The URL can be used to link to this page

Home My WebLink About20191018IRP Volume I.pdf70 19 lntegrate d , l.?r{ou1'ryfrfu I VOLUME I I ocToBER I 8, 20 r9 ,a -t 5 - li I I I \ ^iI {_] tl - -rv--.-_-Ft/- -i-.E-^--r-- tu I \ \t \I t L I I CAI This 2019 Integrated Resource Plun Report is based upon the best ttvailablc information ot the time ofpreparation. The IRP actiotr plttn w'ill be intplemented as descrihed herein, but is subjec't to change as new informalion heconrcs availahle or as circufit.\lances change. ll is PaciliCorp's intention to revisit and reJiesh tlte IRP action plon no le,ss .fiequenth' lhan unnuull.v. Anl' reJ-reshed IRP action plon will be suhmitted to the Sldle (bmmissions.for lheir informatiotr. For more information, contact: PacifiCorp IRP Resource Planning 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 (503) 813-5245 irp@lpacificorp.com rvwu'.pacificorp.com Covcr Photos (Top t0 Bottom): Morengo Wind Pntject 7'ron.snission Line Electric Melcr Pavant lll Solu' Plant Teer-E op CoNTENTS l'A( r[rCoRP :0l9lRP lr\lll li OIj (1)\ Ili\ IS INDEX OF TABLES ............vii INDEX OF FIGURES CHAPTER 1 - EXECUTIVE SUMMARY PnclrrConp's VrsroN RLtM,|GINING THE FL'Tr,,RE BASED oN A CENTURy ot, Ii\iNovArroN...... Rr'l\,'r.\'rt\'6 THE Ft TL RE TIIRoL G H CoLL.tBoR.t (.,\....................... RETHINKt,\'G TrtL FL"ruRE Bt l,\'t't:srr,\'G r^' TtD DtrERstrt' oF THE WE9T................... Lt.t'ot.tn.rt; Sot.t nots ro Bt ttorHE FLTI.Rt-: ....... BTUNG|NG THE BEST oF firE WEST To PACtFlConl, 's Cr-sro,r.1lRs Co.r'v.r zrc rtrE Wl,sr ro MqRE VtLL E...... PacrprConp's INt scru,r'r'co Rnsouncs PLaN AppRoecH..................... Pnrr,nnnpo PoR't t or.ro I IIGHLIGH IS .Yi,L ^to/.lR Rf-.t(.rt R( t.s . . . . . ... . . . . . . . . ........ .\tl wt\D RL\(,r n( 7 ,\ . . . . . . .... . . . . . ....... .\'E,l .Sft)R lL,/. R/:'.s( )f /l( / .s..... x I I 2 J 3 4 J 5 6 c9I 9 D E tr.t.\'D-St DE M.r.\:.,G/1.1/E..\ r......... WHoLESALE PoII,ER MARKET PRICES AND PIJRCH1SES Ntrtnst. C,.ls Rr'so[?( rs.. CoiL RETIRE ti.L \r.s....................... C A RBor DrcxtDE E.u1ss/o,\s........... R E tiq w, A B LE P oRT lto L t o STA N DA RDS ... Lono ,lNo Re sciunc't. Bnl,tNCe C,t p e c r y Blr t,r l' c E....................... Ermcy B..tu.t'ct 2019 IRP ApvRNcrueNrs AND SUppLEMENTAT. Sruorrs I R P A D v.t.\' c t:.\ ft.r rs..................... AcrroN Pr-,rN ....... t0 ....... t2 t2 l-t t6 t6 l7 t8 18 20 22 CHAPTER 2 - INTRODUCTION 29 2019 lNrEcnarED RESoURCE Plan CorvrpoNrNr 30 Tr re Ror.p oF PA( rr-rcoRp's INTEGR^ I ED RusouncE PLANNTNG ................ 3 l PueLIc-lNpur PRoct,ss 3l CHAPTER 3 -PLANNING ENVII{ONMENT WHoLESALE Elr.crnrcllv Menxnrs N.4TL k4 L C,ts U.tt t. n t s t t r v .................... Tur Fu-r'uRg ot FEDERAT. ENVTRONMENTAI R-eculn'rroN AND LEclsLATroN F L D Ht.,l. C u.r'urE C H.t lic E L EG ISLAT|1 N ...... FEDER. . RENEfi'.,tBLE PoRTFoLto SrA,\'t)..tRt)s.... --..... NEW SoURCI PERFortL,tA N(;ti STAND4RDS FoR CARB)N EMrsstoNs- CT.EAN ArR Acr I I I 1(B) CARB)N E itfissnN G urot:r-tNEs FoR ExtsrtNc S)URCES - Cr.rrAN ArR Acr ! I I I (D) ............... CLLAN AIR Acr CRtrenu PoLLttT,tl,"rs Nenoi"-,qt Aiia -:NT AtR QUALITy Sr,txotnos.......... R EG lo.\'. t L H.1 zE.................. MER.uRt ti\iD H.4z.tRDous ArR Polr,urttirs............. C2.AL Co,\tBt sno\. Rt. t)L',tLs W$t R Q(. Attry ST/t\D,1RDs........... 2015 7,1.y EL'TENDER LE(;tsL,lrroN ...... Srern Por.rcv UPDATE C ALIFoRN t,t ..................... Onecox..........-................ WASHtrGT1N...... UTAH.................. WY().uIic Gnte Nnoust Gts ELttsstoN Pb:Rr--oRMANCE ST.4ND-lRDs RENEwABLE Pontclltcl S.t nNoenos CAt.ttt)RNl,t. OREcoN....... UTAu........... W.1sHl,\oroN TnauspontettoN ELECTRIFIcAI ToN HYDRon.ECTRtc RELtcutrtstnG l'ort.\I t..tt lttt' tt t ......... TRt. t t vt\t t: tnt IRP........... .... P.lc t F I C' o R p s A p p Ro l ( t t 1'o H t l ) R( ) t t. r.( l R t c R E I- tCE\rs/.\c .......... Urart Rnrn DEsrcN IrlonuarloN R t:sl I )t .\Tt.t t. R. r rc DEs/c.\...... CoML{ERCLtL AND I}iDtisTRt.tL R4T[ DtisrGN I RR|GATI),\ R r[ Dr..s/c.\'.......... RrcrN l Rt-:souRcn PRoctiREMENT Acttvlrtrs DE,rr..l,\'D S t DE M.IN.1GE,\tt:r-r ( DS M) R1...!o{.,11( r-:s........ 20 I 7 RE,\- EU A BLE E N L ttc t' C Rt Drrs RF P .................... 2017 Rt.tt:tt.tgt t. RFP ................. 20l7Stt.rnRFP )OI7 .14-4RKTT RTS?I- RL.L RFP,,,,,,,, ...35 lurRonucrtoN 36 36 38 43 43 44 44 44 44 44 45 49 49 50 51 52 52 5J 5.i 54 54 i5 55 56 58 60 6t 61 62 63 ()4 64 64 64 65 65 67 68 68 68 68 69 ..65 FhDFRAT. Porrcy UpDATE.......... ENEncv lN4g,\L,\NCE M,r n rcnr......... P^CIFICORP 20I9IRP rABl.t, ( )t, coNTEl l s n PA( rf rcoRr 20l9lRP lr\lll.l, Of (1)\ I I-.N I S 2 0 1 8 O R EGo N C () iu L.t u N IrY So L,t R R F P............. 2018 RENEn,lBr-E ENER6T CREDITS RFP........... ln l9 R[.\EU,1BLE RFP - L'rtrr........ R E \" E w A B LE E N I Rc t' C Rr- D trs R F P ( S A L L )......... RE ti Efi'.,t B L t: E \ t' R c t C R E D lrs R F P ( P L, R( t t.1st' ) 69 69 69 69 69 CHAPTER 4 TRANSMISSION 7l INtnooucrroN REcuraronv REeUTREMTNTS OpE,v Acctss TntNStt sstoN TARtFF R t-u I at urt SrA.v o.JRDs............,...... WALLULA To McNARY Uppar.c Ar,oLUS lo Bntocun/AN lrct-lNE Upon.l e RIeIIEST ]oR ACKNoWLEDGEMBN.I or. Arolus ro MoNA FACT)RS S u p poRTtNG tcKNonLEDG E LtENT .......... Ce'rnwav Wnst - CourrNUED PE,RMITTINc I|/TiDSTAR To Pot,ut.L,s lSt.c tft:nr D).................... P o p tr L L,s 1 o H t.,tt I,\' (; fi ,1 t' ( S E G,v E,\' r E ) .................... PL.,tN To (:o,\,Tt,\L'E PERT I- tG G.trEfi',tt' WEST .. PleN ro CoNrlNrrr PERMrrrrNc - Boenpue.N To HEMINGWAY P t.R unrt.\G U zDATL .............. BENEFrrs... N [^'r STEPS Enrncy Gernw,qv TRANSMISSIoN ExpANSIoN PLAN IlrnoDtcnol.... BACKGR)Ti.\t) ..... P t .1.\ \ t \G l.\ tTt.trtr 8s.................. ... E ),i t: RG I G,trLfi'At' Co\' flG L k'rnoN ENERct' GA'r't.:t At 's CoNTtNUED Et'ot.Un( )N .. E,r.ponrs ro MAxrMrzE FlxrsrrNc Svs |linr C,tpaerL|rv fRr,\,s,r./ss1o,\ .l'risrliv I MpRoL,E tttENTS PL,tcED I ti-SERL,t( t: S, i(L fl IL 20 I 7 IRP Pt.t,l'tt--t> Tn.l,l:str.t.slo,r.9}.,srt-.\,r l,\,tpRo|t:,\l/.|\t?is,,........................... CHAPTER 5 - LOAD AND RESOURCE BALANCE Extsrtttc Rnsot.rRcrs T H E R tU L P L-[!"T5.......... RE,\,E tr'.4 BI- L: Rt-souRCES......-.. H r ono r ucrn tc G E ti E RATIot| D E MA N D - S I D L M T I\" A G E M I.- N T. - INrnoouc'lt<_rN 71 72 72 73 73 '74 14 15 75 76 76 17 77 77 78 79 79 79 79 8t 85 86 9l 97 97 98 98 98 .99 t03 t04 ltl Svsrtu (lorNr:rot,Nt PF.AK LoAD FoRIi( AS l'...... P^crFrCoRP 20l9lRP l,\lll.t, or coNTtNTS P Rr r.4TE G ENE ktfl oN .............. PoIYER P URC I IA SIi CoNTRACTS Lo,qo aNp Rust.luncE, BAT.ANC t07 108 109 t09 t09 il4 125 125 125 t26 127 t30 t47 149 160 t60 168 169 t7t 172 173 t74 t82 t82 t95 195 t96 196 tq7 t97 202 203 CApACrry AND ENERGy BALANCE OL,tiRt,fi:w .. LoAD tD RES?()Rct Btttxc't CoMpot\it:NTS C,tpAC lrl BALA t*( r. DLTERnt,\'srro,\.............. ENERGl' BALANc r: D trt:R i,fi NATroi{ . E,\LRGy BAt.A.\L t Rr-.sr tr.s............ ....... t22 ....... t23 CHAPTER 6 RESOURCE OPTIONS INtnouuc r rorrr SuppLv-srpp RESouRCES..... DERI t,trro.\. oF RES)L RC E ATTRT B Lr.rs ................ . HA\'|DLING oF Tlic NoLoGt' I!,rpRovEMENT TRENDS AND Cosr UN(t RTAlNzEs....-....,,,,.... RES?URC ti O pn( )NS Ai\i t ) ATTRIBUTES............ Rtso u ttc: t: O t "n ct N D Esc R I pfl o NS.. R ESoURC E Tt-pE5................... DevaNo-slpn Rnsounces RESoURC E O PTIoI,S AN D ATTRI I]L}TI:S Tn,q.llsutsst<,lN Rtsou nces Mopelrxc aNo EvnluerroN S.r'rps RI,SoURCE PoR'tFoLto DEvuLclt,ttt,N t' SvsrE \ t O pn.r t t /.tl'lr.................. Cos r zrlto RtsK ANAI.YSIS...... Pl. l.\.\7.\ 6 l.\D R/sA ...................... OTHER Co.\T Jr\,'D Rtsx CoNsLtr.ntrto.vs Ponrpolr<-l S e l uc'r'r oN FINAL EvALUATIoN AND PREFERRED PoRTFoLro Suln('r'roN CASE I)EFTNITIoN CHAPTER 7 - MODELING AND PORTFOLIO EVALUATION APPROACH. I7I INtnclouc't ti-ttrt C).JL STL Dr[s..... P O RTI'O L I O D H W: I,O P M ENT C,I 585.....,....... PRt:t ERRED PoRTFot.to SELECTI)N CASLS .SE.\yzt 7r) ('.rst Dt t.t trto ts .. ............. MnHrr. r PUR( t IASts P^( [,rCoRP - :019 IRP l,\lll.l, Ol (1)\ 11,\ lS CHAPTER 8 - MODELING AND PORTFOLIO SELECTION RESULTS ...209 INrnoorrc ltor Coar. Sluorrs ..222 210 210 2il 2tl 2t2 221 226 227 227 :J I 235 236 237 ?Jcl 238 245 247 248 248 249 250 C.o)L STL't)ft.s C( )\( 7.r..s/O.\:t. Ponrrol -ro [)r-vt,t.opvrur I N rrrAL P o RTI. otio DEVELop LtEN7............ C-SERTES Ponrror.ros C-St,Rr r,s Po RTt ot,n D [vDLOp trE NT............... a' SrRlEs Cr,s/t C(.r,sr.l,,r,lr RLTr Su,rz \ r.1 I ? t ......... CP-Snnres Porlroltos C P-SER/ES PoRTFoLro DEt'ELop,ttE,\T............ C P - S mt ts C osr.4,\D R/s,( SLlt/.r/',fi )'........ .. FR,NT Ot.'t.'K tt TRA,\is.tcrtoN PoRTt.-oLlos...... 2 028-2 029 Wt'o M t N(i Wt x t t Ctsr:................... CL sro.vER R.t tt PREss1R8.............. Ponrrouo D t t t top L4ENT C)NC LL,s/oAS....... PREF ERRED PoRT't,oLto SEI-Ecrt()N THe 20l9lRP PREFERRED PoRTFoLro ,\EL SoLrR Rr-.s()r /i( fs.............................. Nt:Lt' WIiD RES2URCES..... N E w ST)RAG E R EsoL'nc'rs DEl,ts \D..Srt)t ltl t\.4(;t vE\T..... Wr ToLESALE PotvER M,|RKET PRtcES,IND PLiRL-HASES Ntt t ntt G,ss Rrsoi Rcrs.. C o..t t R tt' t n t ;.t t r,v.s .. ('. t R Bo.\ D to.\ t I ) t E V/.s.s/o.t.s............. R t,,\' t u'.18LE P oRTt oLlo S?:.,\D.{RD.'........ ('.tt .t< ttr , \t) E \/,?u) D ET,1l LED P Rt. t. t'nn t t t Ponrrou t t........... AootttoNar. SLNstttvlrv ANAr.ysrs Low L)AD Gnow'rtt StxynL'ffy (S-01) ... H IGH LoAt) C Rowrr r St:Nstrt t,trt (S-02 ).................. I-rx-20 Loto GnofirH SENsrrfi'rrt (S-03) ..............k r P ru rtr e G e,\ER { zo.\ SErslr/nrv ( S- 04 )......... HrGH PRrr'..lTE G t.\En., zo,\'Sr.\s1z nrr (S-05) ....... B(,s/^'r.ss Pl,..r,\ .t,\'s r n v ff v ( S - 0 6 ) ...... No CLsro M t:R P R/r/.r.Rr:\ar.tr,[s/71 r tr't ( S-07 )....... H rcr t C usro tfi:R PREFEREvcE,SEA,S ITI nry (S-08 )... ..251 .25t .252 .253 . 256 .257 263 . 263 . 264 . 265 . 266 . 267 . 268 . 269 . 270 PA( rf r(l )RP - :019 IRP TABI I: Or.( ON ll]N IS CHAPTER 9 - RESOURCE OPTIONS 213 ZIJ 275 275 276 278 279 279 279 280 289 289 289 295 296 298 298 298 298 298 299 300 300 301 302 303 303 303 303 303 303 TI IE 20 I 9 IRP Ac.TIoN PI,AN l. t..\'tsrt.\G RES?LTRCE ..tcr,to \s...... 2.,\ Efi' RES)L RC E :1crtoN\............. J. rn..l \.t.r/,tss/a\ I crto.\ trt .vs... 4. D E IttAti D-stDL Lt,t N,tG E tIE|.tr (DSr, .lcrtoNS 5. t,Ro\T ot FtcF TRl.\:t lczo.\s........ 6. Rt:N f:fi,,tBLE ENERGT c REDIT ACTtoNs.. --....... PRoGR[ss oN PREVlous Ac lror.r Pr.au lrnr,r AceursrrroN Part t ANalysrs RESo t-, RC E .tND Coit pt.t A NC E STR,trEc I ES ACeLlt.\t7t()^, P;ttl Dt.( tSIoN ll,fu:c tt..t I t,\tt Pnoc'r rrr r:nr nlrr DET.AYS IRP Ac'r'roN Pleu Lrurecs ro BUSTNESS PLANNING....... REst-luttcrp PRocuRIMENT Srne't rcy RENEWTBLE RESaUR(t's, SroRAGt: Rt:souRCES. AND Drsp.trcttABt.t:Rr:souRcES RENEWABLI ENLR(i r C Rt:Drrs D D.t ti \ t !-s )h M.t.\' t(; E.vE.\ T..... AssrssueNr oF OwNTNG ASSETS vERSUS PURCHASTNG PowER MaNacrNc CaRBoN RrsK r-oR ExrsrrNc PLANTS Punposg oF HEDGTNG... R t sx M,t x.t a t nzi'tr P ouc y,lN D H r, t)G t N G P Ro G R.,1 1 ......... C'osT Mt.\ t vtztrro\..... ........ l>oRTl:ot to......... Enth(tl L.\'ESS ME rs{ RE................. /\:srRt .r/f.\'rs...... TnnalvsN'r'or Cus'r'oMER nNn INvesron Rrsrs Str tt- u tsnc Rsx.,l.s.tEssr./Enr....... C.4prr-'tL Cosr Rts,(.t...........--. Sc E N.,t Rto R ts K A.S.$i..s.sr/rr,T..- Vl P^or,rc(mP l0l9 IRP TABI Ij OIj (1)\ I t.\ t\ INopx op'TaeLEs TABt.F. l.l TrrANsMrssroN PRoJECTS lNCt,Lll)trt) rN THri 2019lRP PRr,r r,rrRlrr) Por< r'r.or.ro.. T,rsLe 1.2 TorAL INITIAL CApll A r- r'( ] Dril.rv H( PREr- ERRFTD Porr l.|. ol.lo Trr,lr.:sv rssror.r AND Rr,souRC[ INV l,s r NI t,N I S., 3 _ PITcITIConp I O-YE^R SUMMER CAPACITY PoSITIoN FoRECAST 4 - PecrIrConp l0-YEAR WTNTER CAPACrry PostIoN FoRt CAST .5 20 I 9 IRP ACTIoN PLAN TAI}I-I, 2.I _ 20 I9 IRP PUBI-IC INPUT MEETINGS TABLE 3.1 STArE RPS REeurRLMriNis ...........'I AllLl- 3.2 - CALIFoRNTA C'o\,rpr.rAN( r-. PF.Rr()r) Rr,er.rrREN{ENTs ..'I'Arlr.l 3.3 - CALTFoRNTA BAr.A\cEn PonI-oLto REeUIREMENTS TAllr.r, 3.4 PA( rr,rCoRp's REeUEST FoR PRoposAL AcrrVrrr[s. TneLe 5.I FoRECASTED Suvl,rr,R Corr',rt:rDrN'r PI.AK LoAD, BEFortF. ENF:t{cy EIFtcTENCY AND PRI\rATE G[Nt]tiA I roN ... TABI-r, 5.2 C'oeL-Fur-.r-p-r PL,rNTs T,relr 5.3 - NAn.RAL-GAS-FL;ILr,r) Pr.ANr s TABLE 5.4 - OWNED WrND RF.SoURCES .................... TABl.r, 5.5 - NoN-OwNpo Wlxo RrsouRcES ........... TABLE 5.6 - NoN-OwN-ED SoLAR RLSoUR('r:s TABLE 5.7 - NET METERTNC CusToMF){s AND CAp^CrrrEs ......,......-. TArlr.r, 5.8 - HyDRo[LEC rRrc C0NTRACTS -............ TABLF. 5.9 - PACTFTCoRp OWNED LlyDRol,t-ltc rRrc GuNczucrroN FAC:[.r nrls -CAr,A( r.r'l-.s ... TABLE 5.10 EsTTMATED [MpACr'or. FERC' [.r( t,NsH Rr-Nl-]wALS ANr) RFrr-lc],NSlN(; SI,TTLIMINT C]oN,rMr rMF-NTS oN HyDRoF.LECTRIC GENERATtoN...... TABr.r, 5.1 I Exrs |rrrrc; DSM RESoURCI SL,NIN,rARy 8 tt TArll-1, TArlr.r, T,rtrt.r, ..... 17 .....22 t6 il 56 56 58 67 98 98 99 t00 100 I0t 103 t0l 104 ..... t04 ..... t07 TABLE 5.12 - ST.TMMER PEAK SysTriM CAr,A(.|'r'v [-()aDs arD RF.sor]R( r-.s,I'AI}I,I] 5, I 3 _ WINTIR PLAK SYSTEM CAPACITY LoADS AND RESoURCES. TABLI6.] 20l9SLppLy-SrDr]Rr,souR( r,T^Br.r,(2018).... TAI]I-I. 6.2 _,I.oTar- RIstIuncr- CoST FoR SUPPLY.SIDE RESoURCE OPTIoNS Tnsr.r.6.3 - To'rAL RESOURCE Cosr, FoR vARrous CApACrry FACToRS ($i MWU, 20185)............. I.ABI-I: 6.4 _ C]LoSSARY oI. T},RMS FRoM THL] SSR T,TgI,t,,6.5 - GI-oSSARY oF ACRONYMS USED IN THE SUPPLY-SIDI RLSoUR(.IiS.. TABLE 6.6 DEMAND RESpoNSri Prt(xiltAM A n RrB[.JTF.s WEsr C0NTRoL AREA........................ TAI}I,II 6.7 _ D[N,IAND RF,SP0NSE PRoCRAM ATTRIBUTES EAST CoNTRoL ARI,A TABL.t-t 6.8 S'r'A'r'r,-spECrFIC TRANSMtsstoN ANt) DrsrRlBUTlou CnuD|r's......... TABLE 6,9 - 20-YEAR CuMLrr.ATrvr-. ENFrrt(iy ErFrcrENCy PorENrrAL sv Cost BUNDLE (MWH) T,rrrr.r 6.10 - ExIRCy EFFrc]ENCy ADJUSTED PRTcES By Cosr BuNDLtl T,raLF: 6. I I Tr{A\sMrsstoN lNTr,cRAIroN OP r'toNs By [.ocA r roN euD C.rr,,rt |r y IN( REMENT il5|1 t32 li5 145 145 146 162 162 165 r66 167 169 170'l'AULL 6.12 - MAxtMUM AvArr.Atil.Fr FRoNT OFFIcE TRANSAcrror.,- Qu NTrry By MARKET HUB \ll TABLE TABLE TABLI TABI,E T^BLE TABLE TABLE TABLE TAtlt.li TABLE TABLE TABLE Tasr.s Tu\BLE TABLE ABLE 7 .1 SHoRT-TERM LoAD SToCIIASTIC PARAMETT]RS....... 7.2 SHoRT.TERM CAS PRICE PARA\,II.T[RS..... 7.3 -SHoRT-'['LRNl ELr-crRrcrry Prtr(r, PA RA]\,1r, r'riRS...... 7.4 WrNtr,n Sr,,rsoN Pnrct'CloRuir.AIroN...... 7.5 SI,RIN(i St,rsox Pt<tcl C()ttRLt.Al()N 7.6 _ SUMMER SEASoN PRICE CoRRELATIoN........,,, 7.7 FALL SEASoN PRICE CoRRELATIoN.............,... 7.8 - I lyDRo SHoRT- l [Rlvl STocrrASTr( ...... 7.9 IN r I rA r- P< x t l ot.r0 Cnst, Dl,i tNl I toNS 7.10 C-Sr'.RrF.s CAsF. Dr-.r rNfl-roNs 184 184 184 185 185 185 185 ..... 186 ..... 198 ..... 200 ..... 201 .....2027.12 - FRoNr OFFTcE 'l'R{NSACrroN (FO'l') CASI DLIrNlfloNS..... 7.13 -No Ges CASL DLr:lNrTloNs 7. l4 ADDTTToNAL GATr-rwAy CAsE DF.FrNrroNs ........ 7. I5 _ G^TEw^Y SEGMENT DEFINITIoNS 7. I I CP-SERTES CASE DEFrNrrroNS.............................. 7. l6 - SENsrrrvrry CASE DEFrNrrroNS ....................... .....203 .....203 .....203 202. 220TABLF: 8.1 INrrrAl. PoR-r'rol-ro Cos r ANr) RrsK Rl,sr.ll. rs Sur,avrrnv ..... TABLE 8.2 - ADDITToNAL C-SERTES CAsE 8.3 - C SERTES CASE Cosr AND RrsK [lIsuLTS Sut',lurnv .......... 8.4 - CP-Srnrus, Mr,DruM GAS/Mlir)ruM CO2 Rr:sur.'rs Suv vanv................. 8.5 PRICE.PoLICY CASES. MF,DIIJM G^si MF]DIt]M CC)2 RESIJLTS STJMMARY 8.6 CP-SERTES, Low GAS/ZERo CO2 RESULTS SuMMARy.......... 8.7 PRrcr-PoLrcy CASES, Low GAs/No CO2 Rl.:sr-,r-r's SUMMAny.......... 8.8 CP.SERIES. HIGH G^S/HIGH CO2 RESULTS SUMM^RY 8.9 - PRrcE-PoLrcy CASES, llraH Ges/Htcu C02 RESULTS SuMMARy...... 8.10 - CP-SERrEs SocrAL Cosr oF CARBoN Rr-rsrJr-Ts SUMMARy 8.1 I - PRrcE-PoLrcy CASE RESULTS SUMMARY................. 8.12 - FOT Cesr RESULTS SuMMARy.......... 8. ll FOT CASF. S ysft.r\,r Cosr INrpA( r Sr.N,r\'r rty 8.I4, N'o CAS RESULTS SLI},IMARY.......... 8.15 Ga r r,wav Casr, Rr,slrr. r's StiMN.rArty................... 