.16 - Maximum Available Front Oflice Transaction Market Hub
tufid4olumbia (hfidC)
FlatAlrrrlral ('7x24'\or
Heavy l,oad Hor:r ('6X16')
Heal,y Load How ('6X16')375
400
375
400
California Oregon Border (COB)
Flat Ann al ('7124') or
Heary toad Hour ('6X16')
400 400
Nevada Oregon Border QYOB)
Heavy load Hour ('6X16')100 100
lllona
Heaw [,oad Hour ('6X16')300 300
142
PacmrConp-2017IRP CHAPTER 7 _ MoDELING AND PORTFOLIO EVALUATION AppROeCTT
CgaprER 7 _ MOOELING AND POnTTOLIO
EvaTUATION AppnoACH
a
a
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a
Cn^rprrn Hrcrrr,rcrrr s
The Integrated Resource Plan (IRP) modeling approach is used to assess the comparative
cost, risk, and reliability attributes of resource portfolios. The 2017 IRP modeling and
evaluation approach consists ofthree screening stages used to select a preferred portfolio,
including Regional Haze screening, eligible portfolio screening, and final screening.
PacifiCorp uses System Optimizer (SO) to produce unique resource portfolios across a
range of different planning assumptions. Informed by the public input process, PacifiCorp
ultimately produced and evaluated 43 different SO portfolios for its 2017 IRP.
PacifiCorp uses Planning and Risk (PaR) to perform stochastic risk analysis of the
portfolios produced by SO. For each SO portfolio, PaR studies are developed for three
natural gas price scenarios (low, base, and high) and two carbon dioxide (CO, emissions
limit assumptions, which together form six price-emissions scenarios.l The resulting cost
and risk metrics are then used to compare portfolio alternatives and inform selection of the
preferred portfolio.
Taking into consideration stakeholder comments received during the public input process,
PacilrCorp also developed24 sensitivity cases designed to highlight the impact of specific
planning assumptions on future resource selections along with the associated impact on
system costs and stochastic risks. Six of the sensitivities developed over the course of the
2017 IRP were considered for the preferred portfolio.
Informed by comprehensive modeling, PacifiCorp's preferred portfolio selection process
involves evaluating cost and risk metrics reported from PaR, comparing resource portfolios
on the basis of expected costs, low-probability high-cost outcomes, reliability, COz
emissions and other criteria.
a
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.
The first section of this chapter describes the screening and evaluation processes for portfolio
selection. Following sections summarize portfolio risk analyses, document key modeling
assumptions, and describe how this information is used to select the preferred portfolio. The last
section of this chapter describes the cases examined at each screening stage, including Regional
Haze cases, core cases, and sensitivity cases. The results of PacifiCorp's modeling and portfolio
analysis are summarizedin Chapter 8.
I In select instances only, the base price assumptions are modeled to evaluate a sensitivity case; these exceptions are
described in Volume I, Chapter 8: Modeling and Portfolio Selection Results.
143
PACIFICORP-20I7IRP CHapTsn 7 -MODELDTG AND PORTFOLIO EVALUATION APPROACH
Figure 7.1 summarizes the portfolio evaluation steps used in the 2017 IRP, with three screening
stages highlighted in green. The three stages are (l) Regional Haze screening, (2) eligible portfolio
screening, and (3) the final portfolio screening. The result of the final screening stage is the
preferred portfolio.
Figure 7.1 - Portfolio Evaluation Steps within the IRP Process
lr.cr l)lurrrting
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IJlil;rner'
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t44
PACIFICoRP - 2017 IRP CHAPTER 7 - MoDELTNG AND PoRTFoLIo EVALUATIoN APPRoACH
For each screening stage, PacifiCorp developed unique resource portfolios, analyzed cost and
stochastic risk metrics for each portfolio, and selected, based on comparative cost and risk metrics,
the specific portfolios considered in the next screening stage. The outcomes of each can inform
the need for additional studies to test or refine assumptions in a subsequent screening analysis. The
basic portfolio evaluation steps within each screening stage are highlighted in red in Figure 7.1
above and include:
Resource Portfolio Development
All IRP models are configured and loaded with the best available information at the time a
commitment must be made for the model run. This information is fed into SO, which is used
to produce resource portfolios with sufficient capacity to achieve a target planning reserve
margin. Each resource portfolio is uniquely characterized by the type, timing, and location of
new resources in PacifiCorp's system over time.
a
a Cost and Risk Analysis
Resource portfolios developed with SO are simulated in PaR to produce metrics that support
comparative cost and risk analysis among the different resource portfolio alternatives.
Stochastic risk modeling of resource portfolio alternatives is performed using Monte Carlo
sampling of stochastic variables across the 2O-year study horizon, which include load, natural
gas and wholesale electricity prices, hydro generation, and unplanned thermal outages.
o Portfolio Selection
The portfolio selection process in each screening stage is based upon modeling results from
the resource portfolio development and cost and risk analysis steps. The screening criteria are
based on the present value revenue requirement (PVRR) of system costs, assessed across six
price-emissions scenarios on an expected-value basis and on an upper-tail stochastic risk basis.
Portfolios are ranked using a risk-adjusted PVRR metric, a metric that combines the expected
value PVRR with upper-tail stochastic risk PVRR. The final selection process considers cost-
risk rankings, robustness of perforrnance across pricing scenarios and other supplemental
modeling results, including reliability and COz emissions data.
Resource expansion plan modeling, performed with SO, is used to produce resource portfolios
with sufficient capacity to achieve atargetplanning reserve margin over the 2}-year study horizon.
Each resource portfolio is uniquely characterizedby the type, timing, and location of new resources
in PacifiCorp's system over time. These resource portfolios reflect a combination of planning
assumptions such as environmental and tax policies, wholesale power and natural gas prices, load
growth net of assumed private generation penetration levels, and new resource cost and
performance data. Changes to these input variables cause changes to the resource mix.
System Optimizer (SO)
The SO model operates by minimizing operating costs for existing and prospective new resources,
subject to system load balance, reliability and other constraints. Over the2D-year planning horizon,
it optimizes resource additions subject to resource costs and capacity constraints (summer peak
145
PACIFICoRP-2017IRP CHAPTER 7 - MoDELING AND PoRTFoLIo EVALUATIoN APPRoACH
Ioads, 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, SO will select additional resources as required to meet summer and
winter peak loads inclusive of the target planning reserve margin.
To accomplish these optimization objectives, SO performs a time-of-day least-cost dispatch for
existing and potential ptanned generation, while considering cost and performance of existing
contracts and new demand side management (DSM) altematives within PacifiCorp's transmission
system. Resource dispatch is based on a representative-week method. Time-of-day hourly blocks
are simulated according to a user-specified day-type pattern representing an entire week. Each
month is represented by one week, and the model scales output results to the number of days in
the month and then the number of months in the year. Dispatch also determines optimal electricity
flows between zones and includes spot market transactions for system balancing. The model
minimizes the system PVRR, which includes the net present value cost of existing contracts, spot
market purchase costs, spot market sale revenues, generation costs (fueI, fixed and variable
operation and maintenance, decommissioning, emissions, unserved energy, and unmet capacity),
costs of DSM resources, and amortized capital costs for existing coal resources and potential new
resources.
Transmission System
PacifiCorp uses a transmission topology that captures major load centers, generation resources,
and market hubs interconnected via firm transmission paths. Transfer capabilities across
transmission paths are based upon the firm transmission rights of PacifiCorp's merchant function,
including transmission rights from PacifiCorp's transmission function and other regional
transmission providers. Figure 7.2 shows the20l7 IRP transmission system model topology.
Transmission Costs
In developing resource portfolios for the 2017 IRP, PacifiCorp includes estimated transmission
integration and transmission reinforcement costs specific to each resource portfolio. These costs
are influenced by the type, timing, and location of new resources as well as any assumed resource
retirements, as applicable, in any given portfolio.
t46
PACIFICORP-20I7IRP CHAPTER 7 -MODELTNG AND PoRTFoLIo EVALUATION APPROACH
Figure 7.2 -Transmission System Model Topology
W.rhlnCton
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Aalron.
Resource Adequacy
Resource adequacy is modeled in the portfolio development process by ensuring each portfolio
meets a target planning reserve margin. In its 2017 IRP, PacifiCorp continues to apply a l3 percent
target plaming reserve margin. The plarrning reserve margin, which influences the need for new
resources, is applied to PacifiCorp's coincident system peak load forecast net of offsetting "load
resources" such as energy efficiency capacity. Planning to achieve a l3 percent planning reserve
margin ensures that PacifiCorp has sufficient resources to meet peak loads, recognizing that there
is a possibility for load fluctuation and extreme weather conditions, fluctuation of variable
generation resources, a possibility for unplanned resource outages, and reliability requirements to
carry sufficient contingency and regulating reserves. Volume II, Appendix I of this report
summarizes PacifiCorp's updated planning reserve margin study that supports selection of a l3
percent target plaruring reserve margin in the 2017 IRP.
New Resource Options
Dispatchable Resources
SO performs time-of-day least cost dispatch of existing and potential new thermal resources to
meet load while minimizing costs. Dispatch costs applicable to thermal resources include fuel
costs, non-fuel variable operations & maintenance (VOM) costs, and the cost of emissions, as
applicable. For existing and potential new dispatchable thermal resources, System Optimizer uses
2017 rRP
Thansmleelon IRP Topolory
0Ir
lConm3E
147
PACIFICORP - 20I7 IRP CHAPTER 7 - MODELING AND PORTFOLIO EVALUATION APPROACH
generator specific inputs for fuel costs, VOM, heat rates, emission rates, and any applicable price
for emissions to establish the dispatch cost of each generating unit for each dispatch interval.
Thermal resources are dispatched by least cost merit order. The power produced by these resources
can be used to meet load or to make off-system sales at times when resource dispatch costs fall
below market prices. Conversely, at times when dispatch costs exceed market prices, off-system
purchases can displace dispatchable thermal generation to minimize system energy costs. Dispatch
of thermal resources reflects any applicable transmission constraints connecting generating
resources with both load and market bubbles as defined in the transmission topology for the model.
Front Office Transactions
Front office transactions (FOTs) represent short-term firm market purchases for physical delivery
of power. PacifiCorp is active in the western wholesale power markets and routinely makes short-
term firm market purchases for physical deliveries on a forward basis (i.e., prompt month forward,
balance of month, day-ahead, and hour-ahead). These transactions are used to balance PacifiCorp's
system as market and system conditions become more certain when the time between an effective
transaction date and real time delivery is reduced. Balance of month and day-ahead physical firm
market purchases are most routinely acquired through a broker or an exchange, such as the
Intercontinental Exchange (ICE). Hour-ahead transactions can also be made through an exchange.
For these types of transactions, the broker or the exchange provides the service of providing a
competitive price. Non-brokered transactions can also be used to make firm market purchases
among a wide range of forward delivery periods.
From a modeling perspective, it is not feasible to incorporate all of the short-term firm physical
power products, which differ by delivery pattem and delivery period, that are available through
brokers, exchanges, and non-brokered transactions. However, considering that PacifiCorp
routinely uses these types of firm transactions, which obligate the seller to back the transaction
with reserves when balancing its system, it is important that the capacity contribution of short-
term firm market purchases are accounted for in the resource portfolio development process. For
capacity optimization modeling, short-term firm forward transactions are represented as FOTs and
configured in SO with either an annual flat, summer-on-peak (July), or winter on-peak (December)
delivery pattern in every year of the twenty-year planning horizon. As configured in SO, FOTs
contribute capacity toward meeting the20lT IRP's 13 percent targetplanning reserve margin and
supply system energy consistent with the assumed FOT delivery pattern.
Unlike FOTs, system balancing transactions do not contribute capacity toward meeting the 13
percent target planning reserve margin. System balancing transactions include hourly off-system
sales and hourly off-system purchases, representing market activities that minimize system energy
costs as part of the economic dispatch of system resources, including energy from any FOTs
included in a resource portfolio.
A description of FOT limits assumed in the 2017 IRP is included in Chapter 6, Resource Options.
PacifiCorp's evaluation of resource adequacy in the western power markets is summarized in
Volume II, Appendix J.
Demand Side Management
SO can select incremental DSM resources during the portfolio optimization development step of
each screening stage. Selection of DSM resources is made from supply curves that define how
much of a DSM resource can be acquired at a given cost point.
148
PACIFICoRP - 2017 IRP CHAPTER 7 -MoDELI\G AND PoRTFoLIo EVALUATION APPRoACH
Class 2 DSM resources, representing energy savings from energy efficiency programs, are
characterized with supply curves that represent achievable technical potential of the resource by
state, by year, and by measure specific to PacifiCorp's service territory. For modeling purposes,
these data are aggregated into cost bundles. Each cost bundle of the Class 2 DSM supply curve
specifies the aggregate energy savings profile of all measures included in the cost bundle, with a
surrmer and winter capacity contribution based on aggregate energy savings during on-peak hours
in July and December aligning with PacifiCorp's coincident system peak load.
Class 1 DSM resources, representing direct load control capacity resources, are also characterized
with supply curves representing achievable technical potential by state and by year for specific
direct load control program categories (i.e., air conditioning, irrigation, and commercial
curtailment). SO evaluates Class I DSM resources by considering capacity contribution, cost, and
operating characteristics. Operating characteristics include variables such as total number of hours
and number of hours per event that the Class 1 DSM resource is available in a given year.
Additional discussion of DSM resources modeled in the 2017 IRP is included in Chapter 6 and in
Volume II, Appendix D.
Wind and Solar Resources
Wind and solar resources are modeled as non-dispatchable, must-run resources using fixed energy
profiles varying by month and time of day. The total energy generation for wind and solar
resources represents the expected generation levels in which half of the time actual generation
would fall below expected levels, and half of the time actual generation would be above expected
levels.
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 over time. The
capacity contribution of new and existing wind resources in PacifiCorp's east and west balancing
authority areas (BAAs) is set to 15.8 percent and 11.8 percent, respectively. The capacity
contribution of new and existing fixed tilt solar photovoltaic resources in PacifiCorp's east and
west BAAs is set to 37.9 percent and 53.9 percent, respectively. New single axis tracking solar
photovoltaic capacity contribution values in PacifiCorp's east and west BAAs are set to 59.7
percent and 64.8 percent, respectively. Volume II, Appendix N of this report summarizes
PacifiCorp's updated wind and solar capacity contribution study used to derive these values.
Energy Storage Resources
Energy storage resources are distinguished from other resources by the following three attributes:
o Energy take - generation or extraction ofenergy from a storage reservoir;
. Energy return - energy used to fill (or charge) a storage reservoir; ando Storage cycle efficiency - an indicator of the energy loss involved in storing and extracting
energy over the course ofthe take-return cycle.
Modeling energy storage resources requires specification of the size of the storage reservoir,
defined in gigawatt-hours. SO dispatches a storage resource to optimize energy used by the
resource subject to constraints such as storage cycle efficiency, the daily balance oftake and return
energy, and fuel costs (for example, the cost of natural gas for expanding air with gas turbine
expanders). To determine the least-cost resource expansion plan, SO accounts for conventional
generation system performance and cost characteristics of the storage resource, including capital
t49
PACIFICORP _ 20 I7 IRP CHapTsn 7 -MODELTNG AND PoRTFoLIo EVALUATIoN APPRoACH
cost, size of the storage and time to fill the storage, heat rate (if fuel is used), operating and
maintenance cost, minimum capacity, and maximum capacity.
Capital Costs and End-Effects
SO uses annual capital recovery factors to convert capital dollars into real levelized revenue
requirement costs to address end-effects that arise with capital-intensive projects that have
different lives and in-service dates. All capital costs evaluated in the IRP are converted to real
levelized revenue requirement costs. Use of real levelized revenue requirement costs is an
established and preferred methodology for analyzing capital-intensive resource decisions ilmong
resource alternatives that have unequal lives and/or when it is not feasible to capture operating
costs and benefits over the entire life of any given resource. To achieve this, the real levelized
revenue requirement method spreads the return of investment (book depreciation), return on
investment (equity and debt), property taxes and income taxes over the life of the investnent. The
result is an annuity or annual payment that grows at inflation such that the PVRR is identical to
the PVRR of the nominal annual requirement when using the same nominal discount rate. For the
2017 IRP, the PVRR is calculated inclusive of real levelized capital revenue requirement through
the end of the 2036 planrring period.
General Assumptions
Study Period and Date Conventions
PacifiCorp executes its 2017 IRP models for a 2}-year period beginning January 1,2017 and
ending December 3I,2036. Future IRP resources reflected in model simulations are given an in-
service date of January I't of a given year, with the exception of coal unit natural gas conversions,
which are given an in-service date of June lst of a given year, recognizingthe desired need for
these altematives to be available during the summer peak load period.
Inflation Rates
The 2017 IRP model simulations and cost data reflect PacifiCorp's corporate inflation rate
schedule unless otherwise noted. A single annual escalation rate value of 2.22 percent is assumed.
The annual escalation rate reflects the average of annual inflation rate projections for the period
2017 through 2036, using PacifiCorp's September 2016 inflation curve. PacihCorp's inflation
curve is a straight average of forecasts for the Gross Domestic Product (GDP) inflator and the
Consumer Price Index (CPD.
Dissount 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 is 6.57 percent The use of the
after-tax WACC complies with the Public Utility Commission of Oregon's IRP guideline la,
which requires that the after-tax WACC be used to discount all future resource costs.2 PVRR
figures reported in the 2017 IRP are reported in January 1,2017 dollars.
2 Public Utility Commission of Oregon, Order No. 07-002, Docket No. UM 1056, January 8,2007
150
PACIFICoRP-2017IRP CHAPTER 7 -MODEL[.{G AND PORTFOLIO EVALUATION APPROACH
Environmental Policy and Price Scenarios
Six price-emissions scenarios are defured for the 2017 IRP, representing combinations of two
emissions policy scenarios multiplied by three natural gas price scenarios (low, base, and high).
Emissions Policy Scenarios
The two COz emissions policy scenarios are defined by two differing interpretations of the
Environmental Protection Agency's (EPA) Clean Power Plan (CPP).. CPP(a) (or Mass Cap A): Mass-based compliance approach with pro-rata allowance
allocation to PacifiCorp based on historical generation with no set-asides and no new
source complement.. CPP(b) (or Mass Cap B): Mass-based compliance approach with pro-rata allowance
allocation to PacifiCorp based on historical generation with new source complement
allowances allocated on a pro-rata basis, /ess the Clean Energy Incentive Program (CEIP),
renewable and output-based set-asides. It is assumed that PacifiCorp does not receive any
ofthese set-asides.
Figure 7.3 shows the assumed COz mass cap scenarios applicable to emissions for affected units
on PacifiCorp's system. Consistent with the underlying assumptions used to develop these two
scenarios, new combined cycle combustion turbine (CCCT) natural gas plants fall under the Mass
Cap B scenario, but are not subject to emission limits under the Mass Cap A scenario.
Figure 7.3 - PacifiCorp System Mass Cap A & Mass Cap B Assumptions
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35
30
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20 t-- oo o.\ O C.l .o + ra \O F- oo O\ O N co $ r., \Or * (\ aI o.l N N N C.l C\l N N ci ci ci co ca ca ..)ooooooooooooooooooooc.] (\ c.l (\ N N o.l N c't c.l N c'l N N N N N c.l N N
.l-Mass Cap A +Mass Cap B
Price Scenario Development
Natural gas price forecasts are based upon a review of third-pany expert projections. The expert
forecasts are a key input to Aurora, the production cost dispatch model used by PacifiCorp to
generate a long-term wholesale power price forecast for each natural gas price scenario. Aurora is
also configured with CPP assumptions that align with scenarios developed for the 2017 IRP
(CPP(a) and CPP(b)). The end result yields a unique and consistent set of natural gas price and
wholesale power price scenarios for alternative CPP and natural gas price assumptions.
151
PACIFICoRP - 20 I7 IRP CHAPTER 7 _MoDELh{G AND PoRTFoLIo EVALUATIoN APPRoACH
Table 7.1 - Price-Emissions Scenarios
7.1Noteso OFPC - Offrcial Forward Price Curver Califomia is modeled using a CO2 tax {rs a ptoxy for its cap-and-trade program established pursuant to the Califomia Global Warming
Solutions Act of 2006. As such, it is not modeled as being subject to the CPP limits.
Wholesale Electricity and Natural Gas Forward Prices
For 2017 IRP modeling purposes, seven electricity price forecasts were generated: the official
forward price curve (OFPC) and six scenarios. Unlike scenarios, which are alternative spot price
forecasts, the OFPC represents the Company's official price outlook. It is compiled using market
forwards, followed by a market-to-fundamentals blending period that transitions to a pure
fundamentals-based forecast. Figure 7.4 depicts the process used by PacifiCorp to develop its price
curye scenarios.
Figure 7.4 - Price Scenario Modeling
At the time PacifiCorp's 2017 IRP modeling was initiated, the most crrrent OFPC was produced
in October 2016. For both gas and electricity, the front 72 months of the OFPC reflects market
forwards at the close of the markets on a given trading day. For the October 2016 OFPC, prices
over the front 72-months are based on market forwards as of October 12,2016. The blending
period (months 73 through 84) is calculated by averaging the month-on-month market forward
from the prior year with the month-on-month fundamentals-based price from the subsequent year.
The fundamentals portion of the natural gas OFPC reflects an expert third-party price forecast. The
fundamentals portion of the electricity OFPC reflects prices as forecast by AURORA>n'ar (Aurora),
I rpcrt tlrirri-grrrItr
\itlLtnrl ( ilr' I'r'ir'r
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l2-rmnths blend; followed by base
eas)
Oct. 2016 OFPC (72-months market;
l2-months blend; followed by
fu ndarnentals oer AuroraO)
C?P(b) tow U.S. WECCI Mass Czp B total
allocation cap
New source conplement included;
generic combine cycles subject to
consfmint
Low gas Fundamental price forecast per
Aurora@
CPP(b) High U.S. WECC+ Mass Cap Btotal
allocation cap
New source conplerrent included;
generic combine cycles subject to
constmint
High gas Fundamntal price forecast per
Aurora@
CPP(a) Base U.S. WECCi Mass Cap A total
allocation cap
No new source conplerrnt
included; generic combine cycles
not subiect to constraint
Base gas Fundamental price forecast per
AuromO
CPP(a) I,ow U.S. WECC* Mass Cap A total
allocation cap
No new source complement
included; generic combine cycles
not s[biect to consfDint
low gas Fundarnental price forecast per
Aurora@
CPP(a) High U.S. WECC* Mass Cap A total
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not subiect to constmint
High gas Fundanrntal price forecast per
Aurora@
t52
PecrprCoRp - 2017 IRP CTnpIgR 7 -MoDELI.Ic ANo PoRTFoLIo EVALUATION APPROACH
a WECC-wide market model.3 Aurora uses the expert third-parry natural gas price forecast to
produce a consistent electricity price forecast for market hubs in which PacifiCorp participates.
PacifiCorp reviews third party natural gas price forecasts each quarter for the OFPC, and as a
corollary, the electricity OFPC is also updated. Scenarios, unlike the OFPC, do not incorporate
market forwards since scenarios are designed to reflect an altemative view to that of the market.
As such, both electricity and natural gas price scenarios are fundamentals-based forecasts.
PacifiCorp's OFPC for electricity and each of its six scenarios were developed from one of three
(low, base, high) underlying expert third-party natural gas price forecasts in conjunction with one
of three COz compliance designs tied to the CPP. PacifiCorp's base COz compliance design, Mass
Cap B, assumes a WECC-wide (excluding California) yearly COz tonnage cap using EPA's
allocation of state-specified allowances, with new source complement.a As such, Mass Cap B
applies to both targeted existing and new-build resources. Mass Cap B assumes states receive their
fuIl allocation of allowances, based on historical generation, as promulgated in the CPP emission
guidelines. When only modeling PacifiCorp's system, such as in the 2017 IRP, set-asides for the
Clean Energy Incentive Program, output-based set-asides, and renewable set-asides were
subtracted from the overall cap as part of Mass Cap B. However, when developing WECC-wide
price forecasts, PacifiCorp did not subtract set-asides, assuming they would be allocated
somewhere in the region. California was not modeled as part of the CPP since it was already
modeled to meet clean air targets established under the (more stringent) California Global
Warming Solutions Act (Assembly Bill 32). The October 12,2016 OFPC was developed using
Mass Cap B assumptions in conjunction with base natural gas prices. Two alternative electricity
price scenarios, assuming low and high natural gas prices, were also produced under Mass Cap B
assumptions.
Another three electricity price scenarios were generated by Aurora with Mass Cap A
third-party natural gas price forecasts were modeled in Aurora using Mass Cap A compliance
targets. Mass Cap A differs from Mass Cap B only in that it does not include the new source
complement. Finally aCOzprice scenario was produced that combined the underlying base natural
gas price forecast with a plausible COz price assumption as an alternative to the CPP. Thus, in
total, seven (including the OFPC) wholesale electricity price forecasts were produced using three
natural gas price forecasts in conjunction with different COz compliance paradigms.
Figure 7.5 summarizes the seven wholesale electricity price forecasts and three natural gas price
forecasts used in core and sensitivity cases for the 2017 IRP. By the end of the 2}-year planning
horizon, wholesale power prices range from just below $48A4Wh to over $93A4Wh and Henry
Hub natural gas prices range from $4.75lMMBtu to over $1O.O0AvIMBtu.
3 AURORAxrr,p is a production cost simulation model, developed by EPIS, LLC.
a Plausible allocation designs are based on EPA's Clean Power Plan, as frnalized August 3, 2016 and authorized by
$l I l(d) of the Clean Air Act.
1s3
Wholesrle Electricity Prices
Average of Palo Verde and Mid-C (Flet)
2
$100
$80
$60
$40
$20
$-r@60-N-th€r€6
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Henry Hub
a
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PecnrConp-2017IRP CHAPTER 7 _ MongTn.IG AND PoRTFoLIo EVALUATIoN APPRoACH
Figure 7.5 - Nominal Wholesale Electricity and Nafural Gas Price Scenarios
Figure 7.6 through Figure 7.8 illustrate the CPP constraints in relation to regional emissions from
the price curve development process discussed above. The CPP does not constrain emissions
except in the high as price scenarios, indicating that under base natural gas and low natural gas
futures, regional emission targets will be lower than those required by the CPP.
Figure 7.6 - U.S.WECC COz Emissions, Base Natural Gas Prices
cPP(b)
N90€ON{960d+Q60-NNNdN66toooooooooooooooNddNNNdNNdNN
IHistoric IPre-CPP Fors6t rCPP Forec6t
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Limit
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200
150
100
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r54
PACIFICoRP - 20I7 IRP CHAPTER 7 -MoDELING AND PORTFOLIO EVALUATION APPROACH
Figure 7.7 - U.S.WECC COz Emissions, Low Natural Gas Prices
CPP(a)
N<€60NSO6QNSO€O dNNmotoooooooooooooooNNNNNNNNNNNNNNN
r Historic r Pree-CPP Forecast r CPP Forecast
-CPP(a)
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Figure 7.8 - U.S. WECC COz Emissions, High Natural Gas Prices
cPP(b)CPP(a)
0 NCO60N9Q60NSO60oooooooooooooooNANNNNNNNNNNNNN
N+€60Ni060N+@€o NdN66{oooooooooooooooNNNNNNNNNNNNNNN
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Limrt
PacifiCom System CPP Shadow Prices
During the RegionalHaze portfolio screening stage, the selected Regional Haze portfolio is run
through each of the six price-emissions scenarios, producing six sets of outcomes for analysis. The
results of these studies established COz shadow prices representing the marginal cost, measured in
dollars per ton, to achieve the CPP (Mass Cap A and Mass Cap B) emission caps applied to
PacifiCorp's system for each price wholesale market price scenario (low, base and high). Thus,
COz shadow prices were developed for each of the six price-emissions scenarios. These shadow
price results were used in stochastic model optimizations (see Cost and Risk section below) as a
cost-driver designed to avoid exceeding relevant emission caps when analyzing each portfolio in
PaR.
Particulate Matter Emissions
The Washington Utilities and Transportation Commission (WUTC) requested that investor-owned
utilities in Washinglon start incorporating the non-energy benefits of fine particular matter (PMz.s)
emissions in conservation and energy planning calculations going forward, including
incorporating these benefits into the IRP. In further discussion with WUTC staff to clarify this
300
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50
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100
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PACIFICoRP-2OI7IRP CuepTpR 7 _ MoDELNG AI.ID PoRTFoLIo EVALUATIoN APPRoACH
request, it became clear that staffwas requesting a broad health impacts analysis (and potentially
other societal impacts) of PacifiCorp's generating resources. Following further clarification and
conversation with WUTC staff, both staff and PacifiCorp agreed that it would not be feasible to
conduct such an analysis for this IRP (either focused on PMz.s or other emissions), but that this
issue may be raised in future IRPs. Generally, PacifiCorp considers health assessments and other
societal extemalities to be outside the scope of the IRP, which focuses on the economic costs of
various resource decisions including direct costs to serve our customers.
Planning and Risk (PaR)
PaR uses the same corrmon input assumptions described for SO with additional data provided by
the SO outcomes (e.g., COz shadow prices and the selected resource portfolio). While SO supplies
a capacity view basis for determination of optimized portfolios for each case, PaR is able to bring
the advantages of stochastic-driven risk metrics to the evaluation of the studies. While PaR cost-
risk metrics are ultimately used in the preferred portfolio selection, SO results remain valuable and
informative, especially in their role as a magnitude and direction indicator to compare to PaR
outcomes.
Cost and Risk Analysis
Once unique resoruce portfolios are developed using SO, additional modeling is performed to
produce metrics that support comparative cost and risk analysis among the different resource
portfolio alternatives. Stochastic risk modeling of resource portfolio alternatives is performed with
PaR.
The stochastic simulation in PaR produces a dispatch solution that accounts for chronological
commitment and dispatch constraints. The PaR simulation incorporates stochastic risk in its
production cost estimates by using the Monte Carlo sampling of stochastic variables, which
include: load, wholesale electricity and natural gas prices, hydro generation, and thermal unit
outages.s Wind and solar generation is not modeled with stochastic parameters; however, the
incremental reserve requirements associated with uncertainty and variability in wind generation,
as determined in the updated flexible reserve study, are captured in the stochastic simulations.
PacifiCorp's updated flexible reserye study is provided in Volume II, Appendix F (Flexible
Reserve Study).
The stochastic parameters used in PaR for the 2017 IRP are developed with a short-run mean
reverting process, whereby mean reversion represents arate at which a disturbed variable retums
to its expected value. Stochastic variables may have log-normal or normal distribution as
appropriate. The log-normal distribution is often used to describe prices because such distribution
is bounded on the low end by zero and has a long, asymmetric "tail" reflecting the possibility that
prices could be significantly higher than the average. Unlike prices, load generally does not have
such skewed distribution and is generally better described by a normal distribution. Volatility and
5 FOTs included in resource portfolios developed using System Optimizer are subject to the Monte Carlo random
sampling of wholesale electricity prices in PaR.
1s6
PacmrConp-2017IRP CHAPTER 7 _MODELING AND PORTFOLIO EVALUATION APPROACH
mean reversion parameters are used for modeling the volatilities of the variables, while accounting
for seasonal effects. Correlation measures how much the random variables tend to move together.
Stochastic Model Parameter Estimation
Stochastic parameters are developed with econometric modeling techniques. The short-run
seasonal stochastic parameters are developed using a single period auto-regressive regression
equation (commonly called an AR(l) process). The standard error of the seasonal regression
defines the short run volatility, while the regression coefficient for the AR(l) variable defines the
mean reversion parameter. Loads and commodity prices are mean-reverting in the short term. For
instance, natural gas prices are expected to hover around a moving average within a given month
and loads are expected to hover near seasonal norms. These built-in responses are the essence of
mean reversion. The mean reversion rate tells how fast a forecast will revert to its expected mean
following a shock. The short-run regression errors are correlated seasonally to capture inter-
variable effects from informational exchanges between markets, inter-regional impacts from
shocks to electricity demand and deviations from expected hydroelectric generation performance.
The stochastic parameters are used to drive the stochastic processes of the following variables:
o Representative natural gas prices for PacifiCorp's east and west BAAs;o Electricity market prices for Mid-C, COB, Four Corners, and Palo Verde;o Loads for California, Idaho, Oregon, Utah, Washington and Wyoming regions; ando Hydro generation.
Volume II, Appendix H of this report discusses the methodology on how the stochastic parameters
for the 2017 IRP were developed.
For unplanned thermal outages, PacifrCorp assumes a uniform distribution around an expected
rate. For existing units, the expected unplanned outage rates by unit are based on its historical
performance during the 4-year period ended December 2015. For new resources, the unplanned
outage rates are as specified for those resources as listed in the supply side resource table in
Chapter 6.
Table 7.2 - Short Term Load Stochastic Parameters
Winter 2017IRP 0.0M 0.033 0.031 0.42 0.049 0.017
Sprine 2017IRP 0.034 0.029 0.0s2 0.029 0.038 0.016
0.038 0.039 0.048 0.045 0.048 0.016Summer 2017IRP
0.034 0.049 0.033 0.044 0.017Fall20lT IRP 0.041
0.237 0.175 0.4 0.202 0.263Winter 2017IRP 0.21
Sprine 2017IRP 0.278 0.204 0.0n 0.398 0.25 0.271
Summer 2017IRP 0.197 0.294 0.101 0.211 0.184 0.316
0.218 0.268 0.21 0.287 0.184 0.1y2Fall2017 IRP
t57
PACFICoRP_2017IRP CHAPTER 7_MoDELNG AND PORTFoLIo EVALUATION APPROACH
Table 7.3 - Short Term Gas Price Parameters
Table 7.4 - Short Term Electricity Price Parameters
Table 7.5 - Winter Season Price Correlation
Table 7.6 - Spring Season Price Correlation
Winter 2017IRP 0.132 0.14
0.1Spring 2017IRP 0.104
Summer 2017IRP 0.027 0.u2
Fall20lT IRP
Winter 2017IRP 0.219
0.028
0.197
0.06
Sprine 2017IRP 0.652 0.s37
Summer 2017IRP 0.068 0.125
Fall2017 tRP 0.06 0.157
Winter 2017IRP 0.106 0.136 0.t62 0.106
Sprine 2017IRP 0.087 0.229 0.42 0.058
Summer 2017 IRP 0.105 0.235 0.383 0.088
Fall2017IRP
Winter 2017IRP 0.t29
0.066
0.135
0.074
0.138
0.079
0.16
0.05
Sprine 2017IRP 0.4ffi 0.435 0.51 0.308
Summer 2017IRP 0.27 0.39 0.91 0.252
0.247Fall2017 IRP 0.372 0.227 0.188
Nahnal Gas East I
Four Comers 0.531 I
COB 0.271 0.538 I
Mitl - Cohrnbh 0.268 0.s28 0.965 I
Palo Verde 0.521 0.785 0.714 0.684 I
Natural Gas West 0.919 0.46 0.28 0.275 0.451 I
NaturalGas East I
Four Comers 0.131 I
COB 0.085 0.421 I
Mlt - Cohrnbia 0.057 0.347 0.862 I
Pab Verde 0. r8 0.639 0.456 0.328 1
Natural Gas West 0.874 0.1 18 0.09 0.059 0.tM I
158
PACIFICoRP - 2017 IRP CHAPTER 7 _Mooprntc ANo PORTFOLIO EVALUATION APPNOACTT
Table 7.7 - Summer Season Price Correlation
Table 7.8 - Fall Season Price Correlation
Table 7.9 - Hydro Short Term Stochastic
Natural Gas East I
1Four Corners 0.074
COB 0.104 0.449 I
Mlt- Cohrnbb 0.055 0.345 0.661 I
0.841 0.525 0.369 1Pab Verde 0.109
Natural Gas West 0.563 0.097 0.131 0.054 0.132 I
Natural Gas East I
0.137 IFour Corners
COB 0.072 0.452 I
0.376 0.853 IMit- Cohrmbia 0.041
0.166 0.734 0.501 0.368 IPalo Verde
0.027 0.043 0.006 INatural Gas West 0.347 0.063
Winter 2017 IRP 0.208 0.806
0.t34 0.373Spring 20l7IRP
0.r49 1.436Summer 2017 IRP
0.28 1.056Fall2017IRP
1s9
PACIFICORP-20I7IRP CHapTpR 7 _MoDELhIG AND PoRTFoLIo EVALUATION APPRoACH
Figure 7.9 and Figure 7.10 show annual electricity prices at the first, 10th, 25th, 50th, 75th, 90th,
and 99th percentiles for Mid-C and Palo Verde market hubs based on a Monte Carlo simulation
using short-term volatility and mean reversion parameters. For Mid-C electricity prices,
differences between the first and 99th percentiles range from $4.694{Wh to $10.69lMWh during
the 2}-year study period. For Palo Verde electricity prices, the difference between the first and
99th percentiles range from$2.72n4wh to $3.88/\4Wh.
X'igure 7.9 - Simulated Annual Mid-C Electricity Market Prices
B
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PACIFICoRP - 2OI7 IRP CuapTTn 7 - MoDELING AND PORTFOLIO EVALUATION APPROACH
Figure 7.ll and Figure 7.12 show annual electricity prices at the first, 10tr, 25th, 50th, 75fr,90fi,
and 99ft percentiles for west and east natural gas prices. For west natural gas prices, differences
between the first and 99ft percentiles range from $0.22&tMBtu to $0.48/IvIMBtu during the 20-
year study period. For east natural gas prices, differences between the fust and 99rt percentiles
range from $0.27lMMBtu to $0.53/lvIMBtu.
Figure 7.ll - Simulated Annual Western Natural Gas Market Prices
Fq
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6.50
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trz=aD
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161
PACIFICORP _20I7IRP CHAPTER 7 - MODELNG AND PORTFOLIO EVALUATION APPROACH
Figure 7.13 through Figure 7.18 show annual loads by load area and for PacifiCorp's system at the
first, lOth, 25fr,50h,75th, 90th, and 99ft percentiles based on a Monte Carlo simulation using short-
term volatility and mean reversion parameters. For Idaho (Goshen) load, the annual differences
between the first and 99ft percentiles range from 184 GWh to 382 GWh For Utah load, the annual
difference ranges from 1,408 GWh to2,683 GWh. For Wyoming load, the annual difference range
from 139 GWh to279 GWh. For Oregon/Califomia load, annual differences range from 895 GWh
to 1,551 GWh. For Washington load, the annual difference ranges from233 GWh to 473 GWh.
For PacifiCorp's system load, the annual difference ranges fuom2,110 GWh to 4,643 GWh.
Figure 7.13 - Simulated Annual Idaho (Goshen) Load
2,500
2,400
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1,800
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PecmrConp-20l7IRP CHAPTER 7 -MODELTNG AND PORTFOLIO EVALUATION APPROACH
39,000
38,000
37,000
36,000
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32,000
31,000
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Figure 7.14 - Simulated Annual Utah Load
Figure 7.15 - Simulated Annual Wyoming Load
10,200
9,900
9,600
9,300
E 9.000
(J 8,700
8,400
8,100
7,800
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PACIFICORP-20I7IRP CHAPTSN 7 _MODELI.{G AND PORTFOLIO EVALUATION APPROACH
Figure 7,16 - Simulated Annual Oregon/California Load
16,500
16,000
15,500
15,000
E 14.500
B(, 14,ooo
13,500
13,000
12,500
12,000
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Figure 7.17 - Simulated Annual Washington Load
B()
5,600
5,400
5,200
5,000
4,800
4,600
4,400
4,200
,$ ,$. dP .e,t ,$ .$P r{F "$ ,*t ,*t "{il ,s,. "NF ,s," d} rd} "-f "e- ,dli ,s,'
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r64
PACIFICoRP _ 20I7 IRP CuepTpR 7 _ MoDEL TG AND PoRTFoLIo EVALUATIoN APPRoACH
Figure 7.18 - Simulated Annual System Load
75,000
72,500
70,000
67,500
B os.ooo
62,500
60,000
57,500
55,000
,d$ ,$" ,s't ,srt ^N| dP,{F ,s} ,{F ,s,t ,$ ,{,,. "NF ,s," d} rd} r{t ,s" ,si, ,*'
+99th {-90th ril-75th -.f6mean +25th -a'-l0th -+lst
Figure 7.19 shows hydro generation at the hrst, I}th,25:e,50e, 75ft, 90ft, and 99th percentiles based
on a Monte Carlo simulation using short-term volatility arid mean reversion parameters.
PacifiCorp can dispatch its hydro generation on a limited basis to meet load and reserve
obligations. The parameters developed for the hydro stochastic process approximate the volatility
of hydro conditions as opposed to variations due to dispatch. The drop in 2021 is due to the
assumed decommissioning of the Klamath River projects. Amual differences in hydro generation
between the first and 99th percentiles range from 286 GWh to 634 GWh.
Figure 7.19 - Simulated Annual Hydro Generation
F
4,800
4,600
4,400
4,200
4,000
3,800
3,600
3,400
3,200
3,000
,$ ,-). .f ,s,t "$ "{P ,s "dr "s "*t "$ "$,. "{P "s,"+99th {r90th -+75th {msan +25th {El0rh --,r--lst
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165
PACIFICORP-20I7 IRP CHAPTER 7 _ MoDELTNG AND PORTFOLIO EVALUATION APPROACH
Monte Carlo Simulation
During model execution, the PaR model makes time-path-dependent Monte Carlo draws for each
stochastic variable based on input parameters. The Monte Carlo draws are percentage deviations
from the expected forward value of each variable. The Monte Carlo draws of the stochastic
variables among all resource portfolios modeled are the same, which allows for a direct
comparison of stochastic results among all of the resource portfolios being arralyzed.In the case
of natural gas prices, electricity prices, and regional loads, the PaR model applies Monte Carlo
draws on a daily basis. In the case of hydroelectric generation, Monte Carlo draws are applied on
a weekly basis.
For the 2017 IRP, PaR is configured to conduct 50 Monte Carlo iterations for the 2U-year study
period. For each of the 50 Monte Carlo iterations, PaR generates a set of natural gas prices,
electricity prices, loads, hydroelectric generation and thermal outages. Then, the model optimizes
resource dispatch to minimize costs while meeting load and wholesale sale obligations subject to
operating and physical constraints. In a 50-iteration simulation, the resource portfolio is fixed. The
end result of the Monte Carlo simulation is 50 production cost figures for the 2}-year study period
reflecting a wide range of cost outcomes for the portfolio.
The expected values of the Monte Carlo simulation are the average result of all 50 iterations.
Results from subsets of the 50 iterations are also summarized to signifi, particularly adverse cost
conditions, and to derive associated cost measures as indicators of high-end portfolio risk. These
cost measures, and others are used to assess portfolio performance, which are described below.
Stochastic Portfolio Performance Measures
Stochastic simulation results for each unique resource portfolio are sunmarized, enabling direct
comparison among resource portfolio results during the preferred portfolio selection process. The
cost and risk stochastic measures reported from PaR include:
. Stochastic mean PVRR;. Risk-adjusted mean PVRR;. Uppertail Mean PVRR;. 5th and 95ft percentile PVRR;
. Average annual mean and upper-tail energy not served (ENS);
o Loss of load probability; and. Cumulative COz emissions.
Stochastic Mean PVRR
The stochastic mean PVRR is the average of system net variable operating costs among 50
iterations, combined with the real levelized capital costs and fixed costs taken from SO for any
given resource portfolio.6 The net variable cost from stochastic simulations, expressed as a net
present value, includes system costs for fuel, variable O&M, unit start-up, market contracts, system
balancing market purchases expenses and sales revenues, and ENS costs applicable when available
resources fall short of load obligations. Capital costs for new and existing resources, taken from
SO, are calculated on an escalated real-levelized basis. Other components in the stochastic mean
6 Fixed costs are not affected by stochastic variables, and therefore, do not change across the 50 PaR iterations.
t66
PecmrConp - 2017 IRP CHAPTER 7 - MODELNG AND PORTFOLIO EVALUATION APPROACH
PVRR include fixed costs for new DSM resources in the portfolio, also taken from SO, and COz
emission costs for any scenarios that include aCOz price assumption.
Risk-Adjusted PVRR
The risk-adjusted PVRR incorporates the expected-value cost oflow-probability, high cost
outcomes. This measure is calculated as the PVRR of stochastic mean system variable costs plus
five percent of system variable costs from the 95th percentile. The PVRR of system fixed costs,
taken from SO, are then added to this system variable cost metric. This metric expresses a low-
probability portfolio cost outcome as a risk premium applied to the expected (or mean) PVRR
based on 50 Monte Carlo simulations for each resource portfolio. The rationale behind the risk-
adjusted PVRR is to have a consolidated stochastic cost indicator for portfolio ranking, combining
expected cost and high-end cost risk concepts.
Upper-Tail Mean PVRR
The upper-tail mean PVRR is a measure of high-end stochastic cost risk. This measure is derived
by identifying the Monte Carlo iterations with the three highest production costs on a net present
value basis. The portfolio's real levelized fixed costs, taken from SO, are added to these three
production costs, and the arithmetic average of the resulting PVRRs is computed.
95th and 5th Percentile PVRR
The 5th and 95th percentile PVRRs are also reported from the 50 Monte Carlo iterations. These
measures capture the extent of upper-tail (high cost) and lower-tail (low cost) stochastic outcomes.
As described above, the 95th percentile PVRR is used to derive the high-end cost risk premium for
the risk-adjusted mean PVRR measure. The 5th percentile PVRR is reported for informational
purposes.
Production Cost Standard Deviation
To capture production cost volatility risk, PacifiCorp uses the standard deviation of the stochastic
production cost from the 50 Monte Carlo iterations. The production cost is expressed as a net
present value of annual costs over the period 2017 through2036. This measure meets Oregon IRP
guidelines to report a stochastic measure that addresses the variability of costs in addition to a
measure addressing the severity of bad outcomes.
Averase and Uooer-Tail Enerey Not Served
Certain iterations of a stochastic simulation will have ENS, a condition where there are insufficient
resources, inclusive of system balancing purchases, available to meet load or operating reserve
requirements because of physical constraints. This occurs when Monte Carlo draws of stochastic
variables result in a load obligation that is higher than the capability of the available resources in
the portfolio. For example, this might occur in Monte Carlo draws with large load shocks
concurrent with a random unplanned plant outage event. Consequently, ENS, when averaged
across all 50 iterations, serves as a measure of reliability that can be compared among resource
portfolios. PacifiCorp calculates an average annual value over the 2017 through 2036 planning
horizon, reported in gigawatt-hours, as well as the upper-tail ENS (average of the three iterations
with the highest ENS). In the 2017 IRP, ENS is priced at $1,000AvIWh.
Loss of Load Probability
Loss of load probability (LOLP) reports the probability and extent that available resources of a
portfolio cannot serve load during the peak-load period of July in the 2|-year period. PacifiCorp
reports LOLP statistics, which are calculated from ENS events that exceed threshold levels.
167
PACIFICoRP-20I7IRP CHAPTER 7 - MODELI.{G AND PORTFOLIO EVALUATION APPRoACH
Cumulative COz Emissions
Annual COz emissions from each portfolio are reported from PaR and summed for the twenty year
planning period. Comparison of total COz emissions is used to identiff potential outliers among
resource portfolios that might otherwise be comparable with regard to expected cost, upper-tail
cost risk, and/or ENS.
Forward Price Curwe Scenarios
Each of the unique resource portfolios developed with SO during the resource portfolio
development process are analyzed in PaR among the six price-emissions scenarios. The price curve
scenarios include PacifiCorp's October 2016 OFPC along with price curves developed assuming
low and high natural gas price assumptions. PaR results using each of these scenarios inform
selection of the preferred portfolio.
Price assumptions for each of these scenarios are subject to short-term volatility and mean
reversion stochastic parameters when used in PaR. The approach for producing wholesale
electricity and natural gas price scenarios used for PaR simulations is identical to the approach
used to develop price scenarios for the resource portfolio development process.
Other PaR Modeling Methods and Assumptions
Transmission System
The transmission topology used for SO, shown in Figure 7.2, is identical to the transmission
topology used for PaR simulations.
Resource Adequacy
The resource portfolio developed with SO, which meets an assumed 13 percent target planning
reserve margin, is fixed in all PaR simulations. With flrxed resources, the unit commitment and
dispatch logic in PaR accounts for operating reserve requirements. These reserve requirements
include contingency reserves, which are calculated as 3 percent of load and 3 percent of generation.
In addition, PaR reserve requirements account for regulation reserves. PacifiCorp's regulation
reserve assumptions are outlined in PacifiCorp's flexible reserve study, provided in Volume II,
Appendix F.
Energy Storage Resources
PaR unit commitment is implemented on a week-ahead basis. The model operates the storage plant
to balance generation and charging, accounting for cycle efficiency losses, in order to end the week
in the same net energy position as it began. The model chooses periods to generate and return
energy to minimize system cost. It does this by calculating an hourly value of energy for charging.
This value of energy, a form of marginal cost, is used as the cost of generation for dispatch
pulposes, and is derived from calculations of system cost and unit commitment effects. For
compressed air energy storage (CAES) plants, a heat rate is included as a parameter to capture fuel
conversion efficiency.
General Assumptions
The general assumptions applied in SO for the study period (2O-years beginning 2017) annual
inflation rates (2.22 percent), and discount rates (6.57 percent) are also applied in PaR.
168
PACIFICoRP _ 2017 IRP CHAPTER 7 -MODELTNG AND PoRTFoLIo EVALUATIoN APPRoACH
Other Cost and Risk Considerations
In addition to reviewing stochastic PVRR, ENS, and COz emissions data from PaR, PacifiCorp
considers other cost and risk metrics in its comparative analysis of resource portfolios. These
metrics include fuel source diversity, and customer rate impacts.
Fuel Source Diversity
PacifiCorp considers relative differences in resource mix among portfolios by comparing the
capacity of new resources in portfolios by resource type, differentiated by fuel source. PacifiCorp
also provides a summary of fuel source diversity differences among top performing portfolios
based on forecasted generation levels of new resources in the portfolio. Generation share is
reported among thermal resources, renewable resources, DSM resources and FOTs.
Customer Rate Impacts
To derive a rate impact measure, PacifiCorp computes the percentage change in nominal annual
revenue requirement from top performing resource portfolios (with lowest risk adjusted mean
PVRRs) relative to a benchmark portfolio selected during the final preferred portfolio screening
process. Annual revenue requirement for these portfolios is based on the stochastic production cost
results from PaR and capital costs reported by SO on a real levelized basis. The real levelized
capital costs are adjusted to nominal dollars based on the timing of when new resources are added
to the portfolio. While this approach provides a reasonable representation of relative differences
in projected total system revenue requirement among portfolios, it is not a prediction of future
revenue requirement for rate-making purposes.
The final step in the evaluation process within each screening stage is portfolio selection. In the
fust screening stage portfolio selection step, the least-cost least-risk Regional Haze case is
selected. In the second screening stage, the draft preferred portfolio is selected from among the
cases eligible for consideration. [n the final screening stage, the preferred portfolio is selected.
Within each screening stage, each portfolio under examination is compared on the basis of cost-
risk metrics, and the least-cost, least-risk portfolio is chosen. Risk metrics examined include the
mean PVRR, upper-tail PVRR, risk-adjusted PVRR, mean ENS, upper-tail ENS, and emissions.
The comparisons of outcomes are detailed, ranked, plotted and assessed in the next chapter
(Volume I, Chapter 8: Modeling and Portfolio Selection Results).
Due to the lengthy nature of the IRP cycle, the final screening stage is the last opportunity to
consider not only the draft preferred portfolio, but also significant indicators from all studies,
additional sensitivities, possible updates driven by recent events, and additional stakeholder
feedback. Additional sensitivities may refine the portfolio selection based on portfolio
optimization and cost and risk analysis steps.
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PACIFICORP - 20 I7 IRP CHapTsn 7 _ MoDELTNG AND PoRTFoLIo EVALUATION APPROACH
During the final screening process, the results of any further resource portfolio developments are
ranked by risk-adjusted mean PVRR, the primary metric used to identifu top performing portfolios.
Portfolio rankings are reported for the low, base, and high price curve scenarios under both CPP
scenarios. The average portfolio rank among each of the price curve scenarios is also produced.
Resource portfolios with the lowest risk-adjusted mean PVRR receive the highest rank. Final
screening also considers system cost PVRR data from SO and other comparative portfolio analysis.
At this stage, PacifiCorp reviews additional stochastic metrics from PaR looking to identiS if
expected and upper-tail ENS results and COz emissions results can be used to differentiate
portfolios that might be closely ranked on a risk-adjusted mean PVRR basis.
Case definitions specify a combination of planning assumptions used to develop each unique
resource portfolio during the resource portfolio development step of each screening stage.
Regional Haze cases provide a range of compliance alternatives detailing coal unit retirement
strategies. Core cases include combinations of altemative assumptions tailored to target specific
resource technologies and that promotes resource diversity. Sensitivity cases isolate the impact to
resource portfolio and system costs when modifring a single assumption. The resource portfolio
and system cost data from sensitivity cases are compared to a benchmark case portfolio appropriate
to the timing and needs of the sensitivity.
Regional Haze Case Definitions
Seven Regional Haze compliance scenarios were developed forplanning purposes (the 'reference'
case plus Regional Haze cases 1 through 6). In addition to analyzing known and prospective
Regional Haze compliance requirements, PacifiCorp's portfolio development process incorporates
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 RegionalHaze case considered in the portfolio development process 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 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.
If it poses a reasonable scenario, a given coal plant may continue operating until end-of-life, retire
in an earlier year, convert to gas plant operations, or undergo a selective catalytic reduction (SCR)
refit to continue operations with reduced emissions.
Regional Haze Case 6 is an endogenous retirement case, created in response to stakeholder
feedback received during the public input process. The endogenous retirement case differs in
approach from the designated retirement strategies embodied in the reference case and Regional
Haze cases I through 5. Specifically, under Regional Haze Case 6:
t70
PACIFICoRP _ 2OI7 IRP CHAPTER 7 -MODEL[.{G AND PORTFOLIo EVAIUATIoN APPRoACH
SO is configured to choose early retirement or SCR installation as competitive compliance
outcomes.
Cost impacts of early retirement altematives are approximated for the following coal units:
Hunter 1, Hunter 2, Huntington 1, Huntington 2, Jim Bridger 1, and Jim Bridger 2.
Cost impacts assume that early retirement, if chosen by SO, occurs at the end of the month
prior to the month SCR equipment would otherwise be installed.
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 Regional Haze case
definitions represent a range of strategic paths to be evaluated, no individual unit commitments
are being made at this time.
Table 7.10 summaizes Regional Haze case key assumptions for the seven compliance scenarios.
The 2015 IRP Update assumptions are also included for reference.
Table 7.10 - Regional Haze Case Assumptions
I The Alternative Regional Haze cases for Hunter units I and 2 and Jim Bridger units I and 2 have been developed for analysis
purposes only with consideration given to the fact that the emissions profiles for the units are effectively identical in the Regional
Haze context. The compliance actions in this scenario could effectively be swapped and provide t}re same Regional Haze
compliance outcome. The matix presentation of different compliance actions between the units is necessary for analysis data
preparation, but does not dictate or represent pre-determined individual partner plant owner strategies or preferences or individual
unit strategies or preferences.2 The Altemative Regional Haze cases for Huntington I and 2 have been developed for analysis purposes only with consideration
given to the fact that the emissions profiles for the units are effectively identical in the Regional Haze context. The compliance
actions for the units in this scenario could effectively be swapped and provide the same Regional Haze compliance outcome.
The matrix presentation ofdifferent compliance actions between the units is necessary for analysis data preparation, but does
not dictate or represent pre-determined individual unit strategies or preferences.3 Naughton 3 will cease coal fueled operation by year-end 20 I 7, under this scenario .a Craig I will cease coal fueled operation by end of August2023, under this scenario.
t7t
o
a
a
SCR2O2I
Ret.2042
scR202l
Ret. 2042
No SCR;NQrI
2021
Rcl204.2
No SCR
Ret.203l
No SC&NOd
2026
Rct.2042
scn.zoztttr
Rat.20/.2
RH.I sct. 8/4/2021
RetT/31/2021
SCR2O2I
Ret.2042
No SCR;NQrI
2021
REt.2M2
No SCR
Rct.203l
No SCR
Ret.2032
No SCRNOTT
2427
Ret.20/.2
No SCRNOrI
2c,:lt)
Ret.2042
RH.I sm.8/4/2021
RatT/3112021
scR2022
Ret.2036
SCR2O2I
Rct.2036
No SCR
Ret.2036
No SCR
Ret.2036
No SC&NOr+
2026
Ret.2036
scn zoztt2>
REt.2036
RH.I scR 8i/4/202t
REtT/31/2021
No SCR
Ret.2029
SCR2O2I
Rct.2036
No SCR
Ret.2035
No SCR
Rgt.2036
No SCxlNqC
2rn7
Ret.2036
No SCR;NOrI
20212\
Ret.2036
RH.I scR.8/4/202r
Rft7/3y2021
scR2022
Ret.2037
No SCR
Ret.2032
No SCR
Rct.2024
scR2022
Ret.2037
No SCR
Rct.2028
No SC&NOrr
2a2(\
Ret.2032
RH.3 scx.w3y2022
Ret |AW2A2
scR202l
P€t.2037
scR202l
Rot.2037
No SCR
Rct.2035
No SCR
R€t.2028
No SCR
Ret.2032
scn zozt(t)
Ret.2037
RH.3 scR lz3rl2021
REt 12130/2Al
No Gas Conv
Ret.2017
Gas Conv.20l{3)
Ret.2029
No Gas Conv
Rct.20l7
Cas Conv.20ll3)
REr.2029
No Cas Conv.
Ret.20U
Gas Conv.20ll3)
Ret.2029
RH.2 No Cas Conv.
Ret.2017
Gas Conv.2025
Rf;t.20/.2
No Cas Conv.
Ret. Apr-2025
No Gas Conv.
Ret. Apr-2025
No Gas Conv.
Ret.2020
No Gas Conv.
Rct. Apr-2025
No Gs Conv.
Ret. Apr-2025 RH.2 No Gas Conv.
Ret. Apr-2025
SCR2O2I
Ret.2034
No SCR
Ret.2025
No SCR
Rct.2025
Cas Conv.2023(a)
Ret.2034
No SCR
Rct.2025
No SCR
Ret.2025
RH-I No SCR
Ret.2025
PACIFICoRP - 2OI7 IRP CHAPTER 7-MoDELTNIG AND PoRTFoLIo EVALUATION APPROACH
Core Case Definitions
PacifiCorp defined six core cases to be modeled and examined as part of the second screening
stage (eligible portfolios) of the 2017 IRP process. Informed by the public input process from
current and prior IRP cycles, core cases target specific types of resources, promoting portfolio
diversity and eliminating the need for deterministic risk analysis. Resources having operating
characteristics not valued in SO are also analyzed in PaR during the cost and risk analysis phase
of the portfolio development process. Doing so allows resources that may have been neglected due
to the limitations of SO, the opportunity to take advantage of PaR model capabilities and
stochastics-driven cost-risk metrics. The core case definitions reflect multiple combinations of
planning assumptions.
Table 7.11 provides the core case definitions for this IRP, which are described in more detail in
Chapter 8. Core case refinements and additions were modeled on the basis of outcomes and
stakeholder feedback in the 2017IRP public input process.
Table 7.ll - Core Case Definitions
Case 1: Optimized Portfolio (OP-l)
This case is the least-costJeast-risk Regional Haze case emerging from screening stage l. The
Regional Haze case with the best cost-risk metrics is promoted to become core case l, and serves
as the basis for further studies, including the remaining core cases and sensitivities. Therefore, as
with the underlying Regional Haze case, all resources have been optimized (selected endogenously
by SO), andanalyzed in PaR.
Case 2: Flexible Resources (f'R-l)
Fast ramp resources are added with a capacrty of at least 1 0 percent of the system L&R need. Fast-
ramp resources available for selection include: SCCT Aero (i.e., LM6000); Intercooled SCCT
Aero (i.e., LMSl00); IC Reciprocating Engines; pumped storage, compressed air energy storage,
and battery storage.
Case 3: Flexible Resources (FR-2)
As with FR-l, fast ramp resources are added but with a capacity of at least 20 percent of the system
L&Rneed.
Optimized
ICPlo of
Increnpntal
I.&R halance
2tr/o of
IncrenBntal
T,&R balance
Optimized Optimized Optimized OptimiredFlenble
Resources Optimized
Renewable
Resources Optimized Optimired Optimired
Just-in-Tinp
Physical RPS
Compliance
(oR)
Just-in-Tirp
Physical RPS
Conpliance
("wA)
Just-in-Time
Physical RPS
Conpliance
(ORand WA)
Earty Physical
Compliance
Jusrin-Tirp
Physical RPS
Conpliance
(ORand WA)
Class l DSM
Resources Optimized Optimired Optimired Optimized Optimized
5o/o of
IncrerEntal
L&Rbalance
Optimized
SYo of
IncrenBntal
[&Rbalance
All other
Resources Optimized Optimized Optimircd Optimired Optimized Optimired Optimized Optimized
t72
PACIFICoRP - 2017 IRP CTTapTpn 7 - MODELhIG AND PORTFOLIO EVALUATION APPROACH
Case 4: Renewable Enerry (RE-l)
Endogenous renewables from core case 1 (OP-l) are retained. Additional renewables are added to
physically comply with projected Oregon and Washington renewable portfolio standard (RPS)
requirements, with additions made beginning the first year in which there is a projected compliance
shortfall (ust-in-time compliance).
Case 5: Renewable Enerry GE-2)As with RE-1, endogenous renewables from core case 1 (OP-l) are retained. Additional
renewables are added to physically comply with projected Oregon RPS requirements, with
additions are made in 2021 (proxy for year-end 2020) to meet requirements throughout the
planning period (early compliance).
Case 6: Direct Load Control (DLC-l)
Additional Direct Load Control (DLC) is added to core case I (OP-l) in the first year (2021), with
a capacity of at least 5 percent of the system load & resource balance need. Renewable resource
assumptions are taken from core case 4 (RE-1).
Additional details on core cases can be found in Appendix M: Case Study Fact Sheets
Sensitivity Case Defi nitions
PacifiCorp initially identified l6 sensitivities based on prior IRP cycle experience, stakeholder
feedback, and anticipated areas of interest. Additional sensitivities were identified during the2017
IRP cycle, and are described in Volume I, Chapter 8. Each sensitivity is designed to highlight the
impact of specific planning assumptions on future resource selections along with the associated
impact on system costs and stochastic risks. Note that some sensitivities are considered eligible
for preferred portfolio selection in screening stages 2 and 3 of the IRP process. Other sensitivities
are for informational purposes and serve to illustrate how the system behaves under a variety of
conditions that may be theoretically possible but which cannot be supported on the basis of cost-
risk metrics (e.g., the 1-in-20 load sensitivity).
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PACIFICoRP-20I7IRP CHAPTER 7 - MODELING AND PORTFOLIO EvALUATION APPROACH
Table 7.12 - Sensitivity Delinitions
Additional details on the sensitivity cases can be found in Volume II, Appendix M: Case Study
Fact Sheets.
Regional Haze Sensitivities
An additional sensitivity (RH-2a) was performed relevant to Region Haze case 2 (RH-2) in
response to stakeholder feedback at the PacifiCorp IRP January 26-27 ,2017 public input meeting.
As a result, the selected Regional Haze case (RH-5) was modified and re-optimized, becoming
RH-5a. Both additional cases are described in Volume 1, Chapter 8.
Load Sensitivities
PacifiCorp includes three different load forecast sensitivities. The low load forecast sensitivity
reflects pessimistic economic growth assumptions from IHS Global Insight and low Utah and
Wyoming industrial loads. The high load forecast sensitivity reflects optimistic economic growth
assumptions from IHS Global Insight and high Utah and Wyoming industrial loads. The low and
high industrial load forecasts focus on increased uncertainty in industrial loads further out in time.
To capture this uncertainty, PacifiCorp modeled 1,000 possible annual loads for each year based
on the standard error of the medium scenario regression equation. The low and high industrial load
forecast is taken from 5th and 95ft percentile. The third load forecast sensitivity is a 1-in-20 (5
percent probability) extreme weather scenario. The 1-in-20 peak weather scenario is defined as the
year for which the peak has the chance of occurring once in 20 years. This sensitivity is based on
l-in-20 peak weather for July in each state. Figure 7.20 compares the low, high, and 1-in-20 load
RFDa ReebnalHare oP-l Base Base BaseMass Cap B None
LD-I 1 in 20 t oads oP-l I rl,20 Base Mass Cap B Base None
LD-2 Low Load oP-l [.ow Base Mass Cap B Base None
LD-3 HishLoad oP-1 Hieh Base Mass Cap B Base None
PG-1 Low Private Gen oP-l Base Low Mass Cap B Base None
PG.2 HMPrirrate Gen oP-l Base Hidt Mass Cap B Base None
CPP.C CPP Mass Cap C oP-l Base Base Mass Cap C Base None
CPP-D CPP Mass Cap D oP-l Base Base Mass Cap D Base None
FOT-I Limited FOT oP-l Base Base Mass Cap B Restricted None
coz-l CO2 Frice oP-l Base Base Tax, No CPP Base None
NO-CO2 No CO2 OP-NT3 Base Base No Targ No CPP Base None
BP Business Phn OP.NT3 Base Base Mass Cap D Base None
GWI Gateway I OP-NT3 Base Base Mass Cap B Base Segnent D
GW2 Gateway 2 OP-NT3 Base Base Mass Cap B Base Segnent F
GW3 Gateway 3 OP-NT3 Base Base Mass Cap B Base Seprnent D&F
GW4 Gateway4 OP-NT3 Base Base Mass Cap B Base Segnent D2
Battery Batterv Storase FS-GW4 Base Base Mass Cap B Base Seprnent D2
CAES CAES Storase FS-GW4 Base Base Mass Cap B Base Seprnent D2
V/CA WCA FS.REP Base Base Mass Cap B Base None
WCA.RPS WCARPS FS-REP Base Base Mass Cap B Base None
t74
PACIFICoRP - 2017 IRP CHAPTER 7 - MoDELTNG AND PoRTFoLIo EVALUATIoN APPRoACH
sensitivities, net ofbase case distributed generation penetration levels, alongside the base case load
forecast.