8.16 TRANSMrssloN Pno.lrcTs INcLr.rr.rr,D r\ rrr2019 8. I7 - I'orAL lNrr,\L CAprrAL To IIELTVER PREFERRED TItANsMlsstoN A)!t) [tt]souti( t, lN V t,s I\4t,Nt-s............... TABLE TAur.t'- TABLE TABLE TABLE TABLE TABLE TABLE TABLE TABr-t, TABLE 'IABLE TABl.r'. TABLE TABLE 226 232 232 l) ) 233 234 234 235 23s 236 236 240 244 247 .....22t iRP P;;;;;;; P;;;;;';.; PoRTFoLIo TABLE TABLE TABt,E TABLE TABLE TABLI TABLE TABLE TABLE TABLI,] TABLE TABLE 8. l9 8.20 8.21 8.22 8.23 8.24 8.25 8.26 8.2',7 247 258 259 260 261 262 263 263 264 265 266 267 268 8. l 8 PAClt-.r('or{p's 20l 9 lRP Pr<r,r.r,rrr<r,D Porr 1.tl1.r0............. PREFERRED PORTFoLIo SurvrMER CApACITy LoAD AND RESoTJRCE t-]ALA\cti (2020-2029) PRr,r'rrRRrrD PORTr,olro SuN,rN.rr,R ('ApACrry LoAD AND l{t:souR( li ll^I.A\( r, (2010-2018) Pnl ,rrnr,DPorrrr,or.roWrNIr,RC'ApA(r|y[.oAr)A\r)Rr.sol]r{0,BAT.AN(r-(2020-2029) PREFERRED PoRTFoLro WrNTr,r{ CArr\( rry LoAl) A\r) RF.sourtcr-. BALANCE (2030-2038) Su\,rMARY oF ADDTTToNAL S[NSrrrvrry CAs8S........,,............. S rrx r r,rs Irt M r,AN PVRR ( Br,N r,r.r r )/Cos'r ( )r, S-0I vs. P-45('NW.................................... SrocHASrc Mr--^N PVRR ( BL:Nr..r rT )/(l()sr of S-02 vs. P-45(1NW.................................... SrocHAsrrc M[.,\N PVRR ( L]r,Nrir rr)/Cosr oF S-03 vs. P-45CNW............,....................... S Irx'rras |rr: Mr,AN PVRIT ( llr:N r,r, r I)/('os r o| S-04 vs. I'-45('N W.................................... 8.2 8 Srocrr^Src MrlAN PVRR (Br,Nr,r.r ),/('os r or. S-05 vs. P-45('NW 8.29 - SrocHAsrrc MEAN PVRR (BENEFTT)/Cosr oF 5-06 vs. P-45CNW P,\crFlCoRP 2019lRP vll l l)\lll.l Ol ( ON l lr\ lS P^( THC0RP 20l9lRP lAl]l-llol coN iLN 15 T^rlLr 8.30 Sro(1rAsrrc MEAN PVRR (BENEFTT')/Cosr or, S-07 vs. P-45CNW T^tlr.rr 8.31 PVRR (IIENEFrr)/Cosr oF S-08 vs. P-45CNW ............................... ....269 ....270 'I Aur-F.9. I 20l9lRP A(-rroN PLAN 215 280 290 29'7 .IABLE9,2 -2017 [RP ACTIoN PLAN STATIJS UI,I)ATL ... TABL[ 9.3 - NEAR-TERM AND LoNG-TERM RESoTJRCE AceutstloN PATHS .......................... TABLE 9.4 - CoMpARrsoN oF rHE 2019IRP PREFERRED PoRrl'ol-ro wl1 rr SINSrrvrry CASE 5-06........... tx INoEx op FrcuRes PACrr,rCoRP - 2019 IRP l.AIll_l: ol, (1)N l1 N ts FrciUr i l.l KEyELEMINTSoFPA(I lc'our,'s20l9 lRPAppRoACIl...... FrGr.rRE 1.2 2019 tRP PRl,r,r,rrr'-D PoR rr-oLro (ALL RLSouRCr,s) FIGURE I .3 - 2019 IRP PRr,r I-TRRED PoRrFoLro N Ew SoLe n Capacrry 6 7 9 9[;ICURL FlcuRr, F rair.rR F. I .4 - 201 9 IRP PREFERRED PoRTFoLro NLw WrNr) CApACrry 1.5 - 20l9lRP PREFERRED PoR' ,or.ro NFw SToRAGE CAPACrry......... 1.6 LoAD FoREcesr Coupenrsr)N BETWEEN RECENT lRPs (Brir-oRE INCRLMENTAL ENrir{( iy EFFrcr EN-cy SAVINCS ).......... FIGURE |.7 -2019 IRP PRF.IERRED PoRrFoLro ENIRCy E[rrcrEN.y ANr) DrRF.cr LoAD CoNTRoL CApACrry ................... Frc;u Rr-. I .8 - CoMpARrsoN oF PowER Pr{r('t,s ANn NATURAL GAS PRI ,S rN RF.C}:NT I RPs FrcuRE 1.9 2019 tRP PRu,r,RREr) Por{rr.oLro FRoNT OFFTcE TRANSA( rroNs (FOTS)..... FIGURE l.l0 - 2019 IRP PRI]I'FTRRED PoRrFoLro NArUr{Ar. GAS PF-^KINC .10 l0 ...... I I ...... I I ...... t2 .t2 .13 ANI) CoMBINED CYCLE CAPACITY FrcUIrF l. l l 2019 tRP PREFERRED P()R l l.()1.ro CoAL Rt.TtREIVIENTS...... FIGURE l . t2 - 2019 [ RP PRr,r,l,Rr{F.r) Potr I} olro CO: [,l,rrssroNs et D Pac rr,rConp CO: EN1rssroNS TR,UECToRy FlauRr, I . l3 ANNUAL STATE RPS CoMpltANCL. FoRl,( ASt'.. FrGt.rRF. l.l4 - EcoNoMrc SysrEM Drsp^ r(1r oF ExrsTING RESoURCt:s lN Rr,r.A noN To MoNTHLY LoAr) FrGUrtF. J.l - HENRY HUB DAY-AHEAD GAS PRrcF- Hrs t1)tiy FIGURE 3.2 - U.S. DRy NA rlitdAL GAs PIroDLrcrroN (TRrLLroN CuBrc Fr,r-.r) FrcuRu 3.3 Lowr-.n 48 St'ArEs SHALI PLAys FlctJRF.3.4 PLAys AccouNIlNG r,oR Ar.l. NA |[]RAL (i^s PRoDUCTtoN Gnow.r rr20ll-2018 FTGURE 3.5 - I IENRY Hur] NYMEX FUTT.|RES FrcL;Rri 1.6 ENr-.R(iy IN|BALANCE M.,\RKET ExpA\sloN i9 t4 t5 l8 40 40 4l 43 66 76 76 84 FICL RE 4, I - Sr cvr Hr t) ............ FrauRr 4.2 - SFr(illeNr 8............... Frct]RE 4.3 - ENERGY GATEWAY TRANSMrssroN ExpANstoN PLAN l. rc;uRL 5.l PRrvA r !. Glrl.n,l oN MARKIT PINETRA oN ( MWAC ), 2019-20]8 FIGI]RF- 5.2 CoNTRACT CAPACITY IN .I.IIIi 20I9 IRP SI]MMER LoAD AND RISoURCI.) B^LANCE FIGURE 5.3 - SuMMr.R PriAK CApACrry CoNTRIBUTIoN VALU[s r,ott WrNr) AND SoLAR..........,. FlauRl, 5.4 - WTNTER PEn K CAPACITY CoNTRTBUTToN VAl.ut'.s F'oR WIND AND SoLAR ............, FIG[JRF. 5.5 - ENERcy EFFTcTENCY PEAK Co:r rnrnLi rrox tN STjMMER CApACrry Lo,\D AND RtsoUR('r, BAI.AN( i. FrcuR[ 5.6 - Sr]MMr-rR SysrEM CApAcrry PosrrroN'I'RLND.. FrG(Jnr.r 5.7 - WINTER SysrEM CApAc]Ty Posr't-loN TRr.tNr)... FrcuRE 5.8 - EAsr SUMMDR CApACrry PosrrroN TREND...... FrcuRE 5.9 - Wrsr Suurvrr CAPACTTY PosrTroN TREND.... I08 108ill lll 113 ll9 120 tzl 122 123FICURTi 5.10 SysrF.vrAvriRAcEMoNTHLyE\ERCyPos1rroNS....................... \ FICURE 6.2 - HISToRIC CARBoN STf IL PRI(.INC..........,,,, Flcunr: (r.1 - Wcxr.rr C,rrrrs0N STEEL PRtctNc By Typt-: f rcuR[ 6.3 NoM tNAL Y[AR-r]y-Yr'A rt Es( A r.A r-roN t oR RtrsouRCE CAprrA.L Cos Frcur{L 6.4 - I lrsroRy or: SSR PV Cos't & FoR}r(:As'r' FTGTJRE 6.5 - HrsroRy or SSR WIND Cosrs & FoRF.cAs r .......... FIGURE 6.6 HISToRY oF SSR BATTERY ENERCY SToR^GE SYSTEM CosTs & FoI{I.,CAS'I F ICURE 6.7 ENDoGI,\oUS 'I.RANSN,IISSION MoDt.LIr'-(i 128 t29 130 l5l t53 r55 168 Fr(iLiRL FICURE FICURE FICURI, FIGU F, FIGURE FIGURE FICURE F tci u RIl FIGUItF. FIGURE FrcuRE FICit.rRr-. FIGURE f'TGURE Fr( iuRL FIGURE FIGURE FrciuRL FtGt-rRE FIGURE 7. [ - PoRTFoLro Evrr.u.r'r rO\ S Ir,ps wll lIN T ri IIIP PRO( [ss............... 7.2 TnensvrssroN SysrEM MoDEL Topolocy 7.3 CO2 PRICES MoDELLD BY PRICI]-POLICY SCINARIoS 7.4 - NoMINAL WH0Lr,snt.t, E.l.l:('llir('r ly ANt) NAI uRAL GAS PRIcL Scrl..lnros..... 7.5 - Srprulerrt) A\NuAr. MIt)-C Et.r,('r'Rr( n y MARKT,'r PRr( rs ............... 7.6 SrMUl.A |r'.r) ANNUAL PALo VERDE ELF:crRICli y MArtKr, r Pr{r(1,s..................... 7.7 - SIMI-TLATED ANNUAL WesrrnN NATURAL (;AS MARKET PRrcrES 7.8 SIMULATED ANNUAL EASTLRN NATURAL CAS MARKET PRICES 7.9 - STMULATED A:rNuat. Ir)AHo (G()sUr,N) LoAt) 7.10 - Srraulnr-l.r) ANNUAL UTAH LoAD 7.ll SrMUr.^'r'ED ANNUAL WyoMrNG LoAD 7.l2 STMULATEoAnNueLOnLcoN/CALIFORNTA LOAD......... 7. I 3 - SruuleruD ANNt-rAL WASHTNGTON LoAl)...................... t72 t75 180 182 186 187 187 188 188 189 t89 190 190 l9t7.I4 SIMUT-^TEDANNUAL SYSTEM LoAD.............. 7.15 SIMULATED ANNLiAL Hvono GrNe nltroN 7.16 - lNrrrAL CAsc Feuttt-v Tnsr: . 7. l7 - C-SF-R!l:s FAMTLY TREE..... 7. l8 - S^MPLE YEAR 202 I FOT MrDC FPC AND SCALED PRrcE CURVES 7.I9 _ LoAD AND PRIVATIj GI.:NI.:RAI.IoN STiNSITIvITY ASSUMPTIoNS...... 7.20 - Pruvarr: GENERATToN SENSITIVITy Assr.lMp.IloNs.........--,,,-....-..-- 7.21 GENERATIoN REQUIREMENTS FoR CUSToMER PREFERENCE SENSITIVITIEs............. 8.1 - INTTAL Pori rFoLros CoAL AND GAS Rl.sorjrr(:r, Rrr |nriMriNi s SuMMARy............. 8.2 - INTTAL PoRTFoLIoS NEw RENEWABLE AND SToRAGE RESOIJRCES SIJMMARy...................... .. l9l .. t99 ..200 20t 205 206 207 FIGLTRFI FIGURE FIGUR[ FIGT,RE FIGURE FICURE F IGtJ Ii F. FICURE FIG I ltt F FIGURE FICURI FIGURE FIGURE Frcuru, FIGTJRF, FICURE FrGUns 213 214 2t5 216 2t'7 218 219 221 222 1,,LS t./. s 224 225 225 227 228 228 8.3 - lNrflAL 8.4 - INrrral 8.5 INrrrAr- 8.6 - INITIAL 8.7 - INrrrAL 8. l2 8.t3 8. l4 8.15 8. t6 8.t7 PoRTI'oLtos Pott I l-ol-tos PoRTFoLIoS PoRTFoLI0S P(ni I F( )l-l( )s l\( Rr \,fl N rAt t)SM SUMMARY .......... Nr.w NAnJrtll. GAs Rr,souRo,s S u M M ER FRON T oF [' I c F] TRANS A c't I o\ s S r r M v A r,i. y WrNTr,R F-RoNT Ol't'tcE'I RANSACTToNS SUMMARy CC)2 E N.r rssroNs Sr.\,rMAr{y.......... 8.8 - RELATIvE Closr or, Srocrtesrc MtrAN To fltE LowEST-Cosr INI AL CAsI 8.9 - Cl-Srnl[s CoAl- ANr) GAS Rr-.l rRr-.M r-.N'r's Sr]MMAriy ...........,, 8.IO C.sI-]ITIES NEw RENEWABLE AND SToRAGE RESoI]RCES SI]MMARY 8.I I - C.SERIES INcRITII.NIaI- DSM SI]MMARY C-Sr,Rrr,s Nl.w NATt]RAL (;As Rusor.rR( r-. C.SERIES FRoNT OFFICL'fRANSACTIoNS SLI\,IMARY C-SERTES Cl02 EM rssroNs SlrMMAuy Rr,r.ArrvFrCosroFSToc ASTtcMUANro1lt[..Lowr,sr.C(]sICSr-.ruLsC,lsr-. CP.SERIES CoAL AND CAs RETIR[MENTS SuvIiIIny........,. CP-Snntrrs Nr,w RtiNtiwn nl.t, ANI) S'tottA(il Rlsor.rR('ls S t.rMM4Ity............... Pi.cI.rCoRl,- 2019 IRP xl l:\lll.l Ol ( O\ llN lS FrcuRr 8.18 CP-SERTES INCREME\-TAL DSM SUMMARY ....... Fr(iURr, 8.19 - CP-SERrEs NEw NATURAL C;As RESoURCE....... FI.iI-RI] 8,20 CP-SERIES FRo\T Or.IICt' .I.RA\SACTIONS SUN,I\,IARY Fr<;unr 8.21 CP-SERTES CO2 EMlssloNS SUMMARy FICURE 8.22 _ ANI.'.UL CO2 EMISSIONS ^MONC CP-SERIES C^SES Fr(;LrRr 8.23 - WyoMrNG WrND ALTERNATIVE PoRTFoLto AND Cosr EvALUA' oN ..... FI.iI]RI,8.24 CHANGE IN THE CUMULATIVI PVRR RELATI\T[ To P-4.5C]NW Fr(iuRL tl.25 P-29 No GAS CAsIr Rtisolirt('r, AND Closr Cor,lpenr.D ru P-45('NW It(iLrRr, 8.26 - P-29PS No GAs wr1I Pr]Nfl,r.r) Hyr)Ro STORAGE COMPARED To P-45CNw FrcuRr, 8.27 - P-22 (SEGMT,.NTS D.3 ^ND F) CoMP^RED ro P-45CNW......... Frci(rRr'.. 8.28 P-23 (ADDrrroNAL SEGMENTS D.3, E, F AND H) Coupenur; To P-45CNW FTGTJRE 8.29 P-25 (ADDrrroNAL SEGMENTS D.3, E, F AND H) CoMpAr .]) r'o P-45CNW .................. 229 .................. 229 FlcuRE 8.30 - P-26 (SEGMENTS Ir AND H) CoMPARED ro P-45CNW F'rcuRL 8.3 I - 20l9 lRP PREI rrRRr'.r) PoR.r'ror-ro (ALL RESoTJRCES) . Fr(;ur{r,8.:}2 2019lRP PRerr.nnr-r.r PoR-t'FoLtoNEw SoLAR CAPACITy....... FIGI jRIl 8.33 2O I9 IRP PREFERRED PoRTFoLIo NEw WIND CAPACITY ........2.+8 FIGURE 8.34 - 2019 IRP PREFERRED PoR'r'l,or-ro Nrrw SToRACF. C,qp,rc;r |y.......... ........... 249 F ICURL 8.35 - Lolr Fonucesr CoMpArtrsoN Br-.TwEEN RECENT IRPs (BEFoRE lNCr{F.Ml-rN |AL ENrnc;v ErprcteNcy SAVINGS)...... .....................249 FIGURE 8.36 2019 IRP PREFERRED PoRTFoLro ENIRCy EFFrcl[NC]y ANr) DTRECT LoAD CoNTRoL CAPACn Y FI(;ur{r 8.37 - CoMpARrsoN oF Powr,rR PRrcr.rs AND NATTiRAL GAS PRTCES rr-- RECENT lRPs FIGt]Rr-. 8.38 - 2019 IRP PREFERRED PoRrFoLro FRoNT OFFTcE TRANSACTToNS (FOTS)..... FICURI. 8.39 _ 20 I9 IITP PREF F,RIi,T':I) P0R1 I-0I-Io NA I T]RAL GAS PEAKING ANI) CoMBINED CYCLE CAPACITY. FIGURE 8.40 - 20 I9 IRP PREFERRID PoRTI.OLIo CoAL RITIREMI.NI.S FI(;ur{r 8.41 -20l9lRP PRF.| r-.Rr -.r) PoRlrolro CC)2 EMrssroNS AND PACTFTCoRP C()2 EMlssroNs TRAJECToRY FICURE 8.42 - ANNUAL STATI RPS CoMpr.rANCr, FoRricAST FI( iuRri 8.43 - Mr,.u'r'rNc Pectf lCoRl,'s CApnclry NFTEDS wrrH PREFERRED PoRTFoLro RlsouRCEs......... FtcunE 8.44 PRoJECTED ENERcy Mrx wrrH PREFERRED PoRTFoLIo Rrisour{('ris........ FICURE 8.45 - PRoJECTED CApACITy Mrx wrn t PRr,r,r,RR-I.D PoR'r'rol.ro RF.soutlcF.s................................. Fl.iuRF. 8.46 INCR I]ASE/(DECRFTASE) rN NAMEpLATE CApACrry oF S-01 RELATTvL ro Clese P-45CNW.. FlcuRE 8.47 INCREASE/(DECREASE) rN NAMEPLATE CAPACrry oF S-02 Rrir-A rrvH To C^sE P-45CNW.. I.rcuRE 8.48 - INCREASE/(DECREAS[ ) rN NAMr,pLAre Cerer:rry or S-03 RF.r.ATlvE To CASE P-45CNW.. Fr(;LlRr, 8.49 - lNcmesr(Dr'.c nr'.es[) rN NAMHpT-ArE CApACrry oF S-04 RELATTVE ro CASE P-45C]NW.. FIcURF. 8.50 INCREASE/(DECRE^SE) rN NAMEPLATE CApACrry oF S-05 RELATTVE ro CIASI P-45CNW.. FrcuRE 8.51 - INCREASE/( DECREASE ) rN NAMIpLArE CApACrry oF 5-06 Rlil.A'r rvF..ro C^sE P-45C]NW.. Fr(;URri 8.52 - INCREASE/(Dr,cR riASr, ) rN NAMlipl.A |r Capacu y oF S-07 RELATTvE To CASE P-45CNW.. FIGURFT 8.53 INCREASE/(DECREASE) rN NAMEPLATE CApACrry oF S-08 RELATTvI ro C]ASrr P-45CNW.. \ .............246 .............248 230 231 231 tJ I 238 239 240 241 242 243 244 250 2s0 25t 25t 252 ...........253 255 256 257 257 264 265 266 267 268 269 2'70 27t P.\L'I rC(mP l0l9lRP I ]\Rl I ()lj(1)\ I l:\ ls PACTFTCORP 20l9lRP CHAp rER I Ext.:(Ultvt StiMtv{ARy CuaprBR I -ExecurrvE SuvrueRy PacifiCorp's 2019 [ntegrated Resource Plan (lRP) rvas developed through comprehensive analysis and a public-input process spanning nearly a year and a half resulting in the selection of a least- cosl, least-risk pret'ened portfolio. The 2019 IRP preferred portlolio includes accelerated coal retirements and investment in transmission inliastructure that will t'acilitate adding over 6,400 megawatt (MW) of new renewable rqsources by the end of 2023, with nearly I 1,000 MW of new renewable resources over the 2O-year planning period through 2038.' The 2019 IRP preferred portlblio advances PacifiCorp's long-term vision as described in the follorving section. PacifiCorp shares a bold vision with our customers for a future where energy is delivered aflbrdably, reliably and without greenhouse gas emissions. A future rvhere our vast, modem encrgy grid connccts local communities to the low-cost and reliable energy they nccd to innovatc and achievc their goals. PacifiCorp bclicvcs that afTordability and sustainability go hand in hand and together, they fbrm the foundation for a reliable, resilient energy future-where regional and state economies bcncfit from investmcnts in energy resources and infrastructure that help them pionecr new growth opportunities. [t is an ambitious vision, but it is absolutely achicvable. By connecting the West's diversc resources to the vast reach of our transmission system and by investing in technology, pannerships and rnarkets, PacifiCorp is positioned to create the luture our customers and communities seek. Reimagining the Future Based on a Century of Innovation When PaoifiCorp joined Berkshire Hathaway Energy in 2006, the company set out to be the best energy company in terms ofservice to its customers rvhile delivcring sustainablc cncrgy solutions. The path forward rvas viewed as an invitation to reimagine not just how energy is produced but how it is dispatchcd and delivered. It was clear that PacifiCorp's greatest opporlunity would be discovcred in understanding the needs and aspirations of its customcrs and communities. The company saw the West itsell with its abundance ofdiverse natural resources, as a way to deliver greater value. And bclieved that the greatest gains could be realized by building upon the more than 100 years of innovation that helped create PaciliCorp's tcn-state energy grid. By drawing on its track record of parlnership and tcchnology-driven innovation, PacifiCorp could transform its expansive grid into an industry-leading, interconnected energy system-a system uniquely equipped to acccss the best energy resources the West has to olI'er and efliciently dclivcr those resources to customers and communitics across the rcgion. PacifiCorp has rnade signilicant progrcss over the past l3 years, becoming the largest regulated utility owner ol'wind porver in the West. From 2018 to 2020, PaciflCorp will havc incrcascd the percentagc ofzero-carbon energy resourccs in its portfblio by 70 pcrccnt. The company made sure to do it all while capturing and returning savings to its customers.r I Resourcos acquircd through customer panncrships, used lbr renervablc portfblio standard compliance, or for third- pany sales of renewable attributes are included in the total capacity figures quoted. 1 Id. EMtSStONS l0ll 20rr 20,11 20t0 WINO ANO 50I-AR CAPACITY'ENERCY COSI SAVINGS o1 a E u)o ,or I i ro.ooo {or s E ..ooo PACIf ICORP ENTRGY COSI lAVING' DUE IO EIH PARIICIPA'ION Reinventing the Future through Collaboration Over the past l3 years, PacifiCorp has successl'ully reduced its carbon emissions and improvcd reliability rvhile simultaneously delivering energy cost savings to ils customcrs. These results have been achieved by collaborating with others to create a more open and connected Westem grid and through the visionary and collaborative efforts of PacifiCorp's own generation, transmission, information technology and energy supply management teams. ln 2014, Pacifi(lorp pioneered the Western Energy Imbalanoe Market (EIM) in partnership with the California lndependent System Operator. This innovative market allows utilities across the Wcst to acoess the lowest-cost energy available in near real time, making it easy lor zero fuel-cost renewablc cncrgy to go where it is needed. II'excess solar energy in Calilbmia, excess wind liom Wyoming or hydropower from Washington and Orcgon is available, PacifiCorp will hamcss it and transport it instantly across the company's 16,500-mile grid. Through participation in the ElM, PacitiCorp has saved its customers over $200 million so lar. The savings get bigger every year, and the company has reduced its porrfolio carbon emissions ovcr l5 million tons the equivalent oltaking 3 million cars offthe road lor a year. Since its inception, nine utilities havejoined the EIM and I I more have committed tojoin by 2022, altogclhcr representing almost 70 percent of the West's total electricity demand. As more participants join thc ElM, the beneflts increase. To date, participating utilities across the West have saved customers over $730 million while simultancously dccarbonizing thc Wcstern grid. PacillClorp continues to engage new partners in evolving the real-time EIM to include a day-ahead market fbr evcn biggcr future benefits. a : J E 10r. 20rt !016 10t, 1010 l0r9 PACIFICORP ANO TOTAL EIM ACNEFITS !rchL k!,I l,^c1r,r(l)RP - l0l9 IRP CIIAPTIR [ _ [XECUTIVI S(JMMARY IP Crf tcoRP Erlr5lroNs{HrLL,oNt sT) ,or, CtrA.prER I - EXECUIVF] SUVMARY AV€RAGE TOIAL ELECTRICITY RATES FOR RETAIL CUSTOMERS EV CHARGING ri.oo a r0 00 i" N€W STORACE CAPACITY a t00 2ort iori 2016 rol, zola aPAClltCOiPr tU.S.AVaRAGE So*. Ed!rcn Ele<tn< lnlttlte S.ls ei Relenle Dala fttrthe I morths €.dry Dffib.r of e&h te& T !016 loi, 10ra 1019 { OF EV PORI' ENAALED BY PACIFICORP Rethinking the Future by Investing in the Diversity of the West PaciliCorp continues to ofl'er its customers somc of thc lowcst cncrgy prices in the country-rvell below the national averagc while simultaneously expanding the depth and breadth of its energy portlolio and solutions. Energy Vision 2020: In 2017, PaciliCorp announced its largest historical invcstmcnt in the development of rcnewable energy and infrastructure-Energy Vision 2020. This $3 billion project to be completed in 2020 embodies the company's commitment to a lulurc that benefits its customers, its communities and the environment. It will dramatically increase PacifiCorp's renewable encrgy portfolio with new and repowered wind resources and new transmission while leveraging federal production tax incentives to provide hundreds of millions of dollars in savings to its customers over the lil'e of the projccts. Encrgy Vision 2020 also beneflts rural communitics across thc West by creating hundreds of construction jobs and adding millions ofdollars in construction tax revenue and ongoing annual state and local tax revenue. Proposed New Resource Investments: PacifiCorp's 2019 IRP sets forth a plan to expand its resource porttblio rvith nerv lolv-cost wind generation, solar generation and storage to rneet changing customer needs.r lnnovating Solutions to Build the Future Demand Response: PacifiCorp is championing technical innovations that use fast-acting residential demand response resources to support the bulk power system. PaciliCorp's approach moves beyond peak-load managemcnt to creatc a grid-scale solution that turns dernand response rcsources into t-requency-responsive operating resetl'es. With ovcr 92,000 customers pafiicipating in this program, mure than 200 MW of operating rcserve is available every day and can bc dispatchcd in a matter ofseconds. I'his reduces PaciliCiorp's Wind (lD, UT, WA, WY)Over 3,500 MW Over 4,600 MW Solar (lD, OR, UT, WA, WY)Ncarly 3,000 MW Over 6,300 MW Storaue (lD,()R, Ul, WA, WY)Nearly 600 MW Over 2,800 MW P^orrcoRP 201 9 IRP Resource Through 2023 Through 2038 P,\( Ir r( oRP - l0l9 IRP CHAP r F.R I Ext( t llvt SUMN4ARY need to supply operating reserves with higher cost altematives, and it is only used in cmergencies, minimizing inconvenience to customers- PacifiCorp is also partnering with 'l he Wasatch Croup to develop and manage a tirst-ol: its-kind residential battery demand response solution. This nerv all-electric apartment building in Utah I'eatures on-site energy storage ttrr each of its 600 units, totaling 12.6 MWh of solar-powercd battcry storage. This innovative all-electric design provides emergency back-up power to residents, hclps addrcss air quality issucs in thc arca and beneflts overall electric grid operation. Electrification; The electric transportation market is in an emerging state that represents a potcntial drivcr fbr firture load growlh, improved air quality, reduced greenhouse gas emissions, improved public health and sat'cty, and creation olfinancial bcneflts fbr drivcrs, particularly for low and moderate-income populations. PacifiCorp is investing over !i26 million to support electric vehicle (EV) f'ast chargers along key corridors, develop robust workplace charging prograrns, implemcnt smart mobility programs and dcvelop opportunities lor customers in its rural communities. '['he company's investments include a Xi4 million partnership award fiom the U.S. Department of' Energy to research and develop electric transpofiation primarily in Utah and $3 million as part of the Oregon Clean Fucls Program. Bringing the Best of the West to PacifiCorp's Customers PacifiCorp's 2019 IRP includcs investments in diverse new resources like, renewables, storage and modem grid technology among them. lt outlincs ncw transmission infrastructure invcstmcnts across our territory that are needed to remove existing transmission constraints and improve grid resilicnce so the lowest-cost renewable resources can flow freely to customers across the West. PaciliCorp's IRP also provides the roadrnap by which it will dramatically reduce its grecnhousc gas emissions ovcr the next 20 years. The IRP shows that, by 2030, PacifiCorp will have reduced greenhouse emissions by nearly 60 perccnt fiom 2005 levels. Along with adding renewables and leveraging new technology, emissions reductions will bc achieved by the phased transition ol ils coal flcct. ,l Customized Renewable Energy Solutions: PacifiCorp is parlnering with communities and customers across the West to champion customized energy solutions kr achieve their renewable energy goals. For example, thc company's work with Faccbook is rcsulting in the construction of677 MW of nerv solar and wind capacity, all in service by the cnd of 2020. These projects support Facebook's operations in Oregon, enabling it to achieve its 100% rcncwable goal while simultaneously lowering energy supply costs for all PacifiCorp customers. ln addition, PacifiCorp securcd 122 MW olnew solar energy capacity on behall' ofFacebook's data center in Eagle Mountain, Utah. PacifiCorp's thermal assets and operations teams havc played an essential role in cnabling thc progrcss made to date, and the company recognizes the vital part that these resources play in their communities too. PacitiCorp is commilted to open and transparent communication about our coal transition, and equally committed to working with our employees and communities to develop plans that help them through this time ofchange. P^cr[rCoRP-]0l9lRP CI tAt't l,R I F-xi.('u uvti Sl NiMAlty Connecting the West to More Value PacifiCorp believes a path to reduced carbon emissions must be substantiated with a prescriptivc and thoughtful plan. The cornpany's plan rcvolves around three interrelated strategics to reimagine an energy I'uturc that serves all of its communities. CONNECT THEWESTTO MORE VALUE Through a technology-enabled, interconnected grid PacifiCorp sees the energy diversity of the Wcst as a catalyst. The company's plans to meet the energy needs of its customers and communities across the West will continue to evolve, but PacifiCorp's commitment to making the West stronger and bctter is unwavering. PaciliCorp rvill achieve this by continuing to find answers in new partnerships, advanced technologies and expanded energy markets, and by pursuing energy solutions thal hamess and bring the best energy resources thc West has to offer to its customers' door. PacifiCorp has been making progress in its efforts to bring the best of the West to its customers, and PacifiCorp's 2019 IRP presents the company's plans to make significant advancemcnts in this vision. The 201 9 IRP sets forth a clear path to provide reliable and reasonably priccd 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 servc customers. ln the 2019 IRP, PaciliCorp presents a preferred porttblio that builds on its vision to deliver energy af'lordably, reliably and responsibly through near-term investments in transmission infrastructure that rvill fhcilitatc continued groMh in new rencwable rcsource capacity while maintaining substantial investment in energy efticiency programs. The primary objective ofthe IRP is to identity thc bcst mix ofresources to serve customcrs in the future. The best mix of resources is identified through analysis lhat measures cost and risk. The lcast-cost, least-risk resourcc portfolio-defined as the "pref-errcd portfolio"-is the portfblio that can be delivered through specific action items at a reasonable cost and with manageable risks, while considering customer demand fbr clean energy and ensuring compliance with state and f'cderal regulatory obligations. l By investing in erpanded enerry markets and renevrable energy resources By co-creatng energy solutions with customers and communities PacifiCorp's Integrated Resou rce Plan Approach SUSTAIN THE LIVABILITY OF THE WEST ENABLE THE W€ST TO GROW CIIAP iR I ExFr(r r rvr.. SUMM,\RY Thc tull planning process is completed every two years, rvith a review and update completed in the ofTyears. Consequently, these plans, particularly the longcr-range elements, can and do change over time. PacifiCorp's 2019 IRP rvas developed through an open and cxtcnsive public process, rvith input from an active and diverse group ofstakeholders, including customcr advocacy groups, community members, regulatory stafI, and other interested parties. The public-input proccss began with thc tlrst public-input rneeting in June 2018. Over the subsequent year and a half, PacifiCorp met with stakcholders in live states and hosted eightecn public-input meetings. Throughout this effort. PacifiCorp receivcd valuable input liom stakeholders and prescntcd tindings liom a broad range ol'studies and technical analyscs that shaped and informed the 2019 lRP. As depicted in Figure l.l, PacifiCorp's 2019 IRP was developed by working through five fundamental planning stcps that began with a comprehensive and robust analysis of its coal units. The narrow scope of the coal study, which lbcused on unit-by-unit analyses with prescriptive rctircment timing assumptions, was nevcr intended kr infbrm retirement decisions, but rather to inform thc more in-depth and refined analysis in the subsequent portfolio-development proccss. The portfolio-devclopment process is where PacifiCorp produced a range ol dilferent resource portli)lios that meet projectcd gaps in the load and resource balance, cach uniquely characterized by thc type, timing, and location of new rcsources in PacifiCorp's system that considcrs a wide range of potential coal retirement dates and other planning unoertainties. In the resource portlblio analysis step, PacifiCorp conducted targeted reliability analysis to ensure porlfblios had sufficient flexible capacity resourccs to meet reliability requirements. PacifiCorp then analyzed these diffcrcnt resource portlolios to measurc thc comparative cost, risk, retiability and emission levels. This resourcc portlblio analysis informed selection ofa prel'ened portfolio and development ofthe associated near-terrn rcsource action plan. Throughout this process, PaciliCorp considered a wide range of t'actors to develop key planning assumptions and to identily key planning uncertaintics, r,r,ith input from its stakcholder group. Supplemental studics were are also done to produce specific modeling assumptions. Fi ure l.l -F-g[ Element. of PacifiC0 IRP Approach Preferred Portfolio Highlights PacitiCorp's selection of the 2019 IRP prel'ened portfolio is supported by comprehensive data analysis and an extensive stakeholder input process, described in the chapters that follow. Figure 1.2 shows that PacifiCorp's pref'ened porttblio continucs to include new renewables, facilitated by incremcntal transmission investmcnts, dcmand-side management (DSM) resources, and firr the first timc, significant battery storage resourccs. By the end of2023, the prcf-crrcd portfolio includes nearly 3,000 MW of ncu' solar resources and morc than 3,500 MW of nerv u'ind resources, inclusivc ol'resources that will comc online by the end of2020 that wcrc not in the 2017 IRP.r The preferred portfblio also includes nearly 600 MW of'battery storage capacity (all collocated rvith Preferred Portfolio Aclion PlanCoal Studics 6 P^crFrCoRP - 20l9lRP Rcsourcc Port lir I itrs Rcaource Pordolio Analysis P^crr,r( oRr' 2019IRP CnAp l.liR I - LxECI-TrvL SrJN{vARy new solar resources), and over 700 MW of incremental energy efliciency and new direct load control resources. Over the 20-year planning horizon, the prel'erred portlolio includes more than 4,600 MW of'nerv wind resources, more than 6,300 MW ol ncw solar rcsourccs, morL- than 2,800 MW of battcry storage (nearly 1,400 MW of which are stand-alone storage resources starting in 2028), and more lhan 2,700 MW of incremental energy elficiency and new direct load control resources.s While the preferrcd portfolio includes new natural gas peaking capacity beginning 2026, this falls outside ol'the 2019 IRP action plan windorv, which provides timc fbr PaciflCorp to continuc to cvaluatc r.r,hcther non-emitting capacity resources can he used to supply the flexibility necessary to maintain long-tcrm systcm reliability. Figure 1.2 - 20f9 IRP Preferred Portfolio (All Resources) 20,m0 17,500 15,000 12,500 10,000 7,500 5,000 2,500 0 (2,soo) (5,000) (7,500) 110,0001 2019 2020 2021 2al7 )071 1074 2A2a 2026 2A77 2023 2029 2030 2031 20!2 203' tO34 r Wind ! Wind+gat t Solar+Bat r gattery r Class 2 DSM { Class 1 DSM r Gas Conv. I Gas Peaker r Gas CCCT r FOT r Removed Capacitv ts ,: 3 E .=TII NI 2015 2035 2037 2013 To facilitate the delivery of'new renewable energy resources to PacitiCorp customers across the West, the preferred portfolio includes a 400-mile transmission line known as Gateu,ay South, planncd to come online by the end of2023, that will connect southeastem Wyoming and northem Utah. The nevv transmission linc is in addition to the 140-mile Cateway West transmission line in Wyoming currcntly under construction as part ofPacifiCorp's Energy Vision 2020 initiative. The preferred porlfolio further includes ncar-tcrm transmission upgradcs in Utah and Washington. Ongoing investment in transmission infrastructure in Idaho, Oregon, Utah, Washington, and Wyoming will facilitate continued and long-term growth in new renewable resources. Table l.l summarizes the incremental transmission projects included in the 2019 IRP preferred portfolio, and Table 1.2 summarizes the total amount of initial capital investment required to deliver incremental transmission and resource investments through the 20-ycar planning pcriod of the 20 t I tRP. 7 ffi N I I PACTFTCoRP 20l9lRP Cl t,\p l liR I F,x|( lr VI, SIIMMARy 'l'able l. l - 'l'ransmission Pro ects lncluded in the 2019 IRP Preferred Portfolio* *Note: TTC = total transfer capability. The scope and cost of transmission upgrades are planning estimates. Actual scope and cosls \&ill vary depending upon the interconnection queue, the transmission service queuc, the spccillc location ofany given generating resource and the type ofequipment proposed for any given generating resource. Tablc 1,2 - Total Initial Capital to Deliver Preferred Portfolio Transmission and Resource Investments $ million New Solar Resources The 2019 IRP preferred portfolio includes more than 3,000 MW oinew solar by the end of202l, which accounts ftrr resources that u.ill be online by the end of2020 but not in the 2017 IRP, and more than 6,300 MW of ncw solar by 2038 as shown in Figure 1.3.6 8 2021 69 MW Wind (20?l) 231 MW Sol.u (2024) Within Southcrn lll Irirnsmission Areil lilablcs l (10 M w o I intcrconn.ction: t l l Vallc! 3,15-ll8 kV . l.]8 kV reinlorecment ($tlm) 20:.r 354 MW Solar l2{124)Within llridgcr wY lransmission Arca Reclaimed trunsmission lrpon retircmcnt ol lim Bridser I ($0) l0l.l 674 MW Solar (:02.{)Wilhin No(hcrn LIT lransmission Arca Enables 600 Mw of irterconnecl ion: Norlhem UT l.l5 kV rcinforccmcnt ($30m) t02J 1.920 NIW wind (2021r t jl \urth Unahlcs I,92{) MW ol i lcrconncclkm with 1.700 NIW of l'lCr [ncr!:! G.rLewa\ South ($1.75]m) l0:l 395 MW Solar {:014) i0 MW W;nd 12029) \\rirhin Yakima WAli nsDrission ArrLr l:nahlcr 405 MW of intcrconnectbn I local reinlbrcement (Slm) t0t.