Figure 7.20 - Load Sensitivity Assumptions
Coincident System Peak
Bt-a
13,500
13,000
12,500
12,000
I1,500
I1,000
10,500
10,000
9,500
9,000
,dl
"$.r$o.reo
rs).NP"-f ,$rsF r*t r$ ne*nd rs," "*. "$"di rs"rd "s'frBass .{F I in 20 ..*-High Load +Low Load -.)eHigh PG {blow PG
System Load
80,000
75,000
60,000
55,000
"$ r$"r$t r&"r$"-fl"sP rsrr$ rs,t "$ rSnd "pt "Nl$rdi "e"rdt rs,'
-ftBffis .-l-High Load -)tlow Load -iieHigh PG -.-Low PG
Private Generation Sensitivities
Two private generation sensitivities are analyzed. As compared to base private generation
penetration levels that incorporated annual reductions in technology costs, the low private
generation sensitivity reflects reduced reductions in technology costs, reduced technology
Frlr
70,000
65,000
175
PACIFICoRP - 20I7 IRP CHAPTER 7 - Moogln.Ic AND PoRTFoLIo EVALUATIoN APPROACH
performance levels, and lower retail electricity rates. In contrast, the high private generation
sensitivity reflects more aggressive technology cost reduction assumptions, higher technology
performance levels, and higher retail electricity rates. Figure 7.21 summarizes private generation
penetration levels for the low and high sensitivities alongside the base case.
Figure 7.21 - Private Generation Sensitivity Assumptions
EishBucLow
4,5m
4,000
3,5m
3,m
2,500
2,000
1,500
I,m0
500
0 ..IIIIIIIIIIIIIffiIII ..IIIIIIIIililIIffiII
4,500
4,000
3,5m
3,000
2j$
2,000
1,500
l,0m
ffi
ifi .,,,,,,,,,ilIIffifll1
a
===!ccdqd^!nn!!!anFe
ruT eOR.WA.WY nlD rCA .UT {OR.WA .WY illD rCA .UT xOR rWA .WY nID rCA
CPP Mass Cap C
CPP Mass Cap C: Mass-based compliance approach with pro-rata allowance allocation to
PacifiCorp based on historical generation with no new source complement /ess the CEIP,
renewable and output-based set-asides. It is assumed that PacifiCorp does not receive any of these
set-asides.
CPP Mass Cap D
Mass Cap D: CPP with no set-aside program and with new source complement. The new source
compliment assumes that the mass-based limit grows to accommodate new resources that are
needed to meet load growth.
Limited Availability of FOTs
As noted in Chapter 6, PacifiCorp develops FOT limits based on 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. Alternative FOT limit assumptions
applied during the portfolio development process eliminates the availability of FOTs at the NOB
(100 MW) and Mona (300 MW) market hubs in summer and winter beginning 2021.
COz Price
With the introduction of EPA's CPP, PacifiCorp has reflected how future regulations targeting
COz emission reductions in the electric sector might influence its resource plan. The CPP is
reflected in all RegioralHaze, core cases and sensitivities in the emissions-price scenarios. The
COz Price sensitivity_examines the impact of replacing the CPP with a COz price proxy beginning
in the year 2025, based on the possibility that even if the CPP is not in effect, there will be some
type of carbon-based policy in place by this time. An additional "No COz" sensitivity was added
in response to stakeholder feedback late in the 2017 IRP cycle. This additional study is described
as part of Volume I, Chapter 8.
t76
PACIFICORP - 20I7 IRP CHAPTER 7 -MODELhIG AND PORTFOLIO EVALUATION APPROACH
Figure 7.22 shows COz price assumptions used in the 2017 IRP COz sensitivity case. Prices are
applied to each ton of COz emissions from new and existing resources, beginning in 2025 at
$4.75lton and reaching $38.02itonby 2036.
f igure 7.22 - Nominal CO2 Price Assumptions for the CO2 Sensitivity
S+o
s3s
s30
s2sc
{ szo
rt>
s1s
Sro
Ss
SO
"$ "$|" "d r&t
"d> "dP "dP "S "d "d," "$ "&- "d "&" "-f "dP "dP "e" "d "&"
No COz Policy
An additional sensitivity was performed in response to stakeholder feedback, representing the
PacifiCorp system in the absence of a COz policy. The development and results of this sensitivity
are presented in Volume I, Chapter 8.
Business Plan Sensitivify
This sensitivity complies with the Utah requirement to perform a business plan sensitivity
consistent with the commission's order in Docket No. 15-035-04. Over the first three years,
resources align with those assumed in PacifiCorp's Fall 2016 Business Plan. Beyond the first three
years of the study period, unit retirement assumptions are aligned with the draft preferred portfolio
selected from the second screening stage. All other resources are optimized. Note that initially,
these assumptions were expected to align with core case 1. Due to the timing of this sensitivity,
the study was modeled based on the outcome of a later screening stage. This serves to make the
business plan sensitivity closer to the preferred portfolio, and therefore a more indicative
comparison.
Energy Gateway Sensitivities
PacifiCorp modeled four Energy Gateway transmission sensitivities, expanding on scenarios
defined in the 2013 and 2015 IRP cycles. Incremental to the base case, the Energy Gateway
sensitivities are as follows:
177
PACIFICORP_2OI7IRP CHaTTen 7 _MoDELNG AND PoRTTouo EVALUATIoN APPRoACH
Table 7.13 - Enerry Gateway Sensitivities
Enerry Storage
PacifiCorp includes two energy storage sensitivities. Both force large scale energy storage
resources into the resource portfolio, but allow the models to optimize their usage. The first storage
sensitivity forces 80 MW of battery storage capacity in PacifiCorp's east BAA (Wyoming). The
second storage sensitivity forces an 80 MW compressed air storage plant (CAES) sited in
PacifiCorp's east BAA (Utah South). The sites selected were based on a qualitative assessment of
locations best suited for storage to provide support for added renewables, in the expectation that
storage plants have the ability to mitigate the non-dispatchable nature of wind and solar energy
production.
EastAilest Split
As required by the Washington Utilities and Transportation Commission, PacifiCorp's 2017 IRP
includes a sensitivity that produces standalone resource portfolios for the west control area (WCA)
compared to operation as part of PacifiCorp's integrated system. This sensitivity required different
assumptions for the west BAA model and for the WCA break-out from the base model results,
summarized below. An additional sensitivity (WCA-RPS) examines the impact of assuming a
physical renewable portfolio standard (RPS) compliance strategy in the WCA break-out.
WCA Assumptionso Maintains I 3 percent target planning reserve margin, applicable to summer and winter peako Class 2 DSM capacity contribution values are updated to align with summer and winter
peak;o All of Jim Bridger is included in the west BAAo Colstrip is included in the west BAA up to transmission limits
t78
Cateway I Segment D W indstar to Anticline (as sumed in-s ervice 2022)
C-ateway 2 Segment F W indstar to Mona / Clover (as s umed in-s ervic e 20D3)
Cateway 3 Segnnnt D&F Windstar to Anticline and Aeolus to Mona / Clover (assunpd in-service
2A/2. and 2023, respectively)
Cateway 4 Segnrnt D2 Aeolus to Anticline (assumed in-service year-end 2020)
PACIFICORP _ 20 I7 IRP CHAPTER 8 _MODELING RESULTS
Cuaprpn 8 - MopELTNG AND Ponrpot,ro
SprpcrroN Rpsurrs
Cnq.Prnn Hrcnr,rcrrrs
. Using a range of cost and risk metrics to evaluate a wide range of resource portfolios,
PacifiCorp selected a preferred portfolio reflecting a cost-conscious plan to transition to a
cleaner energy future with near-term investments in both existing and new renewable
resources, new transmission infrastructure, and energy efficiency programs. More than 200
Planning and Risk (PaR) studies were performed over three portfolio screening stages to
inform selection of the preferred portfolio. Considering each PaR study includes 50
iterations of system performance, this equates to over 10,000 simulations of potential 20-
year system dispatch outcomes.o The preferred portfolio includes 1,100 MW of new Wyoming wind resources that will
connect to a new 140-mile transmission line running from the Aeolus substation near
Medicine Bow, Wyoming, to the Jim Bridger Plant. This time-sensitive project requires
that the new wind and transmission assets achieve commercial operation by the end of 2020
to maximize wind production tax credit (PTC) benefits.o Repowering 905 MW of existing wind resources by the end of 2020 will re-qualify these
zero-emission resources to receive the full value of PTCs for an additional ten years. With
the installation of modern technology and improved control systems, the repowered wind
facilities will produce more energy for a longer period of time at reduced operating costs-
saving customers hundreds of millions of dollars.o Energy efficiency continues to play a key role in PacifiCorp's resource mix. Over the first
tenyears ofthe planning horizon, accumulated acquisition of incremental energy efficiency
resources meets 88 percent of forecasted load growth (up from 86 percent in the 2015 IRP).
Over the longer term, direct load control programs play an increasing role in PacifiCorp's
transitioning resource mix.. The preferred portfolio does not include the installation of any incremental selective
catalytic reduction equipment for coal generation. Avoiding installation of this equipment
will save customers hundreds of millions of dollars and retain compliance-planning
flexibility for the Clean Power Plan or other potential state and environmental policies. By
the end of the planning horizon, PacifiCorp assumes 3,650 MW of existing coal generation
will be retired.o Natural gas-fired resources do not appear in the preferred portfolio utxil2029 (one year
later than in the 2015 IRP). By the end of the planning horizon, naturalgas-f,rred capacity
totals 1,313 MW, a reduction of 1,540 MW relative to the 2015 IRP preferred portfolio.
PacifiCorp will continue to evaluate potential long-term supply alternatives, including the
potential penetration of energy storage, through its on-going resource planning efforts.
o The preferred portfolio reflects PacifiCorp's on-going efforts to provide clean energy
solutions for our customers. As compared to the 2015 IRP, projected carbon dioxide (CO,
emissions are down by 2l percent over the first ten years of the planning horizon. By the
end of the plaruring period, system COz emissions are project to fall by 24.5 percent.
t79
PACIFICoRP - 2017IRP CHAPTER 8 _ MODELtr.{G RESULTS
This chapter reports modeling and performance evaluation results for the resource portfolios
developed with a broad range of input assumptions using System Optimizer (SO) and simulated
with PaR. Using model data from the portfolio development process and subsequent cost and risk
analysis of unique portfolio altematives, PacifiCorp steps through its preferred portfolio selection
process and presents the 2017 IRP prefened portfolio.
The chapter is organized around the three screening stages identified in the previous chapter:
(l) Regional Haze case screening; (2) eligible case screeninBt and (3) final screening for preferred
portfolio selection. The final preferred portfolio screening stage is informed by all relevant case
results and incorporates additional updates and sensitivities indicated by preceding results, recent
relevant events and stakeholder feedback. This chapter also presents modeling results for
additional20lT IRP sensitivity cases that, while informative, were not considered for selection as
the preferred portfolio.
Results of resource portfolio cost and risk analysis from each screening stage are presented as
PacifiCorp steps through the following discussion of its portfolio evaluation processes. Stochastic
modeling results from PaR are also summarized in Volume II, Appendix L (Stochastic Simulation
Results).
Resource Portfolio Development
Aligning with the screening methodology described in Chapter 7, the seven Regional Haze cases
assume differing sets of retirement assumptions, which together comprise a range of compliance
strategies for modeling and comparative analysis. Each Regional Haze scenario considers the
timing and magnitude of run-rate capital and operations and maintenance costs for individual coal
units in PacifiCorp's fleet. For instance, if a specific Regional Haze scenario assumes an early
retirement for a given coal unit as part of a Regional Haze compliance solution, 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 2}-year planning horizon
and avoidance of future costs related to known or assumed environmental compliance costs as
described in Chapter 7 Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach).
Figure 8.1 summarizes the cumulative capacity of new resources and the cumulative reduction in
existing resources through 2036, as optimized by SO under the reference Regional Haze scenario.
Figure 8.2 through Figure 8.7 present corresponding summary results for resource portfolios
developed under Regional Haze cases I through 6.
Each case is driven by key retirement strategy assumptions as presented in the previous chapter.
In nearly every case, PTCs drive the addition of roughly 300 MW of renewable wind capacity in
Wyoming, constrained by available transmission.
Detailed resource portfolio results for each core case, showing new resource capacity and changes
to existing resource capacity by year, are contained in Volume II, Appendix K (Capacity
180
PACIFICoRP - 20I7 IRP CH.cPrEn 8 -MoDELTNG RESULTS
Expansion Results Detail). Summary portfolio results are also shown in the case fact sheets
presented in Volume II, Appendix M (Case Study Fact Sheets).
Figure 8.1- Cumulative Capacity through 2036, Regional Haze Reference Case
Figure 8.2 - Cumulative Capacity through 2036, Regional Haze Case I
I
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181
PacmrConp-2017IRP CHAPTER 8 _MODELING RESTJLTS
8.3 - Cumulative
8.4 - Cumulative
Haze Case 2
Haze Case 3
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182
PACIFICoRP _ 20 I7 IRP CHAPTER 8 -MODELTNG RESULTS
a Other
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8.5 - Cumulative Haze Case 4
Figure 8.6 - Cumulative Capacity through 2036, Regional IJaze Case 5
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183
PecmrConp-2017IRP CHEPTER 8 _MODEL[.{G RESULTS
8.7 - Cumulative Haze Case 6
System Costs
Figure 8.8 shows the present value revenue requirement (PVRR) of system costs among resource
portfolios developed under reference Regional Haze compliance assumptions and under Regional
Haze cases 1 through 6.
Figure 8.8 - System Optimizer PVRR Costs for RegionalHaze Cases
$25
$20
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$I5
$I0
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184
PACIFICORP-20I7 IRP Cruprpn 8 - MoDELTNG REsuLrs
Based upon the System Optimizer PVRR, Regional Haze cases 1 and 5 provide the lowest net
system costs, which are notably lower than the system costs from all other cases developed
assuming medium natural gas prices and Clean Power Plan (CPP) COz emission limits as defined
under the Mass Cap B scenario.
When enabling endogenous early retirements (Regional Haze case 6), net system costs are reduced
relative to the Reference Case, but net costs are higher relative to other Regional Haze compliance
cases that reflect a range of potential negotiated compliance alternatives. Regional Haze case 6
produced the following key Regional Haze outcomes:
o Jim Bridger Unit2 retires year-end202lo Selective catalytic reduction (SCR) equipment was installed on Hunter Units I & 2,
Huntington Units | &,2, and Jim Bridger Unit 1
Figure 8.9 summarizes the comparative difference in PVRR system costs for each Regional Haze
case relative to the system costs from the Reference Case. Detailed portfolio cost results, showing
system cost line items by year, are included in Volume II, Appendix K (Capacity Expansion
Results Detail). Summary portfolio costs are also shown in the case fact sheets presented in
Volume II, Appendix M (Case Study Fact Sheets).
8.9 - Increase in PVRR Costs vs. Reference Case
Regional lJaze Cost and Risk Analysis
PaR Configuration and Metrics
PaR model results are used to develop portfolio ranking metrics, which include the mean PVRR,
upper-tail PVRR, risk-adjusted PVRR, mean Energy Not Served (ENS), upper-tail ENS, and COz
emissions. PaR is configured to calculate 5O-iterations of 12 sample weeks representing the months
of each study year (2017 through 2036). Sample weeks capture the peak load week for each month.
0.0
IIIr
Reference RHI RH2 RH3 RH4 RH5 RH6
o
tqe
il
pr
($ l.o)
($1.2)
$0.0
($0.2)
.8($0 )
($0.4)
($0.6)
185
PACIFICORP-20I7IRP CHAPTER 8 -MODELTNG RESULTS
Each of the 50 iterations applies varying stochastic shocks to loads, gas and power prices, thermal
outages and hydro inputs. Fifty iterations have been demonstrated to provide practical performance
and are sufficient to ensure convergence of stochastic draws.
COz shadow prices from SO are input into PaR to influence thermal dispatch, as required, to
achieve CPP mass cap emission limits. The resulting COz costs reported by PaR represent the
opportunity cost of the CPP, but are not real expenses, and thus they are removed in the final
PVRR reporting.
Scatter plots, shown in Figure 8.10 and Figure 8.11, present the mean PVRR of each unique
Regional Haze case portfolio on the horizontal axis and the upper-tail mean PVRR on the vertical
axis. Portfolios toward the left-bottom corner of each scatter plot contain the least-cost, least-risk
mix of resources, while portfolios toward the upper-right corner contain the highest-cost and
highest-risk mix of resources.
8.10 -Haze Scatter Plots Mass C B
Medium Gas, Mass Cap B High Gas, Mass Cap B
&il
a=
oAD
$25.0
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$24.5 $24.8
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Low Gas, Mass Cap B
u
$22.9 $23.3 523.7
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$24. r $24.5
XRef.RHl lRH2 ORH3 aRH4 RH5 trRH6
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)
$27.4
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$27.0
$26.8
$26.6
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$26.0
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Saoch.lfic Mee PVRR($ billiotr)
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,l
l
1
$22.s
With fixed costs included in the upper-tail mean, which does not change among stochastic
iterations, the mean PVRR cost and the upper-tail mean PVRR risk metrics are highly correlated.
Case RH-5 is least cost, least risk under both medium and low natural gas price scenarios. While
RH-5 is a close competitor in the high gas price scenario, RH-l provides the most favorable cost
and risk results when high natural gas prices are assumed.
186
PacrrCoRp - 2017 IRP CHAPTER 8 - MODELTNG ITESULTS
Figure 8.11 - Regional Haze Scatter Plots, Mass Cap A
Medium Gas, Mass CapA
&&
IE^.E-=EE
FV
I
$25.0
$24.8
n4.6
$24.4
$24.2
$24.0
$23.8
$23.6
x
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A
I
$23.1 $23.5 $23.8 $24.2 $24.5
Stoch
Ntic Mm PVRR(S billiotr)
XRef oRHl lRH2 ORH3 ARH4 RH5 trRH6
$24.9
High Gas, Mass CapA
&*
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+
$27.4
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$26.8
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a
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Stoch$tic Mcu PVRR(S billio!)
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$21 0
Low Gas, Mass CapA
&il
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$23.8
$23.6
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x
tr
A
Dt
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$24.3
XRef aRHt IRH2 ORH3 ARH4 RHs ORH6
With fixed costs included in the upper-tail mean, which does not change among stochastic
iterations, cost and risk are highly correlated. RH-5 is least-cost, least-risk under both medium and
low natural gas price scenarios. RH-l is least-cost, least-risk when high natural gas prices are
assumed. The degree of distribution between cases is similar to Mass Cap B.
Risk-Adjusted PVRR
Figure 8.12 shows the stochastic mean PVRR of each Regional Haze case ranked against the best
performing case in each price-emission scenario. In this view, Regional Haze case 5 (RH-5)
produces the lowest risk-adjusted PVRR in four out of the six price scenarios. The Reference Case
and case RH-6 consistently produce the highest risk-adjusted PVRR among all Regional Haze
cases.
187
PACIFICoRP_20I7IRP CHAPTER 8 -MOOSTII\IG IIESULTS
Mass Cap B
d
bD
$1,500$0
RH5
RHI
RH3
RH2
RH4
RH6
Ref
do
oz
RHI
RH3
RH5
RH4
RH2
RH6
Ref
RH5
RH2
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Ref
$s00 $r,000
$ million
Mass CapA
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b0
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$ million
$0 $s00 $1,000 $1,500
RH5
RHI
RH3
RH2
RH4
RH6
Ref
RHI
RH3
RH5
RH4
RH2
RH6
Ref
RH5
RHl
E RH2
3 RH3
RH4
RH6
Ref
8.12 - Risk-PVRR Relative to the Lowest Cost Haze Case
Average Enerry Not Served (ENS)
Figure 8.13 presents the stochastic mean average annual ENS of each Regional Haze case ranked
against the best performing case in each price-emission scenario. In this view, all cases have mean
ENS levels that are a fraction of total load (annual mean ENS ranges between 10.8 and 14.9 GWh),
signaling that all of the cases would be expected to provide reliable service. Relative to other cases,
RH-3 consistently produces the lowest mean ENS levels. The Reference Case consistently
produces the highest mean ENS levels.
188
PACIFICoRP-2017IPO CHAPTER 8 _ MODELTNG RESULTS
8.13 - Stochastic Mean Annual ENS Relative to the Best Case
Upper-tail Average ENS
Figure 8.14 shows the upper-tail average annual ENS of each Regional Haze case ranked against
the best performing case in each price-emission scenario. As is the case for mean ENS metrics, all
cases have upper-tail ENS levels that are a fraction of total load (upper-tail annual ENS ranges
between 30.1 and 35.8 GWh), signaling that all of the cases would be expected to provide reliable
service. Relative to other cases, RH-5 and RH-4 consistently produce the lowest upper-tail ENS
levels. RH-2 and the Reference Case consistently produce the highest upper-tail ENS levels.
0.00 0.s0 1.00 1.50 2.00 2.50 3.00
GWh
Mass Cap B
do
E
!o
RH3
RH5
RHI
RH4
RH2
RH6
Ref
RH3
RHI
RH5
RH4
RH2
RH6
Ref
d
o0
RH3
RH5
E RH2
E ruroJ
RH4
RHI
Ref
0.00 0.50 1.00 l.so 2.00 2.s0 3.00
GWh
Mass CapA
Ho
u0
E
!o2
RH3
RH5
RH4
RHI
RH2
RH6
Ref
RH3
RHI
RH5
RH4
RH2
RH6
Ref
RH3
RH5
6 RHr
E rur+J
RH2
RH6
Ref
189
PACTFICoRP_2OI7IRP CHAPTER 8 _MODELING RESULTS
8.14 - U Annual ENS Relative to the Best Case
COz Emissions
Figure 8.15 shows total COz emissions of each Regional Haze case relative to the best performing
case in each price-emission scenario. RH-2, with the earliest coal unit retirement assumptions,
consistently yields the lowest emissions among all Regional Haze cases. Case RH-5 yields
comparatively low emissions relative to most cases. Case RH-4, with the latest coal unit retirement
assumptions, consistently yields emissions that are higher than other Regional Haze cases.
0.00 1.00 2.00 3.00 4.00 s.00 6.00
GWh
Mass Cap B
do
ho
d
IJ
E
!o
RH5
RH3
RH4
RH6
RHl
Ref
RH2
RH4
RH5
RH3
RH6
RHI
Ref
RH2
RH5
RH3
E RH6
E nn+-l
RHI
Ref
RH2
Mass CapA
Io
)1'o
do
a0
RH5
RH3
RH4
RH6
RHI
Ref
RH2
0.00 1.00 4.00 s.00
RH4
RH5
RH3
RH6
RHI
Ref
RH2
RH5
RH4
6 RH3
g RH6
RHI
Ref
RH2
2.00 3.00
GWh
190
PecrrCoRp-2017IRP CHAPTER 8 _MODELTNG RESULTS
8.15 - CO2 Emissions Relative to the Best Haze Case
Shadow Prices
CPP emission limits are enforced in PaR by aCOz shadow price, which is an output from SO. The
COz shadow price represents the incremental system cost, expressed in dollars per ton, of meeting
CPP mass cap emission limit assumptions. This represents a modeling improvement relative to the
2015 IRP, where a shadow price could not be derived from SO, and therefore, not enforced when
evaluating portfolios in PaR. Exceedances under the CPP Mass Cap A and Mass Cap B scenarios
are rare (less than six percent of iterations among all cases and price curye scenarios). For the state
of Washington, the Clean Air Rule (CAR) limit is used to restrict emissions at PacifiCorp's
Chehalis plant, the only fossil-fired resource PacifiCorp owns in the state. Washington CAR
exceedances occur in greater frequency and volume relative to the CPP; however, CAR allows for
use of emissionreductionunits (ERUs). WithoutanERUmarket, RECs canbe convertedto ERUs.
Figure 8.16 and Figure 8. 17 show the range in shadow prices, which varies among each Regional
Haze case portfolio and price-emission scenario.
IIIII
IIII
II
10,000 20,000 30,000 40,000 50,000
Thousand Tons
Mass CapA
6
b0
E
6o
a,o
0
RH2
RH5
RH3
Ref
RH6
RHI
RH4
RH2
RH5
RH3
RH6
Ref
RHl
RH4
RH2
RH5
E RH3
E nHoJ
Ref
RHI
RH4
IIIII
IIIIII
IIIII
IIII
IIII
I
Mass Cap B
6
E
o
0 40,000
6
0o
RH2
RH5
RH3
Ref
RHI
RH4
RH6
RH2
RH5
RH3
RHI
Ref
RH4
RH6
RH2
RH3
E Rer
3 RHr
RH4
RH5
RH6
10,000 20,000 30,000
Thousand Tons
191
PAcrprCoRp-2017 IRP Cuaprsn 8 -MoDELTNG RESULTS
8.16 -in CO2 Shadow Mass C B
8.17 - Ran in CO2 Shadow Mass Ca A
Shadow prices under Mass Cap B persist longer. This is because the Mass Cap B limit applies to
new combined cycle combustion turbine (CCCT) resources per the new resource compliment
interpretation of the policy. Under Mass Cap B, annual prices are influenced by timing of coal unit
retirements among cases and timing of new CCCT additions. For example, RegionalHaze case 1
(RH-l) has more coal operating in 2032whenCCCTs are added, driving the seemingly anomalous
price spike. Overall, higher gas prices, which tend to increase coal dispatch, produce higher COz
shadow prices.
Regional Haze Case Portfolio Selection
On the basis of cost-risk metrics, PacifiCorp selected Regional Haze case 5 (RH-5) as the top
performing portfolio in this phase of the portfolio selection process. However, stakeholder input
received by PacifiCorp during the public input process influenced a change to the configuration of
RH-5. To present a complete picture of the Regional Haze case final selection, this section begins
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t92
PACIFICoRP - 20 I7 IRP CFIAPTER 8 - MODELING RESULTS
with a review of the initial outcomes, followed by a full assessment of the enhancement to RH-5
and the impact this enhancement had on cost-risk metrics.
Initial Results and Conclusions
The metrics described in the cost and risk analysis are condensed into a comparative sunmary as
outlined in Table 8.1. Across the various measures, RH-5 is consistently a top performer. It should
also be emphasized that the rankings, while indicative of relative rankings among portfolios, tend
to obscure how close some of the outcomes are in terms of absolute measures (e.g., total COz
emissions).
Table 8.1 -- Risk PVRR T Portfolios Phase One
I Based on average of6 price-emissions scenarios
PaciflCorp identified case RH-5 as the top performing RegionalHaze case based on the following
observations communicated with stakeholders during the public input process:
o Case RH-5 produces the lowest risk-adjusted PVRR in four out of six price scenarios and
is among the top three cases in the other two price scenarios.
o Case RH-5 is consistently among the top performing portfolios when ranked on mean and
upper-tail ENS.
o Case RH-5 is among the top two portfolios when ranked on COz emissions in five out of
six price scenarios.o Case RH-5 produces a notably lower risk adjusted PVRR than the top performing
emissions portfolio (RH-2).
o Emission differences between cases are closely bunched in the remaining price scenario.
o Case RH-5 produces a low PVRR relative to other Regional Haze cases based on the PVRR
from SO.o Case RH-5 and RH-l are very close when evaluating the PVRR from SO, but case RH-l
only exhibits the lowest risk-adjusted PVRR in the high natural gas price scenarios when
evaluated in PaR.o Case RH-5 is a blend of Cases RH-I, RH-2, and RH-3, and is a balanced representation of
potential Regional Haze outcomes.
RiskAdlstedt ENS Scenarb Average ENS Upper TailAverage COz Embsbns
Rnk
Total CO2
Emissbns,
2017-2036
(Thousand
Tom)
Change
from
Lowest
Embsixr
PGtfoliD RankCase
PVRR
($m)
Change
from
Lowest
Cost
Porfolio
($m)Rank
Average
kmual
ENS,
2017-
2036
(GWh)
Change
from
Lowest
ENS
Porfolio Rank
Average
fumual
ENS,
2017-
2036
(GWh)
Changp
from
Lowest
ENS
Portfolb
6 786.334 27.895 4Ref26.395 $1.146 7 t4.1 2.6 7 33.7 3.3
0.4 4 31.5 l.l 5 789.172 30.732 6RHI)< 7to $0 I I t.9
12.2 0.7 5 34.7 4.2 7 758.440 0 IRH225.sM $295 4
1 1.5 0.0 I 30.6 0.1 2 7'78.734 20294 3RH325.414 $165 3
I 1.9 0.4 3 30.6 0.2 3 790.896 32.456 7RH425.157 $508 5
2 tt.7 0.3 2 30.4 0.0 I 773.115 14.676 2RH525,307 $58
6 12.4 1.0 6 3l.l 0.7 4 787.410 28.971 5RH626,r r r $862
193
PACIFICoRP_2OI7 TRP CTIAPTER 8 _ MoDELING RESULTS
Regional Haze Case 5 Enhancement
In response to stakeholder feedback, PacifiCorp performed an additional sensitivity, designated as
case RH-2a, to examine the impact of a Naughton Unit 3 retirement at year-end 2017 and a Craig
1 retirement at year-end 2025 x an alternative to the gas conversions assumed in case RH-2.
Sensitivitv RH-2a
Table 8.2 shows the impacts of the RH-2a modifications when compared to the RH-2 and RH-5
results. As compared to case RH-2, system costs are reduced when Naughton 3 and Craig I are
assumed to retire instead of converting to natural gas. These cost savings do not surpass the system
cost benefits from RH-5, and therefore do not support adopting RH-2a as the selected Regional
Haze case.
Table 8.2 - PYRR of RII-2a vs. RII-2
8.18 - Cumulative in RH-2a Resources vs. RII-2
Sensitivity RH-5a
While the RH-2a results did not suggest replacing RH-5 as the selected Regional Haze case, the
favorable impacts were sufficient to justify an additional sensitivity as a variant to case RH-5. Case
RH-5a assumes Naughton 3 continues to operate as a coal-fired facility through the end of 2018,
reflecting changes in its operating permit, and then is retired. This is a variant of case RH-5, where
Naughton 3 was assumed to cease coal-fired operation rri.2017, convert to natural gas in 2019, and
retire at the end of 2029. Table 8.3 shows the impacts of the RH-5a modifications when compared
to case RH-5.
t94
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RH-2 ($7e)($l 12)Change from
RH.5 $227 $112
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PACIFICoRP_2017IRP Crnprpn 8 -MoDELTNG RESULTS
Table 8.3 - PVRR of RII-Sa vs. RH-5
8.19 - Cumulative in RI{-Sa Resources vs. RH-5
X'inal Regional Haze Portfolio Selection
Case RH-5a yields lower costs relative to case RH-5 in all price-emission scenarios. Cost
reductions are most significant with high natural gas price assumptions. Based on these results,
PacifiCorp adopted Regional Haze compliance assumptions from case RH-5a for use in
subsequent core case and sensitivity case studies being considered for the preferred portfolio.
In summary, Regional Haze compliance assumptions coming out of case RH-5a are as follows:o No incremental selective catalytic reduction (SCR) emission control installations.o Assumed coal unit retirements (there are no natural gas conversions):o Naughton Unit 3 (Retired 2018)o Cholla Unit 4 (Retired 2020)o Craig Unit I (Retired 2025)o Dave Johnston Plant (Retired2027, end-of-life)o Jim Bridger Unit I (Retired 2028). Naughton Units 1 & 2 (Retired2029, end-of-life)o Hayden Units I & 2 (Retired 2030, end-ofJife)o Jim Bridger Unit2 (Retired 2032). Craig Untt2 (Retired 2034, end-ofJife)
Change from
RH-5 ($125)($21 ($e;($372)($s;($+:1 ($3:21
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195
PACIFICORP_20I7IRP CHAPTER 8 - MoDELING RESULTS
a Huntington Plant (Retired 2036, end-of-life)
The selected Regional Haze case becomes core case I in the following screening stage of eligible
portfolios, and serves as the basis of subsequent studies in that stage. RH-5a is therefore referred
to in following sections of this chapter as core case I with the abbreviation OP-NT3 in reference
to the change in the assumed Naughton Unit 3 retirement versus gas conversion assumptions.
Eligible Portfolio l)evelopment
Eligible portfolios are those portfolios deemed eligible to be considered for preferred portfolio
selection. The eligible set of portfolios is a combination of the six identified core cases plus a set
of select sensitivity cases. For all eligible portfolios, Regional Haze compliance assumptions are
based on Regional Haze case RH-5a (referred to as OP-NT3 throughout the rest of this chapter).
The use of OP-NT3 in this IRP as the common basis for further screening stages addresses
2015 IRP stakeholder feedback recommending that cases considered for selection as the preferred
portfolio be compared among common Regional Haze assumptions. The following discussion
begins with an examination of the core cases and subsequent sensitivity cases considered for
selection as the preferred portfolio.
Core Case Portfolio Development
Core case 4 (RE-l) has been expanded in this viewto represent the additional modeling necessary
for a full examination of just-in-time physical renewable portfolio standard (RPS) compliance.
Case RE-la is modeled to show the impacts ofjust-in-time physical compliance meeting Oregon
RPS requirements. RE-lb is modeled to show the impacts of just-in-time physical compliance
meeting Washington RPS requirements. Finally, RE-lc is modeled to show the impacts ofjust-in-
time physical compliance meeting both Oregon and Washington physical RPS requirements
concurrently. Table 8.4 lists the names and key characteristics of the core cases examined in
screening stage two.
Table 8.4 - Core Cases
The following tables and figures present portfolio additions and system costs for the core cases.
Additional information is provided specific to the merits of each case, including situs-assigned
renewable additions for the renewables core cases, RE-l through RE-lc and RE-2. Detailed
Flexble
Resources Optimized
lE/o of
lncrenental
I &Rbalance
2U/o of
lncrenpntal
L&Rbalance
Optimized Optimized Optimized Optimized Optim!red
Renewable
Resources Optimized Optimized Optimized
Just-in-Time
Physical RPS
Corpliance
(oR)
Just-in-Tinp
Physical RPS
C-ompliance
(wA)
Just-in-Tirne
Physical RPS
Conpliance
(ORand WA)
Early Physical
Conpliance
Just-in-Tine
Physical RPS
Conpliance
(ORand wA)
Class I DSM
Resources Optimized Optimircd Optimized Optimized OptimiEd
5o/o of
Increrental
[.&Rbalance
Optimizd
5%o of
lncrernental
I-&Rbalance
All other
Resources Optimiad Optimi@d Optimired Optimized Optimized Optimized Optimized Optimized
196
PACIFICoRP - 20I7 IRP CHAPTER 8 -MODELING RESULTS
resource portfolio results for each core case, showing new resource capacity and changes to
existing resource capacity by year, are contained in Volume II, Appendix K (Capacity Expansion
Results Detail). Summary portfolio results are also shown in the case fact sheets presented in
Volume II, Appendix M (Case Study Fact Sheets).
Cumulative Additional Resource Capacity
Figure 8.20 through Figure 8.27 summarize the cumulative capacity of new resources and the
cumulative reduction in existing resources through 2036, as developed for the core cases in SO.
As with the Regional Haze cases, in nearly every core case the availability of PTCs drive the
addition of roughly 300 MW of renewable wind capacity in Wyoming.
8.20 - Cumulative Core Case OP-NT3
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PecrrConp-2017IRP CHAPTER 8 _ MoDELING RESULTS
Figure 8.21- Cumulative Capacity through 2036, Core Case FR-l
Figure 8.22 - Cumulative Capacity through 2036, Core Case x.R-2
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198
PACIFICoRP - 20I7 IRP CHAPTER 8 -MoDELING RESULTS
Figure 8.23 - Cumulative Capacity through 2036, Core Case RE-la
X'igure 8.24 - Cumulative Capacity through 2036, Core Case RE-lb
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PACIFICORP - 2OI7 IRP CHAPTER 8 - MoDELTNG ITESULTS
Figure 8.25 - Cumulative Capacity through 2036, Core Case RE-lc
Figure 8.26 - Cumulative Capacity through 2036, Core Case RE-2
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200
PACIFICoRP - 2017 IRP CHAPTER 8 _ MoDELTNG RESULTS
Figure 8.27 - Cumulative Capacity through 2036, Core Case DLC-I
Situs-Assigned Renewable Resources
Renewables core cases RE-la, RE-lb, RE-lc and RE-2, assume physical RPS compliance to meet
incremental requirements specific to each case, assuming system renewable resources from OP-
NT3 are retained.
Just-in-Time Compliance
In cases RE-la, RE-lb and RE-lc, additional renewables are added to physically comply with
Oregon and Washington RPS:
o REla - Oregon
o RElb - Washinglon (West Control Area renewable resources only)
o RElc - Oregon and Washington (West Control Area renewable resources for
Washington)
In each of these cases, renewable resource additions are made beginning the first year in which
there is a projected compliance shortfall fiust-in-time compliance), after accounting for the system
renewable resources included in case OP-NT3. Figure 8.28 through Figure 8.30 show the physical
resource additions needed to meet RPS requirements for just-in-time compliance in each of the
three cases (REla, RElb, and RElc). The total capacity of situs-assigned renewable resources in
Figure 8.30 (Oregon and Washington) is less than the sum of situs-assigned renewable resources
in Figure 8.28 (Oregon) and Figure 8.29 (Washington). When optimizing renewable energy targets
for both states simultaneously, SO selects a higher proportion of wind vs. solar resources. Wind
resowce capacity factors are higher than the solar resource capacity factors, based on the resource
selections from SO, and therefore, there is a reduction in total situs-assigned resource capacity in
case RE-1c when compared to the sum of situs-assigned renewable resource capacity in cases RE-
la and RE-lb.
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201
PACIFICoRP-20I7IRP CHAPTER 8 _MODELTNG RESULTS
o
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8.29 - Cumulative Situs Renewable C Core Case RE-lb RPS)
8.30 - Cumulative Situs Renewable C Core Case RE-lc R+WA Combined)
Early RPS Compliance Strategy
In the early compliance strategy, additional renewables are added to physically comply with
projected Oregon RPS beginning2}Zl (proxy for year-end2020) to meet requirements throughout
350
300
250
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150
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50
0
,$ r$"rd9 "e"r$r{P"-f ,s}rsF""rtr$ rs,"rd rs,trd}"$"-f "-r"rdt"..r'r East Wind West Wind r East Solar West Solar I Geothermal
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202
PRCITICORp - 2017 IRP CHAPTER 8 - MODELTNG RESULTS
the planning period (early compliance). This strategy tests whether the benefits of early
compliance (higher production tax credits and earlier availability of capacity to the system) make
this option competitive with other eligible portfolios. Figure 8.31 shows the renewable Oregon
situs resource additions resulting from this strategy. Washington cannot significantly benefit from
the early compliance strategy due to the comparatively restricted banking rules for RECs as applied
to the RPS requirement (one year REC persistence), and thus only Oregon RPS targets are
considered in core case RE-2.
8.31 - Cumulative Situs Renewable C Core Case RE-2
SO System Costs
SO provides a least-cost resource portfolio optimization. While preferred portfolio selection
considers PaR measures, SO results provide an additional indicator and support for the subsequent
PaR stochastic results. Among the core cases studied in SO, case OP-NT3 reports the lowest
PVRR, while flexible resource cases (cases FR-l and FR-2) report the highest PVRRs.
Figure 8.32 - System Optimizer PVRR Costs for Core Cases
$28
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Eligible Sensitivity Portfolio Development
Table 8.5 lists the names and key characteristics of the wind repower and Energy Gateway
transmission sensitivity cases considered for preferred portfolio consideration in screening stage
two. Each case is benchmarked against OP-NT3, the selected Regional Haze case which emerged
400
350
300
2s0
200
150
100
50
0
,$r$."-f ,s,t^N|r{P"NFr$!rsFr$,tr$rdt."s,t".$trd}"s*r$".,r-rS"-}'
r East Wind West Wind East Solar West Solar I Geothermal
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203
PecrprConp-2017IRP CHAPTER 8 - MoDEI-ING RESULTS
as least-cost, least-risk in screening stage one. The OP-REP case was added as a sensitivity to
evaluate, in the context of the IRP, the economic benefits of PacifiCorp's December 2016 safe-
harbor wind-turbine-generator (WTG) equipment purchase, securing the option to repower
existing wind facilities and re-qualifying the repower projects for PTC benefits over a l0-year
period. The OP-GW4 case was added to study the cumulative impacts of layering the most
favorable Energy Gateway scenario on top of the Wind Repower case. Figure 8.33 provides a high-
level map of the Energy Gateway segments under consideration.
Table 8.5 - Sensitivities Considered for the Preferred Portfolio
Sensitivity Short
Name Gateway
Wind Repower OP-REP Base
C-ateway I GWI D
Cateway 2 GW2 F
C-ateway 3 GW3 D&F
Cateway 4 GW4 D2
Cateway Repower OP-GW4 D2
re 8.33 -Gatew Transmission ansron
This map is for general reference only and reflects cunent plans.
lt may not reflect the final routes, construction sequence or exact line configuration.
WASHINGTON
MONTANA
W.1lul.
OREGON IDAHO
G ?!wAY Wr sr WYOMING
C.pt&rrcka
Ceder B+{djcr/AnttBlh.
lr
)t.ol0FFZ<|{(,U
{\loCALIFORNIA9
aNEVADA|lom o COLORADO
PacifiCorp retail service area
New transmission lines:
- 500 kV minimum voltage
- 345 kV minimum voltage
"" 230 kV minimum voltage
o Existing substation
O New substation
Sliurdt
a{u' o 'eaeuo{
ARIZONA NEW MEXICO
204
PACIFICoRP - 20I7 IRP CHAPTER 8 - MODELTNG RESULTS
Resource Capacity Impacts and PVRR Results
Figure 8.34 through Figure 8.39 summarize the resource capacity impacts of new resources and
reductions in existing resources through 2036, as developed forthe eligible sensitivity cases in SO.
As with the RegionalHaze and core cases, PTCs drive the addition of wind capacity in Wyoming.
Wind Repower (OP-REP)
PacifiCorp successfully executed WTG equipment purchases in December 2016 with General
Electric and Vestas. These safe-harbor equipment purchases support repowering of the Wyoming
wind fleet (Glenrock, Rolling Hills, Seven Mile Hill, High Plains, McFadden Ridge, and Dunlap),
the Marengo project in Washington, and the Leaning Juniper project in Oregon by the end of 2020,
enabling the projects to qualify for 100 percent of PTCs. Repowering of other projects in
PacifiCorp's fleet may be feasible (i.e., Foote Creek and Goodnoe Hills).
Repowered WTGs must meet the Intemal Revenue Service 80120 test, meaning that the retrofitted
WTG qualifies for PTCs if the fair market value of the retained property (i.e., tower and
foundation) is no more than 20 percent of the facility's total value after installation of the new
property (i.e., nacelle and blades).
Wind repowering has many benefits, including the ability to capture an additional ten years of
PTCs for the full output of each repowered facility. These savings are passed through to customers.
Modern technology and longer blade lengths increase annual energy production by * estimated
14 to 32 percent, depending upon the project. Existing foundations and towers are used, resulting
in minimal environmental impact and permitting requirements. Also, new equipment reduces
future operating costs and extends the project life by approximately ten years. The wind repower
sensitivity (OP-REP) represents the fulfillment of this significant opporlunity.
The OP-REP sensitivity assumes 905 MW of existing wind resources are repowered by the end of
2020 (Glenrock, Rolling Hills, Seven Mile Hill, High Plains, McFadden Ridge, Dunlap, Marengo,
and Leaning Juniper). The repowering of wind projects across the fleet provides significant
customer benefits in all market price and CPP scenarios.
Due to the extended life of repowered wind units, there are large known benefits extending beyond
2036 through 2050. The increased energy expected from the repowered wind facilities increases
the full output of each repowered plant over the period when the life is extended. Over the existing
life of the repowered projects, incremental annual energy production is in excess of 500 GWh.
Incremental annual energy production beyond the current existing life (ust beyond the IRP
planning horizon) exceeds 3,100 GWh. Table 8.6 presents PVRRvalues through2036 and through
2050. Capturing the benefits of the extended life increases customer benefits significantly.
However, even when truncating the value of the wind repower project at year 2036, results are
notably favorable to the benchmark non-repower case (OP-NT3).
205
System
Optimizer PaRStochastic ilftan
Nhss B ll4rss A l!&ss B
PVRR(O
CcU@enefit)
($ million)
ll&dumCos I.owCas IVftdumC*s HghGas IowCias l}ftdumGas Ingh C,as
Change from
OP-NT3 (2036)(s66)($51)($66)($ls2)($48)(s64)($143)
Change from
OP-NT3 (20s0)($412)($:+o;($387)($63e)($333)($381)($6oe)
PACIFICoRP 20IT IRP CHAPTER 8 - MODELTNG RESULTS
Table 8.6 - PVRR efit of OP-REP vs. OP-NT3
8.34 -in Res OP-REP vs. OP-NT3
Gateway 1 (GWl)
Energy Gateway I assumes the addition of Energy Gateway segment D - Windstar to Anticline
(assumed in-service date in 2022).In addition to the 300 MW of Wyoming wind in case OP-
NT3, the additional transmission enables 440 MW of Wyoming wind additions in2022.The
PVRR results indicate an overall increase to system costs, with improving benefits under high
natural gas price assumptions.
Table 8.7 - PVRR C of GWl vs. OP-NT3
""$ "^r.
.,.'9
"-ot "s,t "{P "$ "$ "*t "s,t "{l "s." .tp" "(,t "st ".+ "rS "$ "S ,{,"
.DSM rFOTs rGas,rRenewable rGasConversion Other rEarlyRehrement ,EndofLifeRehrement
O
O
600
400
200 -
(200)
(400) -
(600) -
(800) -
( r,000)
( 1.200)
( 1,400)
System
Optimizer PaRStochastic ll&an
ll&ss B Il&ss A }hss B
PVRR(O
Cct(Benefit)
($ nitlion)
Il&dlumGas IowGas Il&diumGas Egh C;as Lon,Gas I\&diumGas Itrgh Gas
Change from
OP-NT3 $541 ss60 $483 $125 $5s9 M7e $124
206
PACFICoRP_20I7IRP CHAPTER 8 -MODELNG RESULTS
8.3s -in Resources, GWl vs. OP-NT3
t
; 600
a3 4oO
! zoo
E)(J
r,200
1,000
800
1,200
r,ooo
(2oo)
(4OO)
"d9 "ds "$'" ""s "e",$ rS.rS "$ "{, "dr," "$ "$,S ,s" -..tr "{p "d} "€} "*r "*"IDSM rFOTs rca rRdwable rG6Convqsiotr .Othq lEdlyRctirem@! rEtrdoflifeRetir@cnt
Gateway 2 (GW2)
Energy Gateway 2 assumes the addition of transmission segment F - Windstar to Mona/Clover
(assumed in-service date in 2023).In addition to the 300 MW of Wyoming wind in case OP-NT3,
the additional transmission enables 440 MW of Wyoming wind additions in 2023. The PVRR
results indicate an overall increase to system costs, higher than case GWl, with improving benefits
under high natural gas price assumptions.
Table 8.8 - PVRR of GW2 vs. OP-NT3
in Resources, GW2 vs. OP-NT3
800
=x 600
6 4oo
E zoo
(.)
(2OO)
(4oo)
,"+r$"$rS"&""{tt"{P"{tr-*F"sF"&t"$re""dret-$"€}"dr"dl,""sr"dl,"
$906Change from
OP-NT3 $874 $829 M78 $904 $824 $r'.77
aDSM rFOTs rGB r RoneMble r Gc Convemion I Other rE{ly Retir@etrt r Erd of Life Retiremont
207
PACFICoRP-2OI7IRP CHAPTER 8 _ MoDELNG RESULTS
Gateway 3 (GW3)
Energy Gateway 3 assumes the addition of transmission segments D & F - Windstar to Anticline
and Aeolus to Mona/Clover (assumed in-service dates n2022 and2023,respectively). In addition
to the 300 MW of Wyoming wind in case OP-NT3, the additional transmission enables 440 MW
of Wyoming wind additions in2022 and760 MW in 2023.In2021,150 MW of Goshen wind is
eliminated. The PVRR results indicate an overall increase to system costs, higher than cases GWI
and GW2, with improving benefits under high natural gas price assumptions.
Table 8.9 - PVRR of GW3 vs. OP-NT3
Figure 8.37 - Increase(Decrease) in Resources, GW3 vs. OP-NT3
'2
a
(J
o
c,Eao
1,400
1,200
1,000
E00
600
400
200
(200)
(400)
,$ ,$. rs" ,S "ot "-sP "-sP "dF
dF ',^$,t "$ "{t" "d "S "st "dP ""tr "^+ "st "s,"rDSM IFOTS aG6 rRilewable rGcConversion rOther rEulyRetLmmt .EodoflifeRettment
Gateway 4 (GW4)
Energy Gateway 4 assumes the addition of transmission segmerfiD2 - Aeolus to Bridger/Anticline
(assumed in service year-end 2020).In addition to the 300 MW of Wyoming wind in case OP-
NT3, the additional transmission enables 900 MW of Wyoming wind additions tn202l (proxy for
year-end 2020).1n2021,150 MW of Goshen wind is eliminated. This sensitivity shows improved
economics relative to cases GWl, GW2, and GW3, with favorable benefits under high natural gas
price assumptions.
Change from
OP-NT3 $1,363 $1,453 $1,316 $724 81,452 $1,308 $726
208
PACIFICORP - 20 I7 IRP CHAPTER 8 - MODELTNG RESULTS
P\mR(O
CosU@enefft)
($ million)
System
Optimizer PaRStochastic l\&en
ll&ss B I&ss A lVlass B
ItftdumC*s LorvGas il&dumGas HghGas InwCas lVftdumGas Itrgh Gas
Change from
OP-NT3 s107 $295 s20s (s236)$29s $r99 (s234)
Table 8.10 - PVRR Cos of GW4 vs. OP-NT3
re 8.38 - Increas ecrease tn GW4 vs. OP-NT3
Gateway Repower (OP-GW4)
Considering the overwhelmingly favorable result of the Wind Repower sensitivity (OP-REP) and
the encouraging Gateway 4 results showing favorable PVRR results in the high gas price
scenarios, PacifiCorp conducted an additional Energy Gateway sensitivity. The Gateway
Repower (OP-GW4) sensitivity assumes the addition of the Aeolus to Bridger/Anticline
transmission segment D2 (assumed in service year-end 2020), as well as 905 MW of wind
repowering represented in the OP-REP Wind Repower sensitivity.
Incremental to the 300 MW of Wyoming wind in core case OP-NT3, the increased transmission
enables 900 MW of Wyoming wind additions tn 2021 (proxy for year-end 2020). Compared to
OP-NT3, 150 MW of Goshen wind is eliminated rn 2021. This sensitivity yields improved
economics relative to cases GWl, GW2, GW3, and GW4, with increasingly favorable benefits
under high natural gas price assumptions.
Table 8.ll - PVRR Cos of OP-GW4 vs. OP-NT3
PVRR(O
CcU@enefit)
($ million)
System
Optimizer PaRStochastic l\&an
ll4rss B l!&ss A Il&ss B
ll&dumGas l,owGas ll&dumGas Ingh Gas InwGas IVftdumCas Itrgh C,as
Change liom
OP-NT3 $7t s309 s20r ($3 I 5)$3 l0 $196 ($3 I o)
Change from
OP-NT3 (2050)($275)$19 ($l1e)($803)$26 ($120)($775)
E 600
.E 400
,( 2oo
-=E (200)
U (100)
(600)
(800)
".4 "$ ""$ ""'q ,s," r&t "O r6P dF rS "o" r$ """ "{F ,s,t rst rd} rd} ,e" rst "s'rDSM rFOTS tGas dRenewable rGasConversion Other tE[lyRetirement EndofLrfeRetirement
I,200
1,000
800
209
PacrnConp - 2017 IRP CFIAPTER 8 _ MoDELTNG RESULTS
8.39 -in Resources OP-GW4 vs. OP-NT3r
SO System Costs
Figure 8.40 and Figure 8.41 add sensitivities eligible for consideration to the core case results
previously presented in Figure 8.32. Among the eligible cases studied in SO, the OP-REP and OP-
GW4 cases produces the lowest system PVRRs. Cases FR-2 and GW3 report the highest system
PVRRs. The results for the OP-REP and OP-GW4 cases include benefits for the wind repower
project through 2050, accounting for the significant incremental energy benefits beyond the IRP
planning period when the life of repowered wind resources is extended. During the public input
process, PacifiCorp received feedback from stakeholders that including these long-term
incremental benefits may distort comparisons with portfolios that do not include the wind repower
project. Stakeholders requested that PacifiCorp address these concerns by including the wind
repower project as part of the RE-lc and RE-2 cases. In response to these comments, PacifiCorp
considered these additional sensitivity cases during the final portfolio screening stage.
I While Figure 8.39 is visually similar to Figure 8.38, there are differences in DSM and FOTs that are not visible at
this resolution
"d$ ,$" n$ ,S "6| rdP,S ,$ "{F """" ,$ ,e* ,"f "s," "st "-dl "dP
,$ "di ,."'
r DSM r FOTS l Gc r Renewable r Gs Convssion Othq a Eulv Retirmmt r End of Life Retirement
z
(.)
a
E
O
1,200
1,000
800
(200)
(400)
(600)
(800)
600
400
200
2t0
PACIFICoRP-20I7IRP CHAPTER 8 _MoDELING RESULTS
$28
$2s
$23
$20
$18
$15
$13
$10
$8
$5
$3
$0 oO+iNd.ooNiNOV, E E * x E iA 9: E E E elrYUUo
tro&&
Cr
r Variable Cost t Fixed Cost
8.40 -PVRR Costs for Core Cases and Sensitivities
8.41-PVRR C from OP-REP
Eligible Portfolio Cost and Risk Analysis
PaR Configuration and Metrics
The PaR portfolio ranking metrics, which include mean PVRR, upper-tail PVRR, risk-adjusted
PVRR, mean ENS, upper-tail ENS, and emissions, are fundamentally alike for each screening
stage. As in the Regional Haze screening stage, COz shadow prices from SO are input into PaR to
reduce thermal dispatch, as required, and achieve mass cap emission limits. The resulting COz
$2.0
$1.8
$1.6
$1.4
$1.2
$1.0
$0.8
$0.6
$0.4
$0.2
$0.0 EE*JD:t,i=iiXi.7.?rrttd'doooooo6
tq6il
F
2tt
PACIFICoRP-20I7IRP CHAPTER 8 _MODELTNG RESULTS
costs reported by PaR represent the opportunity cost ofthe CPP, but are not real expenses, and
thus they are removed in the final PVRR reporting.
Scatter plots present the mean PVRR of each unique core case and eligible sensitivity portfolio
on the horizontal axis, and the upper-tail mean PVRR on the vertical axis. Portfolios toward the
left-bottom corner of each scatter plot contain the least-cost, least-risk mix of resources, while
portfolios toward the upper-right corner contain the highest-cost and highest-risk mix of
resources. Figure 8.42 and
Figure 8.43 show the scatter plot results for eligible cases under both the Mass Cap A and Mass
Cap B scenarios. As observed in the Regional Haze case results, cost and risk in the upper-tail
mean are highly correlated. The OP-REP case is least-cost, least-risk under the low and medium
price scenarios, and ranks second in the high gas price scenario. OP-GW4 is least-cost, least-risk
in the high gas scenario. GW3 produces the highest cost and risk under each price-emission
scenario, with the exception of high natural gas price scenarios, where FR-2 produces the
highest- cost, highest-risk results.
8.42 -Portfolio Scatter Mass B
$22.8 $23.1 $23.5 523.8 $24.2
Stoch8aic Mcm PVRR(S billion)
.OP.NT3 IOP-REP OP.GW4 FR-I XFR-2
aRE-2 +DLCI -GWl -GW2 aGW3
Medium Gas, Mass Cap B
a
!E^CE
>=
I
D
$24.5 $24.9
x RE-lc
!GW4
s2s.2
$24.9
$24.6
t24.3
$24.0 --
$23.7
$23.4
$23. r
s27.7
921.3
$27.0
f26.6
$26.3
$25.9
$25.6
$25.2
$24 8 $2s.2 S25.6 $26.0 $26.4
Stochrstic Meu PVRR(S billiotr)
.OP.NT3 .OP-REP OP.GW4 AFR.I XFR.2
aRI-2 |DLCI -GWl -GW2 aGW3
A
High Gas, Mass Cap B
I&
!
CE
>=
=E
4
D
$26.8 $27 2
xRE.Ic
tGw4
ia
I
$22.0 $22.4 t22.8 $232 $23 6
Stochastic Meu PVRR($ billiotr)
IOP-NT] TOP-REP
^OP.GW4
FR.I XFR.2
.RE-2 +DLCI -CWl -GW2 aGW3
Low Gas, Mass Cap B
*F
a
F
I
A
E
!
$24.4
-X124.0
123.7
$24.0
xRE-lc
rGW4
$24.6
$24.3
$234 t
$23. I
$22.8
$22.5
2t2
PACTFICoRP_2OI7IRP CHAPTER 8 - MODELThIG RESULTS
8.43 -Portfolio Scatter Mass A
s25.2
t24.9
w.6
t24.3
s24.0
N23.7
t23.1
t23.t
a
x
,
df
t23.2 t23.6 324.0 W.4 $24.8
StodadcMuPvRR(t EIim)
.OP-NT} IOP.REP OP.GMI4AFR.I XFR-2
aRB-2 +DICI -Gtill -G\lrZ .@3
Medium Gas, Mass CapA
g
a
925.2
Ia
II
=I
3.q
122.8
xRE-lc
IGW4
t27.1
w.3
w.0
326.6
t26.3
$25.9
t25.6
125.2
-^
;-
A
sa.5 E25.0 U5.5 t26.0 $26.5
Sbchenic Man PVnf,(S trilllm)
.OP.NB IOP.REP AOPS'4 FR.I XFR.2
aR3-2 +DLCI -GWr -GW2 aGW3
Eigh Gas,Mass CepA
&4
LA^.E
>'ETE
t.F
s1:1.0 9t7.5
xRE-lc
tGw4
922.4 ttt.8 t23.2 t23.6 S24.0
Stochstic Mm Pvnno Dilltod)
{tOP-NT3 IOP-REP !OP€w4 AFR-I xFR-2
anE-2 +DLCI .Gtrr -G\I'2 aG\Ir3
x

Low Gas, Mass CrpA
ad
t
=
tta
N24.4w.0
124.9
t24.5
w2
xRE-lc
AGVII
€ sz.r
aw-5
t23.t
$nE
$n.4
213
PlcmrConp - 2017 IRP CHAPTER 8 -MoDELING RESULTS
Risk-Adjusted PYRR
Figure 8.44 shows the stochastic mean PVRR of each case ranked against the best performing case
in each price-emission scenario. OP-REP produces the lowest risk-adjusted PVRR in four out of
the six price scenarios. OP-GW4 produces the most favorable risk-adjusted PVRR in the high gas
price scenarios. Cases GW3 and FR-2 consistently have the highest risk-adjusted PVRR.
8.44 - Risk-PYRR Relative to the Best Case
$500 $r,ooo sr,500 $2,ooo s2,500
$ million
IVass Cap B
=
o>rt
$o
oP-G.w4
OP-REP
Gu/4
RE.2
RE-lc
6 DLC,
.9P OP-NT3
Gu/I
GW2
FR-I
GW3
FR-2
OP-REP
OP-NT3
oP-Gu/4
RE-2
RE-lc
DLCl
GW4
FR.T
G\vI
Gu/2
FR-2
GW3
OP-REP
oP-Gv/4
OP-NT3
RE-2
RE-lc
DLCT
GW4
Gv/I
FR-T
Gu/2
FR-2
GW3
I\zlass Cap A
(,
!
z
(,
FoJ
$o $3,OOO$r,ooo $2,ooo
S million
oP-G.w4
OP-REP
G.w4
RE-2
RE-lc
€ DLCI
E oP-NT3
GWl
GW2
FR.-T
G.w3
FR..2
OP-REP
OP-NT3
oP-G.w4
R.E-2
RE-1c
DLCl
G-w4
FR-T
Gw'1
GW2
FR..2
G.w3
OP-REP
oP-G.w4
OP-NT3
RE-2
RE-1c
DLCI
G.\v4
G.wr
FR-T
G.w2
FR.-2
G.w3
2t4
PACFICoRP_2017 IRP CHAPTER 8 -MoDELTNG Rssul-rs
Average Enerry Not Seryed (ENS)
Figure 8.45 presents the stochastic mean average annual ENS of each eligible case ranked against
the best performing case in each price-emission scenario. All cases have mean ENS levels that are
a fraction of total load (annual mean ENS ranges between 2.8 and 13.8 GWh). Relative to other
cases, FR-2, with incremental peaking capacity, consistently produces the lowest mean ENS levels
(between 2.8 and 3.1 GWh).
8.45 - Stochastic Mean Annual ENS Relative to the Best Case
Mass Cap A
u
oE
do
BoFI
0.0 15.05.0 10.0
GWh
FR-2
OP-REP
GW3
RE-1c
RE.2
oP-GW4
GWI
GW4
GW2
OP-NT3
FR-I
DLCl
FR-2
GW3
OP-REP
oP-GW4
GW4
RE.2
RE-lc
GWI
GW2
OP-NT3
FR.I
DLCI
FR.2
OP.REP
GW3
GW4
RE-lc
oP-GW4
RE-2
GWI
GW2
OP.NT3
FR-I
DLCl
o.o 2-o 4.0 6.0 8.0 r0.0 l2.o
Mass Cap B
Glvh
FR.2
GW3
OP.REP
GW4
RE-1cI ne-z
.:0 0P-GW4
GWI
GW2
OP.NT3
FR.I
DLCI
FR.2
GW3
OP-REP
oP-GW4
GW4
6 RE-lcE nr-zJGW1
GW2
OP.NT3
FR.I
DLCl
FR.2
OP.REP
GW3
GW4
oP-GW4
,g RE-rcg RE-2
GWI
GW2
OP.NT3
FR.1
DLCl
2t5
PacmrCoRp-2017IRP CHAPTER 8 -MoDELTNG RESULTS
Upper-tail Average Enerry Not Serued (ENS)
Figure 8.46 shows the upper-tail average annual ENS of each eligible case ranked against the
best performing case in each price-emission scenario. All cases have upper-tail ENS levels that
are a fraction of total load. As with the mean ENS metric, relative to other cases, FR-2, with
incremental peaking capacity, consistently produces very low upper-tail ENS levels.
8.46 -Annual ENS Relative to the Best Case
I:IIIIIIIII
IIIIIIIIIII
IIIIIIIIIII
10.0 15.0 20.o 25.o 30.0
GWh
Mass Cap B
u
o.o 5.0
FR.2
RE-2
oP-GW4
RE-lc
GWI
GW3
GW2
OP.REP
GW4
OP.NT3
FR-I
DLCl
FR.2
RE-2
RE-lc
GWI
- oP-GW4I cw3E cwz'l OP-REP
GW4
OP-NT3
FR-I
DLCI
FR.2
RE.2
RE-lc
GWl
oP-GW4I cw3E cw2z,OP-REP
GW4
OP.NT3
FR.I
DLCI
IrIIIIIIIII
IIIIIIIIIII
IIIIrIIIIII
10.0 15.0 20.o 25.o 30.0
Gu/h
Mass Cap A
o
o
0.0 s.0
FR.2
RE.2
oP-GW4
RE-1c
GW3
GWI
GW2
OP-REP
GW4
OP-NT3
FR-1
DLCl
FR.2
RE-2
oP-GW4
GW3
GWl5 RE-rcE cwzJOP.REP
GW4
OP-NT3
FR.I
DLCI
FR.2
RE-2
oP-GW4
GWI
GW3
6 RE-lc
E Gw22,OP-REP
GW4
OP-NT3
FR-I
DLCl
216
PACIFICoRP _ 20 17 IRP CH,APTER 8 - MODELTNG ITESULTS
COz Emissions
Figure 8.47 shows total COz emissions of each eligible case ranked against the best performing
case in each price-emission scenario. Case GW3 and OP-GW4, which contain the highest level of
renewable resources among the cases, consistently yield the lowest emissions levels. The DLC-I
case performed most favorably in the high gas price scenarios. Case OP-REP yields mid-to-high
emissions relative to other cases.