+159 MW Solar {1014)\r'ithin Ilridg$r WY Irrnsrri\sxn) i\ rcl Rcclaime(l transmission uplrn retircmcnl ol Jinr Bridgcr 2 (lio) l0'10 (;oshen lD t I \orth Enables I.I00 MW of interconnection with 1{00 MW of IlC ($25.1m) 1,040 Mw Wind {2030) 60 MW Wind (1012) :0i0 500 N'IW Solnr (2010)Within Sourhcm tl'l Transmission Area Hnablcs 5 (10 MW o f intcrconncction: l l l Vallc\ local arca rcinforccmcnl ( S206m ) l(,ll l7i N'lU' Solrr ll0 i l)Within Southcm OR'lraftnlission Are:r Itnablt5.l75 Mw olinterconnection: Medford area 500 kV'230 kV reinfbrcement (5102m) :0i6 .l l9 MW Soldr (3016)Southcm ()R Enables 410 MW otinterconneclion \r ith 450 Mw ol l"lCi Yakinl6 WA to Bcnd OR 2l{) kV ($255m) 20i7 s09 MW Solflr t:017)SoLrth.nr I I \orthcflr U-I Rcclaimcd lransmission upon rclircmcnl of Iluntin[ton l-2 {S0) :0i7 {.11 MW cas (2037)wirhin $'illamettc vallc] oR Transmission Arca l-:nables 6l5 Mw ofinlenconnection: Alban! oR area reinforcement ($40m) :017 170 MW Cas (2037)Wilhin Soulh$csl WY lmnsmission Arc, Enablcs 500 Mw ol inrerconncction: sepamtion of doublc circuir 210 kV lincs ($l9m) :018 701 M$' Solitr (2018)$'ithin llridgcr lv'r' lransmissi(,n Arcx Rcclaimed transmission upon rclircnrnl ofJim Bridser 3-4 (S0) s254 s 1,659 sl,9l2 Oregon $264 xi2,540 s2,804 Utah s 1.004 $3,466 s4,470 Washington $136 s r ,s09 s l .644 Wyoming $765 $5,376 s6,l4l Colorado $370 SO s370 Total \) 7ql $ 14.550 s17,342 DescriutionYearResource(s)From To State Transmission Resources Total Idaho Figure 1.3 - 2019 IRP Preferrcd Portfolio New Solar Capacity* 3 .9 a,ooo 3 i,ooo E 2,ooou 1,ooo 0 7,000 6,000 5,000 ililrtilrlllill 2019 2020 2021 1022 7024 2024 2025 2026 1027 2023 2029 2030 r 2019 IRP+ 2017 IRP 2031 2032 2033 2034 2035 2036 2037 2033 20lr 203) 2ol3 2034 2035 2035 1037 2033 *Note: 2019 IRP solar qapacity shown in the figure includes 559 MW ofcontracted new solar (all pou,er-purchase agreements) that lvas not identilicd in thc 2017 lRP. Thesc resources rvill bc onlinc by the cnd of2020 and arc shown in thc lirst full year ofoperation (the year alier year-online dates). Resources acquired through customer partnerships, used for rencwable portfolio standard compliance, or fbr third-party sales ofrene$able anributes are included in the total capacity figures quoted. New Wind Resources As shown in Figure 1.4, PacifiCorp's 2019 IRP preferred portfblio includes more than 3,500 MW of ncw wind gencration by the end of 2023, which accounts for new resources that will come online by thc end of 2020 but not in the 2017 IRP, and more than 4,600 MW of'new wind by 2038.? Figure 1.4 - 2019 IRP Preferred Portfolio New Wind Capacity* 7,000 = 6,000 > s,000 9 a,ooo ! 3,ooo E.*o 1,ooo 0 2019 2020 2021 1022 2023 2011 Z02a 2075 2027 202a 2029 2030 r 2019 IRP* ,2017 IRP ,,lllllllllllllll *Notc: 2019 IRP rvind capacity showr in the figure includes 1.533 MW ofcontracted new wind (21 percent powcr- purchase agreements) that was cither idcnlilled in thc 2017 IRP and is under construction or that was not identified in the 2017 IRP and is under contracl, Tlrese resources rvill come on-line by the end of2020. These resources are shorvn ill the first full year of operation (thc ycar allcr ycar-cnd online datcs)- Rcsourccri acquired through cuslomer partncrships, uscd lirr reneuable pontblio standard compliance, or for third-pany sales of reneu,able attributes are included in the toul capacity tigures quotcd. New Storage Resources 'l'his is the first PacifiCorp IRP that identities new battery storage resourccs as part of its lcast- cost, least-risk portfblio. As shown in Figure I.5, PacifiCorp's 2019 IRP prelerred pofilolio includcs nearly 600 MW ofbattery sturage by the end of2023. All ofthe sturage resources planned through this period are paired rvith ncw solar gcneration. The plan also adds nearly 1,400 MW of stand-alone storage resources staning in 2028. l)^( I,rCoRP - 2019 IRP C Ap II'R I - Exl.cu rrvE SIJMN,TARY 9 tr tr n Figure 1.5 - 2019 IRP Preferred Portfolio New Storage Capacity = j E 500 000 500 000 500 2, 2, t, 1.,rrrrtllllllll 2019 2020 2021 2022 202t 2024 2025 2026 t 2019 tRP 2027 t028 2029 2ol0 2011 2032 203' 2034 2035 2036 2017 2018 2017 IRP (None) Demand-Side Nlanagement PacifiCorp evaluales new DSM opportunities, which includes both energy ctliciency and direct load control programs, as a rcsource that competcs with traditional ncw generation and wholesale power market purchases when developing resource portlolios for the lRP. 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 lbrecast is reduced by the selected additions of energy efliciency resources in the IRP. Figure 1.6 shows that PacifiCorp's load lorecast before incremental energy efficiency savings has increased rclative to projected loads used in the 2017 IRP and 20l7lRP Update. On average, lorecasted system load is up 2.4 percent and lorecasted coincident system peak is up 3.4 percent when compared to the 2017 IRP Update. Over the planning horizon, thc average annual growth rate, betbre accounting for incremental energy efficiency improvements, is 0.73 percent lor load and 0.64 percent lbr peak. Changcs to PacitiCorp's load tbrecast arc drivcn by highcr projected dcmand fiom data centers driving up the commercial forecast and an increase the residential forecast. Figure 1.6 - Load Forecast Comparison between Recent lRPs (Before lncremental Energy Efficiency Savings) Forecrsted Annurl System l,oxd (Gwh) 80.000 60.000 40.000 t0.[00 10.000 r0.000 14.000 l:.0u) t0.0u) 8.(XX) 6.(XX) .t.(u) 2.(XX) 0 Foftcrsted Annual System Coincidcnt Peak (MW) -t0t9 tRP o :0t7 IRP Updar. +:0t7tRP -l(rle IRP a l(rlT lRPl Id le --rFlr)l7ll(l' DSM resources continue to play a key role in Pacifi('orp's resource mix. The chart to the left in Figure I .7 compares total energy elliciency savings in the 20 I 9 I RP prel'ened portlblio relative to the 201 7 tRP prct'errcd porttblio. 10 ( ll^| l riR I l]xr,c{ r rvlr SUN.rvAlryPACTFTCORP 20l9lRP Figure 1.7 - 2019 IRP Preferred Portfolio Energy Efficiency (Class 2 DSM) and Direct Load Control Capacity (Class I DSM) Energy Efficiency (Clast 2 DSM) Direct Load Control (Class l DSM) r..lr.rrlI PACIncoRl, 20l9lRP C Ap triR I - ExF.( lit'tvFt Sl rMMARy s3 56 t5 9l t2 51 ll j E 3 .z ! E.,,,rrrllllllllllll 2,500 2.000 1,5m 1,0m 5@ r 2019lRP 2017 IRP r 2019 rRP 2071 tRP Wholesale Power l\'Iarket Prices and Purchases Figure 1.8 shows that the 2019 IRP's base case forecast for natural gas and power prices has increased lrom those in the 2017 tRP and 2017 IRP Update. These forecasts are based on prices observed in the forward market and on projections from third-party experls. The higher power prices observed in the 20l9lRP are primarily driven by the assumption ofa carbon pricc that is higher and starts earlier (2025) than what was assumed in the 201 7 IRP Update (2030).8 Moreover, the 201 9 IRP assumed higher natural gas prices than cithcr the 20 I 7 IRP or 20 I 7 IRP Update as Henry Hub, in particular, is boosted by inoreasing LNG expons. While not shorvn in thc figure below, the 2019 IRP also evaluated lorv and high price scenarios when evaluating the cost and risk of diflcrent resourcc ponfolios. Figure 1.8 - Comparison of Power Priccs and Natural Gas Prices in Recent lRPs Average of Midc/Palo Verde Flat Power Praces (Nom 5/MWh) t30 s60 s50 520 510 50 Henry Hub Natural Gas Prices (Nom S/MMBtu) 3 The 2017 IRP did not assume a carbon price hut, instead, rellected implementation oithe Clean l'ower Plan Figure 1.9 shows an overall decline in reliance on wholesale rnarket firm purchascs in the 2019 IRP prefened porlli)lio relativc to thc market purchases included in the 2017 IRP pret'erred portfblio. In particular, rcliancc on markct purchascs during summcr pcak pcriods averages 366 In addition to continued inveshnent in energy et'ficicncy programs, thc prel'ened portlblio continues to show a role lor incremental direct load control programs with total capacity reaching 444 MW by the end of'the planning pcriod. The chart to the right in Figure 1.7 compares total incrcmental capacity of direct load control program capacity in the 2019 IRP prefened ponfolio relative to thc 2017 IRP preferred portfolio and does not includc capacity liom existing programs. 2,500 2.000 1,500 1,0@ soo +2o1e RP(sep2or3l - -2017rRPUpdile(Dec2017) -2017IRp(o(t2016) +2019 RP(s.p201s) - -2017 RPUpdrr.(D.c2oI7) -roITrRP(o.t1016) PA( .rCoRP-2019IRP (lltAp ,R I - Bxt,ctJTIv[ St.rMN.tARy MW per year over the 202O-2027 timetiame-down 60 pcrcent from market purchases identified in the 2017 IRP pref'erred portlolio. This reduction in market purchases coincides with the period over which thcre are resource adequacy concems in the region. While market purchases increase beyond 2027, PacifiCorp is actively participating in regional efforts to devclop day-ahead markets and a resource adequacy program that will help unlock regional diversity and facilitate market transactions over the long tcrm. Figure 1.9 - 2019 IRP Preferred Portfolio Front Office Transactions (FOTs) Summer FOTS 3 ! E 3 ! E ,000 ,500 ,000 500 ,...,llllllh,llrll SPRPE il 9: Winter FOT5 = .* > 1,soo .H ,* E l.rrrrrlJrtJJ0 l.- II RRR r 2019 IRP 2017 IRP r 2019 tRP 2017 tRP Natural Gas Resources In the 201 9 IRP preferred portfolio, Naughton Unit 3 is converted to natural gas in 2020, providing a low-cost resource to reliably scrvc our customers during peak-load periods. Ne*,natural gas pcaking resources appear in the preferred portfolio starting in 2026, rvhich is outside thc action- plan windorv. This provides time fbr PacifiCorp to continue to cvaluate whether non-emitting capacity resources can be used to supply the flexibility necessary to maintain system reliability Iong into the future- Figure l.l0 - 2019 IRP Preferred Portfolio h-atural Gas Peaking and Combined Cycle Capacity* Natural Gas Peaking Capacity* Natural Gas CCCT Capacity 00500 000 500 IhhhIIIIrilrrrlll9R'XT:i]P:P0 500 0 r 2019lRP r2017lRP r2019lRP rr2017lRP * Note: 2019 IRP natural gas peaking capacity includes the conversion ofNaughton Unit 3 to natural gas in 2O2O (241 MW). Coal Retirements Coal resources have been an important resource in PacifiCorp's resource portlolio. Changes in how PacifiCorp has been operating these assets (i.e., by lowering operating minimums) has allowed the company to buy increasingly low-cost, zero-emissions rcncwablc energy from market participants, r,l'hich is acccsscd by our cxpansive transmission grid. PacifiCorp's coal resources will continue to play a pivotal role in following fluctuations in renervahle energy as those units approach retirement dates. Driven in part by ongoing cost pressures on cxisting coal-fired facilities t2 -E PA( I,rCoRP 20l9lRP and dropping costs filr nerv resource altematives, ol'the 24 coal units currently sen,ing PacifiC'orp customers, the prelbrred pontblio includcs rctircmcnt of l6 ofthe units by 2030 and 20 of'the unirs by thc end of the planning period in 2038. As shou.n in l'igure Ll l, coal unit retirements in thc 2019 tRP pref-erred porllolio rvill reduce coal-lireled generation capacity hy over 1,000 MW by the end of2023, nearly I ,500 MW by thc cnd of2025. ncarly 2,800 MW by 2030, and nearly 4,500 Mw by 2038. Coal unit retirements scheduled under lhe prel'erred portlblio include:. 2019: Naughton Unit 3 (same as 2017 IRP), converled to natural gas in 2020o 2020-2O23 = Cholla Unit 4 (same as 2017 IRP). 2023 = Jim Bridgcr Unit I (instead of 202U in thc 201 7 IRP)c 2025 - Naughton Units l-2 (instead of2029 in rhe 2017 IRP). 2025: Craig Unit I (same as 2017 IRP). 2026: Craig Unit 2 (instead of 2034 in the 2017 IRP). 2027: Dave Johnston Units l-4 (same as 2017 IRP) . 2027 : Colstrip Units 3-4 (instead ol'2046 in the 2017 IRP)o 2028 : Jim Bridger Unit 2 (instead ol'2032 in the 2017 IRP)o 2030: Hayden Units l-2 (same as 2017 IRP). 2036 = Huntington Units l-2 (same as 2017 tRP)o 2037 - Jim Bridger Units 3-4 (same as 20l7lRP) 3 (r.ooo) 9 {2.ooo) = (3.000) E J (4.ooo) -rrrrrllll il ll ltlll (s,000) 2019 2020 2021 2022 tO71 2024 2075 7025 7021 2023 2029 2030 2o:!1 2012 2ol3 2or4 2035 2036 2037 203a r 2019 IRP ,n 2017 IRP * Note: Coal retiremenls are assumed to occur by the end of the year before the year slrorvrr in the graph- The graph shorvs the year in rvhich thc capacil) will not be availablc lirr meeting summer peak load. All ligures represent Pacifi Corp's orvnership share of.iointly orvned l'acilities. The 2019 IRP prel'errcd porttblio ref'lects Pacitl('orp's on-going effbrts to provide cost-effectire clean-energy solutions lor our custonrers and accordingly reflects a continued trajectory of declining carbon dioxidc (ClO:) cmissions. PaciliCorp's cmissions have bccn declining and continue to declinc as a result of a number of factors, including PacifiCorp's participation in the Energy lmbalance Market (EIM), which reduccs customer costs and maximizcs usc of clcan energy; PacifiCorp's on-going cxpansion olrcncwablc rcsourccs and transmission; and Regional llaze compliancc that capitalizes on flexibility. The chart on the leli in Figure l.l2 compares projected annual CO: emissions betueen the 2019 IRP and 2017 IRP preferred portfolios. In this graph, emissions are not assigned to market purchases or sales, and in 2025, annual CO: emissions are down sixtecn pcrccnt rclative to the CIIAP.ttjR I ' EXI,CTITIVE SLIMMAR\ Figure l.l I - 2019 IRP Preferred Portfolio Coal Retirements* Carbon Dioxide Emissions 0 l3 PAul,rCor{r, l0l9ll{t) 2017 IRP prcfcrrcd portfblio. By 2030, average annual CO: emissions are dou'n 34 percent relative to the 2017 IRP preferred portfolio, and dorvn 35 percent in 2035. By the end of'the planning horizon, system CO: emissions are projected to fall from 43.1 million tons in 2019 to 16.7 million tons in 2038-a 6l .3 percent reduction. The cha( on the right in Figure I . l2 includes historical data, assigns emissions at a rate o10.4708 tons/MWh to market purchases (with no credit to market sales), and extrapolates projections out through 2050. This graph demonstrates that relative to a 2005 baseline (a ubiquitous baseline year in thc industry), systcm CO: emissions are down 43 percent in 2025, 59 percent in 2030, 6l percent in2035,74 percent in 2040, 85 percent in 2045, and 90 percent in 2050. Figure l.l2 - 2019 IRP Preferred Portfolio COu Emissions and PacifiCorp CO: Emissions Trajectory* CO2 Emissions Pacificorp COz Emissions Trajectory CHAPTFR I Exri( l;l.lvli S(tNtv,\RY E;l lllllllltru rrn n !, :EA:: I: i R RAABBEERRR: € 60 50 t0 2A 10 0 lillllhru,u,,... llur- lllllllllltni;lHHflililil HEHEEHHH I 0.8 0.6 0.4 0.2 0 o s r 2019 tRP 2017 tRP - peir.,rpLm $oro (Mi ioi 'r)-rm58de lmilioi *Note: PaciliCorp CO: l-missions Trajeclory rcllecls actual emissions through 2018 lrom owned fhcilities, specified sources and unspecified sources. Frorn 2019 through the end ofthe t*enty-year planning period in 2038, cmissir)ns reflect those liom the 2019 IRP prcl'erred portlblio with market purchases assigned the Calitbmia Air Resources Board def'ault emission lactor (0.4708 tons/MWh) emissions liom sales are not removed. Beyond 2038, emissions rctlcct the rolling avcragc cmissions ol'cach rcsourcc liom thc 2019 IRP prcl'crred portlblio through the lil'e ol'the resource. Renewable Portfolio Standards Figure l.l3 shows PacifiCorp's renewable portfolio standard (RPS) compliance lbrecast fbr Califomia, Orcgon, and Washington atier accounting lbr nerv renewable resources in the preferred portfolio. While these resources are included in the preferred portfolio as cost-effective system resources and are not included to specifically meet RPS targets, they nonetheless contribute to meeting RPS targcts in PacifiCorp's rvestcm states. Oregon RPS compliance is achieved through 2038 rvith the addition ofnew renervable resourccs and transmission in thc 2019 IRP pret'erred portlblio. The Califbmia RPS compliance position is also improved by the addition of nerv renewable resources and transmission in the 2019 IRP prel'ened portfolio but requires a small amount of unbundled renervable energy credit (REC) purchascs undcr 150 thousand RECs per year to achieve compliance through the near tcrrn. Washington RPS compliance is achieved with thc bcneflt of repowercd wind assets located in the west side, Marengo, l-eaning Juniper and Goodnoe Hills, increased system renewable resources contributing to thc rvcsl side beginning 2O2l'), and unbundled REC purchases under 300 thousand e PaciliCorp will proposc thc Multi-Statc Protocol allocation methodology in a l)ecember 13, 2019 Washingkrn gereral rate case (CRC) filing. The methodology would allocate a system generation share of all non-emitting systcm rcsourccs k) Washington. The 2019 IRP Annual State RPS Compliance Forecast retlected in Figure I .l3 reflects PacifiCorp's proposal to be liled in the rale case staning in 2021. Upon approval, the efl'ectivc date ol'the ncw allocalion mcthotlology would be .lanuary l, 2021. 