8.47 - COz Emissions Relative to the Best Case
Mass Cap A
0 40,00010,000 20,000 30,000
Thousand Tons
DLCI
FR.I
oP-GW4
RE-1c
GW3E cw44.9p FR-2
RE.2
OP-NT3
GWI
GW2
OP-REP
GW3
oP-GW4
GW4
GWI
GW26 DLCr
E RE-lcz,FR.I
RE-2
OP-REP
OP-NT3
FR-2
oP-GW4
GW3
GW4
DLCI
GWIE cw2
E RE-lcz,FR.I
RE-2
OP-NT3
OP-REP
FR-2
tIIIII
TIII
IIIIIT
-
I
Mass Cap B
EuE
0 40,o00t0,o00 20,ooo 30,000
Thousand Tons
DLCI
FR-I
RE-lc
FR-2
oP-cw4
RE.2
OP.NT3
GW4
GW3
OP-REP
GWl
GW2
GW3
oP-GW4
cw4
GWI
GW2
6 DLCIE nB-t",l FR-I
OP-REP
RE-2
OP.NT3
FR-2
oP-GW4
Gv/3
GW4
DLCI
RE-lcE cwr
E FR-lzGW2
RE-2
OP-NT3
OP-REP
FR-2
2t7
PRCIUCORP-2017IRP CHaprEn 8 - MooEr-rNG RESULTS
Eligible Portfolio Selection
The metrics described in the cost and risk analysis are condensed into Table 8.12. The OP-REP
case ranks first in the risk adjusted PVRR metric, second in the average ENS metric, eighth in the
upper-tail ENS metric, and eleventh on emissions. The rankings, while indicative of order, tend to
obscure how close some of the outcomes are in terms of raw measures (e.g., total COz emissions).
Case OP-REP performs very well in comparison to other top candidates eligible for consideration
as the preferred portfolio.
Table 8.12 -usted PVRR T Perfo Phase Two
lBased on average of6 emissions/price scenarios
PacifiCorp identified case OP-REP as the top performing case for phase two of the portfolio
selection process. This selection is based on the following observations:
Case OP-REP produces the lowest risk-adjusted PVRR in four out of six price scenarios
and is among the top two cases in the other two price scenarios.
All cases produce low ENS levels; case OP-REP is consistently among the top performing
portfolios when ranked on mean ENS.
All cases show similar levels of COz emissions; the relative differences among cases does
not warrant using the COz emissions metric to select a higher-cost, higher-risk portfolio.
Case OP-REP produces a low PVRR relative to other eligible cases based on the PVRR
from SO.
Case OP-REP and OP-GW4 are very close when evaluating the PVRR from SO, but case
OP-GW4 only exhibits the lowest risk-adjusted PVRR in the high natural gas price
scenarios when evaluated in PaR.
Final Pordolio Screening
Final Portfolio Development
In screening stages one and two, PacifiCorp evaluated nine Regional Haze cases (including the
additional RH-2a and RH-5aNaughton Unit 3 retirement sensitivities), eight core cases (including
2t8
a
o
a
o
a
Rbk Adjrstedr ENS Scenarb Averace ENS Upper Tail Averace COr Embsbns
Case
PVRR
($m)
Change
from
Lowest
Cost
Portfolb
($m)Rank
Average
Annual
ENS,
2017-
2036
(GWh)
Change
from
Lowest
ENS
Portfolb Rank
Average
Annual
ENS,
2017-
2036
(GWh)
Change
from
Lowest
ENS
Portfolb Rank
Total CO2
Embsi:ns,
2017-2036
(Thousand
Tors)
Change
from
Lowest
Embsbn
Portfolb Rank
OP-NT3 25.167 $,161 4 t2.5 9.5 l0 31.4 23.l l0 '170,651 13.323 l0
OP.REP aJ6 $0 I ll.3 E.4 2 31.0 ?2.1 E ntN 139s6 ll
OP-GW4 24,857 $ls0 )l t.5 8.5 5 30.s 22.2 3 757,32'1 0 I
FR-I 2s,695 $988 9 12.7 9.7 lt 3 1.5 23.2 il '16,344 9,017 6
17250 t2FR.2 26,358 $1.6s2 il 3.0 t, t,I 8.3 0.0 I 174,5'7'7
I 1.5 8.5 6 22.3 6 76.t54 8.827 5RE-lc 25,189 M83 5 30.5
S,l4l 3 I 1.5 8.5 7 22.0 2 '169."138 12.41 9RE.2 25,148 30.3
DLCl 2s.2ts ss09 6 13.2 10.2 t2 32.1 23.9 t2 't6t.w5 3.768 4
GWI 25.575 $869 8 l 1.6 8.6 8 30.5 4 76.789 9.461 7
GW2 2s.941 $1234 l0 12.0 9.0 9 30.9 22.6 'l 767.825 10.498 8
GW3 26.388 $ 1.681 t2 I 1.4 8.4 3 30.5 22.2 5 757.8M 479 2
G.w4 ,s rso $553 7 I1.4 8.4 4 31.2 22.9 9 759.W 2,636 3
PACIFICoRP-20I7 IRP CTLcPTen 8 - MODELTNG RESULTS
the expanded examination of RE-la, RE-lb and RE-1c), and six sensitivities eligible for preferred
portfolio consideration (OP-REP, GWl, GW2, GW3, GW4, and OP-GW4).
In the final portfolio screening stage, PacifiCorp conducted additional studies informed by the
analysis performed during the prior screening stage. The initial results for the GW4 and OP-GW4
sensitivity cases suggest there may be potential for a time-limited opportunity to align development
of Energy Gateway sub-segment D2 with wind projects that can qualify for the full value of PTCs.
In the final screening stage, PacifiCorp has quantified additional benefits reasonably expected from
the new transmission line, assessed how more current near-term assumptions for project capital
costs and wind capacity factors affect the analysis, and completed power flow and dynamic
stability analysis to refine transmission assumptions. In response to stakeholder feedback,
PacifiCorp also re-evaluated the RE-lc and RE-2 cases to include the wind repower project and
updated Energy Gateway sub-segment D2 transmission assumptions. This ensures final selection
is performed on portfolios developed with comparable assumptions as informed by analysis
completed in stage two of the screening process. Final screening portfolios receive an "FS-"
designation to indicate that they are distinct from prior screening versions of cases having the same
name. Table 8.13 summarizes the portfolios considered for final screening in the20lT IRP cycle.
Table 8.13 - Final Portfolios
Wind Repower (FS-REP) Portfolio
After completing the original OP-REP core case studies, PacifiCorp received monthly shaping
profiles for the incremental annual energy output expected for the repowered wind plants. These
updated monthly profiles, which show the increased annual production associated with installing
more modern equipment is higher during the summer months, when wind speeds are lower, than
in the winter months, when wind speeds are higher. These monthly profiles were incorporated into
the updated repower case (FS-REP) and subsequently used in all final screening portfolio studies.
Enerry Gateway 4 (FS-GW4) Portfolio
At the end of screening stage two, the preferred-portfolio-eligible Gateway studies indicated
potential for a time-limited opportunity to align the development of Energy Gateway sub-segment
D2 with wind projects that can qualiff for the full value of PTCs. During the public input process,
PacifiCorp indicated its intention to further evaluate its assumptions for case OP-GW4. Since the
last public input meeting, PacifiCorp completed power flow and dynamic stability analysis to
Flexible Resources Optimized Optimized Optimized Optimized
Renewable
Resources Optimized Optimized
Just-in-Time Physical
RPS Compliance
(OR and WA)
Early Physical
Compliance
(oR)
Class l DSM
Resources Optimized Optimized Optimized Optimized
All other Resources Optimized Optimized Optimized Optimized
Gateway 4 No Yes Yes Yes
2t9
PACIFICoRP _ 20 I7 IRP CHAPTER 8 -MoDELTNG RESULTS
support updated transmission assumptions, updated its transmission capital cost assumptions,
assessed wind cost and performance assumptions, and quantified incremental cost and benefit
drivers associated with the Energy Gateway sub-segment D2 transmission line. These updates,
summarized below, are used in PacifiCorp's final screening portfolio studies.
Enersv Gatewav Sub-Seement D2 Assumptions
Power flow and dynamic stability analysis confirmed that the Energy Gateway sub-segmentD2
transmission line can accommodate new and existing wind resource interconnections at levels at
or above those assumed in PacifiCorp's original OP-GW4 sensitivity case. This analysis further
supports an increase in the transfer capability from 650 MW, as assumed in the original sensitivity
case, to 750 MW as assumed in the updated analysis. PacifiCorp also completed a detailed review
of its assumed cost to build the new transmission line. The results of this review support reducing
the originally assumed capital cost of the transmission line by approximately $113m. The updated
transfer capability and reduced capital costs directionally improve the economics of the
transmission project.
Wind Cost and Performance Assumptions
Considering the potential to expand new wind resource capacity with addition of the transmission
line, PacifiCorp reviewed the Wyoming wind cost and performance assumptions adopted for the
2017IRP with a more detailed review of potential wind projects located in Wyoming, taking into
consideration equipment costs, interconnection costs, and potential development fees. This
analysis supports reducing nominal wind capital cost assumptions included in the original
sensitivity case of $l,834lkw by 10.7 percent to $1,6371kW. Directionally, the updated wind
capital cost assumptions improve the economics of the updated sensitivity case.
In its review of updated wind capital cost assumptions, PacifiCorp also assessed projected
Wyoming wind resource capacity factors for potential projects that might connect to the new
transmission line. This review supports reducing the 43.0 percent capacity factor assumed for
proxy Wyoming wind resources in the2017 IRP to 41.2 percent Directionally, the updated wind
capacity factor assumptions increase the cost of the updated sensitivity case.
Additional Cost/Benefit Drivers
The qualifying facility (QF) pricing methodology used in Wyoming includes two price streams-
one with and one without incremental transmission upgrades. PacifiCorp reviewed existing
qualiffing facility (QF) contracts located in constrained areas of the transmission system in
Wyoming to estimate the potential change to contract pricing that might be triggered by the new
transmission line. Directionally, accounting for changes in QF contract pricing assumptions
increases the cost of the updated sensitivity case.
A new transmission line in parallel with existing lines reduces resistance and therefore reduces
line losses. With reduced line losses, an additional 12 aMW of incremental annual energy is
expected to flow out of eastern Wyoming. The potential value of reduced line losses was calculated
using a production cost model simulation to capture the value of this energy specific to the location
on PacifiCorp's system where line loss savings would occur. Directionally, accounting for reduced
line losses improves the economics of the updated sensitivity case.
220
PACIFICORP - 20I7 IRP CHAPTER 8 -MODELTNG TTESULTS
A new transmission line also provides reliability benefits by reducing transmission de-rates
associated with outages of transmission system elements that would not occur with the addition of
the Energy Gateway sub-segment D2 line. Avoided average transmission path de-rates are
estimated at 146 MW. Incremental reliability benefits were calculated using a production cost
model simulation to capture the avoided transmission de-rates that account for estimated outage
days for affected transmission system elements. Directionally, accounting for reduced
transmission de-rates improves the economics of the updated sensitivity case.
Finally, the new transmission line is expected to provide incremental benefits in the energy
imbalance market (EIM). [n the EIM, power flows across the system are able to take advantage of
within-the-hour available transmission of the participating EIM entities due to unscheduled or
unused transmission capacity. The EIM currently includes NV Energy, Arizona Public Service
Company, Puget Sound Energy, and the California Independent System Operator Corporation.
The EIM is expected to include Idaho Power Company and Portland General Electric Company,
which provides a significant amount of transmission capacity across the west to move power more
efficiently. Due to the large number of entities in the EIM with participating transmission, there is
an ability to move additional energy from Wyoming to offset higher priced generators in the
PacifiCorp system both in the east and the west, or make a sale to an EIM participant. EIM benefits
were estimated by simulating incremental transfer capabilities from the east to the west using a
production cost simulation model, thereby capturing the incremental benefits of moving additional
energy out of Wyoming to the west. Directionally, taking into consideration the ability to move
low-cost energy from Wyoming to a larger market improves the economics of the updated
sensitivity case.
Summar.v of Updated Assumptions
Table 8.14 summarizes the incremental adjustments applied to capture the impacts of updated
assumptions on the net cost of the FS-GW4 sensitivity case.2 In aggregate, the updated analysis
reflects a net economic improvement ranging between $18lm and $209m.
Table 8.14 -Benefits
2 The increased transfer capability assumed in the updated analysis is captured in the SO and PaR simulations and
not quantified as a specific adjustment here.
4
Natural Gas Price Scenario Base Low Base Hieh Low Base Hish
Mass B Mass B Mass B Mass B Mass A Mass A Mass AClean Power PIan Scenario
$3 s3 $3 $3 $3 $3Wind QF PPA Prbe Increase $3
Wind CF Adiustment $29 s24 $28 $45 $24 s27 $45
($84)($84)(s84)($84)($84)($84)($84)Wind CapEx Adiustment
($71)($71)(s7l)($71)(s7l)($71)($71)Transmission CapEx Adiusfinent
(s22\($19)(s22\($37)(s19)($22),($36)Line Loss Value Adiustrnent
Reliabilfu Vahre Adiustment ($17)($14)($121 ($27)($14)($16)($27)
EIM Value Adiustrnent ($24)(s20)($24)($39)($20)($24)($39)
($185)($ 181)(sr86)(s209)($181)(s186)($209)Total Adiustments
22r
PACTFICoRP-2017IRP CHaprgn 8 - MoosLNG RESULTS
Renewable Enerry (FS-Rlc and X'S-Rjl) Portfolios
Based on analysis from the prior screening stage and stakeholder feedback, PacifiCorp recognized
that cases RE-lc and RE-2 should be considered for final selection when studied with comparable
wind repower and Energy Gateway assumptions. Adding the wind repowering project and
comparable Energy Gateway and new wind resources to these cases significantly reduces the base
RPS shortfall relative to RE-lc and RE-2.
Cumulative Additional Resource Capacity
Figure 8.48 through Figure 8.51 summarize the cumulative capacrty of new resources and the
cumulative reduction in existing resources through 2036, as developed for the final screening cases
in SO.
8.48 - Cumulative Final Case FS-REP
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222
PACIFICoRP _ 20I7 IRP CHAPTER 8 -MoDELTNG I{ESULTS
8.49 - Cumulative f inal Case FS-GW4
8.50 - Cumulative Final Case FS-Rlc
rII
'XIIIITTT
t- € o!\ O i N cO <. r \O r,- 0O O\ O - Ol cO $ la \Od H a C.l N C.l C{ O.l N C{ (\.l N C',1 co to cO cO cO co cOooooooooooooooooooooN N C.l cal N N N N c.l c.l a.l a'l o.l c.l O.l C.l C.l C.t C{ C.l
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rFOTs rGasI Gas Conversion tt Other
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223
PACIFICoRP_2OIT IRP Crnprgn 8 -MODELTNG RESULTS
8.51- Cumulative FinaI Case FS-Ril
SO System Costs
Figure 8.52 and Figure 8.53 report SO system PVRR results for the final screening portfolios. In
this stage of the analysis, wind repower benefits through 2050 are reported in the total PVRRs for
all four cases to account for extended operational life benefits. Among the final cases studied in
SO, FS-GW4 reports the lowest total PVRR, while case FS-REP reported the least favorable
PVRR. The SO result for FS-GW4, representing optimum resource expansion on a capacity basis
for the Gateway 4 scenario, shows a benefit $52.2m favorable compared to FS-REP.
8.52 -PVRR Costs for Final Cases
rII
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0(l)
rDSM
rRenewable
tEarly Retirement
rFOTs lGas
r Gas Conversion r Otherr End of Life Retirement
$25
$23
$20
$18
$15
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Ar
I Variable Cost I Fixed Cost
p
V)r*
o
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(Afr
224
PecHCoRp - 2017 IRP CHAPTER 8 _ MoDELTNG RESULTS
$0.0
-$ 10.0
-$40.0
-$50.0
-$60.0 o
aIl
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ol4of!
0.Eld6t!
$B
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8.s3 -PVRR C from FS-REP for Final Cases
Final Portfolio Cost and Risk Analysis
PaR Configuration and Metrics
The PaR portfolio ranking metrics, which include mean PVRR, upper-tail PVRR, risk-adjusted
PVRR, mean ENS, upper-tail ENS, and emissions, are fundamentally alike for each screening
stage. As in the previous screening stages, COz shadow prices from SO are input into PaR to affect
thermal dispatch in a way that achieves assumed CPP mass cap emission limits. The resultingCOz
costs reported by PaR represent the opporhrnity cost ofthe CPP, but are not real expenses, and
thus they are removed in the final PVRR reporting.
Scatter plots present the mean PVRR of each unique final screening portfolio on the horizontal
axis, and the upper-tail mean PVRR on the vertical axis. Portfolios toward the left-bottom comer
of each scatter plot contain the least-cost, least-risk mix of resources, while portfolios toward the
upper-right corner contain the highest-risk and highest-cost mix of resources. Figure 8.54 and
Figure 8.55 show the scatter plot results for eligible cases under both the Mass Cap A and Mass
Cap B scenarios. As observed in the previous screening stages, cost and risk metrics are highly
correlated. FS-REP is least-cost, least-risk portfolio under the low price scenario, while FS-R2 is
least least-cost, least-risk portfolio under the medium and high gas price scenarios. FS-GW4 is
second least-cost, least-risk portfolio under all scenarios. The difference in costs among the four
cases is very small.
225
I
s23.448
$23.440
$23.432
$23.424
$21.4t6
$23.408
$23.400$23.03 $23.04 $23.05 S23.06
Stochrttic Mm PVRR(S billion)
aFS REP lFS GW4 AFS Rlc
Medium Cas, Mass Cap B
AFS R2
$23.07 S23.08
ec
!
e!
>=
=E
oop
025.900
s25.800
$25.700
$25.600
$25.500
$25.400
$25.300
High Gas, Mass Cap B
.FS_REP
a
$25.50
A
s24.90$24.75
&4
Iee
E==E
t_q
$25.05 t25.20
Stochastic Mean PVRR($ billiotr)
aFS GW4 aFS Rlc
$25.35
/lFs_R2
$22.840
$22.820
$22.800
e.i-szz.'tso
!
-$zzla
$22.740
s22.720
$22.38 922.41 $22.44 $22.47 $22.50
Stochrttic M.u PVRR(S billioo)
aFS REP IFS GW4
^FS
Rlc AFS R2
I
l
a
Low Gas, Mass Cap B
&I
=Ft
$22.53
PecmrCoRp - 2017 IRP CFIAPTER 8 _MoDELTNG RESULTS
8.54 - Final Portfolio Scatter Mass B
8.55 - Final Portfolio Scatter Mass A
$23.472
$21.464
$23.456
$23.448
$23.440
$23.432
s23.424$23.058 $23.065 523.072 $21.079 $21.086
Stochrttic Mean PVRR($ billion)
aFS REP IFS GW4 ^FS RIc FS R2
Medium Gas, Mass CapA
A
$23 093
u&
>=
=4
D
$26.000
s25.870
t25.740
$25.610
$25.480
$25.350
125.220 .
124.9 t25.r $2s2 $2s.4
Sao.h8tic Meu PVRR(S billiotr)
.FS REP TFS GW4 AFS RIC FS R2
I
High Gas, Mass Cap A
I
$24.8 t25.5
&c
E^CE
>=
=E
tA
=
t22.880
$22.860
$22.840
$22.820
$22.800
$22.?80
s22.1@
a
$22.4t 522.44 $22.47 $22.50
Stochutic Mcan PVRR(S biliotr)
aFS_REP IFS_GW4 :FS_RIC
Low Gas, Mass CapA
FS-R2
$22.53 $22.s6
&c
1.9z=
=E
taD
226
PecrrCoRp-2017IRP CHAPTER 8 _ MODELNG RESULTS
Risk-Adjusted PYRR
Figure 8.56 shows the stochastic risk-adjusted PVRR of each final screening portfolio ranked
against the best performing case in each price-emission scenario. FS-REP performs the best in low
natural gas price scenarios, followed by anearly indiscemible difference between cases FS-R2 and
FS-GW4. FS-R2 produces the lowest risk-adjusted PVRR in the medium natural gas price
scenario, with a nearly indiscernible difference relative to case FS-GW4. Under high natural gas
price scenarios, FS-R2 and FS-Rlc produce slightly lower risk-adjusted PVRRs relative to FS-
GW4.
8.s6 -PVRR Relative to the Best Case
III
T
$0 sl00 $200 $300 $400 s500 $600
$ million
Mass Cap A
FS_REP
FS GW4do
Borl
FS Rlc
FS GW4
ad
C)
E(D FS Rlc
FS REP
FS_RIc
FS-R2oc,(,
o0
)J{FS GW4
FS_REP
FS R2
FS R2
$0 $100 $200 $300 $400 $s00 $600
$ million
Mass Cap B
FS_REP
FS GW4
FS Rlc
FS GW4
q
Cd(J
E
o FS_Rlc
FS_REP
FS_R2
FS Rlc
FS GW4
FS REP
FS R2
B
Fl
0c,o
o0
H
H FS_R2o
227
PACIFICORP_2OI7IRP CHAPTER 8 _ MODELING RESULTS
Average Enerry Not Served (ENS)
Figure 8.57 presents the stochastic mean average annual ENS of each final screening portfolios
relative to the best performing case in each price-emission scenario. All cases have mean ENS
levels that are a fraction of total load (annual mean ENS ranges between 2.8 and 13.8 GWh).
Relative to other cases, FS-Rlc, with additional renewables to meet RPS, consistently produces
the lowest mean ENS levels (between 0.2 and 0.5 GWh).
8.57 - Stochastic Mean Annual ENS Relative to the Best Case
0.0 0.1 0.2 0.3 0.4 0.s 0.6
Mass Cap B
FS Rlc
FS GW4
FS REP
FS Rlc
FS GW4
FS REP
FS_Rlc
FS GW4
FS-REP
F]
€o
bI)
- FSR26-
- FSR2d-o
- FSR2
GWh
0.0 0.1 0.2 0.3 0.4 0.5 0.6
Mass Cap A
FS Rlc
FS GW4
FS REP
FS_Rlc
FS-GW4
FS REP
FS Rlc
FS GW4
FS REP
GWh
BoJ
d
!c)
do
bI)
g FS_R2
FS R2
FS R2
I
228
PACIFICoRP_2OI7IRP CHAPTER 8 - MODELTNG ITESULTS
Upper-tail Average Enerry Not Served (ENS)
Figure 8.58 shows the upper-tail average annual ENS of each final screening portfolio relative to
the best performing case in each price-emission scenario. All cases have upper-tail ENS levels that
are a fraction of total load. Relative to other cases, FS-GW4 consistently produces the lowest
upper-tail ENS levels, except under high gas price scenarios.
8.s8 - U Annual ENS Relative to the Best Case
Mass Cap A
FS-GW4
6,(J
Borl FS Rlc
FS REP
FS GW4
()
q)
FS Rlc
FS REP
FS Rlc
FS GW4d
o0
FS REP
FS_R2
FS
FS
0.6 0.8
R2
R2
0.0 0.2 0.4
GWh
0.0 0.1 0.2 0.3 0.4 0.5 0.6
Mass Cap B
FS GW4
FS_Rlcct
oJ
FS REP
FS GW4
FS RlcodotC)
FS REP
FS Rlc
FS GW4o
CO
ho
FS REP
FS_R2
GWh
FS R2
FS R2
229
PacmrCoRp-2017IRP CHAPTER 8 _ MoDELTNG RESULTS
COz Emissions
Figure 8.59 shows total COz emissions of each final screening portfolio relative to the best
performing case in each price-emission scenario. Cases FS-R2 and FS-RIc consistently yield the
lowest emissions among all portfolios. Case FS-Rlc performed most favorably in the high gas
price scenarios. Case FS-REP yields higher emissions due to lower renewables relative to other
cases.
8.59 - COz Emissions Relative to Best Case
Each of these cases achieves emission goals in Oregon and Washington, which rely on 1990
emissions as a benchmark.3 For PacifiCorp's system, the 1990 emission level was approximately
3 Washington has a goal to reduce emissions to 1990 levels by 2020. Oregon has a goal to reduce emissions to ten
percent below 1990 levels by 2020.
5,000 10,000 15,000 20,000 25,000
Thousand Tons
Mass Cap B
FS Rlc
FS GW4
FS REP
FS Rlc
FS GW4
FS Rlc
FS GW4
FS R2
FS REP
FS R2
FS-R2
FS-REP
3
E@
0
o6t()
Forl
Glo€C)
5,000 10,000 15,000 20,000 25,000
Thousand Tons
Mass Cap A
FS Rlcd()
Borl
FS REP
FS-R2
6l
!o
FS GW4
FS_REp
FS GW4
FS-R2
FS REP
FS Rlc
FS_Rlc
0
FS_GW4
3oE@
FS R2
230
46.O
45.0
44.O
40.0
39.0
38.0
FS-REP FS-R1c FS-R2
47.O
FS-GW4
cl
U
43.0
42.0
PACIFICORP-20I7 IRP CHAPTER 8 -MoDELTNG RESULTS
46 million tons. As seen in Figure 8.60, all final screening portfolios show 2020 emissions that fall
well below 1990 emission levels.
8.60 - 2020 Forecast COz emissions versus 1990 Estimated Emission Levels
Final Preferred Portfolio Selection
The metrics described in the cost and risk analysis are condensed into Table 8.15. FS-R2 ranks
first in the risk adjusted PVRR metric, while FS-R1c ranks first in average ENS, and FS-GW4
ranks first in upper-tail ENS. The rankings, while indicative of order, tend to obscure how close
some of the outcomes are in terms of raw measures. The separation among the three Energy
Gateway cases on the average risk-adjusted PVRR metric is $20m, which is just 0.08 percent of
the system PVRR, suggesting that these cases are essentially equivalent. All three of the Energy
Gateway cases (FS-GW4, FS-R1c, and FS-R2) yield a risk-adjusted PVRR that is notably
favorable to the FS-REP case.
Table 8.15 -PVRR T Portfolios
Based on average of 6 emissions/price scenarios
Fuel Source Diversity
Figure 8.61 summarizes the nameplate capacity of cumulative resource selection through 2026
among the portfolios considered for final selection. This figure illustrates the similarity among the
ENS Scenarb Averaee ENS Uooer Tail Averase CO, EmbsbnsRbk Adjustedt
Rark
Average
Annual
ENS,
2017-
2036
(GWh)
Change
ftom
Lo.tilest
ENS
Portfolb Rank
Average
Annual
ENS,
2017-
n36
(GWh)
Change
from
Lowest
ENS
Portfolio RankCase
PVRR
($m)
Change
Aom
Lowest
Cost
Porfoln
($m)
TotalCO2
Embsbns,
mt1-2036
(Thousatrd
Tons)
Change
from
Lowest
Embsbn
Portrolio Rank
4 I 1.8 0.4 4FS REP 23,939 $150 30.6 0.3 4 7',70.8136 t2,720 4
sl8 2 1.7 0.3 3 30.3 0.0 I 758.774 ffi1 JFS (tV4 23,808
$20 3 I 1.4 0.0 30.3 0.0 2 758.167 0 IFS Rlc 23,810
FS R2 23;790 $0 1 l 1.6 0.2 2 30.4 0.2 3 7s8.361 194 )
23r
PACIFICORP - 20 I7 IRP CTTAPTER 8 - MoDELING RESULTS
top performing portfolios through the first ten years of the planning period, when differences
among portfolios are most likely to influence PacifiCorp's action plan. The FS-REP portfolio,
without Energy Gateway transmission, contains less wind and more front-office transactions
(FOTs). All of the Energy Gateway portfolios have nearly identical levels of energy efficiency,
FOTs, and new wind resources.
The modest difference in new wind resource additions in 2021 in the FS-R1c case (57 MW of
additional west-side wind) is driven by the Washington RPS program.a Considering banking
restrictions in the Washington RPS program, the addition of this incremental202l west-side wind
resource contributes to over-compliance for the Washington RPS later in the planning horizon
when system renewable resources located in the Washington Utilities and Transportation
Commission (WUTC) West Control Area (WCA) are added to the resource mix. In the FS-R2
case, an additional 61 MW of Idaho wind is added to the portfolio to offset a potential Oregon RPS
shortfall that would otherwise occur beyotd2034, once accounting for system renewable resources
already included in the resource mix.
8.61 -of Resources in the Resource Portfolios
Customer Rate Impacts
Figure 8.62 shows the difference in cumulative PVRR between FS-Rlc and FS-R2 relative to case
FS-GW4 under base case emissions-price assumptions. Through year 2023, FS-R2 tracks closely
with FS-GW4, while FS-RI c reports a higher, albeit relative small, and escalating cost. After 2023,
FS-R2 improves while FS-RIc continues to be unfavorable. FS-RIc sees a spike in unfavorable
PVRR in the final t'wo years, coinciding with the addition of incremental west-side wind needed
to achieve RPS requirements. Over the 2U-year study horizon, FS-R2 yields a small aggregate
cumulative benefit relative to FS-GW4 (-$7m PVRR, a 0.029 percent reduction relative to FS-
GW4). As this benefit occurs farther out the curve, it is not only small but is also more speculative.
a Under FS-RIc and FS-R2, system renewable resources in the portfolio eliminate any need for incremental
renewable resources in the front ten years ofthe planning period.
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232
PACIFICoRP - 20I7 IRP CNAPTEN 8 - MODELING IGSULTS
Figure 8.62 - Change in the Cumulative PVRR relative to FS-GW4
$12
$10
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=(,;$o
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2017 2018 2019 2020 2021 2022 2023 2024 202s 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Axis Title
-r-FS-Rlc ..r-FS-R2
Preferred Portfolio Selection
Informed by all of the analysis used to compare resource portfolios throughout the three-stage
screening process, PacifiCorp has selected case FS-GW4 as the preferred portfolio for its 2017
IRP. Pacif,rCorp's preferred portfolio selection is based on the following:
The preferred portfolio reflects Regional Haze compliance assumptions consistent with
least-cost, least-risk comparative analysis performed in the first screening stage of the
selection process.
The preferred portfolio incorporates the wind repowering project as supported by
additional core case and sensitivity analysis performed during the second screening stage
of the selection process.
The preferred portfolio includes Energy Gateway sub-segment D2, with associated
incremental new Wyoming wind resources, based on updated analysis performed during
the final screening stage ofthe selection process.
The risk-adjusted PVRR and other stochastic metrics among portfolios that include the
Energy Gateway sub-segment D2 transmission line in the final screening stage of the
planning process are closely grouped, with an average variation in the risk-adjusted PVRR
that is just 0.08 percent of the average system risk-adjusted PVRR.
o Among these cases, case FS-GW4 produces the lowest system PVRR when
analyzed in SO.
o Variations in resources among these cases within the first ten years of the planning
period would not alter PacifiCorp's2017 IRP action plan.
o Among these cases, case FS-GW4 mitigates near-term customer rate impacts
caused by Oregon and Washington state RPS programs that result in situs-assigned
costs for customers in these states.
a
a
o
a
233
PACIFICoRP - 20 I7 IRP CHAPTER 8 - MODELTNG RESULTS
The 24fi IRP Preferred Portfolio
The 2017 IRP preferred portfolio reflects a cost-conscious transition to a cleaner energy future.
Table 8.16 shows that PacifiCorp's resource needs will be met with new renewable resources,
demand side management (DSM) resources, and short-term firm market purchases (labeled as
front-office transactions or FOTs) through 2028. Over the 2)-year planning horizon, the preferred
portfolio includes 1,959 MW of new wind resources, 905 MW of upgraded ("repowered") wind
resources, 1,040 MW of new solar resources, 2,077 MW of incremental energy efficiency
resources, and 365 MW of new direct load control capacity.
Notably, PacifiCorp's analysis demonstrates that-by 2020 and with all-in economic savings for
customers-the company can add 905 MW of repowered wind resources, 1,100 MW of new wind
resources, and a new 140-mile 500 kV transmission line in Wyoming to access the new wind
resources and relieve congestion for existing capacity. The preferred portfolio also assumes
existing owned coal capacity will be reduced by 3,650 MW through the end of 2036 (including
assumed coal retirements at the end of 2036 not shown below). The first new natural gas resource
is added in2029, one year later when compared to PacifiCorp's 2015 IRP preferred portfolio,
subject to technology and IRP reassessments over the next decade.
Table 8.16 - 2017 IRP Preferred Portfolio Sum te
*Note: Energy efficiency resource capacity reflects projected maximum amual hourly energy savings, which is
similar to a nameplate rating for a supply side resource. FOTs are short-term firm market purchases delivered only
in the year shown. Reductions in existing coal and natural gas capacity are shown in the year after the assumed
year-end retirement date (909 MW of existing coal capacity is assumed to retire year-end 2036, which would be
reflected beginning 2037). Repowered wind capacity reports the amount of existing wind capacity assumed to be
repowered in the preferred portfolio.
New Renewable Resources and Transmission
Figure 8.63 reports the cumulative renewables additions across the 2\-year study horizon. The
2017 IRP preferred portfolio advances PacifiCorp's commitment to low-cost clean energy with
plans to add 1,100 MW of new Wyoming wind resources by the end of 2020. These new zero-
emission wind facilities will connect to a new 140-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). This time-sensitive project requires
that the new wind and transmission assets achieve commercial operation by the end of 2020 to
maximize PTC benefits. In addition to providing significant economic benefits for PacifiCorp's
customers, the wind and transmission project will provide extraordinary economic development
benefits to the state of Wyoming.
New Resuces
Srrmmer FOT 5rx)52t 878 807 79 916 u4 885 t.u2 978 1.040 1.575 1.575 t.566 t-575 1.575 1.575 1.575 t.575 t.539 nla
Wmter FOT 281 332 273 30'1 3t9 308 t06 247 348 351 29'l 4t?551 516 490 451 4i'7 47'7 4'19 nla
DSM - Enerw Efficrency 154 tz8 lll t22 123 ll4 118 lt8 ll2 l@ 102 96 95 96 75 65 63 63 2_077
DSM - Load Control 0 0 0 0 0 0 0 0 0 0 0 r93 t40 5 I l l 1 3 t2 365
Wind 0 o 0 o I 103 o 0 0 0 0 0 0 0 0 85 0 0 0 0 '7'71 1.959
Solar 0 0 0 0 0 0 0 0 0 0 0 11 97 0 I I8 23'1 226 48 291 t3 I 040
iieothemal 0 o 0 0 0 0 0 0 0 0 0 0 30 0 0 0 0 0 0 0 30
Nahtral Gas 0 0 0 0 0 0 0 0 0 0 0 0 200 436 0 0 6'17 0 0 0 I }l
Existim Resouces
Reduced Coal Caoacty 0 0 (280)0 (387)0 0 0 0 182)0 t'762\(354)(:157)r78)0 (359)0 (82)0 (2141
Reduced Gas Capacty 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (358)0 0 0 1358)
Reoowered Wind Caoacin 0 0 794 ltl 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 905
2017 20lE 2019 2020 2O2l 2{122 2023 2t21 2025 2026 2021 2028 2029 20J0 20Jl 20J2 2033 20.1{ 20.15 2036 Total
234
PacnrConp-2017IRP CHapTsR 8 _MODELTNG RESULTS
Beyond 2020, the preferred portfolio includes an additional 859 MW of new wind coming on
line-85 MW of Wyoming wind in 2031,and774 MW of Idaho wind n2036. New solarresource
additions totaling 1,040 MW come on-line over the 2028 to 2036 timeframe. Approximately 77
percent ofthe new solar is located inUtah (beginning 2031) and the remaining 23 percentis located
in the west side of PacifiCorp's system (beginning 2028).
8.63 - 2017IRP Preferred Portfolio - Cumulative Renewable Resources
Wind Repowering
PacifiCorp WTG equipment purchases in December 2016 preserve the option to repower existing
wind generation facilities and maximize PTC benefits for customers. Analysis performed in the
2017 IRP supports repowering 905 MW of existing wind resources by the end of 2020 and
demonstrates that this exciting project will save customers hundreds of millions of dollars. The
scope of the repowering project involves installing new nacelles and longer blades. With the
installation of modern technology and improved control systems, the repowered wind facilities
will produce more zero-emission energy for a longer period of time at reduced operating costs.
Existing towers and foundations will remain in place, resulting in minimal environmental impact
and permitting requirements.
Demand Side Management
DSM resources continue to play a key role in PacifiCorp's resource mix. Over the first ten years
of the planning horizon, accumulated acquisition of incremental energy efficiency resources meets
88 percent of forecasted load growth from2017 through 2026 (up from 86 percent in the 2015
IRP). Figure 8.64 compares total energy efficiency savings by state in the 2017 IRP preferred
portfolio relative to the 2015 IRP preferred portfolio. Decreased selection of energy efficiency
resources relative to the 2015 IRP is driven by reduced loads and reduced costs for wholesale
market power purchases and renewable resource altematives.
3,300
3,000
2,700
2,400
2,100
1,800
1,500
1,200
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F OO O\ O H GI c.| $ \n \O f-. OO 01 O H N cO $ \n \Oi H i N N c\l N (\l c\t C! c\l (\l N cA cO en cn cO c.) cOooooooooooooooooooooC.l N c! c.l N c.l N N N N N C.l N c.l N N ot ol ol ol
F=a
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235
PACIFICoRP_20I7 IRP CHepTpR 8 -MODELTNG RESULTS
Figure 8.64 - Comparison of Total Enerry Elliciency Savings between the 2017 IRP
Preferred Portfolio and the 2015IRP Preferred Portfolio
In addition to continued investment in energy efficiency programs, the preferred portfolio
identifies an increasing role for direct load control programs with total capacity reaching 365 MW
by the end of the planning period. Figure 8.65 compares total incremental direct load control
program capacity by state in the 2017 IRP preferred portfolio relative to the 2015 IRP preferred
portfolio. The significant increase in direct load control capacity and expansion of progftrms
among states is coincident with assumed coal unit retirements, signaling the importance of these
capacity-based programs in PacifiCorp's transitioning resource mix.
Figure 8.65 - Comparison of Total Direct Load Control Capacity between the 2017 IRP
Preferred Portfolio and the 2015IRP Preferred Portfolio
Wholesale Power Market Purchases
Figure 8.66 compares wholesale market firm purchases from the 2017 IRP preferred portfolio to
the market purchases included in the preferred portfolio of recent IRPs. While market conditions
for firm wholesale power purchases are favorable, reduced loads and continued investment in
energy efficiency progftrms reduce the need for wholesale power purchases relative to the 2015
IRP Update through 2027. Over this period, average annual wholesale power purchases are down
by 27 percent relative to the 2015 IRP Update and on par with wholesale power purchases
projected in the 2015 IRP. Longer term, wholesale power purchases increase coincident with
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236
PACIFICORP _ 20I7 IRP CHAPTER 8 _ MoDELING RESULTS
assumed coal unit retirements. tn this 2017 IRP, PacifiCorp has evaluated regional resource
adequacy and believes its wholesale power purchase limits are reasonable. PacifiCorp will
continue to monitor potential shortfalls in regional supply through its on-going planning process.
Figure 8.66 - Comparison of Summer Market Purchases among Recent IRPs
6q
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F
2,000
1,500
1,000
500
0
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
t2017IRP n2015IRP Update 12015 IRP
Existing Coal Resources
Supported by analysis of potential Regional Haze compliance alternatives,the20lT IRP preferred
portfolio does not include any incremental SCR equipment throughout the planning horizon.
Avoiding installation of this equipment will save customers hundreds of millions of dollars and
retain compliance-planning flexibility associated with the CPP or other potential state and federal
environmental policies. As in past IRPs, the 201 7 IRP studies a range of Regional Haze compliance
scenarios, reflecting potential bookend alternatives that consider early retirement outcomes as a
means to avoid installation of expensive SCR equipment. The individual unit-specific outcomes
assumed in the 2017 IRP preferred portfolio will ultimately be determined by on-going
rulemaking, results of litigation, and future negotiations with state and federal agencies, partner
plant owners, and other vested stakeholders. Consequently, individual unit retirements reflected in
the preferred portfolio, while reasonable for planning pu{poses, are not firm commitments for early
unit closures. Figure 8.67 summarizes coal unit retirements assumed in the preferred portfolio. By
the end of the planning horizon, PacifiCorp assumes 3,650 MW of existing coal capacity will be
retired.
Figure 8.67 - 2017IRP Preferred Portfolio Coal Unit Retirements
2
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4,000
3,500
3,000
2,s00
2,000
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0 II
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 203'.7
rNaughton (WY) rCholla (AZ) trCrarg (CO) rDave Johnston (WY) rJim Bridger (WY) trHayden (CO) rHuntington (UT)
*Note: Retired capacity is reported in the first year in which the unit is no longer available to meet surnmer coincident
peak load.
237
PACIFICoRP_20I7IRP CHAPTER 8 _MoDELTNG RESULTS
Reflecting an updated operating permit from the state of Wyoming, PacifiCorp assumes Naughton
Unit 3 retires at the end of 2018----one year later than in the 2015 IRP Update. PacifiCorp will
continue to review emerging technologies, re-assess traditional gas conversion technologies and
costs, and consider other potential altematives that could be applied to Naughton Unit 3 to allow
continued operation beyond year-end 2018 if proven to be cost effective for customers.
PacifiCorp's analysis also assumes Cholla Unit 4 retires at the end of 2020. This early closure
assumption was considered in PacifiCorp's Regional Haze compliance analysis to account for
changes in market conditions, characterized by reduced loads and wholesale power prices. As with
Naughton Unit 3, PacifiCorp will continue to analyze potential early closure scenarios for Cholla
Unit 4 as part of its on-going planning process. Longer term, the preferred portfolio reflects an
early retirement of Craig Unit I at the end of 2025, Jim Bridger Unit 1 at the end of 2028, and Jim
Bridger Unit2 at the end of 2032. Assumed end-of-life retirements include four units at the Dave
Johnston plant at the end of 2027, Naughton Units I and2 at the end of 2029, Hayden at the end
of 2030, Craig Unit 2 at the end of 2034, and two units at the Huntington plant at the end of 2036.
Natural Gas Resources
Figure 8.68 compares total new natural gas-fired resource capacity in the 2017 IRP preferred
portfolio relative to the 2015 IRP preferred portfolio. The frst natural gas resource, a 200 MW
frame simple cycle combustion turbine (SCCT), is added to the portfolio in2029----one year later
than the first natural gas resource in the 2015 IRP. The first CCCT, a 436 MW G-class 1x1, is
added to the system in 2030-two years later than the first CCCT in the 2015 IRP. In aggregate,
the20l7 IRP preferred portfolio includes 1,313 MW of new natural gas-fired capacity, a reduction
of 1,540 MW of natural gas resources relative to the 2015 IRP preferred portfolio. Reduced loads,
on-going investment in energy efficiency programs, and increased renewables reduce the need for
new natural gas resources in the 2017 IRP. Recognizing the long time horizon before the first
natural gas plant is added, PacifiCorp will continue to evaluate potential long-term supply
alternatives, including the potential penetration of energy storage, through its on-going resource
planning efforts.
Figure 8.68 - Comparison of Total New Natural Gas Resources between the 2017 IRP
Preferred Portfolio and the 2015 IRP Preferred Portfolio
3,000
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238
PecrrConp-2017IRP CHAPTER 8 -MoDELTNG RESULTS
Capacity and Energy
Figure 8.69 graphically displays how preferred portfolio resources meet PacifiCorp's capacity
needs over time. Through 2026, PacifiCorp meets its capacity needs, including a 13 percent target
planning reserve margin, through incremental acquisition of new DSM and wind resources and
through wholesale power market purchases.
8.69 -,s Needs with Preferred Portfolio Resources
Figure 8.70 and Figure 8.71 show how PacifiCorp's system energy and nameplate capacity mix is
projected to change over time. In developing these figures, purchased power is reported in
identifiable resource categories where possible. Energy mix figures are based upon base price
curve assumptions. Renewable capacity and generation reflect categorization by technology type
and not disposition of renewable energy attributes for regulatory compliance requirements.s Orl an
energy basis, coal generation drops below 50 percent by 2025, falls to 38 percent by 2030, and
declines to 32 percent by the end of the planning period. On a capacity basis, coal resources drop
5The projected PacifiCorp 2017 IRP preferred portfolio'oenergy mix" is based on energy production and not resource
capability, capacity or delivered energy. All or some ofthe 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 form of renewable
energy credits or other environmental commodities; or (c) excluded from energy purchased. PacifiCorp's 2017 IRP
preferred portfolio energy mix includes owned resources and purchases from third parties.
12,500
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* Includes 13% Planning Reserves, Sales and Non-Owned Reservest* lncludes retirements, and gas repower. DSM includes both Class I and 2
Obligation + Reserves *
239
PacnrConp -2017IRP CHAPTER 8 -MoDELTNG RESULTS
to 31 percent by 2025, fall to 21 percent by 2030, and decline to 16 percent by the end of the
planning period. Reduced energy and capacity from coal is offset primarily by increased energy
and capacity from renewable resources, DSM resources, and longer-term, new natural gas
resources.
8.70 -Mix with Preferred Portfolio Resources
8.71-Mix with Preferred Portfolio Resources
Renewable Portfolio Standards
Figure 8.72 shows PacifiCorp's RPS compliance forecast for California, Oregon, and Washington
after accounting for the wind repower project 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 RPS targets in PacifiCorp's western states.
Oregon RPS compliance is achieved through 2034 with the addition of repowered wind and new
renewable resources and transmission in the 2017 IRP preferred portfolio. A small increment of
annual unbundled REC purchases, labeled "Unbundled Surrendered" in Figure 8.72 below,
beginning at under 160,000 RECs in 2018 is required to achieve Oregon RPS compliance through
2036.
The California RPS compliance position is also improved by the addition of repowered wind, new
renewable resources and transmission in the20lT IRP preferred portfolio and similarly requires a
240
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2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 203s 2036
lcml rGB lHydrclcctricr. rRmemble. rclsslDsM+Intanpdbles rNewclss2DSM..r rExistingPuc.hffes rFrontoffieTmactions
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rcoal acs tHydroclecricrr tRmewable* aclssl DSM+Intmptibles rNwClN2DSMr" rExistingPuchrcs rFrontOfficcTrmrctim
PACIFICoRP _ 2OI7 IRP CHAPTER 8 _ MoDELTNG RESULTS
small amount of unbundled REC purchases under 150,000 RECs per year to achieve compliance
through the planning horizon.
Washington RPS compliance is achieved with the benefit of the repowered wind assets located in
the west side, Marengo and Leaning Juniper, new renewable resources added to the west side
beginning 2028, and unbundled REC purchases under 200,000 RECs per year. Under current
allocation mechanisms, Washington customers do not benefit from the repowered wind and new
renewable resources added to the east side of PacifiCorp's system. Under an alternative allocation
mechanism, in which Washing receives its system-allocated share of repowered wind and new
wind located in Wyoming, Washington RPS targets would be met without the need for any
incremental unbundled REC purchases throughout the 2D-year planning period.
While not shown in Figure 8.72,PaciftCorp 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, new renewable resources and
transmission in the 2017IRP preferred portfolio.
24t
PACFICORP-2OI7IRP CFIAPTER 8 _ MoDELING RESULTS
X'igure 8.72 - Annual State RPS Compliance Forecast
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Carbon Dioxide Emissioms
The 2017 IRP prefened portfolio reflects 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 EIM that reduces customer
costs and maximizes use of clean energy, PacifiCorp's on-going expansion of renewable resources
242
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20t7 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
!2017IRP r2015IRP
Detailed Preferred Portfolio
Table 8.17 provides line-item detail of PacifiCorp's 2017 IRP preferred portfolio showing new
resource capacity along with changes in existing resource capacity through the 2}-year planning
horizon. Table 8.18 and Table 8.19 show line-item detail of PacifiCorp's peak load and resource
capacity balance for summer and winter (respectively) including preferred portfolio resources,
through the first ten years of the planning horizon.
PACIFICoRP-20I7IRP CHAPTER 8 -MoDELING RESULTS
and transmission, and RegionalHaze compliance that leverages flexibility. Figure 8.73 compares
projected annual COz emissions between the 2017 IRP and 2015 IRP preferred portfolios (as
reported by PaR). Over the first l0 years of the planning horizon, average annual COz emissions
are downby over 10.5 milliontons (21 percent) relative to the 2015 IRP. By the end ofthe planning
horizon, system COz emissions are projected to fall from 43.8 million tons in 2017 to 33.1 million
tons in 2036-areduction of 24.5 percent.
X'igure 8.73 - Comparison of COz Emission Forecasts between the 2017 IRP Preferred
Portfolio and the 2015 IRP Preferred Portfolio
243
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1t''l l11 I
'l=ll lt 't-
I -l--lull
"1"
l =l'-ll
ll-
*lu ils
1t
"t"I
I
'll t'
t"I 'll l
tl l I t"
:l?
tl l tl
l tltl
I l tl
tl I tl
tl il tl
\o
L
q)LL6)
{)L
tl.
F-
(\l
ah
tr
U
(J
Ir-
6o
c!
Er
aFJ:)at!
()
ZJr!
!o2
I
oo
tr.lF
IQ
+!&
F-
N
I
d
OII
Q
PACIFICORP _ 2OI7 IRP CFTAPTER 8 _MODELTNG RESULTS
Table 8.18 - Preferred Portfolio Summer Capacity Load and Resource Balance
Calendr Yeu
Theml
Hydrceloctric
Renembh
Purchoe
Qualifying Facilities
Chss lDSM
Sale
Nonomed Reseryes
Trusfea
EBt Eisting Rerourcc!
Frctrt Offce Tmsactiotrs
Gos.Wind
Solar
Class I DSM
Other
Drst Total R6ourcB
Iaad
Distflbuted Ggneration
Risthg Resows:
Intmptible
Class 2 DSM
New Resowes:
Class 2 DSM
Erst oHigrtion
Planaing Reseres (137o)
DNtRBero
D6t OHig.tiotr + Rererc
Erlt PGilion
EBt RBGru lt[sr3in
2025 2026
6,M
103
199
249
556
373
(652)
(37)
7532
6,46
106
193
u9ffi
3B
(652)
(37')
315
7,547
n
0
o
u
0
0
0
7,547
7,W3
(51)
6,126
u3
2N
u9
689
323
(652)
QN
505
7,5t6
0
0
0
0
0
0
0
7,5t6
7,141
(n)
(l?9)
6,629
887
t87
7,516
0
t!/o
6,t26
113
ml
249
681
38
(652)
(37',)
7,544
0
0
0
0
0
0
o
7544
7,23t
(80)
5,739
l13
199
22t
672
323
(172)
(37)
3@
7,417
0
0
174
0
0
0
174
7,591
5,739
113
l9lnl6t
38
(172',
(37')
4t2
7A3O
0
0
174
0
0
0
t74
7,624
7,4m
(el)
5,739
113
l9lnl
657
323
(tT2)
<37)
424
7,454
0
0
174
0
0
0
174
7,628
7A8s
(e4)
5,739
y2
l9l
22t
603
323
(146)
(37\
485
7472
0
0
174
0
0
0
174
7,646
7,54
(eB)
5,739
y2
l9l
t2t
598
38
(146)
(37)
630
7512
0
0
174
0
0
0
174
7,645
7,61
(lo4)
5,6X
181
t2l
59.1
38
(63)
(37)
543
TArO
29
0
174
0
0
0
203
7St2
7,63
(l 12)
7,5t2
7,00E
(33)
(le5)
(66)
7,331
(86)
(le5)(le5)(le5)(le5)(le5)
(66)
(le5)
(66)
(le5)(l%)
(65)
(5lE)
6J79
907
907
768s
0
l3o/o
(le5)
(65)
(575)
6:tt4
898
898
7,612
o
l3%o
(66)(66)(66)(66)(65)
(n)
6,641
889
E89
7532
o
tT/o
(tu')
6,657
891
891
7F47
0
t!/o
(232)
6,657
891
891
7544
0
l!/o
(28e)
6,695
896
896
7,59r
o
t*/o
(343)
6,725
900
900
7,624
0
l!/o
(402)
6Jza
9@
900
7,624
o
l3o/o
(461)
6,744
w2
902
7,646
0
lT/o
Theml
Ilydrcelecric
Renembh
Purchue
Quahfying Frciities
Class I DSM
Sale
No!4rrned Reserues
Tmsfen
Frcnt Ofroe Tmsactions
Cas
\Mind
Sohr
Class I DSM
Othq
w6t PlenedRqrurcB
}vqt Totrl RBourcd
Ioad
Disintuted Getreration
Eristing Resources:
Int@ptible
Class 2 DSM
New Reso@es:
Class 2 DSM
Wst ouig.tiotr
Platrning Res erves (13olo)
lv6tR6ero
W6t Ouigrtion + Rc!ero
lyet Pcition
WBt R4cre lu.rgitr
2247
855
92
l8
r95
3
(165)
(2)
(x1'l
29s7
532
o
o
o
o
o
532
3,489
3,r59
(s)
2241
859
9l
t8m
3
(165)
(2)
(316)
29rS
552
2247
717
9t
I
2U2
3
(r65)
(2)
(506)
2,549
93l
0
0
0
0
o
93t
,,520
3,UO
(10)
zu1
806
95
I
297
(r65)
(2')
(545)
2,644
856
o
0
o
o
0
856
3504
32s
(l r)
2247
635
95
I
198
0
(16l)
(2)
(361)
2,653
u7
zu1
549
65
I
195
o
(l ro)
(2)
(413)
2J3r
971
0
0
0
0
o
971
3's02
3,310
(15)
(162)
3,099
403
403
3J02
o
tT/o
2247
a4
65
I
tE6
o
(l l0)
(2)
(42t)
2,61O
895
0
0
0
o
o
895
3,504
3,332(la
\47
648
60
I
t85
o
(80)
(2')
(4E6)
2,571
938
0
0
0
o
o
938
3,510
3,358
(le)
2247
634
60
I
184
o
(80)
(2)
(631)
2At3
I,105
o
0
0
0
0
I,105
35rE
3,3U(2\
(215)
3,t14
,lO5
405
35r8
0
l!/o
2247
651
59
I
182
o
(80)
(2)
(544)
2515
l,0G
0
0
0
0
0
1,008
3,52t
3,&5(u)
552
3,487
3,t90
(a
447
3.5Or
3,M
(13)
0
(34)
0
(34)
(63)
3,O86
,t0l
40r
3AA7
o
l3o/o
o
(34)
(33)
3,0E7
zl0l
401
3,4EE
o
rT/o
o
(34)
o
(34)
0
(34)
0
(34)
0
(34)
0
(34)
o
(34)
(e2)
3,115
&5
405
3519
o
l3o/o
(l lE)
3,101
fi3
403
3r5O4
o
lT/o
(a)
3,098
43
403
350r
o
l3o/o
( rEo)
3,101
&3
403
3J0s
0
l3o/o
( le9)
3,r06
&4
404
3,5r0
o
l!/o
(23o)
3,117
405
405
3523
0
l3o/o
Tot l R6ourc6
OHigrtion
Resere!
OHigrtion + Reserc
Sy!tcm PGiaim
R.lere Mrrgin
I 1,020
9,730
1,290
ll,o20
0
l3o/o
11,035
9,743
r292
I r,035
o
l!/o
I 1,035
9,743
r2E)
11,035
o
tT/o
tt,o52
9,758
1,294
lt,o52
o
l3o/o
n,091
9,7C3
r298
tt,g2
o
l!/o
tt,t2t;
9,8U
1,302tt,l
0
l3o/o
ll,l32
9,8D
1,303
lt,t32
o
l3o/o
ll,156
q85O
1,306
ll,156
0
l!/o
tt,2g3
9,8v2
t,3ll
tt2o3
o
l3o/o
ll,l35
9,83r
1,303
I I,135
o
t3o/o
245
PACIFICoRP_2017IRP CHAPTER 8 -MODELING RESULTS
Table 8.19 - Preferred
Thcrcl
Hydrcelectric
Renewble
PrchNe
Qualifying Frcilities
Class I DSM
Salc
Non0wned Reserves
Tmsfes
ErrtEistiog R60rc6
Frcnt Ofrce Tmsactions
Gas
Wind
Solar
Class I DSM
Other
Erst PlutrcdR$ourcc!
ENt Totd Relourccg
lrad
Distnbuted Genentbn
Existing Resowes:
IDt@ptible
Class 2 DSM
New Resowes:
Class 2 DSM
ENt oUigrtiotr
Planning Rcseres (13%)
tr st RBsrus
Eslt OHigstiotr + Rcseres
Erst Poition
EEa R6ere lt rrgitr
Winter Capacity Load and Resource Balance
qst4
7t
t9
734
a7
( r70)
(37)
lm
8,057
0
0
0
0
0
o
E,Os7
5,550
(l l)
6,514
77
199
734
688
0
(r 70)
(37)n
8,(Ill
0
o
0
0
0
0
0
a,o2t
5,617
(17)
6,34
201
734
680
0
(170)
(37)
(52)
7,661
0
0
0
0
0
0
0
7,661
5,686
124',1
5,U7
72
l9t
235
668
0
(r 70)
(37)
(4)
6rE0r
0
t74
0
0
174
6975
5,770
(31 )
5,U7
12
l9l
235
658
0
(r70)
(37)
(29)
6;766
0
0
174
0
0
0
174
6940
5,U7
\32)
5,U7
'72
191
235
604
0
( 170)
(37)
( l6)
6J2s
0
0
174
0
0
0
174
6$99
5,923
(33)
5,U1
12
191
t2l
600
0
(146)
(37)
(2')
6627
0
o
t74
0
0
0
t74
5roo
5,9*
(3s)
5,U7
72
l9l
t2t
595
0
(146)
(37)
(144)
6499
0
0
174
0
0
0
174
6,673
5,919
(37)
5,7e
72
181
tzt
591
0
(63)
(37)
(r35)
6495
0
0
174
U
0
0
174
5,669
5,q24
(40)
6234
't2
l9
734
616
0
( l70)
(37)
48
7J56
( r95)
(:44)
(48)
s2s2
708
708
5p6r
2p96
53Yo
(r9s)
(44')
(r95)
(44)
( l2e)
5294
7J56
5,591
(?J)
( re5)
(44)
(le5)
(:44')
( les)
(44\
( le5)
(44)
(le5)
(253)
s323
717
7t7
(le5)
(44)
(382)
s262
7@
709
(88)
s274
7tl
7ll
s98s
2p36
52/o
1t4
7t4
( l6e)
5,161
@6
696
5,971
702
2T/o
(33e)
sJ43
7b
720
6p63
737
2T/o
(l%)
(44)
(x)
srss
721
721
6,O76
42,2
D/o
(44)
6,040
900
Wo
(42s)
s22O
7U
704
s924
745
N/o
(212)
s288
'7t3
713
6p0r
974
37/o
6p07
1,6s4
45Yo
sBsT
1,898
*/o
Theml
Hydrcelecrric
Roewble
Purchce
Qualfying Frcilnies
Class I DSM
Sale
Non-OMed Resery€s
TmsfeG
W6tEristitrg RBource
Frcnt Office Tmsactions
Gas
Wind
Solar
Class I DSM
Othq
W6t PluE€dRelurcd
WBt Totsl Rerources
lrad
Disrributed GeneEtion
Existing Resorces:
lotmptible
Class 2 DSM
New Resowes:
Class 2 DSM
WBt oUigttio!
Plaming Reswes (13%)
w6t nelcres
W6t Ouigltiu + R6crei
Wert P$ition
West Rseru l\4|rgitr
Totel 8elourccr
OHigrtion
Rcaerc
Ouigraio + R6creg
SystcD P6iaiotr
R6cre It rrgin
z3@
93
v2
6m
0,r62\
(2t
(l0l)
333s
DA
0
o
o
0
o
298
L3U
915
9l
I
tq2
0
(l62)
(2)
(28)
3J16
1<?
0
0
o
0
o
352
3,55E
3,2q
(2)
e3@
943
95
I
195
o
(r 62)
(2)
51
3,43r
2b
0
0
o
0
0
2E9
3,720
3,305
(2)
43G
7U
95
I
190
0
(154)
(2)
3
3,-27
338
0
o
.0
0
o
338
356s
3,359
(3)
(ls)
3,155
410
4r0
3565
0
r!/o
4308
7n
65
I
183
0
(l r3)
(2)
8
3r5r
3
0
0
0
0
0
326
3577
3,378
(3)
( 188)
3,t49
@
409
3,559
l9
l4o/o
13c8
783
65
I
177
0
(l l3)
(2)
l5
323'
324
0
0
0
0
0
324
355E
3,399
(4)
a30B
Tt9
@
I
176
o
(81)
(2)
2l
3,262
3U
0
o
o
0
o
304
3566
3116
(4)
2,W
7
59
I
175
0
(81)
(2)
t43
3,389
368
0
0
0
0
0
36E
3,756
3,540
(s)
(249')
3249
4'
422
3,67r
E7
l@/o
z30B
7
58
I
171
o
(81)
(2)
134
3375
372
2,38
7
95
I
191
o
( 154)
(2)
(4e)
3J35
326
3,633
3,2il
(l)
(37)
3,1EE
414
414
3,603
30
l4o/o
0
(37)
(7?)
3,lto
413
413
3593
75
rsyo
0
(37)
o
(371
0
(37)
0
(37)
0
{37)
0
(37)
0
(37)
0
(37)
0
(37)
(r07)
3,160
4ll
411
3571
149
t*/o
326
366r
3,416
(3)
(l3n
3239
42t
421
3,661
0
l3'/o
I t,416
8,.100
I,l l7
g5l8
1,898
3€/o
(210)
3,149
@
409
35sE
0
t3%
1q456
8,503
l,t3l
9,634
w.
A/o
(31)
3,141
@
409
3553
l3
l!/o
t72
3J47
3,557
(6)
(%7)
3247
4n
422
3$7O
77
ts%
I 1,690
8A4l
1,t239,fl
zt26
3{/o
I 1,688
8,453
1,124
9,s78Lrt
3A/o
I 1,381
8,4s3
1,124
9,578
1,803
35o/o
rq5l7
8,472un
9,599
919
24Yo
lq54o
4443
1,t23
9,56
9',t4
?-?/o
lq4ls
8,67
t,126
9,593
w.
Bv.
rq43l
8,511
t,132
9,43
788
BYo
10,366
a,4st
t,tD
q6l6
7fi
D/o
246
PACIFICORP-20I7 IRP CHAPTER 8 -MODELING RESULTS
In addition to the resource portfolios developed and studied as part of the three-step screening
process used to select the preferred portfolio, a number of additional sensitivity cases were
completed to better understand how certain modeling assumptions influence the resource mix and
timing of future resource additions. These sensitivity cases are useful in understanding how
PacifiCorp's resource plan would be affected by changes to uncertain planning assumptions and
to address how alternative resources and planning paradigms affect system costs and risk.
Table 8.20 lists additional sensitivity studies performed for the 2017 IRP. To isolate the impact of
a given planning assumption, each sensitivity case is compared to a benchmark, which was
established during different stages of the portfolio development and selection processes outlined
earlier in this chapter. Each benchmark case coincides with a resource portfolio developed during
the three-stage portfolio selection process adopted for the 2017 IRP. Sensitivities benchmarked to
the case labeled as "OP-1" in the table below, were performed before selecting the top performing
portfolio from the first screening stage used to.establish the 2017 IRP Regional Haze compliance
assumptions. The OP-l case is RegionalHaze case 5 (RH-5), the top performing portfolio from
the initial screening process before adopting alternative Regional Haze compliance assumptions
forNaughton Unit 3 as used in Regional Haze case 5a (which became case OP-NT3 in the second
stage of the portfolio selection process).
Table 8.20 -of Additional Cases
1-in-20 Load Growth Sensitivity (Case LD-l)
Table 8.21 shows the PVRR impacts of the LD-l sensitivity relative to case OP-1. This sensitivity
assumes l-in-20 extreme weather conditions during the summer (July) for each state. System costs
are higher due to requirements to meet additional peak load. Figure 8.74 summarizes resorrrce
portfolio impacts. Higher peak loads require more FOTs, renewables (+600 MW), DSM (+96
MW), and natural gas resources (+79 MW) by end of study period.
LD-I I in 20 Loads oP-t I in20 Base Mass Cap B Base None
oP-1 [,ow BaseLD-2 l,ow Load Mass Cap B Base None
LD.3 Hieh L,oad oP-l Hiph Base Mass Cap B Base None
oP-l BasePG-I Low Private Gen [,ow Mass Cap B Base None
PG-2 HiehPrivate Gen oP-1 Base Hish Mass Cap B Base None
CPP-C CPP Mass Cap C oP-l Base Base Mass Cap C Base None
CPP.D CPP Mass Cap D oP-l Base Base Mass Cap D Base None
FOT-I LffiedFOT oP-l Base Base Mass Cap B Restricted None
oP-l Baseco2-1 CO2 Price Base Tax, No CPP Base None
NO-C02 No COr OP-NT3 Base Base No Tax, No CPP Base None
BP Business Phn OP-NT3 Base Base Mass Cap D Base None
FS-GW4 Base BaseBatteryBattery Storage Mass Cap B Base Segnent D2
CAES CAES Storage FS-GW4 Base Base Mass Cap B Base Sesrnent D2
FS.REP BaseWCAWCA Base Mass Cap B Base None
WCA-RPS WCA RPS FS-REP Base Base Mass Cap B Base None
247
PACIFICoRP - 2OI7 IRP CHAPTER 8 - MODELTNG RESULTS
Table 8.21- PYRR of LD-lvs. OP-l
8.74 -ln LD-l vs. OP-l
Low Load Growth (Case LD-Z)
Table 8.22 shows the PVRR of the LD-2 sensitivity relative to case OP-l. The reduced
y over the 2}-year study period. Figure 8.75 summarizesloads lower system costs
portfolio impacts. FOTs are by an average of 294 MW through 2029, and increase by an
average of 109 MW with reduced gas and renewable resources. Renewable resources
end of the study period. Natural gas resource capacity is down by
y period.
are reduced by 687 MW by
597 MW by the end of the
Table 8.22 - PVRR ofLD-2 vs. OP-l
Change fiom
Case I (OP-l)$187 s2ffi
"d$ .-$"...9 "{F "{',t "{P "{F!DSM !FOT8 acas rRmcwable .Gs
,000
1,200
S 8oo
b 600
q6 400
! zoo
E(J.