14 PACITICoRP 20 I9 IRP CHAPII.:R I _ EXLCIJ'IIVE SI]MMARY Figurc l.l-3 - Annual State RPS Com pliance Forecast 1,600 I ,400 1,200 I,000 800 600 400 200 0 California Ill'S F (,) +9+p""s).r$"dP""+"dF"s,"^F}"$,".,{P"$"""+"$'""f "s-"di ^6 ^1 ^t.ti\, 1s, "ra,NLlnbundlcd Surrcndcrcdm t,nbundled Bank Surrenderedl:5Ycar-end tlnbundlcd Bank BilancerShonfall IElundlcd SurrcndcrcdIBundlcd llank SxrrendcredI Ycar-Dnd lJundlcd tlank tlalllncc+Rcquircmcnl 60,000 o on RPS F (J 50,000 '10,00 00 00 00 0 0 0 0 0 10. ?o 0 ,".'" -*" "s,t ""f ""f "$"€, .,&" "$ "s," "st "$" dpt ""+-"f -*t -*'"s""-$"$"N (lnbundled SurrendcredtN (Inbundled Bank SurrcndcrcdE Year-end Unburldlcd Rank llalanceIShonlall I llundlcd SurrcndcrcdI Bundlcd B nk SurrenderedI Year-cnd Bundlcd Bank Balancc+Requircnrcnt t)00 Washington RPS f +,ooo = I0OO 3 z,ooo Qu t -000 0 "^.""$"-+t"F-"dP"d|.udF""""$r&""{F.,$""o>t""+"{r"s""Sf "p""Nt"s" rl N [.Jnbundled Surrcndcrcd6s tlnbundled Bank SurrenderedNl Year-end Unbundlcd tlank RalanceISho(fall IBundl€d Surrendered - Bundled Bank Surrcndcrcd - Year-end Bundlcd Bank Balancc+Requirenrcnt l5 RECs per year through 2021 . Under current allocation mechanisms, Washington customcrs do not benelit liom thc new renewable resources added to thc cast side ofPaciflCorp's system. While not shown in Figure L 13, PaciliCorp mccts the Utah 2025 state target to supply 20 percent ofadjusted retail sales with eligible rencwable resources with existing orvned and contracted resources and new renewable resources and transmission in the 2019 IRP preferred portl'olio. I I II I I I I ltl P^( Il rCoRP f0l9 IRP CHAT,TER I EXECLJTIVE SLJVIV1AIIY A key element of PacifiCorp's IRP proccss is to assess its load and resource balance over the 20-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 lor reserve requirements, which ensures reliable electric service lor PacifiCorp customers. In developing the resource plan, PacifiCorp applies a l3 percent planning reserve margin to account lbr near-term and longer-term planning uncertainties. Capacity Balance Table L3 shows PacifiCorp's summcr capacity position fiom 2020 through 2029, with coal unit retirement assumptions and incremental energy ctficiency savings fiom the 20l9lRP pref'ened portfblio belore adding any incremental new generating resources. Before accounting tbr uncommitted market purchases that are assumed to be available when developing resource portfolios, PacifiCorp is capacity deflcit over the summer peak through the planning horizon. When accounting for uncommitted market purchases, PaciliCorp is capacity delicient beginning 2028. With continued load growth and assumed coal unit retirements, the summer capacity position deteriorates over time. L$lb8 R.souNC (Jpacil\ Ll,.tnhulirn Avaihblc lOl (apa.il) Co rdburion I..t6l t0.l-17 l0_290 t..168 1.168 t.16E l.16E 'Iortrll:islin! R.sourlc - fol s lt.9{t l2.ll8 llt{r6 t1t0E I,El5 ll.?s8 ll32l lt.l67 10.467 9T6l obligatiu Nltol loc4Ental I)sM ll% Plotrtring Rrscrc Maryio l.:t07 0.E81 t.]08 l.t ll 9.951 l.lt7 9.982 l.llt 10,00i 1.12.1 9.961 l.l t8 l.l2l L.il.l Ohli8nrir)n, Lto o PhnDiDA Rcscncs ll.18] ll.lqr 1t.:]l ll.2?0 (6]0) ll,l(r'l 11,128 ll.l8l ll.lll,l ll.](x\ ll.lll St sl.n |(,silii,n lvilhour l,nuomitted Marlct hrrch.ses Pascnc NtrrgLr witl{ur Avrilable l:(rl\ (?{6)(519)(591)ll.0l8)rl_ll8)ll.lE-<)r2.307)rl,l€7) Stsl! !l'josilirn Nith UDcomnred Ma*el Purchases Raquircd lo Ml:cl N.cd Pesc^. VaLrir Nith laibhL toTs 0 0 0 0 0 18t9){1.359) Table 1.4 reflects a winter load and rcsource balance tirr the 20l9lRP and sho*'s PacifiCorp's annual winter capacity position from 2020 through 2029, with coal unit retirement assumptions and incrcmental energy efficiency savings from the 2019 IRP preferred portfolio before adding any incremental ncw generating resources. Before accounting for uncommitted market purchases that are assumed to be available when devcloping resource portfolios, PacifiCorp is capacity deficient ovcr the winter peak beginning 2024. When accounting for uncommitted markct purchases, PacifiCorp is capacity deficient beginning 2029. As in the summer, with continued load growth and assumed coal unit retirements, thc winter capacity position deteriorates over time. l6 Load and Resource Balance Table 1.3 - PaciliCorp lO-Year Summer Capacity' Position Forecast (VIW) ,010 202t ,025 2026 2021 2021i 2029 Table 1.4 - PacifiCorp l0-Year Winter Capacity Position Forecast (MW) I !\lirr! lt.rnur.. ( rr)r( 1\ ( L!r1r buriin ,\\rrLJhI I ( r] ( rl).kr\ (, r:rhr liL,r !020 l02l 2022 2n23 ,o24 2025 2016 l,l.ul5 ll.l:lE l?.llr ll.tl9 ll.0]? .r}]6 10.680 10.59: 9.851J 9.{16 Obligarion \lcr otln.rtunial DSM llq6 flanninA R3s.nc M.rsin l.l:o l.l5u lt.?.tl l.t(l) E_73.t I.158 t.l6l t.lt5 l-l{? 8.71i t-l1i l.l5o Ot,ligalion + 1396 PhnninS REs$'cs 9.3:l ttrt) 0 0 (655)Sr sl.h Pus innn $iUrou( t n.omrirled lvlr(ct I'ur!hr's\ Rcscoc Mrrsi,, \rithout A\!ilnble fOTr srsr.mPosiii{}n wih I hcormiu.d Markt Prth.se\ PequiEd Lo Mru \.cd Resene lt{argin sih Arrihble l(rls l.8O(, 91? 24\ 927 2tq Figure l.l4 providcs a snapshot ol'how existing systcm rcsourccs could be used to meet forecasted load across on-peak and ofl:peak pcriods given current planning assumptions and recent wholcsalc power and natural gas priccs.l0 'I'he figure shows expected monthly energy production fiom system resources during on-peak and off-peak periods in relation to load, rcflccting coal unit retirement assumptions and incremental energy cfficicncy savings from the 2019 IRP prelerred portfblio before adding any new gencrating 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 othcr times, economic conditions result in net systcm balancing purchases, which occur more often during on-peak periods. Figure I . l4 also shows horv much system energy is available from exisling resourccs al any givcn point in time.'fhose periods where all available resource cncrgy lalls below tbrecasted loads are highlighted in red. and indicate short energy positions without addition ofany nerv generating resourccs to the portfolio. During on-peak periods, the first notable energy shonl'all appears in summer 2026. There are no cncrgy shortfalls during off-peak pcriods over this timeframe. Ln C)n-pcak hours arc defined as hour cnding 7 AM through l0 PM, Monday through Saturday. Oll'-pcak pcriods are all other hours. 17 P,\crHCoRP - 2019 IRP Ct tAPI],R I - LXECUTTVE SUMMARY 202i ,0?E lolalL\isroB NLr.u,.c . lj()Ti 8(ll (1.410) ,n67)-30/" lt'to ti',, 0 Energy Balance The capacity position shows how existing resourccs and loads balance during the coincident peak summer and rvinter periods, accounting for assumed coal unit retirements and incremental cnergy efficiency savings from the 20l9lRP prefened portlirlio. Outside ofthcsc pcak periods, PacifiCiorp economically dispatches its resources to mect changcs in load while taking into consideration prevailing market conditions. In those periods when system resource costs are less than the prevailing market price for porver, PacifiCorp can dispatch resources that, in aggregate, exceed then-current PacifiCorp customer load obligations, lhcilitating ofT-system wholesale market power sales that reducc costs for PaciliCorp customers. Conversely, at times when system resource costs are grcater than prevailing markct prices, system balancing wholesale market porver purchascs can be used to meet then-current system load obligations to reduce customcr costs. The economic dispatch of system resources is critical to how PacifiCorp manages net power costs on behall'of' its customcrs. l'^( ll rCoRP ]019 IRP CII PTIjR I _ EXECTJTIVE STIMMARY Figure l.14 - Economic System Dispatch of Existing Resources in Relation to Monthly Load On-l'cak Encrgy Balancc 5.000 ,1.000 1,000 2,000 t.0fl1 1) a$ a$ r\ a\ ^'t ^'1, ^1 ^1 .N ^\ ^5 ^5 ab ab .r1 a1 a$ .r$ Itr " r"v' re " Sv" 9{r " 1+v" r"o " f"\'" r.5l' ' rsY" tor " r"v' r.6l " rov" \1il'' \$v' 1.6t'" to\" - F-nergli at or llelou'Load rNet Balancing Sale rNet Balancing Purchase I Energy Shortfall Energy Available -Load Ol'l:-Peak Energy Balance 5,000 4,000 -e 3,000 I z.ooo 1,000 0 .o rt a\ r\ r'L a.. .1 r1 ^\ "\ ^5 11 .b.,os" \o\' \o(' t+v" f"o' SY' foo " fov' fot'' 1+\'" .'osr " 1+\'' ao<"I Energv at or Bclorv Load rNet Balancing Saler Energv Shonfall Encrgy Availablc ^b ^1 "1 ^$ ^$\.rv' \o$' \$Y' 16$' l$Y' - Net Balancing Purchase -Load I RP Advancements During each IRP planning cycle, PacifiCorp identifics and implements advancements to continuously improve the IRP fbr its customers, other stakeholders, and regulatory commissions. Some olthe key advancements implomcnted in the 2019 IRP include: Coal Studics PacifiCorp built upon prior IRP coal unil analysis *,ith a robust and comprehensi\,e analysis of its coal lleet. Results of this analysis, described in more detail in the 2019 IRP Volume II, Appendix R, Coal Studies, inlbrmed the portfolio-development phasc ofthc 2019 IRP. Endosenous Modeling of 'l'ransmission Upgrades As part of it 20 t 9 IRP, PaciliCorp was successfully ablc to providc its System Optimizer (SO) model u'ith the ability to cndogenously view costs and transmission capability associated with certain transmission upgrades that allowed fbr selection of specific transmission investments that coincide with neu' resource additions. This is an improvement liom prior IRPs, rvhere transmission upgrades and associated costs could only be coarscly cvaluated in SO model t8 2019 IRP Advancements and Supplemental Studies Pr\('I,r('oRP l0l9 lRl,(.IIAP I},R I I]XIJ( ( IIIVL SUN,lMARY resource sslcctions that rcquired post-modeling assessment ol'upgradc costs atler resource portfolios were developcd. Neu' transmission modeling capabilitics include the endogenous consideration ol'l) new incremental transmission options tied to resource selections, 2) existing transmission rights tied to thc use of post-retirement hrownlleld sites, and 3) incorporation ofcosts assuciatcd u'ith these transmission options. Limitations ofthis approach includc transmission options that interact rvith rrultiple or complex elements of the IRP transmission topology. '['hese transmission options wcrc therefbre studied as sensitivity cascs in the 201 9 IRP. Targctcd Ponfolio Reliability Analysis PacifiCorp developcd in its 20l9lRP an approach lbr assessing the reliability of its portlolios and the ability of each unique resourcc portfolio to meet reliability requirements. With significant lcvels of economic rencwable resource being selected in every rcsourcc portfolio, PacitiCorp found that subscquent modeling ofthese resource portfblios using the Planning and Risk model (PaR), which considers more granularity and an explicit accounting of operating reserve requirements, consistenlly idcntificd capacity shortfalls needed to maintain reliable operation ol'the system. PacifiCorp developed a process by producing hourly deterministic PaR runs fbr select years to identify the incremental need for rcliability resources that could then be added to a resource portfolio to ensurc thcre is sufficient flexible capacity to mcct reliability requirements. ImDrovcd Storase IlI0dclinI As PacifiClorp obscrved an inoreased presence of battery storage resources in many resource portlolios, it dcveloped a modeling tool to optimize charge and discharge cyclcs against a "net load" profile (load net of wind and solar generation) 10 bcttcr represent battery storage resources in a resource portfolio that has increasing lcvcls of incremental renewahle resourccs. Improvemcnts in Modelinc Assumptions ln the 2019 IRP, PacifiCorp improved granularity of its analysis ofreserve requirements f'rom monthly to hourly. PacifiCorp also incorporated into its modeling capacity contribution values that declinc rvith increasing pcnetration of wind and solar resourccs. Stakeholder Feedback Iiorms In its 2019 IRP, PacifiCorp expandcd upon its stakeholder leedback fbrm proccss by posting not only thc forms receil'cd tiom stakeholders but also PacifiCorp's response throughout thc public-input proccss. Pacificorp received and responded to over 133 stakeholder f-cedback Ibrms in thc 2019 IRP up liom l9 in thc 2017 lRP. Stakeholder Requcsts PaciliCorp lvas able to accommodate numerous stakcholdcr requests to develop additional stakeholder-drivcn studies during thc public-input process. PacifiCorp and stakeholders identilled and requested altcmative rnodeling scenarics, including proposed changes to mcthodology such as an altemate DSM-bundling mcthodology, rvhich rvas inlbrmcd by discussion during the public-input proccss. Further, and as infomred by PaciliCorp's analysis during the coal studies. initial porttblios rvere developed rvith thc ability tbr stakeholder input to rcqucst other variations of coal retirement cascs. Rcsults fiom some ol these studics lcd PacifiCorp to consider additional sccnarios. l9 PaoifiClorp continued to coordinate with stakeholders to include video conference conncctions with locations in Cheyenne, Wyoming, and Dcnver, Colorado, to supplement the existing vidco confcrence connection between Portland, Oregon, and Salt Lake City, Utah, in addition to the phone confercncc capability. PacifiCorp responded to stakeholder requcsts to schedule shorter lunch breaks and starl carlier on the second day ofnvo-day public-input mcetings. a a Public-lnput Mcctings Private Generation Rcsourcc Assessment This supplernental study, prepared by Navigant Consulting, Inc., was refreshed lor thc 2019 IRP to produce updated private generation penctration fbrecasts lirr solar photovoltaic, small- scale wind, small-scalc hydro, combined heat and power reciprocating cngines, and combined heat and power micro-turbines spccitic to PaciliCorp's service tenitory.'l'he private gencration penetration tbrccasts liom this study are applied as a reduction to tbrccasted load throughout the IRP modeling process and uscd in developing assumptions for the low private gcncration sensitivity and high gcncration sensitivity cascs. WesteDllilse!rcqAdcquacy Eval uation PacitiCorp updated its analysis of regional rcsource adequacy k) suppoft its assumptions for wholesale powcr market purchase limits adopted fbr thc 20 l9 tRP. The \,\'estem resource adequacy evaluation presents data fiom the Westem Electricity Coordinating Council's Porver Supply Assessment, reviervs recent resourcc adequacy studies performed for the Pacific Northrvest region, and summarizes PacifiCorp's historical peak pcriod market purchase data. Planning Reserve Margin Study The 2019 IRP was developed targeting a l3 percent planning rcscrvc margin, which influences the need for nerv resourccs and is applied during the portfolio dcvclopmcnt proccss. In the 2019 tRP planning reserve margin study, PaciliCorp analyzes the relationship between cost and reliability among ten dilferent planning rcscrve margin levels, accounting for variability and uncenainty in load and gencralion rcsources. Capacitv ContribLrtion Stud PacifiCorp made signilicant enhancements to the capacity contribution values applied to certain resources for the 2019 IRP.At the start of the IRP process, PacifiCorp dcvcloped resourcc-specilic capacity contribution valucs fbr rvind, solar, storage, energy efficiency, and load control programs, starting rvith the capacity I'actor approximation method ("CF Method") used in previous lI(Ps. For rvind and solar, capacity contribution values rvere modilled to account lor resource penetration levcls based on equivalent conventional power studics. For storage and load control programs, the capacity fhctor approximation calculation was reflned 20 PACTI TC0RP - 20l9 lRP ('lt,\P ,R I ExECtfnvti St \lN{,^RY Supplemental Studies PacifiCorp's 2019 IRP relies on numerous supplemental studics that support the derivation of specific modeling assumptions critical to its long-term resource plan. A dcscription ol'these studies, discussed in more detail in appcndices liled with the 2019 IRP, is provided below. . Conscrvation Potential Assessment An updated conservation potential assessment (CPA), prepared by Applied Energy (iroup (commissioned by PacifiCorp) and the Energy Trust olOregon was prepared to devclop DSM rcsourcc potential and cost assumptions spccilic to PacifiCorp's service temitory. -l'he CPA supports the cost and DSM savings data used during the portfblio-development process. P^cllrCoRP ]019 IRP CUAl,r'l.R I Lxt,cL rrvr, S(;Nliu^RY to account frir outage durations in each iteration, to bcttcr assess the capability ofthese energy- linrited resources. 