(200)
(400)
,{F
"s," "{0 ,{r".uot "S ,s}."f "-di ".+ "et "s,'r Oths rEuly Rairmmt rEndof Life Rctircmat
Ctrange from
Case I (OP-l)($l,6lo)($1,771)
248
PACIFICoRP_20I7IRP CHAPTER 8 _MODELTNG RESULTS
8.75 -tn LD-2 vs. OP-l
High Load Growth Sensitivity (Case LD-3)
Table 8.23 shows the PVRR impacts of the LD-3 sensitivity relative to case OP-l. Higher loads
result in significantly increased system costs. Figure 8.76 summarizes resowce portfolio impacts.
FOTs increase by an average of 299 MW through2028 while renewable resources increase by 7l
MW in 2021 md rise to an additional 360 MW by the end of the study period. An additional 200
MW of natural gas capacity shows up in 2028, with 533 MW of additional gas-fired capacity by
2036. DSM increases by 116 MW by the end of the study period.
Table 8.23 - PYRR of LD-3 vs. OP-1
8.76 -ln LD-3 vs. OP-l
(200)
(400)
(600)
(800)
(1,000)
(1,200)
(1,400)
"d$ "^t" ro9 "S ".O "{P rS,$ "$ "-{F r$ re* "d n$ rS "S rS d r{t
"^s,"IDSM IFOTS rcas rRenewable lcasCoavdsion rOther rEdyRetimmt rEndoflifeRethement
400
200
t
E
Cct(J
s
E
U
$1,641 $1,799Change from
Case I (OP-l)
1,600
1,400
- 1,200,
E r,ooo
g 8oo
Ug 600
6E 400
E(',) 2oo
(200)
,"$ ""). ,$" "$ "$ "{0'nS n$
"sF "^"t r{il "^r. nd nd "st "{e "di "^+ "^dt "s,'IDSM rFOTs acas rRenewable rcasConversion rother rEadyRetirement rEndoflifeRetircment
249
PecmrConp-2017IRP CHAPTER 8 _ MoDELTNG RESULTS
Low Private Generation Sensitivity (Case PG-l)
Table 8.24 shows the PVRR of the PG-l sensitivity relative to case OP-l. The lower
private generation results in higher net loads increasing system costs. Figure 8.77
which are minor through 2028. Over the long-term, this sensitivitysummarizes portfolio impacts,
produces more renewable ty (883 MW) and less natural gas capacity (143 MW).
Table 8.24 - PYRR of PG-lvs. OP-l
8.77 -ln PG-lvs. OP-l
High Private Genera Sensitivity (Case PG-2)
Table 8.25 shows the PVRR of the PG-2 sensitivity relative to case OP-I. The higher
private generation decrease net load, which in turn decreases system costs. Figure
8.78 summarizes portfolio which are minor through 2028. Over the long-term, there is
more renewable capacity (l,l MW) and less natural gas-fred capacity (597 MW).
Table 8.25 - PYRR of PG-2 vs. OP-l
Ctrange from
C-ase I (OP-l)$tn $168
r,200
1,000
800
'3 600
.9g 400
oo 200
!t-
EtQ lzooy
(400)
(600)
"dS .^* "$"" "&" "$.-{P..sF
.
rDSM rFOT8 lcs rRmryable !GBr
$! -"f "{r" "$ "{r".-{F "sr" "st "d6t "{9 "d} r-dF "sr"ionvmion . Othq ! Efl:ly RctimcDt ! End of Life Rettmmt
Ctrange from
Case I (OP-l)($278)(9273)
2s0
PacnrConp-2017IRP CHAPTER 8 _MODELING RESULTS
2,000
1,500
1,000
500
(500)
(1,000)
".$ .-$." "d'" .-d," "ot."P "{P "sF "-{F "&"
.,-{s
"{r" "d "S .^d} "de "S "$ "sr .-r"
rDSM rFOTs rcss rRmewable rGm Convasim .Other lEtrlyRetirmmt rEndoflife Retirement
Ba
Qo
E
U
8.78 -ln PG-2 vs. OP-l
CPP Mass Cap C Sensitivity (Case CPP-C)
Table 8.26 shows the PVRR impacts of the CPP-C sensitivity relative to case OP-1. For the Mass
Cap C sensitivity, PacifiCorp does not receive any allocation of set-asides and the emissions cap
is assumed to only apply to existing resources. High natural gas prices put upward pressure on the
mass cap (higher coal dispatch), which increases the cost of this sensitivity relative to case OP-l
under high natural gas price scenarios. As shown in Figure 8.79, renewables increase by 7l MW
in202l, but 135 MW fewer renewables are added by 2036. Timing of natural gas resources is
accelerated by one year, but reduced by 99 MW by 2036---rombined cycles replace gas-fred
peaking resources.
Table 8.26 - PVRR of CPP-C vs. OP-l
8.79 -tn CPP-C vs. OP-l
Ctrange from
C-ase I (OP-l)$91 $s0 $69 $286 $47 $74 $471
,d$ ""t".uS ,&o "$ "dP r{P "{r,sF.*" r$ "S "{9 ""rt "$t r{} r$ o$ dt rs,'
IDSM IFOTS lcs rRmewable rGmConvmion !Othil tEdyRetil€mmt .EndoflifeRetiment
>2
8@
600
400
200
(200)
(400)
(600)
251
Case I I
Ctrange from ($70
ease/(Decr
($eD ($to1 ($320)($oe;($too;($357)
1J00
1,200
1,000
800
600
400
200
(200)
(400)
(600)
(E00)
"{F "-s," "-6c' "{r" "S
d
"st "{5t "de "s} r-$ ,sr"
'E
r
(.)
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rDSM rFOTs lcs rRencwabla rcs . Oths lEilly Retilmat rEnd oflife Retiment
PACIFICORP_20I7IRP CHAPTER 8 - MoDELnIG REsuLTs
CPP Mass Cap D (Case CPP-D)
Table 8.27 shows the PVRR of the CPP-D sensitivity relative to case OP-1. With a higher
cap to accommodate new dispatch costs are reduced, lowering system costs-most
notably with higher gas New CCCTs are assumed to be covered by the emissions cap, and
there are no set-asides. As in Figure 8.80, there are 220 MW fewer renewables added in
2021, but 443 MW renewables are added by 2036. Timing of natural gas resource
additions is altered, with a of 143 MW by 2036.
Table 8.27 - PYRR of CPP-D vs. OP-l
8.80 -rn CPP-D vs. OP-l
Limited FOT (Case FOT-I)
Table 8.28 shows the impacts of the FOT-I sensitivity to case OP-l. ln the FOT-I
sensitivity, FOTs are at Mona (300 MW) and NOB (100 MW) for both the summer and
winter seasons beginning in 1. Eliminating access to market by 400 MW increases system
costs, particularly over the -term---rconomics improve as gas prices rise, which improves the
value of incremental resource additions. As shown in Figure 8.81, new renewable
resources increase by 71 MW lun2021and increase by 905 MW by 2036. Over the study period,
DSM resources increased by 02 MW. More natural gas capacity is needed n2029, but overall
gas resource additions are
252
by 160 MW at the end of the study period.
PACIFICORP - 2017 IRP CHAPTER 8 MODELTNG RESULTS
Sptcm
Oilimizcr PaRStochaslic ll&an
l}frss B Ilhss A Il&ss B
Lm,G&s Il&dum
Cas HghGas InwCas l\&dium
Gas HghGas
PVRR(O
Costl(BenefiQ
($ million)ll&dfiumC*s
Change llom
Case I (OP-1)s169 $286 $237 $74 $282 $232 $47
Table 8.28 - PVRR Cos of FOT-I vs. OP-l
Figure 8.81 - Increase/(Decrease) in Resources, FOT-1 vs. OP-1
( r.500)
""$ ".r" "d9 "o" "$ ,{P "{P ,$ "s, "s," ,$ C" .,{F
"s,t ,st ".+ r$ "s" "st ,e"
!DSM tFOTS IGas !Renewable lGasConversion Other lEulyRetirement EndofLifeRetirement
COz Price Sensitivity (Case CO2-1)
Table 8.29 shows the PVRR impacts of the CO2-l sensitivity relative to case OP-l. When
compared to case OP-I, system costs are higher in all but the high gas price scenarios since the
value of additional renewable resources increases with higher gas prices. As summarized in Figure
8.82, additional renewable resources are added to the system, particularly in the out years when
the COz price rises above $25lton. The additional renewable resources displace natural gas
resources over the long-term. When compared to case OP-1, system costs are higher in all but the
high gas price scenarios since the value of additional renewable resources increases with higher
gas prices.
Table 8.29 - PVRR Cos of CO2-1 vs. OP-l
PVRR(O
CosU(Benefit)
($ million)
System
Oilimizer PaRStochastic ll&an
l\flass B Ilfass A llfass B
ll&dumC;as IowGas lVftdium
C,aS
HghGas IawGas IVtdium
Gas Itrgh Gas
Change from
Case I (OP-l)$928 $1,028 $862 ($368)s r,018 $830 ($3s3)
z
q
U
O
I.500
1,000
500
(s00)
.000)
253
PacrnConp-2017IRP CFIAPTER 8 _TT,TOOPTN.IC RESULTS
8.82 -
No COz Policy
assumption.
Table 8.30 - PYRR
8.83 -
tn CO2-l vs. OP-l
(Case NO-CO2)
of NO-CO2 vs. OP-NT3
tn NO-CO2 vs. OP-NT3
Table 8.30 shows the PVRR]impacts of the NO-CO2 sensitivity relative to case OP-NT3. As
requested by stakeholders, thg NO-CO2 case examines the impact of having no incremental state
or federal COz emissions polify in place throughout the 2017-2036 study period. Overall, system
costs decrease by between $[Otm (SO) and $194m (PaR). Figure 8.83 summarizes portfolio
impacts. In this study, 150 IvXW of 2021wind in Idaho is eliminated; however, the 300 MW of
wind in Wyoming included in the OP-NT3 case remains cost effective absent a COz policy
,6F ,{F r$ ,s," "d "d "d} "dP "dP "$t rdF ,s,'".$ ""t" "o9 "$ "$ dP"{tr
IDSM rFOTs rcs rRmewsble rG8 . Otha rEuly Retimat rEnd oflife Rctimmt
500
g
.:
IaaQ
tEaQ
3,500
3,000
2,500
2,000
1,500
1,000
(500)
(1,000)
(1,500)
($l6l)($l%)Ctrange from
OP-NT3
600
400
200
g
& (200)
L)g (400)
a? (600)g'
ao iaoo;
,{F ,$," "{0 -*" "d
d
"st "d{, "dr "d "Bt -'dl""^$ ,.t",s" ,S "^&t ""$? "sP r Other rEuly Retirmmt rEnd of Life RetirematrDSM IFOTS rcs .Raewable rcs
(1,000)
(1,200)
254
PACIFICoRP_20I7IRP CHAPTER 8 -MoDELTNG RESULTS
Business Plan Sensitivity (Case BP)
Table 8.31 shows the PVRR impacts of the Business Plan sensitivity relative to case OP-NT3.
System costs increase by $146m when studied in SO and $108m when analyzedusing PaR. This
sensitivity complies with Utah requirements to perform a business plan sensitivity consistent with
the Public Service Commission of Utah's order in Docket No. 15-035-04, summarized as follows:
Over the first three years, resources align with those assumed in PacifiCorp's fall2016
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.
Figure 8.84 summaizes resource portfolio impacts, showing differences associated with Naughton
Unit 3 (assumed to convert to natural gas in the business plan) offset by reduced FOTs through
2027. Longer terrr, there is a difference in the timing of new natural gas resources, renewable
resources, and FOTs.
Table 8.31 - PVRR of BP vs. OP-NT3
8.84 -ln BP vs. OP-NT3
Energy Storage Sensitivities
In the 2017 IRP, storage resources available to the models include pumped storage, compressed
air energy storage (CAES), and lithium and flow batteries. Interest in storage resources continues
to grow as these technologies advance. PacifiCorp recognizes that there are stacked benefits from
storage systems, that certain benefit categories are difficult to value with existing IRP modeling
tools, and that improving storage analytics is a priority. With this in mind, PacifiCorp continues to
explore options for modeling storage resources that are capable of capturing additional benefit
o
a
Change from
OP.NT3 $1,16 $108
1,000
500
(500)
( r,000)
(1,500)
(2,000)
"^$ "$. ,$t "S.-s.t "dP "{F "{D
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,S ,S "d} rd} rS ,$ "{i ,s,"
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IIIIIIIITTI-s
a
'5aAaQ
Eao
255
PACIFICORP _ 2OI7 IRP CHAPTER 8 -MooeI,TNc RESULTS
streams, including voltage sufport, renewable resource integration, and deferral of transmission
and distribution upgrades. Whlile the sensitivity cases conducted in the2017 IRP cycle are limited
in scope, PacifiCorp plans to leverage work being performed in its review of distribution level
studies when evaluating stora$e applications in future IRPs.
PacifiCorp currently the economics for selection of specific energy storage projects, with
a focus on distribution-level outside of the IRP process. [n this context, PacifiCorp
considered procuring an
ultimately withdrew its
procured in Utah with a
storage project in Washington under the Clean Energy Fund 2, but
A combined energy storage plus solar project is being
in-service date mid-2018. In Oregon, PacifiCorp is working to
meet the requirements of HB 2193, which will result in proposing one or more energy storage
projects in Oregon.
For the 2017 IRP, two energy storage sensitivities (battery storage and CAES) were
conducted, using updated
the energy storage studies
assumptions. The two energy storage sensitivities were based on
in Volume II, Appendix P. The energy storage studies include
analysis of benefits associate[ with ancillary services and updated prices. The battery energy
storage study also includes fofiecasted price trends.
Storaee - Battery Sensitivitv (Case Bauery)
In this sensitivity, PacifiCorp pdded an 80 MW battery storage resource rui,2021, coinciding with
the incremental addition of npw wind resources included in the preferred portfolio. Table 8.32
shows the PVRR impacts of ]the Battery sensitivity relative to the FS-GW4 case. System costs
increase by $172m (SO) and $tSt- (PaR).
Table 8.32 - PVRR of vs. FS-GW4
Figure 8.85 shows the portfolio impacts of this sensitivity relative to the FS-GW4
benchmark. The added batterJ, storage resource primarily defers FOTs through 2027.In the out
years of the planning horizon, introduction of the storage system influences timing of new
resources. Given changes to the resource mix over time, by the end of the study period, the battery
storage system results in redluced FOTs and a slight reduction in overall renewable resource
capacity.
$lslChange from
FS.GW4 $172
256
PACIFICoRP-2017IRP CHAPTER 8 - MoDELING IGSULTS
8.85 -tn vs. FS-GW4
Storage - Compressed Air Energ), Sensitivitv (Case CAES)
In this sensitivity, PacifiCorp added an 80 MW CAES resource in 2021, coinciding with the
incremental addition of new wind resources included in the preferred portfolio. Table 8.33 shows
the PVRR impacts of the CAES sensitivity relative to the FS-GW4 benchmark case. As in the
Battery sensitivity, adding the CAES resources increases system costs. Overall system costs
increase by between $131m (SO) and $110m (PaR), less of an increase than seen in the Battery
sensitivity case.
Table 8.33 - PYRR of CAES vs. FS-GW4
Figure 8.86 shows the resource portfolio impacts of this sensitivity relative to the FS-GW4
benchmark. The portfolio impacts are nearly identical to those seen in the Battery sensitivity
case. The added CAES resource primarily defers FOTs through 2027.In the out years of the
planning horizon, introduction of the storage system influences timing of new resources. Given
changes to the resource mix over time, by the end of the study period, the CAES resource results
in reduced FOTs and a slight reduction in overall renewable resource capacity.
1,000
8@
E 600
'9 +oo3Q.9 2oo!aE.ao
(200)
(400)
,d$ ".r" rs d,'"-tr "-sP ns o$ "{F "&"
#S "s,. rd nso rst od n$ n$ "^tr rs,"
rDSM tFOTs lcd tRaewable tcsConvssiotr rOther rEulyRetirement rEndoflifeRettmmt
il I
$13l $l l0Change from
FS-GW4
257
,{F
"-{,,"
.|,..$
"S rd ,$o rst.rd n$ "$ dr.-s,"
r Othtr lEdy Retimat r End of Life Retirmat
West $6,509 $6,863
West
Change from
FS-REP $1,019
PACFICORP_2017IRP
8.86 -
East/West Split
In response to the W
updated its West Control
planning forthe WCA as a
to-system basis as was done in
Split (WCA) sensitivity
Overall system costs increase
FS-REP benchmark case,
side resources.
Table 8.34 - PVRR C
Figure 8.87 shows the
eliminated from the
resources through 2032. A I
with the assumed retirement
wind is added in2036.
reliant on wholesale power
258
CHAPTER 8 _ MoDELING RESULTS
ln CAES vs. FS-GW4
(Case WCA)
Utilities and Transportation Commission (WIJTC), PacifiCorp
(WCA) sensitivity for the 2017 IRP to compare the impact of
system on a WCA-to-WCA basis, rather than on a system-
2015 IRP. Table 8.34 shows the PVRR impacts ofthe East/West
to the benchmark case, FS-REP, reported on a WCA-basis.
between $l,0l9m (SO) and $203m (PaR) when compared to the
on a WCA-basis, indicating that the WCA benefits from east-
of WCA vs. F'S-RBP
portfolio from the WCA case. When the east side of the system is
study, the WCA-system relies on FOTs and incremental DSM
G-class 436 MW natural gas CCCT is added 1n2033, coinciding
Jim Bridger Unit 2 andthe end of 2032, and 500 MW of west-side
east-side resources in the energy mix, the WCA system is heavily
purchases
PACIFICoRP-2017IRP CHAPTER 8 _ MODELING ITESIJLTS
tr- oO O\ O H (\ co $ iA \O f- € O\ O - al co s. t \OH H - C{ (\l C.t c\l C\ C{ C! (\l e{ 6l ci co ci co tl cO cOooooooooooooooooooooc.l C{ C{ Ol C.l c.l N a'.1 C.l ol c\l c\l Ol c\l N N c.l Ol C.l Ol
4
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.,
I
I()
rDSM
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rEarly Retirement
IFOTs IGas
I Gas Conversion r OtherI End of Life Retirement
8.87 - Cumulative East/West Case - WCA
PacifiCorp calculated the FOT values as a percentage of peak load over both the lO-year period
(2017-2026) and 20-year period (2017-2036) for both the WCA case and the benchmark case. This
analysis shows that WCA reliance on FOTs as a percentage of peak load is nearly double that of
the integrated system, as shown Table 8.35. This results in increased market risk exposure under
a WCA structure when compared to the integrated system. Alleviating this market risk would
require accelerating the timing for new generating resources and significantly increase the cost of
this sensitivity relative to the benchmark.
Table 8.35 - FOTs as a Percentage of Net Peak Load
EastAilest Split RPS Sensitivity (Case WCA-RPS)
In this variant of the WCA sensitivity, additional renewable resources are added to the WCA
system to achieve physical compliance with Washington RPS targets. Table 8.36 shows the PVRR
impacts of the WCA-RPS relative to the FS-REP case, reported on a WCA-basis. Overall system
costs increase by between $1,030m (SO) and $216m (PaR) when compared to the FS-REP case,
reported on a WCA-basis.
WCA 26Yo 3t%23%28%
26%3l%o 23%28%WCA.RPS
System 9%l20A r0%t4%
259
PACIFICORP_2017IRP CHAPTER 8 - MODELING RESI]LTS
West (FS-REF)$6,509 $6,863
West (WCA-RPS)$253e $7,079
Ctrange from
FS-REP $1,030 $216
Table 8.36 - PVRR of WCA-RPS vs. FS-REP
Figure 8.88 shows the resoulce portfolio from the WCA-RPS case. When the east side of the
system is eliminated from thg nlanning study and additional renewable resources are added to
achieve Washington RPS targ$ts, the WCA system relies on FOTs and incremental DSM resources
through 2020. Additional west-side wind resources are added n2021 and2022(70 MW), with an
incremental 500 MW of wind added in2036. As in the WCA sensitivity case, a lxl G-class 436
MW natural gas CCCT is ad{bd :.ll,2033, coinciding with the assumed retirement of Jim Bridger
Unrt2 and the endof 2032.
The additional renewable resources do not alleviate the reliance on FOTs described in the WCA
case, and the market risk
to the WCA-RPS case.
with such a ponfolio described for the WCA case also applies
8.88 - Cumulative EastAilest RPS Case - WCA-RPS
2015 IRP WCA Discussion
PacifiCorp conducted a W
balancing authority areas
sensitivity in the 2015 IRP that modeled separate east and west
$ ia \O f- € O\ O H C.l cO $ ra \Oc.l (\l c\ (\l N c{ ci ci cn ci ci c.t cooooooooooooooN(\INC\NNNOiIc..INNC\N
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I
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260
S-10 Separate EasVWest BAAs) in accordance with a
PacmrCoRp - 2017 IRP CHAPTER 8 - MODELING RESULTS
request from the WUTC in its 2013 IRP Acknowledgement Letter.T Results ofthis analysis showed
a need for additional resources in the west BAA during the study period. Following, in the
WUTC's 2015 IRP Acknowledgement Letter, the Commission indicated that sensitivity case S-10
did not meet its request and that cost impacts should be presented at the BAA level rather than the
system level as a means of quantiffing the benefits of system integration to the individual BAAs.8
As described earlier, PacifiCorp's2017 IRP WCA sensitivity cases compare system cost impacts
on a WCA-Io-WCA basis. Additionally, the Acknowledgement Letter discusses subsequent
analysis conducted by WUTC staff as part of the Multi-State Process for interstate cost allocations
that included staff analysis of power flows across the Company's system. Based on this analysis,
WUTC staff concluded that the west BAA is capable of meeting its peak load needs independent
of any transfers from the east BAA, and thereby concluded that the west BAA would not need to
add capacity resources as shown in the Company's S-10 analysis. The WUTC requested that the
2017 IRP repeat the analysis and that inputs consistent with the flow data used by WUTC staff be
applied, or that the Company explain why different inputs are more appropriate.
As presented in the preceding sections, in both of PacifiCorp's 2017 IRP WCA sensitivities,
additional resources are needed in the west BAA, and system costs are higher when compared to
WCA costs derived from an integrated system. The WUTC staff analysis conducted in the Multi-
State Process for interstate cost allocation was based on the scheduled delivery or receipt of energy
based on e-Tag information across PacifiCorp's system. While this analysis showed that the west
BAA is capable of meeting its peak load needs independent of any transfers from the east BAA,
WUTC staffs analysis was limited, as it did not take into account the reserve and capacity
requirements of the west BAA. Specifically, PacifiCorp must meet its load requirements both on
an energy and capacity basis, holding contingency reserves equal to three percent of generation
plus three percent of load, and regulating reserve requirements for ramping and deviations in load
and variable energy resources. There are a limited number of resources in the west BAA that can
hold contingency and regulating reserves, and in operating practice, it is common for the west
BAA to rely on the east BAA for reserves as the most economical practice.
From an operational standpoint, hydro resources are advantageous resources for carrying reserves
due to the high ramp capability of these generating units. However, due to operational limitations
such as minimum flow requirements during high run-offperiods or Endangered Species Act (ESA)
mandated flow requirements, it is not always possible to hold reserves on these hydro resources
during many hours of the year, primarily the winter and spring periods. The remaining resources
in the west BAA that can hold contingency reserves limited to the Jim Bridger coal plant, the
Hermiston gas plant, and the Chehalis gas plant. Reserves are economically held on the marginal
unit on the system while energy is provided with the least expensive resources on the system.
PacifiCorp is able to balance its reserve requirements across the east and west BAAs by holding
reserves in a manner that is most economic. For example, if the Jim Bridger coal plant is less
expense than a gas unit, but the east BAA gas units are less expensive than the west BAA gas
units, PacifiCorp will make the economic decision to displace the west BAA gas unit and hold
reserves on an east BAA gas unit while transferring energy from Jim Bridger to the east BAA and
free up capacity. It is also reasonable to transfer energy to the east BAA form the Jim Bridger coal
7 Docket tJE-120416, Pacific Power & Light Company 2013IRP Acknowledgement Letter Attachment (Nov. 25,
2013) at pages 5-6.
8 Docket IJE-140546, Pacihc Power & Light Company 2015IRP Acknowledgement Letter Attachment (Nov. 13,
2015) at pages 3-4.
26t
PecrrCoRp-20l7IRP CH,APTER 8 _MoDELTNG RESULTS
plant, due to the fact that it can only hold a limited amount of contingency reserves due to ramp
limitations, while the ability of a gas unit to hold reserves is only limited by its capacity. PacifiCorp
conducted an analysis of January 2013,the time period in WUTC staff s analysis referenced in the
2015 IRP Acknowledgement Letter, which showed the west BAA relied on the east BAA for
reserves in 58 percent of the hours, assuming a regulating requirement of 120 MW. This further
supports the importance of considering energy and capacity needs for contingency reserves and
regulating purposes when evaluating a split of the west and east BAAs.
PacifiCorp has consistently held reserves in its east BAA for the west BAA due to economics and
limited generation capacity resulting from hydro operational constraints or planned or forced
outages of west BAA gas plants. While WUTC staff s analysis accurately accounted for the
scheduled delivery and receip of energy through e-Tags across PacifiCorp's system, it was limited
and did not take into consideration capacity needs of the west and east BAAs for contingency
reserves and regulating purposes, which explains why staffls analysis appeared to be inconsistent
with PacifiCorp's WCA sensitivity case presented in the 2015 IRP.
262
PACIFICORP - 20I7 IRP CHAPTER 9 - ACTIoN PLAN AND ITESoURCE PRoCUREMENT
CHaprER 9 - AcuoN PraN AND RpsouRCE
PnOCUREMENT
Cnaprnn Hrcrrrcurs
o The 2017 IRP action plan identifies steps to be taken during the next two to four years to
deliver resources in the preferred portfolio.
o PacifiCorp's 2017 IRP action plan includes action items for renewable resources,
transmission, short-term firm market purchases (front office transactions or FOTs),
demand side management resources, and coal resources.
o The 2017 IRP acquisition path analysis provides insight on how changes in the planning
environment might influence future resource procurement activities. Key uncertainties
addressed in the acquisition path analysis include load, distributed generation, COz
emission polices, Regional Haze outcomes, and availability of purchases from the market.
o Differences betweenthe20lT IRP preferred portfolio and the 2015 IRP Update and fall
ten-year business plan portfolios are primarily driven by changes in load forecasts, the
cost for renewable resource alternatives, and other model assumption updates reflecting
changes in the planning environment.
o PacifiCorp further discusses how it can mitigate procurement delay risk, summarizes
planned procurement activities tied to the action plan, assesses trade-offs between owning
or purchasing third-party power, discusses its hedging practices, and identifies the types of
risks borne by customers and the types of risks borne by shareholders.
PacifiCorp's2017 IRP action plan identifies the steps the Company will take during the next two
to four years to deliver its preferred portfolio of resources with a focus on the front ten years of
the planning horizon. Associated with the action plan is an acquisition path analysis that
anticipates potential major regulatory actions and other trigger events during the action plan time
frame that could materially impact resource acquisition strategies.
Resources included in the 2017 IRP preferred portfolio help define the actions included in the
action plan, focusing on the size, timing and type of resources needed to meet load obligations,
and current and potential future state regulatory requirements. The preferred portfolio resource
combination was determined to be the lowest cost on a risk-adjusted basis accounting for cost,
risk, reliability, regulatory uncertainty and the long-run public interest.
The 2017 IRP action plan is based upon the latest and most accurate information available at the
time portfolios are being developed and analyzed on cost and risk metrics. PacifiCorp recognizes
that the preferred portfolio, upon which the action plan is based, is developed in an uncertain
planning environment and that resource acquisition strategies need to be regularly evaluated as
planning assumptions change.
Resource information used in the 2017 IRP, such as capital and operating costs, are based upon
recent cost and performance data. However, it is important to recognize that the resources
identified in the plan are proxy resources, which act as a guide for resource procurement and not
as a commitment. Resources evaluated as part of procurement initiatives may vary from th proxy
263
PACIFICORP.20IT IRP CHAPTER 9 - ACTIoN PLAN AND RESoURCE PROCUREI\GNT
resource identified in the plan with respect to resource type, timing, size, cost and location.
PacifiCorp recognizes the need to support and justiff resource acquisitions consistent with then-
current laws, regulatory rules and commission orders.
In addition to presenting the 2017 IRP action plan, reporting on progress in delivering the prior
action plan, and presenting the 2017 IRP acquisition path analysis, Chapter 9 covers the
following resource procurement topics:
o Procurement delays;
o IRP action plan linkage to the business plan;
o Resource procurement strategy;o Assessment of owning assets vs. purchasing power;
. Managing carbon risk for existing plants;
. Purpose ofhedging; and
o Treatment of customer and investor risks.
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PACIFICoRP _ 2OI7 IRP CHAPTER 9 _ACTION PLAN AND RESOURCE PRoCUREMENT
Resource and Compliance Strategies
PacifiCorp worked with stakeholders to define portfolio cost and risk analysis in the 2017 IRP.
This analysis reflects a combination of specific planning assumptions related to COz emission
policies, compliance under the Clean Power Plan (CPP), potential Regional Haze compliance
outcomes, state RPS compliance strategies, and DSM acquisition levels. PacifiCorp further
analyzed sensitivity cases on planning assumptions related to load forecasts, private generation
penetration levels, Energy Gateway transmission projects, and COz emission policy variants. The
array of planning assumptions that define the studies used to develop resource portfolios
provides the framework for a resource acquisition path analysis by evaluating how resource
selections are impacted by changes to planning assumptions.
Given current load expectations, portfolio modeling performed for the 2017 IRP shows the
resource acquisition path in the preferred portfolio is robust among a wide range of policy and
market conditions, particularly in the near-term, when cost-effective renewable resources that
qualiff for federal income ta>r credits, FOTs, and energy efficiency resources are consistently
selected. With regard to renewable resource acquisition, the portfolio development modeling
performed in the 2017 IRP shows that new renewable resource needs are driven economics, and
potential CPP outcomes, and over the long-term, state RPS compliance requirements. Beyond
load, the most significant driver affecting resource selection in the 2017 IRP are potential
compliance outcomes related to future Regional Haze requirements that might trigger early coal
unit retirements. COz policy uncertainty, whether related to the CPP or some other future policy
targeting electric sector emission reductions, also influences resource selections in the 2017 IRP.
For these reasons, the acquisition path analysis focuses on load trigger events and environmental
policy trigger events that would require alternative resource acquisition strategies. For each
trigger event, PacifiCorp identifies the planning scenario assumption alfecting both short-term
(20 I 7 -202 6) and lon g- term (2027 -203 6) re source strate gie s.
Acquisition Path Decision Mechanism
The Utah Commission requires that PacifiCorp provide "[a] plan of different resource acquisition
paths with a decision mechanism to select among and modify as the future unfolds."l
PacifiCorp's decision mechanism is centered on the business planning and IRP processes, which
together constitute the decision framework for making resource investrnent decisions. The IRP
models are used on a macro-level to evaluate alternative portfolios and futures as part of the IRP
process, and then on a micro-level to evaluate the economics and system benefits of individual
resources as part of the supply-side resource procurement and DSM target-setting/valuation
processes. PacifiCorp uses the IRP and business plan to serve as decision support tools that can
be used to guide prudent resource acquisition paths that maintain system reliability at a
reasonable cost. Table 9.3 summarizes PacifiCorp's 2017 IRP acquisition path analysis, which
provides insight on how changes in the planning environment might inJluence future resource
procurement activities. Changes in procurement activities driven by changes in the plmning
I Publi" Service Commission of Utah, In the Matter of Analysis of an Integrated Resource Plan for PacifiCorp,
Report and Order, Docket No. 90-2035-01. June 1992.o.28.
276
PACIFICoRP - 2017 IRP CTTapTsn 9 -ACTION PLANAND RESOURCE PROCUREIIENT
environment will ultimately be reflected in future IRPs and will be incorporated in PacifiCorp's
annual business planning process.