'l'hese initial valucs were used in thc portfolio development process. As capacity contribution is dependent on all components in a portfolio. PacifiCorp assessed the reliabilily ofevery ponfblio. For the prelerred portfolio, the effective capacity contribution fbr each resource was rcassessed based on an updated CF Method kr inlirrm developmcnt ol'the load and resource balanse. lrlexible Reserve Study This study evaluatcs the need for llexible resources as a result ol'the variability and unccrtainty in load, r.l,ind, solar, and other generation resources. Thc study produccs an estimate of flexible rcscrvc nceds for each hour thal accounts fbr the specitic load, rvind, and solar resources being evaluated in the PaR model. Reserve costs estimated in the study are also applied during the portfolio developmcnt process in the SO rnodel. Stochastic Pararnetcr Update PacitiCorp's pret'erred porttblio-sclcction process relies, in parr, on stochastic risk analysis using Monte Carlo random sampling ol'stochastic variables. Stochastic variabl,-s include natural gas and u.holesale electricity prices, load, hydro gcncration, and unplanned thermal outagcs. For the 2019 IRP, PacifiCorp updated its stochastic parameter input assumptions with more current historical data. Snrart Grid PacitiCiorp has included an updatc on its Sman Grid elforts with a focus on transmission and distribution systems and customer information. Rcncrvablc Rcsources Assessmenl Commissioned by PacitiCorp for its 2019 lRP, Burns and McDonnell Engineering Company (BMcD) evaluated various renev!'able energy resources in supporl ol'thc development of PaciliCorp's lRP. 'l'he Renervable Resources Asscssmcnt is screening-level in nature and includcs a comparison oftechnical capabilities, capital costs, and operations and maintenance costs that are reproscntative of renewabie energy and skrrage technologies. Encrgy Storaee Potential Er aluation Energy storage resourccs can provide a variety of grid services since they are highly llcxible, rvith the ability to respond to dispatch signals and act as both a load and a resource.'l'his study providcs details on these grid serviccs and on horv energy storage resources can be conligured and sited to maximizc thc benefits they provide. :1 = g (-.r t.lr-c f.r() =o- o'a () E.rCt tu) Er, E 7,-:C EN (Dc>!trLOo()= a!) tr tL, al Qtr tb0_E O,, =odo = !J z oo.=0r'r-.h = 4) -=,LE q- .! l'd dr E E 0., ^ t-;_S .11 , \ :6= :!=0) --- E.= gHF ?1PE- 5EE E.:; _Etrez '; E^tr oO c E-.= _-j .tt U=-: =c € q= E I 9E 6 E>r.. O;.== !+o h =EH E;E: ;s'E Ep"a -.,sE9 EbE -c3lE n9!.4 o,f i .Erri 6Er-6 24.2 ,'E, = ),= 1,, a ;i O c:; BF:EE ;EE E5EE'=col.-.=la)!1 ;:€E re: SEi .Z.luF oE.= :P; EEPE 3'H* I 6 =- ()3:J iH:: ;Ee 19- '= 9+E E -'!-lE E.= F L.. d., a ui o >,-;d 9.!y:9 :=:EB; tr E; J H f i U; >. =E HEEE Ei,E;,"6+ : r >F^ f E f u E =.= e.e : 3 c.9 r;E E-iir. vg,v3Et-,) r 0., ll.jP "="d!.i-^.sE'':^'-=E=-E,i.gZ :EE:';E';8E;- ESEE qIEE:qt'E'i I E : g i =.4 E?+H li.!8-==,E .=?'ct d=age!l i-(J: ===Fo;<-!!AO.t-(tEVh; O b p-; o.o q;= ^cce^.(,).,!oy-- :46'= i'ji.=F =; UEOtru-. I>;;l d#o=i = o .= 7 - a.l - a.l l, a.l,=7 ='.:;51) CtrOoC.-- Z :9.= tr c.l I..t.9 N.:.? - "6-; -q c.r P$=6 =8.!.; C.=OeO.- 6 .- -(- r(-, F 3.2-.,: b f c tr oo.i c-FXE9-o2=.?'o .5 1,;.E g'EE = E: E Q Eil E= )l c .,r Y * o; .! E y tJa6l)==:d-E-5--dkaft.6;*6gdga .i = U F U-Cll,- )- -qr 6= 50 -i-qr=^i:?Jbii iiN-a.l = c..t _.. ct- /1 '^ac c:x dro:.-iEiiOx 9 E :p2! a.l .1,u.!_.t: - tr -c- c. i - o E'E. o-r !O !.r :) >' cc qJ tr.rn(J6, tr'. o,€" i,b :- E tr f 3l; h I'= o.r e >,'-: 'E r- E o, A..2=L cN F =E}HE6 a E-4 9 \ o= r'v droE,^ .r >aN *E != 6.) - >'-o c =(J!_:*U'='= O -.=9Y=;1.E= 7 i "r=-d: *O5'Jcca A'A ,r1 a ii.l3 E'E o, 9E:r-E-.n^G(9,-r D E/ ,- ca o 6l I F * tr r.)o o- 9.4 00 E r.- € vlo E- -=r-.,,Erc: 0-= >a 'o o.. 0., -; or c.l*oJL) i, o_e > -c, x -= PO.- 6 q-! o '!i > _51 ou : -'= u := '- a>- |1P A ,oo,-!-/ o. qE >': ^ -O-'- 'a ../ 0J-c-qJ ., O = i6l9::9- L l'+ 5O =EE5 c- :'1 E -c:i;!.:i ^A i at u c dY ie, ,! il -o : H o;- ^ ()'= o 6-'JX Xi !'9 6,==.8 : =--)iJ :!l t EU I cU o) L o b0 H c€ tJ 6t = = ! LIl ic a) c (-,Ia EJ:o5o- bouall L x3t)O: J'. 'o1),c, x6 troo IDJ EO =+ -,i-o0 L(,1,)|,= l: or :i-J L rt r='J 1,YIJa. -c6:a! .- 5I) -'--ch6 -- !s.c o-d, FoC=o, t-U =<-v >.o E."Pti---!=jg; e ! !.i=- 9 ...r .! L>,ch a = cq -c _<: 6 O. d ivCJ Elf,= ct,,o .- u \t.= ;,:= iiL L .:: I.-'f € o :'3cr: =- (aL t!,i a du;>:.5..LE<.JFY dz', a,o.r i o o h Y- =oo-LE = o E 9? ^ -! .9 aYd: tr.! 9EVF,a o, F *o 9 U IlJ : L o0J u v 0J.=*$26 Y9r<^*-99 - l1)O- o - -i r-:!*:3 y.qE >-JO->'.9 *.1 >,4 -, ^l).(,)l() Y >.^-?l 6l t !/.cSl9dseE al Lr< l, ;,r <l urIl Ei;irE.lo-= Y'E =.ol7)oa..Jd>;Xl 3 rs.! I P 911 - BCG cc, =l .= -r!,= E !rra c "-.c 6ol_ar-(J-ac'lY.Y*84'e ul isqEcl I il - :J - = aJ CX €l l.!9c0irv =6.;l ^ c - z-:' :a 0.1 oo. il -Y !-l U = tr tr ! q 9l E X 6 6 b.sql () - :; ; ., or ;l L Lr/ o o = -o Ul r E; ,; o- 59a- 5Yp (J -a: c = Y,! a) -cv i'i .9 ,- -t'x= :-!a - 0) 5 qo ^o" o iJ'i-:rr- < tr : e raE E =XoE -YGE o q2d'=E.E .".=o'= :x .o!.= 6 (g- .o. an an X a..t a.l al L C.lc.r+€+?? a? -o 'o F'o IEtr9trC0J0)-6)lDoro.r!lorE-c -c I -.c i,ieeoe!) 4 tr.r r- rl lll aaa o co\J (F Y Y:l'Jd,;l,i" E > r:,oE i: c 9 ";, :"7. S 3A= H '', L ox ii oqJ ,: ,;b+ 5x E 'E2v '=P .; iEd f ; e. ZH: E* E :, 9>,a:(F (.l ,=€Qr =H i. r 0J a..t : - e > - 'J3g: EE ,\E2-.\a=a-.--i5'EE EB ieE eE e_ 3.? :o: 5'F >,!antr trE .=6{5coi+t:t EEU_-jla==YcJltrEry(E-3: tiE -oo = J i 5 E 9; E sE I A 9;, - o, '"-'*:E;;E';E.E L 6r'- U'= rJ - C'- o dr >'L; Yl (r qiE;2i2 sE= E r'R E H E b-3sl4€:sIE -EqE!-aP q &E .;E EAilEE9E ryg: EEt?':€8=:EsE1.)=ea{a.laa!.|:a.r^aa = i - ..1 ..r a.r C( a.r i a.r .E ts = ..r .! ..t .. ..1 L .l.L.-Tc.td<.lqJtd?$ =EcC?OXC-O ' a c a o o.: o i ao- E.Q r o'o -'a 7= Ila-c,ccocqEaa'E - ii ai b = o r $ o\JY I tJ 0,, o H oJ # ! ts'5Ee:::E:9:9d3E66fB6pfP aaaaaa al l or z a.l o.) !- {, o)z -tat i ==: L' =I a-c = I o- EE-'; E EE9+i:ttgE:a.a-EcA! lti o '1 e =aOaO:==4.='J =o 4 \ ior -:i = .= i- .-> ?J= o- !_ -b h(!- : .= E = liy,a E E ?3 r:=E = .i v. c R! -o J .= 5: tEB-* ? E iE *€oi E C *'i^-a IC'.-" a o :E=; ;iEa g ,E :al=: ;5EEa?, E F[aIi .6EE.9AE o- =;=oE Ei3!=H b:5UE, .- -o.:; '- -!-t 9): ei iE E+ i zalit! -6-6On i ^'€oi* EiEEEF TYiZE"tZ ?=.'-rE = !.tl 9{o-;=, z.u -E.co FL{J'=o* gEE;;= .e3';;=II E:EI:EEE ;A+Zi2E ;:E=:u =ieHEs; .i:*e-2.-i EE:"e=?; *.= tL 6 .J Q "1 d =,P E t+AU,:d-Eafrj Ef,9aB_:iI+es€trT':E;qsI..,99:;i=-6E€ f&?qbsE|:l#i*l;; Ei:=g€ ilisSEEE+* 3s:;Ea ga rrE;=:: €i?.1; Eq=':j,'E s:E E ?r -fr A i i 6, EI ;?;;F;SSTsESEAIil=eeEaEllii:IqD& EIEFe'8e,9!i;!iiEaa'?l . . . .. . . .. tro'z '= a); ..9tr -c > J.= r: j-qP = f;t i;:Eb,Q5O3:EP ;i'd3- tr lurEJ:2-!8938*;r vv w\J ii? !E ilaEE L.=, CF- (J = tr n'396i8= ^ -^oi ! :1) FEFsi+., _ q_ _ EI aorQ 6 ? => E L' V' 2.-'7 ^.^ '= I oY-5i o >,;* d =!l,Yr>v oJ =eii.yBd E';1 E r gr'Y= trE a, = = ,i.! riJ t] :J?:z€EYF!?"o=5,1 \-./ E J.:- .:/ FL=a-[--.?: f. -? ,C.- - .:61 7; Pv^! rO r.J.qA I.-r: .U S i:i i.a a) -1 -ia2'ilda ! - "(E.r1!2-:cc "i:5ru c-r.: = -5;;C-r,]J E ..J U] .J (?,iEr e plt--t ,J F= a.t>.c >,O >r- aaaa a ot E] E Rt;=r)'J .. '.ca) .rr_ ,uotr1J=tr,1, >.n -v.6oo c.,roic .i :Z 'J 'd -e - aJr +E h +.: v> ea =-llll 'D - >'= .i La u = c-, > *h2ia;iY t!) i"€U E 2'i.v, 41]L!9 'a a aL .a = .-- th '=elDt(.,EEl tr--c 0) EI TI;; @l =! u d)9l d'l:;; EI ''_ E E.=l r! i o odil r,cl !'eR RAr".q=R =l 4Y.., + r >l .i (-, \-/ \J =-cl =dEE>dl =l o .. a.l (J F a{ ,! >: "; r.r o.jr-=aa ") .o l) {;i ? 1-> -L r- = cLo- 'E;.: (,]|E() Fi+E &-\ ,) u1 9) >.:o '*=a an>.=: .e-3,?9.= ,>i = ^, ,7-, Y .=-eS (s(, .. >r Y ^ cca = F6 (!z U--: o.JFE E =eh ii == Le =t -ca a-F Y '= *.- =tr m7 ---.: l'l -qE.=EE€E -o f = E! i t E9 b 5:c(J;ic!LJ- aaa ) z q,r E 0) a = C ; >> -E <ts 5 - -aa:t : .c. A )?, !l(!LriY =dl:uhq ar.J=(g 5 E=EE K.E :d qrd, o =ar:Jlrc(fy!=lq,E P E- o.r s ?.u l=E--t)=ao='=Z ZEEz aL{ ,ASE g! r .!:,*E oJ != n .> <=- -- -=q -= h,== c u C,5.aHI: .=:7.!"Eii, >i!:== P " io r *I>,:rEf =t.ErztsE:* ^{g = t, - - E Og<l 3ro> --,o-.'1 g H; r 5x I ^ a] !!.= -' :, -{t;5.= ac ! ! 3',Ei ^8Ee o 3 F *tr T-E;- dr ;l-c'- tD =iYFE=A 3TE =-:0-r>'t=.J=!'2,9-7=(r'.aa.at.J:j}.=>EE1f -ut2 n,,,.= u f' .c:.!!Soza5 i=a,-a;==r-^.=.i-E*=p1E FEo=-.=F': 68c.o !.i." I o .F.lrZ i:2? ,-{.j-. i?7;a xS+ 6 >. € 6 - 9 X .';EE.E".i !cr3d E!t E: iYiou:>e-Ylco aaaaaa E1) UE22 z. =a iJ 50 q) fllt 22 d o- 9ra? 9 -: \h Y.) 'Ju- y] .1)rr- Y'-E-r=EsTT;.=- - ? N-!.2 ='! =a'-u-.= ^. .-, 0,, ,= I:..l = -i=- q u a -Cg-Cd'= 2l'= -'.Y t- au _ =- t)Pc.:r =Z?,8=?,co_6:a{ q, I i,E E ==+650P xr-q! E;EEE r9e(Dt:--; E.: .,. -a o.c +9!E =6Y=ov .- - = o-EEg; T''=triioo29 I b0 -c t E Z' lna = -:4 0)= E = O *t .=-un!o a-'- ^.NE;.EHqI = = ;; c.r '' "EEExE aaa L 0, ol .v tr :!J'J al,utr ,>r -o: .-tr!r '= -oa>., i^ "Z i:i-..:1) J 50;o brl50 <= q d =tr=LOL) i 11 .ri = = .2= t- u- ! u;.; o-! 6.=E o.r x = ->.; J =,= i;-,:a = -l ,> ;."r 3 t:-o r.aE(g-E 9!' H.9 - !E:.-O_^^E 9 tri: = E510 2:i -- 1 /, 2 Pd: z '- a.('Q i - '.,.9?.oF 9cte = o-y.=.4.Y.2r- E t 3 t'o'" .. - u i _-Q o E d 1 ,r ,- e ^ al r=da':1,,,a,.= C- i.= L orrala\!)z vd'! 2 = '1- 2 ab55gs5 aaaa a.l OJ E (h IJ l! z a o,)t-t + () fr o al o-)AC coo6o! o= 6, oDd = c].nE -5 ^r = ii .'l t aZor ^.c'= o,l o9!g 6 r'l q, >(.: e f 6e arx .= a) tr ;c 2C ;b Q2 = Q' a"l f o- .. (., :C oz: 6 6o E.! ';'r" A'=o90,1t! - "1 hrlh.= -:. .: d1!_3d ? =!' E : -a ; .a Ir E E., E 'a z = ! Eg ! E E E !6 90P >..Y = (.) ) a^) E 3c50€=.= ., a{ u:'tJo0 c- .q = !.- a? " ,!, )Ec ar 'o ^.?&x uXtr 50E * = CEa=a -F ac.r.9/., eE€ Y_6 ee= (J O:P,DZu ,.= :iEf- a az7ia . C-E 9! L oU F <L) r! E' tr,l a d \cal =', €.=(, :: E 6na; g.s .-1 : e.=-F9ar*,a247.-a* .;: o0 _= 11 0,, E .= -lL.9-Ee', !l 3 o c.r'i' - >,+a n,J- :: tr o o 60 -.c =J !+ - i 9aa .=:E-< -: .t, .r !-'oE.9:95*.=.= c\)qaa?.2qt; E 9;E 2 ai3 F€< tr (v co= = a .= E = yp ur.!gc-.w== aq!r ts{ l.o = t,=,9: tn I 'J ,- g _o-, b0 E E=5.= -: na so'E!HcU = a tr'-0r;==coi! o-o ('!l-,orElE>E tPz.9x'Eats.9O E L.= t' L:.v(J:jdLII J Lr. .d O. aaa oa q) OJ l.l f LJ: f(,, l I =:EQ E lp+!6 *+a t).cu a9E th- a t)-?,Y d E .:F; Z 'E,rf ; H-o>,tr24,!-tic9I'o 50 E-9 iE c '2A = t artar !..3!E * E =cA;P Ei* 'a-= coc-: -()l)O!7)NQtr.q:oE?E E Kf ,I| \-/ ct tr i1 d:.i: P.3 I o U.:=Er-Y.:d)-.C€.F'3b=f*^!=>=3EE::tX€i"E E I E c., 'o oc0-cL!tr(B "EETB;€€-- E c,; )< .Jli2E!,-euE*lJ€: r ! = (, -'O-'A = -E 6,s E,s ' =* bB-Eq.= E :,:i= c c,.:Ll:;t:fe':tr:.,->,q6:;HE€!-Etr.:-C.q ..Irii 6.rl.=.J>=-5 eil ta- 3 - i 03;.al P , r)-.= ==V.qlAe-,^E:;E El ;EAa'zE? El !SESPE-+E -EEH*!EEl <2E bEQi o-dlzla a . ! d oo I oU 6 5- F,a.l itro o0 -oo o. tro a .J .J E .J 50) o .E 319 eEl /wal-t==tr!l :r9l =Ul ,,,-q LI CJaJl N !.ll E -El ==t -> Ql. 4l a) tr OIJ 6.! trq = tra ?, =>a >- qY - :L Y 9OJ(B=>r g -p.rt dc(, .= P ll Y" n =)Y u.=' t rAo0o 36tC C A '= , u4.7I? bo- >aE (5 oJ '/A e-,h4Y > .-'=L ---i 1):i(s9.Jq ;-trl<t1)4 d HX gv^-ar / c\ ..r 'd or.) -E /E .E EE+ !.,f; - 9. X'9u)I = a..5 ce i=o e --= = )v) 9,c-2=1a tr --: -'liE (I) !.,1 3: \-, 1J ar = Y,LE.= rr !l.- I tr .- ::2 i,'e cdg<ir'; .h a) = =! l 3 d o I U a- q)t-i, EJ , \o a.l = i< LJ.j a =5 oa c !2 a- l,A(Ir r(l)RP 2019 IRP CIIAPTER 2 - I\ I Rol)l r(-t to\ CHaprEn 2 - IurnoDUCTroN PacifiCorp's selection of the 2019 IRP prelbrred portfblio is supponed by comprchensive data analysis and an cxtensive stakeholder input-proccss, described in the chapters that fbllow. PacifiCorp's preferred portfolio continues investmcnts in new rvind, transmission, and demand- side management (DSM), rvhile adding significant solar and battery. By 2025, the preferred portfblio includes nearly 3,000 megawatt (MW) ol'new solar resources, more than 3,500 MW ol new rvind rcsourccs, nearly 600 MW of battery storage capacity (all of rvhich is combined with nerv solar resources), 860 MW ol incremental energy efliciency resources and nerl direct load control capacity. Over the 20-year planning horizon, the pref'erred portfblio includes more than 4,(100 MW of ne* wind resources, more than 6,300 MW of new solar resources, more than 2,800 MW of'battery storagc by 2038 (nearly 1,400 MW of which arc stand-alone storage resources starting in 2028), and more than 1,890 MW of incremental energy cllicicncy resources and new direct load control capacity. To fircilitatc the delivery of ner.v renewable encrgy rcsourccs to PaciliCorp customers across the West, the preferred portfirlio includes the construction of a 4C)0-mile transmission line known as Gatcrvay South connecting southcastcrn Wyoming and northem Utah. Othcr significant studies conducted to support analysis in the 2019 IRP include: . An updated demand-side management rcsourcc conservation potential assessmentl. A private generation study for PacifiCorp's sen'icc tcrritory; o A renervable resources assessmenti. A planning reserve margin study;. A wcstcm region resource adequacy asscssmentl. A capacity contribution study; r A flexible reserve study developed in coordination with a technical rcvierv committee;. Updated stochastic parameters; and. An updated load and resourcc balancc. Finally, the 2019 IRP reflects continued alignment efforts with PacifiCorp's annual tcn-ycar busincss planning process. The purpose ofthc alignment, initiated in 2008, is to: a Provide corporate benefits in the form oiconsistent planning assumptions; l9 PacifiCorp files an [ntegrated Resource Plan (lRP) on a biennial hasis rvith the statc utility commissions olUtah, Oregon, Washington, Wyorning, tdaho, and Califbmia. This IRP f ulfills the company's commitment to dcvclop a long-tcrm resource plan that considers cost. risk, uncertainty. and thc long-run public interest. It rvas dcvclopcd through a collaborative public-input proccss with involvement from regulatory staff, advocacy groupsi and other interested parties. As the owncr ol'the IRP and its action plan, all policy judgrnents and decisions conccming the IRP are ultimately made by PacifiCorp in light of its obligations to its customers, regulators, and shareholdcrs. PACrr.rCoRP - 2019 IRP CHAP[F]R 2 - IN TRoDUCTIoN Ensure that business planning is inlbrmed by the IRP portlolio analysis, and, likewisc, that the IRP accounts lbr near-tcrm rcsource affordability concems as they rclatc to capital budgeting; and lmprove the overall transparency of PacifiCorp's resource planning processes to public stakeholders, This chapter outlines the components of the 2019 IRP, summarizes the role of the lRP, and provides an overview of the public process. The basic components of PacifiCorp's 201 9 IRP include: r Set of IRP principles and objectives adopted for the IRP cllbrt (this chapter).. Assessmcnt of the planning environment, market trends and fundamentals, legislative and regulatory developments, and currcnt procurement activities (Chapter 3).r Description ofPacifiCorp's transmission planning efforts and activities (Chaptcr 4).o [,oad and resource balance on a capacity and energy basis based on the prefcrrcd portfolio and detcrmination of the load and energy positions lirr the front ten years of the twenty year planning horizon (Chapter 5).o Profile of resource options considered fbr addressing future capacity and energy needs (Chapter 6).o Description ol' the IRP modeling, including a description of the resource portfolio development process, cost and risk analysis, and prcf'crred portfolio selection process (Chapter 7).. Presentation ol'IRP modcling results, and selection of top-perlorming resourcc portfolios and PacifiCorp's preferred portfolio including sensitivitics (Chapter 8).. Presentation of PacifiCorp's 2019 IRP action plan linking the company's prel'erred portlolio with specilic implcmentation actions, including an accompanying resource acquisition path analysis and discussion ofresource procurement risks (Chapter 9). The tRP appendiccs, includcd as a Volurnc I[, contain the items listed belorv o Load Forecast Details (Volume II, Appendix A),o IRP Regulatory Compliance (Volume II, Appendix B),o Public Input Process (Volume Il, Appendix C),. Demand Side Management Rcsourccs (Volume Il, Appendix D),. Smart Grid discussion (Volumc ll, Appendix E),o Flexible Rcscrvc Study (Volume ll, Appendix F),o Plant Water Consumption data (Volume II, Appendix G),r Stochastic Parameters (Volume II, Appendix H),r Planning Reserve Margin Study (Volume II, Appendix I),. Westem Resource Adequacy Evaluation (Volumc Il, Appendix J),. Capacity Expansion Results Dctail (Volumc II, Appendix K),o Stochastic Simulation Results (Volume ll, Appendix L),o Case' Study Fact Sheets (Volume ll, Appendix M),o Capacity Contribution Study (Volume II, Appendix N), 30 2019 Integrated Resource Plan Components . Private Generation Study (Volume tt, Appendix O),o Renewable Resources Assessment (Volume II, Appendix P),. Energy Storage Potential Evaluation (Volume II, Appendix Q), and. Coal Studies (Volume II, Appendix R). In an elfort to improve transparency PacifiCorp is also providing data discs lirr the 2019 IRP.'Ihese discs support and provide additional details fbr the analysis described within the document. Discs containing confidential inlirrmation are providcd separately under non-disclosure agreements, or specific protective ordcrs in docketed procecdings. 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 lbr determining and implementing PacifiCorp's long- term resource strategy according to this IRP mandate. In doing so, it accounts lbr state commission IRP requirements, the current view of the planning cnvironment, corporate busincss goals, and uncertainty. As a business planning tool, it supports intbrmed decision-making on resource procurement by providing an analytical framework for assessing resource investment tradeoffs, including supporting Request for Proposal (RFP) bid evaluation efforts. As an extemal communications tool, the IRP engages numerous stakeholders in the planning proccss and guides them through the key decision points leading to PacifiCorp's prel'ened portfolio of generation, demand-side, and transmission resourccs. While PacitiCorp continues to plan on a system-wide basis, thc company recognizes that ncw state resource acquisition mandates and policics add complexity to the planning process and present challengcs to conducting resource planning on this basis. The IRP standards and guidelines for certain statcs require PacifiCorp to havc a public input process allowing stakcholder involvemenl in all phases ofplan dcvelopment. Pacifi(lorp organized six state meetings and held l8 public-input meetings, some ofwhich spanning trvo days to facilitate information sharing, collaboration, and expectations for the 2019 IRP. 'fhe topics covcred all facets of the IRP proccss, ranging tiom specific input assumptions to the portlolio modeling and risk analysis strategies employed. 'l'able 2.1 Iists the public input meetings/conlbrences and highlights major agenda items covered. Volume II, Appendix C (Public Input Process) providcs more details conceming the public-input proccss. 'fable 2.1 - 2019 IRP Public Input Mcetings I The Public Utility Commission ofOregon and Public Service Commission of Utah cite "krng-run public interest" as part oftheir delinition ofintcgrated resource planning. Public interest pertains to adequately quantilying and capturing firr resource evalualion any resource costs cxtcmal to the utility and its ratepayers. For examplc, the Public Sen ice Commission of Utah cites the risk offuture internalization ofenvironmental costs as a public intercst issuc that should be factored into thc rcsource portfolio dccision-rnaking process. 3l 6/l l/2018Slatc N'lccting Oregon state stakeholdcr comments P,\CIIICoRP 20I9IRP CHAPTER 2- INTRODUCTIoN The Role of PacifiCorp's Integrated Resource Planning Input Process Meetins Tvoc Datc Main Agrnda Items P^cr.rCoRP 20l9lRP Cl l,\P ,R 2 IYtRoDtr( tt{)N Statc Mccring 6/t2it8 W&shington state stakeholder commcnts State Meetins 6ll8lt 8 Idaho state stakcholdcr comments Statc Meetins 6it9it11 Wyoming state stakeholder commcnts Statc Mccting 6/20/ I 8 tltah stale stakeholder comments State MeetinE 8/9./t 8 Urah State Stakcholder Meeting on IRP Process 6i28/t8 2019 IRP Kick-olI Meeting, Model C)ven,icvr,, Unit-by-Unit Coal Study RcsultsGeneral Meeting (2-Day) 6i19,'llt Dernand-Side Managcmcnt Workshop 7/26t8 Energy Storagc Workshop, Renervable Resourcc Schcdules and Load Forccast, Distribution System Planning, Supply-Side Resource StudyCeneral Meeting (l-Day) 1/11 /18 Environmcntal Policy. Renewable Porttblio Standards, Modeling Assumptions and Study Updates 8it0i I 8 Private Gencration Study, Consenation Potential Assessment and Energy tllficiency Credits, Portfolio Devclopmcnt Process and lnitial Sensitivity Studies, Flexible Rcscrvc StudyCeneral Mecting (2-l)ay) Ii/i t/ I 8 Market Reliance Assessment, Planning Reserve Margin Study, Capacity Contribution Study 9il6l l8 Draft Supply-Side Resource Tablc, lntra-Hour Flexible Resourcc Credit, Invironmental Policy, Price-Policy Scenarios, Transmission Overvierv and Updatcs Ceneral Meeting (2-Day) 9i2'7lt8 Flexible Reservc Study Cost Results, Planning Rcscrvc Margin Study and Capacity Contribution Study Results, Portlblios Discussion/Coal studics Next Steps, Demand-Side Management Credits and Conscrvation Potential Asscssment Gencral Meeting (phone conference)t0/9/1 ti Supply-Side Rcsource Table, Intra-Hour Flcxiblc Resource Credits, Updated CO: Assumptions General Meeting /l/lft Supply-Side Resource Table, Modcling Improvements and Updates, Update on Coal Sludics l2.ai l8 (iral Studies Discussion(icncral Meeting (2-Day) I 2/4/ l8 (bal Studies Discussion Gencral Mccting t24/t9 Capacity Contribution Values lor Lnergy-Limited RcsotLrces, Coal Studies f)iscussion Gencral Meeting (phone conlirence)2t2t/t9 (icncral Updates. Summary of Oregon Energy Efticiency Analysis Rcsulls Gencral Mccting 3/21/19 Coal Studies Discussion Gencral Mccting 4i25/1e ( oal Studies Discussion 5/20t19 (onscrvation Potential Assessment, DSM Bundling Methodology, Updated Ponlolio Vatrix anrl AnalysisCeneral Meeting (2-Day) 5/2|/t9 Portfblio Analvsis Discussion 6i10it9 Modeling Updates, Ponfolio Analysis RcsultsGencral Meeting (2-Day) 612 ti t9 Portli)lio Analysis Results DSM Workshop 7112/tt)Consen ation Potential Assessmcnt, Demand-Side Managemcnt Portlblio Mcthodokrgy General Meeting (phonc conltrence)7i 13i l9 (icncral Updatcs General Meeting Ponlolio Analysis Results t0/3/19 Prefened Ponfblio and Action Plan, Portlolio Development and SclcctionCeneral Meeting (2-Day) 10t4lt9 Porttblio Development and Selcction, Sensitivities 32 Mectins TvDe Date l\f din Asenda Items 9/5/19 P,\(lrlCoRP-20l9lRI'}CltAPlliR 2 - INTRODLTC I toN ln addition to the public-input meetings, PacifiCorp used other channels to lacilitate resourcc planning-related inlirrmation sharing and stakeholder input throughout the IRP process. The company maintains a public website: (www.pacificorp.com/cncrgy/integrated-resource- plan.html), an e-mail "rnailbox" (irp@Tpaciticorp.com), and a dedicated tRP phone linc (503-813- 5245) to suppo( communications and inquirics among participants. Additionally, a Stakeholdcr Feedback Form rvas used kr provide opponunities for stakcholders to submit additional input and ask questions throughout the 2019 IRP public input process. Thc submitted lirrms, as rvell as PacifiCorp's responscs to these feedback tbrms are located on the PacitiCorp's IRP u'ebsite: wrvw.pacificorp.corn/energy/integrated-resourcc-plan/comments.html. A surnrnary of stakeholdcr f'cedback lorms received and company response was provided during the public-input meetings. 33 P,\( lr r( (n{r, l(lltl IRP Cl lAPi I-R 2 - INTRoDL:crtoN 34 P\( l,r(l)Rr, l0l9lRP CII,,IPIER 3 PI- NNI\(; LNVtRoNNlt,N I CHrprgR Htt;uLtr;uts ln 2009 Appalachia (mostly Pennsylvania and Wcst Virginia), produced almost no natural gas; by late 2013 it was producing almost l2 billion cubic l'eet per day (BCF/D) and by end- of-year 201 8, Appalachia rvas producing over 28 B(lF/D. ln short, supply fiom Appalachia continues to grow as volumes and costs prove to be, respectively, higher and lorvcr than anticipated. Today, Appalachia accounts fbr 34 pcrccnt ol'the nation's gas supply, and by 2040 is cxpccted to account for 44 percent, spurred by incrcascd drilling elliciencies and rising demand. Day-ahead 2018 Henry Hub prices averaged S3.15/Million British thcrmal units (MMBtu), dorvn 64 percent liom 2008 prices. Federal and state tax credits, declining capital costs, and improved technology pcrlbrmance have put rvind and solar "in the money" in areas ot'high potential. As such, rvind and solar rvill dominale U.S. capacity additions fbr thc ncxl decade. To better integrate these resources into thc larger grid requires more flexible gencration. transmission, ne!\ storage technologies, and market design changes. In 2019, the Washington Legislature approved the Clean Energy Transfbrmation Act (CETA) that rvill requirc the statc to powcr 100 percent of its electricity from carbon-free resourccs by 2045. Rulemaking by state agencics, including the Washington Utilities and Transponation Commission (WUTC) and the Washington Department of Commcrcc commenced in July 2019. PacifiCorp is participating in rulemaking proceedings and will pcrlbmr an analysis of the poftfolio cfflcts o1'the new requirements under CETA in a Supplement to the 2019 Integrated Resource Plan (lRP) on or bcforc Dcccmbcr 31, 2019. On March 8,2019, Wyoming Senate File (Str) 0159 was passcd into law. SF 0159 lirrits thc recovery costs fbr the retirement ol'coal Ilred electric generation facilities, provides a proccss fbr thc sale of an otherwise retiring coal llrcd electric generation lacility, exempts a person purchasing an cthenvise retiring coal fired electric gcneration fbcility fiom rcgulation as a public utility; requires purchase ol'electricity generated from purchased retiring coal fircd electric generation thcility (as specilied in Iinal bill); and provides an effectivc date. PacifiCorp and the Clalifornia Independent System Opcrator Corporation (CAISO) launchcd the voluntary energy imbalance market (EIM) November l,2014, the first western energy markct outside of Califomia. The EIM has produccd signilicant monetary benefits (.$736 million total footprint-wide benefits as of .luly 31, 2t)19). A signiticant contributor to E,lM bcncllts are transfbrs across balancing authority areas, providing access to lou'er-cost. supply, rvhile t-actoring in the cost ofccnrpliance rvith greenhousc gas emissions rcgulalions whcn energy is transl'erred into the CAISO balancing authority area. Nsar-temr pro{.rurement activities lbcused on three areas-the purchase and sale of renewablc cncrgy credits, the purchase ol new or rcpowcrcd wind energy, firm porver lirr western balancing authority, and Oregon solar resources. 35 CHRprsR 3 - PIaNNING ENvIRoNMENT P^crFrCoRP 20l9lRP CHAPfLjR 3 PLANNING ENVIRoNMENT Chapter 3 profilcs the major external influences that all'sct PacifiCorp's long-term resource planning and recent procurement activities. Extemal intlucnccs include events and trends al1'ecting the economy, rvholesale porver and natural gas prices, and public policy and regulatory initiatives that inlluence thc cnvironment in rvhich PacifiCorp operates. Major issues in the porver induslry markct includc capacity resource adequacy and associated standards fbr the Westem Electricity Coordinating Council (WECC). As discussed clsovhcre in this IRP, Iuturc natural gas prices, the role of gas-fired generation and thc falling costs and increasing cfflcicncies ofrenewables are some ofthe critical lirctors attccting the selection ofthe portfolio that best achieves least-cost, least-risk planning objcctivcs. On the govemment policy and regulatory fiont, a significant issue facing PacifiCorp continues to be planning lbr an cvcntual, but highly uncertain, climate change regulatory regime. This chapter lbcuses on climate change regulatory initiatives. A high-lcvel summary of PacifiCorp's greenhouse gas emissions mitigation strategy is included as well as a review ofsignilicant policy developments ttrr ourrently regulatcd pollutants. Other topics covcred in this chapter include regulatory updates on the Environmental Protection Agency (EPA), regional and state climate change regulation, the status of renewable portfblio standards, and resource procurement activitics. PaciliCorp's systcm docs not operate in an isolated market. Operations and costs arc tied to a larger electric system known as the Westem Interconnection which tunctions, on a day+o-day basis, as a geographically dispersed marketplacc. Each month, millions ol rnegawatt-hours ol'encrgy are traded in the wholcsale electricity market. These transactions yield economic cfliciency by assuring that resources with the lowest operating cost are scrving demand in a region and by providing reliability benefits that arise fiom a larger porttblio ofresources. PacifiCorp actively participates in the wholesale market by making purchases and sales kr keep its supply portlblio in balance with customcrs' constantly varying needs. This interaction with the markct takes placc on time scales ranging from sub-hourly to years in advancc. Without the wholesale market, PacifiCorp or any other load serving entity ra,ould need to construct or own an unnecessarily large margin ol'supplics that would go unutilized in all but the most unusual circumstances and rvould substantially diminish its capability to cost effeclively match delivery pattems to the profile olcustomer demand. The benelits ol'access to an integratcd wholesale market have grown with the inoreased pcnctration of intermittent generation such as solar and wind. Intemittent generation tcnds to come online and go offline abruptly in congruence with changing weathcr conditions. Federal and state (where applicable) tax crcdits, declining capital costs. and improved technology perf'ormancc have put rvind and solar "in the money" in areas of high potential. As such, wind and solar will dominate U.S. capacity additions for the next decade. To better integrate these resourccs into the larger grid requires more flexible generation, transmission, new storagc tcchnologies, and market design changes. 