Table 9.3 - Near-term and Resource uisition Paths
Higher sustained
load growth
High economic
drivers and
increased demand
from industrial
customers
o lncrease acquisition of west
side FOTs
o Escalate acquisition of Class
2 DSM
o lncrease acquisition ofgas-
fired thermal resources;
accelerate acquisition of
selected thermal resource by up
to 5 years
o Balance timing ofthermal and
renewable resource acquisition
with FOTs and cost-effective
Class 2 DSM energy effrciency
resourceso Increase acquisition of Class 2
DSM
Lower sustained
load growth
Low economic
drivers suppress
load requirements
with reduced
demand from
industrial customers
r Reduce acquisition of FOTso Reduce acquisition of
re,newable resources
o Reduce and defer acquisition of
gas- fred thermal resourceso Balance timing of thermal
resource and renewable
acquisition with FOTso Reduce Class 2 DSM enerry
efficiency resources
(particularly n20291
Higher sustained
private generation
penetration levels
More aggressive
technology cost
reductions,
improved
technolory
perfomrance, and
higher electricity
retail rates
o Small reduction in
acquisition of FOTsr Continue to pursue Class 2
DSM energy efficiency
resources
o Reduce and defer acquisition of
gas-fired thermal resourceso Balance timing of thermal
resource and renewable
acquisition with FOTs and
Class 2 DSM energy efficiency
resources
Lower sustained
private generation
penefation levels
Less aggressive
technology cost
reductions, reduced
technology
perforrrance, and
lowcr electricity
retail rates
o Continue to pursue Class 2
DSM energy effrciency
resourceso Small increase in FOTs
o Accelerate acquisition ofgas-
fired thermal resources by four
years (addition rrl.2029\o Balance timing ofthermal
resources with FOTs and cost-
effective Class 2 DSMo Evaluate cost effective RPS
compliance strategies in 2033-
203 6, including ffadeoffs
between increased renewable
resource acquisition and use of
compliance flexibility
mechanisms like banking and
use ofunbundled RECs
277
PACIFICORP _ 2OI7 IRP CHAPTER 9 -ACnoN PLAN AND TTESoURCE PRoCUREMENT
The main procurement risk is an inability to procure resources in the required timeframe to meet
the least-cost, least-risk mix of resources identified in the preferred portfolio. There are various
State
implementation of
Clean Power Plan
Mass Cap
Mass Cap C orD
applied to
PacifiCorp's system
covering COz
emissions from
existing and new
fossil-fired
generation
beginning 2022
o Increasc acquisition of Class
2 DSM resouneeso Balance timing of thermal
riesource acquisition and
renewable resource
acquisition with FOTso Continue to pursue Class 2
DSM enerry efficiency
resources
o Increase acquisition of Class 2
DSM resourceso Balance timing of thermal
nesource acquisition, Class 2
DSM resource acquisition and
renewable nesource acquisition
with FOTs
New COz policy
replacing Clean
Power Plan
Fossil-fred
generation is faced
with a CO2
emissions cost
beginning n2025 at
M.75lton and
reaching $38.02lton
bv2036
o Continue to pursue Class 2
DSM enerry efficiency
resources
o Procure increased renewable
nesource n 2029, increasing
each year through 2036o Balance timing of Class 2 DSM
nesource acquisition and
renewable resource acquisition
with FOTs
No COz policy Clean Power Plan
and Washington
CAR are never
enacted; assumes no
replacement policies
are adopted
r Evaluate cost effective
renewables strategies,
including tradeoffs between
renewable relnurce
acquisition, REC purchases,
and banking strategies
o Increased acquisition of fossil-
fired assets offsetting decreased
Class 2 DSM and FOT
rresources (particularly n 2028,
concurrent with assumed Dave
Johnston unit retirements)o Balance timing ofthermal
resource acquisition with
reduced renewable, Class 2
DSM and FOT resources
Regional Haze
outcome with
varying coal
retirements and
emission controls
Potential Regional
Haze inter-temporal
and fleet trade-off
compliance scenario
with coal unit
assumptions as
defined in Regional
Haze cases I
through 4, and case
6 (see Volume I,
Chapters 7 and 8)
r Balance timing of thermal
and renewable r€source
acquisition with FOTs, cost-
effective Class 2 DSM
energy efficiency resourceso Evaluate cost eflective
renewables strategies,
including fadeoffs between
renewable resource
acquisition, REC purchases,
and bankine strateeies
o Balance timing of thermal and
renewable resource acquisition
with FOTs, cost-effective Class
2 DSM energy efficiency
nesourceso Evaluate cost effective
renewables sfrategies,
including tradeoffs between
renewable resource acquisition,
REC purchases, and banking
stratesies
Limited availability
ofFOTs
Eliminates
availability of FOTs
atNOB (100 MW)
and Mona (300
MW) beginning
2019
o Continue to pursue Class 2
DSM enerryefficiency
resources
o Strategic REC and renewable
nes<xrnce acquisition to
maintain RPS compliance,
balanced with reduced FOTs
and accelerated timing of
thermal nesource acquisitiono Increase acquisition of Class 2
DSM resource
278
PACIFICoRP-2017 IRP CHAPTER 9 _ACTIoN PLAN AND RESoURCE PRoCUREMENT
reasons why a particular proxy resource cannot be procured in the timeframe identified in the
2017 IRP. There may not be any cost-effective opportunities available through an RFP, the
successful RFP bidder may experience delays in permitting and/or default on their obligations, or
there might be a material and sudden change in the market for fuel and materials. Moreover,
there is always the risk of unforeseen environmental or other electric utility regulations that may
influence the PacifiCorp's entire resource procurement strategy.
Possible paths PacifiCorp could take in the event of a procurement delay or sudden change in
procurement need can include combinations of the following:
o In circumstances where the Company is engaged in an active RFP where a specific bidder
is unable to perform, alternative bids can be pursued.
o PacifiCorp can issue an emergency RFP for a specific resource and with specified
availability.
. PacifiCorp can seek to negotiate an accelerated delivery date of a potential resource with
the supplier/developer.
. PacifiCorp can seek to procure near-term purchased power and transmission until a
longer-term alternative is identified, acquired through customized market RFPs,
exchange transactions, brokered transactions or bi-lateral, sole source procurement.
o Accelerate acquisition timelines for direct load control programs.o Procure and install temporary generators to address some or all of the capacity needs.o Temporarily drop below the target l3 percent planning reserve margin.
. Implement load control initiatives, including calls for load curtailment via existing load
curtailment contracts.
Primary drivers in the resource differences between PacifiCorp's 2017 IRP and the 2015 IRP
Update include decreased load forecasts and lower power prices. The 2017 IRP preferred
portfolio assumes Naughton Unit 3 retires at the end of 2018, reflecting updated operating
permits, instead of the end of 2017 as assumed in the 2015 IRP Update. The 2017 IRP preferred
portfolio also assumes Cholla Unit 4 retires at the end of 2020 and Craig Unit 1 at the end of
2025.In the 2015 IRP Update, the preferred portfolio assumed Cholla Unit 4 would continue
operating through the end of 2024 and that Craig Unit I would continue operating through the
end of 2034. Finally, the 2017 IRP includes an updated DSM conservation potential assessment,
which, when combined with an updated load forecast, informs changes to DSM acquisition
targets relative to the 2015 IRP ar;d 2015 IRP Update. Other changes in the portfolio reflect
changes to renewable resource acquisition levels driven by investment in new transmission
infrastructure and availability of federal income tax incentives.
Table 9.4 compares the 2017 IRP preferred portfolio with the 2015 IRP Update portfolio for the
front ten years of the 2017 IRP planning period (2017-2026). The table shows year-by-year
capacity differences by major resource categories (yellow highlighted table).
279
PACIFICoRP - 20 17 IRP CuapTEn 9 -ACTION PLAN AND RESOURCE PROCUREMENT
Table 9.4 - Comparison of the 2017 IRP Preferred Portfolio with the 2015 IRP Update
Portfolio
2017 IRP vs 2015 IRP Update
201 7 IRP Preferred Portfolio
Clpaity(MW)
Ratoufta 2016 20t7 20la 20t9 2020 2021 7lJa2 7073 2024 ,o2s 2026
Eromrion Ootionr
Gs - CCCT
DSM - Encrh EfEc€ncr t51 128 l3 t t22 t7l lt4 il8 lt)lll
DSM-t adCoilrc
l.100
Rencw,hle - aeorh.ma
Rcnewablc - IJdlie Sohr
Rcncwable - Bimss
Sbmee - PmEd Hvdro
CAFS
Storase - O$er
Front OfiEc Trmsactioru 7il 853 l.li I t.t l5 l.t l8 I )23 I 150 t.t72 1.190 1.i29
hritfro Ilnt Cf,rnoer
aml Farb Retiri:menraonvenhn.r780\ntTl ltrl
Themal Plrnt End-of-[fc Retirements
Coal Plant Gas Convesion Addtbns
Turbme UMades
Tntrl
Study Neughton
Ralourc. Tottl!
20]1-2026
t -219
l.l 00
l.t2E
t1 491
R.torEc Tot lr
24il7-2026
t2s4)
(63)
llm
t2
(821
Rcroure Totak
aotT-1126
r.483
6l
l-l l6
1667'
at
FOT in resource total are lo-year averag€s, ed include lvnter FOTS in th€ 2017 IRP
2017 IRP Preferred Portfolio less 2015 IRP
FOT in resource total tre l0-year rverages
2015 IRP Update
Crp.cit (MW
20t6 2011 20r8 20r9 ,o20 202t 2122 ,o23 202L 2n23 20a6
Erousion Ootionr
CEs - CCC'I
DSM - Enerev Efficbncr t28 ll8 lJ6 t58 112 t.l9 155 l6l 152 ll5 ll6
DSM 39 24
Re nc\\able 'Crothemal
Stonsc - Pmmd H\drc
Stonee - CAES
Orher
Front Offre Trmsactnns m3 71{i I 094 I 246 I 201 970 I0m 993 l{0 I {t0
Erirdno rrnir Cf,rnorr
aoil F,rh Rer,r.m.nt/a6nre^h6.{?80)(3E7)
Themal Plrnt End-of-lfc Retremcnts
Coal Pldt Gos Converson AddftDns
Totrl I 01r 886 960 t -403 I 145 I t20 I 215 I 126 I I55 1 227 I 600
Saudy includes Neughton 3 gs conv€Nion in 20lS
FOT in rcsoufte totel are lo-year averages
Clprity(Mw)
2016 ,nl1 20r a 20r9 ,oao 2021 2022 ,o23 2n2t 202t 2026
Ero$ion Ootionr
DSM . Enem Efficbncr t6 (t9'(zTt (71\(21)t4t'I45)(a1 (241
DSM-ledCffi (39'(24
ttm
Rerewable - Geotheru
SbEE - PmEd Hvdft
.AFS
Shtue - orfier
Fr6lOfteT@btr 33 (24t (9:(8{148 163 185 179 (51 fllf
E i.6no IInil m.no..
Cel Eartu Retircment/Cmwnixs 280 t280'(1ea i87 (a)
Themal Plad End-of-life Retirement
CMI Phnr Gq Cddv.^h A#ih.
Tuftine tlmrade!
Tota (EE6){9601 (l.403]fl.J45)fl.1201 (1.215',il.1 26)fi.1 55t 0.227)fl.600
280
PACIFICoRP-20I7 IRP CHAPTER 9 - ACTION PLAN AND RESOURCE PROCTIREMENT
Table 9.5 compares the fall2016 ten-year business plan portfolio with the 2017 IRP prefened
portfolio. Differences between the two portfolios are driven by changes to coal unit retirement
and natural gas conversion assumptions, changes to load projections, updated DSM supply curve
assumptions, and changes to renewable resource costs driven by the availability of federal
income tax incentives. The 2017 IRP preferred portfolio assumes Naughton Unit 3 retires at the
end of 2018, reflecting updated operating permits, instead of a natural gas conversion
implemented by the summer of 2018 as assumed in the fall2016 business plan. The 2017 IRP
preferred portfolio also assumes the retirement of both Cholla Unit 4 at the end of 2020 and
Craig Unit 1 at the end of 2025.In the fall2016 business plan, the resource portfolio assumed
Cholla Unit 4 would continue operating through the end of 2024 and that Craig Unit 1 would
continue operating through the end of 2034. Finally, the 2017 IRP includes an updated DSM
conservation potential assessment, which, when combined with an updated load forecast, informs
changes to DSM acquisition targets relative to the fall2016 business plan. Other changes in the
portfolio reflect changes to renewable resource acquisition levels driven by investment in new
transmission infrastructure and availability of federal income tax incentives.
281
PACIFICoRP - 20 I7 IRP CHAPTER 9 - ACTION PLAN AND RESOURCE PRoCUREMENT
Table 9.5 - Comparison of the 2017 IRP Preferred Portfolio with the Falt 2016 Business
Plan Portfolio
2017 IRP Preferred Portfolio
CTrity(MW)
R!!oma 2016 2017 2021 2022 2ol23 ,ozt 2023 ,,J7.6
Eimiotr ODlioil
Cas - CCCT
Cas- Peakns
DSM - Enerw Efficiencv 154 128 lll t22 123 I I4 il8 ll8 lt2 lll
DSM - Load Cmtrol
Renewable - Wnd I i00
Renewable - C*ofieru
Renewable - UtrLtv Solar
Renewable - Bbms
Sbraee - Pl]md Hvdro
Storaee - CAES
Storare - O6er
Fr@t Office Truacim 781 853 I.I5I l.l l5 l.l l8 1223 l_150 t_t72 lJ90 I 329
nri.tu I Inir Gfr.r
Coal Early Rehemeni/Convers0N (280)(38V,(82'
m.m,l Pl,nr Fnil^f-lif. RFirFm.nt<
Coal Phnt Cas Conwrsim Addnoro
T',rhin. I In6.d.<
Tntrl
Study includ€s Nughton 3 EtiEmtrt at the end of 20lE
FOT in rcsoune total N l0-,rr Nenges
2017 IRP Preferred Portfolio less Fall 2016 Ten-Year Business
FOT in nsoune lotd e l0-yer avcmgcs
Fall 2016 Ten-Year Business
Study includes Ntughton 3 gs conveNion at lhe end of2018
FOT in nsoune totd e l0-yer avcmges
n aoma Tot li
,tl7-rna6
t -229
r-l00
t.l2t
(7 49\
Rcrotrfta Tobl!
anll-rn6
456'.
650
t55
(28s1
Rclouc Totrlr
20t7-2026
t -246
450
q61
(1n9\
245
Crpdty(MW)
Raloma 20t5 aotT 20tt 20t0 ,to ,ort ,J|a2 2,)aa mrt 20ra ,N'A
Ermion Odior
C4s - CCCI
Ges- Peekiu
DSM - Enep Efficicm (4)(29\fi7 a0l fll ((
DSM - L@d Cdko
650
R.neMhlt - (..dfi.'.m
R.*.uhh - Iltlitu S6h'
Sbe@ - CAE
Sbrae - Other
Frd Office Tlffi&ti*(l0 (250)263 317 219 219 219 220 225 T25
ErisliE Unia Cte!
a.,l FArlv R.#md/.tu^h<
Themel Phm FrrlofJifr Retiremr
Cml Plrnr (-as CtrGnir ArHitim</2t51
Tot"l (949'.fl-260',fl.041)19!9)It -084)1t-ll8)1t-o49)fl -o7l )(t -2x2)1l - t -131
C.prity(MW)
20t 6 2,i17 20 tf,,oto 2no ,nt 262',naT anu ,oa1 2n26
Ermio, Odioil
Cas - CCCT
Cas- Peakirjp
DSM - Enerry Effrciencv 158 t5'7 t48 t22 t22 Il4 il8 il9 il8 lll
DSM - Load Contol
Renewable - Wind 450
Renewable - Geotherol
Renewable - tltiltu Solar
.A FS
Front Office Transactons 791 I I03 887 7S8 8Sg t0M glt s5,I I55 IIM
Eri.tiE Urit Cad..
Coal Eartu Retirement/Cmversions a2R0'l 1r87 r87'
Theml Plant End-of-lfe Retiremenl
Cml Plant Cs Conversion Additio[s 285
Tubine Uosade:
Totrl 949 l -260 l -041 919 l-084 r-049 l -071 1.242 l -t33
282
PACIFICoRP - 20I7 IRP CTnpTpn 9 -ACTIoN PLAN AND RESOURCE PROCUREMENT
PacifiCorp's 2017 IRP preferred portfolio will serve as the starting point for resource
assumptions in the fall20l7 ten-year business plan. Changes to the portfolio may be influenced
by assumptions such as updated load forecast inputs, updated price curve inputs, an updated load
and resource balance, and updated environmental policy developments.
To acquire resources outlined in the 2017 IRP action plan, PacifiCorp intends to continue using
competitive solicitation processes in accordance with applicable laws, rules, andlor guidelines in
each of the states in which PacifiCorp operates. PacifiCorp will also continue to pursue
opportunistic acquisitions identified outside of a competitive procurement process that provide
clear economic benefits to customers. Regardless of the method for acquiring resources,
PacifiCorp will support its resource procurement activities with the appropriate financial analysis
using then-current assumptions for inputs such as load forecasts, commodity prices, resource
costs, and policy developments. Any such financial analysis will account for any applicable
long-term system benefits with business planning goals in mind. The sections below profile the
general procurement approaches for the key resource categories covered in the 2017 IRP action
plan.
Renewable Resources
PacifiCorp uses competitive request for proposals (RFPs) to procure renewable resources
consistent applicable laws, rules, and/or guidelines in each of the states in which PacifiCorp
operates. In Oregon and Utah, these state requirements involve the oversight of an independent
evaluator. The renewable resource RFPs outline the types of resources being pursued, defines
specific information required of potential bidders and details both price and non-price scoring
metrics that will be used to evaluate proposals.
Renewable Energy Credits
The Company uses shelf RFPs as the primary mechanism under which REC RFPs and reverse
REC RFPs will be issued to the market. The shelf RFPs are updated to define the product
definition, timing, and volume and further provide schedule and other applicable criteria to
bidders.
Demand-side Management
ln2016, through competitive procurement processes, the Company selected vendors to continue
and adaptively manage the successful, cost-effective delivery of its two largest Class 2 DSM
programs: Home Energy Savings and wattsmart Business.lt20l7, The Company will evaluate
and re-procure, as appropriate, the delivery contract(s) for residential behavior program(s).
As PacifiCorp acquires new resources, it will need to determine whether it is better to own a
resource or purchase power from another party. While the ultimate decision will be made at the
283
PACIFICoRP-20I7IRP CgaprpR 9 - ACTION PLAN AND RESoURCE PRocunrveNr
time resources are acquired, and will primarily be based on cost, there are other considerations
that may be relevant.
With owned resources, PacifiCorp is in a better position to control costs, make life extension
improvements, as being implemented with the wind repower project analyzed in the 2017 IRP,
use the site for additional resources in the future, change fueling strategies or sources, efficiently
address plant modifications that may be required as a result of changes in environmental or other
laws and regulations, and utilize the plant at embedded cost as long as it remains economic. In
addition, by owning a plant, PacifiCorp can hedge itself from the uncertainty of the ability to
perform consistent with the terms and conditions outlined in a power purchase agreement over
time.
Depending on contract terms, purchasing power from a third party in a long term contract may
help mitigate and may avoid liabilities associated with closure of a plant. A long-term power
purchase agreement relinquishes control of construction cost, schedule, ongoing costs and
compliance to a third party, and exposes the buyer to default events and contract remedies that
will not likely cover the potential negative impacts. Finally, credit rating agencies impute debt
associated with long-term resource contracts that may result from a competitive procurement
process, and such imputation may affect PacifiCorp's credit ratios and credit rating.
COz reduction regulations at the federal, regional, or state levels could prompt PacifiCorp to
continue to look for measures to lower COz emissions of fossil-fired power plants through cost-
effective means. The cost, timing, and compliance flexibility afforded by COz reduction rules
will impact what types of measures that might be cost-effective and practical from operational
and regulatory perspectives. As evident in the 2017 IRP, known and prospective environmental
regulations can impact utilization of resources and investment decisions.
Under the CPP, compliance strategies will be affected by how states choose to implement the
rule and on-going legal challenges to the rule. Alternative policies could impute a carbon tax or
implement a cap-and-trade framework. Under a cap-and-trade policy framework, examples of
factors affecting carbon compliance strategies include the allocation of emission allowances, the
cost of allowances in the market, and any flexible compliance mechanisms such as opportunities
to use carbon offsets, allowance/offset banking and borrowing, and safety valve mechanisms.
Under a COz tax framework, the tax level and details around how the tax might be assessed
would affect compliance strategies.
To lower the emission levels for existing fossil-fired power plants, options include early
retirement, changes in plant dispatch, changing the fuel type, repowering with more efficient
generation equipment, lowering the plant heat rate so it is more efficient, and adoption of new
technologies such as COz capture with sequestration, when commercially proven. Indirectly,
plant COz emission risk can be addressed by acquiring offsets or other environmental attributes
that might become available in the market. Under an aggressive COz regulatory environment,
and depending on fuel costs, coal plant idling and replacement strategies may become tenable
options.
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High COz costs would shift technology preferences both for new resources and existing
resources to those with more efficient heat rates and also away from coal, unless carbon is
sequestered. There may be opportunities to repower some of the existing coal fleet with a
different less carbon-intensive fuel such as natural gas, as has been evaluated for the Naughton
Unit 3 and Cholla Unit 4 generating units. An ongoing consideration is whether new
technologies will be available that can be exchanged for existing coal economically, particularly
if market and policy drivers lead to large scale and abrupt early retirements across the region and
the U.S. as a whole.
While PacifiCorp focuses every day on minimizing net power costs for customers, the Company
also focuses every day on mitigating price risk to customers, which is done through hedging
consistent with a robust risk management policy. For years PacifiCorp has followed a consistent
hedging program that limits risk to customers, has tracked risk metrics assiduously and has
diligently documented hedging activities. The Company's risk management policy and hedging
progftrm exists to achieve the following goals: (1) ensure reliable sources of electric power are
available to meet PacifiCorp's customers' needs; (2) reduce volatility of net power costs for
PacifiCorp's customers. The purpose is solely to reduce customer exposure to net power cost
volatility and adverse price movement. PacifiCorp does not engage in a material amount of
proprietary trading activities. Hedging is done solely for the pufpose of limiting financial losses
due to unfavorable wholesale market changes. Hedging modifies the potential losses and gains in
net power costs associated with wholesale market price changes. The purpose of hedging is not
to reduce or minimize net power costs. PacifiCorp cannot predict the direction or sustainability
of changes in forward prices. Therefore, the Company hedges, in the forward market, to reduce
the volatility of net power costs consistent with good industry practice as documented in the
Company's risk management policy.
Risk Management Policy and Hedging Program
PacifiCorp's risk management policy and hedging program were designed to follow electric
industry best practices and are periodically reviewed at least annually by the Company's risk
oversight committee. The risk oversight committee includes Company representatives from the
front office, finance, risk management, treasury, and legal department. The risk oversight
committee makes recommendations to the president of Pacific Power, who ultimately must
approve any change to the risk management policy. PacifiCorp's current policy is also consistent
with the guidelines that resulted from collaborative hedging workshops with parties in Utah,
Oregon, Idaho and Wyoming that took place in 2011 and20l2.
The main components of the Company's risk management policy and hedging program are
natural gas percent hedged volume limits, value-at-risk (VaR) limits and time to expiry VaR
(TEVaR) limits. These limits force PacifiCorp to monitor the open positions it holds in power
and natural gas on behalf of its customers on a daily basis and limit the size of these open
positions by prescribed time frames in order to reduce customer exposure to price concentration
and price volatility. The hedge program requires purchases of natural gas at fixed prices in
gradual stages in advance of when it is required to reduce the size of this short position and
associated customer risk. Likewise, on the power side, PacifiCorp either purchases or sells power
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in gradual stages in advance of anticipated open short or long positions to manage price volatility
on behalf of customers.
Since 2003, PacifiCorp's hedge program has employed a portfolio approach of dollar cost
averaging to progressively reduce net power cost risk exposure over a defined time horizon while
adhering to best practice risk management governance and guidelines. The Company's current
portfolio hedging approach is defined by increasing risk tolerance levels represented by
progressively increasing percentage of net power costs across the forward hedging period.
PacifiCorp incorporated a time to expiry value at risk (TEVaR) metric in May 2010.In May
2012, as a result of multiple hedging collaboratives, the Company reintroduced natural gas
percent hedge volume limits of forecast requirements into its policy. There has been no conflict
to-date between the new volume limits and the Company's VaR and TEVaR limits, although the
volume limits would supersede in such conflict, consistent with the guidelines from the hedging
collaboratives.
The primary governance of PacifiCorp's hedging activities is documented in the Company's
Risk Management Policy. In May 2010, PacifiCorp moved from hedging targets based on
volume percentages to targets based on the "to expiry value-at-risk" or TEVaR metric. The
primary goal of this change was to increase the transparency of the combined natural gas and
power exposure by period. It enhances the progressive approach to hedging that the Company
has employed for many years and provides the benefit of a more sophisticated measure of risk
that responds to changes in the market and changes in open natural gas and power positions.
Importantly, the TEVaR metric automatically reduces hedge requirements as corlmodity price
volatility decreases and increases hedge requirements as correlations among commodities
diverge, all the while maintaining the same customer risk exposure.
Dollar cost averaging is the term used to describe gradually hedging over a period of time rather
than all at once. This method of hedging, which is widely used by many utilities, captures time
diversification and eliminates speculative bursts of market timing activity. Its use means that at
times the Company buys at relatively higher prices and at other times relatively lower prices,
essentially capturing an affay of prices at many levels. While doing so, PacifiCorp steadily and
adaptively meets its hedge goals through the use of this technique while staying within VaR and
TEVaR and natural gas percent hedge volume limits.
The result of these program changes in combination with changes in the market (such as reduced
volatility to which the Company's program automatically responds), has been a significant
decrease in PacifiCorp's longer-dated hedge activity, l.e., four years forward on a rolling basis.
As a result of the hedging collaboratives, PacifiCorp made the following material changes to its
policy in May 2012: (1) a reduction in the standard hedge horizon from 48 months to 36 months
and (2) a percent hedged range guideline for natural gas for each of the three forward l2-month
|eriods, which includes a minimum natural gas open position in each of the forward l2-month
periods. The percent hedged range guideline is greater for the first rolling twelve months and
gradually smaller for the second and third rolling twelve-month periods. PacifiCorp also agreed
to provide a new confidential semi-annual hedging report.
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Cost Minimization
While hedging does not minimize net power costs, PacifiCorp takes many actions to minimize
net power costs for customers. First, the Company is engaged in integrated resource planning to
plan resource acquisitions that are anticipated to provide the lowest cost resources to our
customers in the long-run. PacifiCorp then issues competitive requests for proposals to assure
that the resources we acquire are the lowest cost resources available on a risk-adjusted basis. In
operations, PacifiCorp optimizes its portfolio of resources on behalf of customers by maintaining
and operating a portfolio of assets that diversifies customer exposure to fuel, power market and
emissions risk and utilize an extensive transmission network that provides access to markets
across the western United States. Independent of any natural gas and electric price hedging
activity, to provide reliable supply and minimize net power costs for customers, the Company
commits generation units daily, dispatches in real time all economic generation resources and all
must-take contract resources, seryes retail load, and then sells any excess generation to generate
wholesale revenue to reduce net power costs for customers. PacifiCorp also purchases power
when it is less expensive to purchase power than to generate power from our owned and
contracted resources.
Hedging cannot be used to minimize net power costs. Hedging does not produce a different
expected outcome than not hedging and therefore cannot be considered a cost minimization tool.
Hedging is solely a tool to mitigate customer exposure to net power cost volatility and the risk of
adverse price movement. However, PacifiCorp does minimize the cost of hedging by transacting
in liquid markets and utilizing robust protections to mitigate the risk of counterparty default. In
addition, PacifiCorp reduces the amount of hedging required to achieve a given risk tolerance
through its portfolio hedge management approach, which takes into account offsetting exposures
when these commodities are correlated, as opposed to hedging commodity exposures to natural
gas and power in isolation without regard for offsets.
Portfolio
PacifiCorp has a short position in natural gas because of its ownership of gas-fired electric
generation that requires it to purchase large quantities of natural gas to generate electricity to
serve its customers. PacifiCorp may have short or long positions in power depending on the
shortfall or excess of the Company's total economic generation relative to customer load
requirements at a given point in time.
The Company hedges its net energy (combined natural gas and power) position on a portfolio
basis to take full advantage of any natural offsets between its long power and short natural gas
positions. Analysis has shown that a "hedge only power" or "hedge only natural gas" approach
results in higher risk (1.e., a wider distribution of outcomes). There is a natural need for an
electric company with natural gas fired electricity generation assets to have a hedge program that
simultaneously manages natural gas and power open positions with appropriate coordinated
metrics. PacifiCorp's risk management department incorporates daily updates of forward prices
for natural gas, power, volatilities and correlations to establish daily changes in open positions
and risk metrics which inform the hedging decisions made every day by Company traders.
PacifiCorp's hedge program does not rely on a long power position. However, the Company's
hedge program takes into account its full portfolio and utilizes continuously updated correlations
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of natural gas and power prices and thereby takes advantage of offsetting natural gas and power
positions in circumstances when prices are correlated and a forecast long power position offsets a
forecast short natural gas position. This has the effect of reducing the amount of natural gas
hedging that the Company would otherwise pursue. Ignoring this correlation would instead result
in the need for more natural gas hedges to achieve the same level of customer risk reduction.
PacifiCorp's customers have benefited from offsetting power and natural gas positions. Power
and natural gas prices are closely related because natural gas is often the fuel on the margin in
efficient dispatch, as is practiced throughout the westem U.S. This means power sales tend to be
more valuable in periods when natural gas is high cost, producing revenues that are a credit or
offset to the high cost fuel. If spot natural gas prices depart from prior forward prices, power
prices will tend to do so in the same direction, thereby naturally hedging some of the unexpected
cost variance.
Effectiveness Measure
The goal of the hedging program is to reduce volatility in the Company's net power costs
primarily due to changes in market prices. The goal is not to "beat the market" and, therefore,
should not be measured on the basis of whether it has made or lost money for customers. This
reduction in volatility is calculated and reported in the Company's confidential semi-annual
hedging report which it began producing as a result of the hedging collaborative.
Instruments
The Company's hedging program allows the use of several instruments including financial
swaps, fixed price physical and options for these products. PacifiCorp chooses instruments that
generally have greater liquidity and lower transaction costs. The Company also considers, with
respect to options, the likelihood of disallowance of the option premium in its six jurisdictions.
There is no functional difference between financial swaps and fixed price physical transactions;
both instruments are equally effective in hedging the Company's fixed price exposure.
The IRP standards and guidelines in Utah require that PacifiCorp "identiff which risks will be
borne by ratepayers and which will be borne by shareholders." This section addresses this
requirement. Three types of risk are covered: stochastic risk, capital cost risk, and scenario risk.
Stochastic Risk Assessment
Several of the uncertain variables that pose cost risks to different IRP resource portfolios are
quantified in the IRP production cost model using stochastic statistical tools. The variables
addressed with such tools include retail loads, natural gas prices, wholesale electricity prices,
hydroelectric generation, and thermal unit availability. Changes in these variables that occur over
the long-tenn are typically reflected in normalized revenue requirements and are thus borne by
customers. Unexpected variations in these elements are normally not reflected in rates, and are
therefore borne by investors unless specific regulatory mechanisms provide otherwise.
Consequently, over time, these risks are shared between customers and investors. Between rate
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cases, investors bear these risks. Over a period of years, changes in prudently incurred costs will
be reflected in rates and customers will bear the risk.
Capital Cost Risks
The actual cost of a generating or transmission asset is expected to vary from the cost assumed in
the IRP. State commissions may determine that a portion of the cost of an asset was imprudent
and therefore should not be included in the determination of rates. The risk of such a
determination is bome by investors. To the extent that capital costs vary from those assumed in
this IRP for reasons that do not reflect imprudence by PacifiCorp, the risks are bome by
customers.
Scenario Risk Assessment
Scenario risk assessment pertains to abrupt or fundamental changes to variables that are
appropriately handled by scenario analysis as opposed to representation by a statistical process or
expected-value forecast. The single most important scenario risks of this type facing PacifiCorp
continues to be govemment actions related to emissions and changes in load and transmission
infrastructure. These scenario risks relate to the uncertainty in predicting the scope, timing, and
cost impact of emission and policies and renewable standard compliance rules.
To address these risks, PacifiCorp evaluates resources in the IRP and for competitive
procurements using a range of COz policy assumptions consistent with the scenario analysis
methodology adopted for PacifiCorp's 2017 IRP portfolio development and evaluation process.
The Company's use of IRP sensitivity analysis covering different resource policy and cost
assumptions also addresses the need for consideration of scenario risks for long-term resource
planning. The extent to which future regulatory policy shifts do not align with PacifiCorp's
resource investments determined to be prudent by state commissions is a risk borne by
customers.
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