36 I ntroduction Wholesale Electricity Markets P^CII.ICoRP_20I9IRP With regard to transmission, there are long-haul renewable-driven transrnission projects, in advanced development in the U.S. WECC. Thcsc lines ultirlately connect areas ol'high renervable potential and lorv population density to arcas o1'high population density with less renewable potential. This includes PacifiCorp's proposed 400-mile 1,500 rncgawatt (MW) Gatcway South projcct, with an online date of 2024, to transport Wyoniing wind to central Utah. Similarly, Gateway Wcst, a jointly proposed 1,000-mile project by PacifiCorp and ldaho Porver rvould transport Wyorring rvind lo rvcstcm Idaho to bc picked up lirr westrvard delivery with a 2024 online date. In the eastcm interconnect, the Grain Bclt Exprcss. a 780 milc 4,000 MW dircct- currcnt line is in advanced development to go live in 2021 to transpo( Kansas wind to Missouri, Illinois, and Indiana. Moreover, the eastem seaboard is seeing a rising acceptance of olf'-shore u,ind. After years of resistance, local opposition has sollened as technology improvements allow rvind turbines to be located t'urthcr fiom shore. To datc, castem states have sernctioned over 17,000 MWs ol'olllshore rvind power and the Bureau of Occ'an lJncrgy Managcmcnt has sccn rccord priccs paid for lcascs in federal rvaters. Regardless, offshore rvind remains expensive and requires govemment policy support and subsidization. The intermittency ofrenervable generation has also given rise to a greater need lbr fast-responding storage essential for grid stability and resiliency. Pumped storage has been the traditional storage option but expansion is extremely limited due to topography limitations, with the best resources already harnessed. Of rcmaining mechanical, thermal, and chsmical storagc options, Lithium-ion (Li-ion) batteries have shorvn the most promise in terms of cost and perfbrmance improvement. ln 2013, the Califomia Public Utility Commission (CPUC) required investor-o*,ned utilities to procure 1,325 MW ol'storage by 2020t that requirement is norv close kr being rnet. Utility-scale fbur-hour battery storage modules have lallen in price to S l500ikilowatt (kW); costs are cxpected to continue to decline as electric vehicle manulacturing drives further innovation. To date, five states have implemenled energy sloragc targets or mandales, with another 1wo states seriously considering implcmentation.r In California, the world's largest Li-ion battery, 300 MW. is scheduled to go online at Pacific Cas & Electric (PG&E)'s Moss l-anding Power Plant in 2021. Hybrid co-located solar photo voltaic (SPV) and batlcry systems are now in Hawaii, Arizona, Nevada, Calilbmia, and Texas. ln Irebruary 2019, Arizona Public Scrvicc announccd it would pair existing solar rvith 200 MWs of battery storage rvhile Nevada Energy has contracted for 100 MW of battery storage to be paired with solar. But. perhaps most importantly, in 2018, the Federal Energy Regulatory Commission (FERC) directcd rcgional transmission organizations (RTO) and independent system operators ([SO) kr develop market rules for the participation ofenergy storage in wholesale energy, capacity, and ancillary services marketsr. The FERC gave operators nine months to file tarifl-s and another year to implement - esscntially opcning wholesale markets to energy storagc. Operators' proposed tariffs have varied substantially among regions rvith PJM requiring a l0-hour continuous discharge capability rvhile New England rcquires a continuous 2- hour capability. As part of its 2019 IRP, PacifiCorp is evaluating the cost ellectiveness ofseveral energy storage systems, including pumped skrrage, stand-alone li-on batteries, trs rvell as co- locatetl solar and co-located rvind.l I Califbmia, New Jersey, Ncw York, Massachusetts, {nd Orcgon havc cithcr mtndalcd or sct cncrgy storagc tartte(s while Nevada and Arizona are seriousJy studying thc implementation oftargets,:162 ILRCI61,l27UnitedStatcsolAnrcricanFcdcral Encrgy Rcgulatory Cornmission, l8CFRPan-'i5[DockctNos.RMI6- 23-000; AD I 6-20-000; Order \o. 841I Eledtk: Skrrtge Partic irotbti in lrla*cts Operdrcd h.\, RaEional Tran.snisyitn Organizotiotts unct lntlependent Svsttu Oper,rr.r/ (l ssucd Fcbruary I 5. 20 I 8) r Solar or wind resources couplcd rvith baltcry storagc. (' ,\pI R:i Pl.,\NNrN(i ENVrrtoNN,rr,Nr 31 l'^crr,r(1)RP 20l9lRP Incrcascd renewable generation has also contributed to the need for balancing sub-hourly demand and supply across a broader and more diverse market. For balancing purposcs, PacifiCorp combined its resources with those ol'the CAISO. The resulting EIM became operational November l, 2014. By Dcccmbcr 2015, Ncvada Energy hadjoined as did Puget Sound Energy and Arizona Public Scn,ice in 2016. Portland General Electricjoined in 2017, followed by Pou'erex and ldaho Power in 2018, and Balancing Authority of Northem Calil'omia in 2019. Today, Salt Rivcr Projcct and Seattle City Light are slated to join in 2020; Los Angeles Water & Powcr, Northwestern Energy, and Public Service Company of Ncw Mcxico in 2021 , ibllowed by Avista and '['ucson Electric Power in 2022. The multi-scrvicc arca lbotprint brings greater resource and geographical divcrsity allowing for increased reliability and cost savings in balancing generation with demand using l5-minute interchange scheduling and tlve-minute dispatch. CAISO's role is limitcd to thc sub-hourly scheduling and dispatching of'participating EIM gcncrators. CAISO does not have any other grid opcrator rcsponsibilitics for PacifiCorp's scrvice areas. As with all markets, electricity markets are f'aced with a wide range ol uncertaintics. Howcver, some uncertainties are easier to evaluate than others. Markct participants are routinely studying dcmand unccrtaintics drivcn by wcather and overall cconomic conditions. Similarly, there is a rcasonable amount ofdata available to gauge resource supply developments. The North American tslectric Reliability Corporation (NERC) publishes an annual assessment ol regional powcr reliability and any number of data services arc availablc that track the status of nerv resource additionsr. In its latest assessmcnt, publishcd Dcccmbcr20l8, the NERC indicates that WECC as a whole, has adequate resources through 2026. However, WECC's Northwest Power Pool (NWPP), Rockies, and southwest reserve sharing group (SRSG) sub-regions thll short starting 20275. The NE,RC's probabilistic studies indicatc that WECC's CAiMX sub region's resource adequaoy is at risk during offpeak hours, starting as early as 2020. There are other uncertainties that are more difficult to analyze that can heavily inlluence ths direction of future prices. One such uncertainty is the evolution o['natural gas priccs ovcr the coursc ol'the IRP planning horizon. Given the incrcascd rolc of natural gas-fired generation, gas prices are a critical determinant of westem electricity prices, and this trend is expected to continuc over the term of this plan's decision horizon. Another critical uncertainty that wcighs hcavily on thc 2019 [RP, as in past IRPs, is thc unccrtainty surrounding future greenhouse gas policies, both federal and/or state. PacifiCorp's official fonvard price curve (OFPC) does not assume a l'cdsral carbon dioxide (CO:) policy, but other price scenarios developed fbr the IRP consider impacts of polcntial future f-ederal CO: emission policics. Horvcvcr, PaciliCorp's OFPC does include enforceable state climate programs that have been signed into lau 6. Natural Gas U ncertainty Sincc 2008, North Amcrican natural gas markcts havc undergone a remarkable paradigm shifl. As sliown in F igure 3. [, llenry tlub day-ahead gas prices hit a high ol$ 13.31/MMBtu on .luly 2, 2008 irnd a low ol'$ I .49lMMBtu on Maroh 4, 2016. Day-ahead prices averaged $8.86/MMBtu in 2008, droppcd to 53.94 in 2009, and havc avcraged $2.82 since 2015. Day-ahead 2018 Henry Hub prices r 201 I l,ong-ternr Reliability Assessment. Decenlber 201 8. North American Electric Reliability Asscssn]cnt 'SRS(i: South!\cst Rcsenc Sharing (iroup: NWPP: Northwcst Porvcr Purl.t'A tbrecast ofCalifbrnia carbon allorvance prices is used as a proxy fbr future cap-and-trade allorvance auction priccr. Orcgon's Housc Bill 2020, establishing a Clinratc Policy Otlicc and dirccting it to adopt an Oregr-rn Climate Action Prograrn bv rule is still in Commirtee and has not yet bccn signed into lau. J6 ('ri,\P rr R i Pl. \\lN(,LNVTRo\r\'fl.\r P^( ,r(l)RP 2019IRI'CI I,\PTER 3 _ PLANNINc LNvIRoNMLNT averaged 53.15/MMBtu, down 64 percent liom 2008 prices. The relative price placidity srnce 2009, labeled the "Shale Cale", reflects a story ofsupply mostly that of Appalachian and, latcr, Permian supplyT. In 2009 Appalachia (mostly Pennsylvania and West Virginia), produced almost no natural gas; by latc 2013 it was producing almost I 2 BCF/D and by end-of-year 2018, Appalachia was producing over 28 BCF/D. ln short, supply from Appalachia continues to grorv as volumes and costs prove to be, respectively, higher and lower than anticipated. Today, Appalachia accounts for 34 percent ofthe nation's gas supply, and by 2040 is expected to account fbr ul4 percent, spurred by increased drilling elficiencies and rising demand. ure 3.1 - H llub l)Ahead Cas Price Histo Source: Thomson Reuters as cited by the Energy Infbrmation Administration at *'wu..eia. gov/dnav/ng/hist/mgw hhdD.htm. Historically, deplction 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 shows natural gas by source and location. ? Other significant shale gas plays includc: Bagle Ford (TX); Hayncsvillc (LA/TX); Niobrara (CO/WY); and thc Bakken (ND/MT). s18 S16 514 512 S10 $8 $6 54 s2 so II u1 O@t l! aO Qg O O O O .r d N rl (n ln * ll 4 '/1 OOr\ N&@Oce999e9c?9?r !r,ri;i!ritriiEiiisiE:s gi g! gi gi gi gtis isi Rise of Permian Su r Technological advancements yield gro!,/th in shale gas supply ' Economi( downturn E E -AnnualAverage r oay Ahead hd€x Shale Gale 39 Rise nf Annalarhian Srrnnlv t... Fi ure 3.2 - U.S. D Natural Gas Production Trillion Cubic Feet Figurc 3.3 - Lowcr 48 States Shale Plays Sourcc: U.S. [)cpartmcnt ol Flncrgy, Encrgy Inftrrmation Administration Reference 2020 2030 2050 tighUshale gas 2014history projections Lower 48 states shale plays ',Q eIa F l- \T -t- a a t d 6 dr. nd1 db6 ai&atd .di \. trs-;",**tu f_-. ' Mk d rri. t cDl !r.y- M'r.d lrEE a ll.E l* d.y.,. [&.d rh& e (baloEilbloE{rld.b.i pl.y -- &,6d $J. e l.n b..jl.b.4n.bt@ prry - c6rn ,.t - d.r fir.d prry cm"l pby - iirn dr- d.Cr.t .b.r.d pr., cdEr t3 - .n.De6.{/laie.r .hdcd pry 40 P^crrrcoRP - 2019IRP CHAPITiR 3 Pr.A\N1N(i F,NVtRo\MliN I --- I I I rer Iower 48 lower 48 offshore other 60 50 40 30 20 10 2010 2040 o 2000 iobrata Permian Figure 3.4 - Plays Accounting for All Natural Gas Production Orowth 201I -2018 Bakken Marcellu Eagle F Source: Drilling Pntdudi|it).Report, Ma! ll.1019. U.S. Dcpartmcnt ofEnergy. Energy Information Adminislration Figure 3.5 shows Henry Hub NYMEX futures, as of May 28, 2019. While lutures are rising it would appear that price expectations ofl'er little "signal-to-drill" after all, annual Iutures don't even crack $4.00 pcr MMBtu. Ilut as produccrs chase production etficiencies the "signal+o-dril1" price becomes lower. Producers have discovered the economics o1'scale ofdeeper ll'ells, super laterals, clustered well spacing, and repetilive tiacking. The Utica's'Purple Hayes" rvell, drilled in 2017, is over 27,000 t'cct dccp with a lateral cxtcnsion ot'20, 803 feet.8 As such, it has onc ofthe longest onshore laterals ever drilled. The developer estimated that supersizing the well yielded an incremental intemal rate ofretum ol'130 percent and 215 perccnt, fbr condensate and natural gas, respectivcly. But, for the next decade ultra-cheap natural gas will come fiom oil-targeted plays, especially in the Permian Basin. West Texas lntcrmediate two-year futures are curently hovering around S58/banel -- more than enough to spur oil-targeted drilling in westem Canada, the Permian, and Bakken. In the Bakken break even costs are below $SOibarrel, *'hile in the Permian, break-even costs range from S26ibarre[ to S50ibarrel. Moreover, producers are "front-loading" oil production which releases a disproportionately large amount ofassociatcd gas. Front-loading involves drilling closely spaced "child" wells to quickly boost initial oil production but the resulting decrease in well pressure also releases inordinate quantities of associated gas.e This is especially true of Permian Basin oil wells, whose output naturally contains 20 to 50 pcrcent natural gas. Currently, there is not cnough Permian take-away capacity to accommodate this surge ofnatural gas. As such. lhere's been heavy flaring and pricing dislocation in the Permian as evidenced by Waha cash prices which averaged a negative $3.75lMMBtu on April 3, 2019. New take-away capacity coming 8 Super Laterals: Going Reall.v, Reall.,- Long in lp1tulncltra, Larry Prado, IIan Dnergy. q Note that $,hile liont-loading increases initial produclion it ollcn shortons productive well life P^crFrCoRP-f0l9lRP CItAprER 3 - PLANNTN(; ENvTRoNMENT 4l tt{It PA( rCoRP-2019lRl'('lrAP rr,R i Pr.{\\rN(, []\\jrr{o\\rri\ r online in 2019 2020 will help alleviate the glut but natural gas prices are expcctcd to remain depressed through 2020. In 2016, lollou,ing crude's pricc collapse, U.S. production finally t'cll to 8.8 million barrels ol'oil per day (MMbpdr0) liom a high of 9.6 MMbpd in 2015. In 2018, U.S. production averaged 10.9 MMbpd, hitting an all-time high ol' I 1.97 MMBpd in December 2018. Moreover, thc IltA estimatcd that as of April 2019, 8,390 rvells rcmain drilled but uncompleted; thcse wells can be put into production quickly and rcprcscnt a significant source ol'supplyll. U.S. production can ramp up very quickly. This rcsiliency ofsupply coupled with the flexibility to quickly ramp up production will shorten thc lcngth of asynchronous supply and demand cycles. Unexpected weather-induced demand spikes or supply disruptions will still whipsaw prices for short pcriods of time. But, [-iquelicd Natural Gas (LNC) stanups, outages or dial backs could swing prices for longer periods given thc magnitudc of volumes coupled with locational concentrationrl. The global LNG market is cxpccted to be in oversupply through 2022, cspecially during summer months. Summer feed gas normally bound for liquetaction would then be diverted onto thc U.S. market, depressing prices. This summer dial back rvill act to also moderate winler priccs by increasing storage and thc likelihood ofentering rvinter with an overhang. Although U.S. LNC tends to be the marginal global supplier, buyers are interested in U.S. LNC due to its lorv-cost natural gas supply and contract flexibility. Of note, even oil-rich Saudi Arabia has entered into a 2O-year supply agreement lbr U.S. LNG. The imported LNG is expected to be used to replacc Saudi Arabia's oil-lired power gencration, thereby freeing up oil lirr export. To summarize, the key drivers ol'U.S. demand are: t) LNG exports, 2) Mexican exports, and 3) pou,er generation. OI'the threc, power generation is by lar the largest but exports (especially LNG) arc thc fastest growing. ro MMbpd: Million barrels per day,rr lrlA does not distinguish between oil and gas u,ells since ovcr 50 percent of wells produce bothrr (iurrent and cxpcctcd l-acilities are mostly concentrated in the GulfCoast. 42 4 1.5 1.5 l 1.5 I 0.5 0 ;, Annual Strip as llf i\'la1 28, 2019 'at F urc .J.5 - Hcn Huh NYNIEX Futurcs Appalachian gas production will slow in the 2020s as associated gas, fiom oil+argeted plays, displaces it. However, Appalachian production and take-away capacity will pick up in the 2030's as associated gas volumes begin to dwindle. Rocky Mountain production gets squeezed by rvcstcm Canadian, lower-48 associated gas, and Appalachian volumes. In the Northwest, rvhere 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 Appalachia in serving AECO's Ontario and Midwest markets. In short, the challenge in gauging the uncertainty in natural gas markets rvill be one of timing. The North Amcrican natural gas supply curve conlinues to Ilatten as production ettciencies expose an ever-increasing resilient, flexible, and low-cost resource base. In such a world, 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 altematives and the cost of existing resources in PaciliCorp's generation portfolio. PacifiCiorp monitors these regulalions to determine the potential impact on its generating assets. PacifiCorp also participatcs in rulcmaking processes by tiling comments on various proposals, participating in scheduled hearings. and providing assessrrents of proposals. Federal Climate Change Legislation To date, no federal legislative climate change proposal has been passed by thc U.S. Congress. The election ol Donald Trump as U.S. President rcduces the likelihood of federal climate change legislation in the near term. 4i P^crlrCoRP-20l9lRP CHAPTER I - PLA\\-tNG ENvIRoNVEN I The Future of Federal Environmental Regulation and l New Source Perlbrmance Standards for Carbon Emissions -CleanAirAct$ lll(b) New Sourcc Performance Standards (NSPS) are established under the Clean Air Act for cerlain industrial sources of emissions determincd to endanger public health and rvelfare. On August 3, 2015, the United States Environmental Protection Agency (EPA) issued a flnal rule limiting CO: emissions liom coal-fuclcd and natural-gas-fueled power plants. New natural-gas-fueled power plants can emit no morc than 1,000 pounds of CO: per mcgawatt-hour (MWh). New coal-fuclcd power plants can emit no more than 1,400 pounds of C0:/MWh. The final rule largely cxe mpts simple cycle combustion turbines fiom meeting the standards. On Deccmber 6, 2018, the EPA proposed kr revise the NSPS for greenhouse gas emissions liom new, modified, and reconstrucled fbssil lucl-fired power plants. EPA's proposal would rcplace EPA's 2015 determination that carbon capture and storage technology was the best system ol emissions reduction for new coal units. The comment period tbr the proposed revisions closed in March 2019. On Fcbruary 9, 2016, the U.S. Supreme Court issued a stay ofthe CPP suspending implemcntation of the rule pending the outcome of the mcrits of litigation belore the D.C. Circuit Court of Appeals. On October 10, 20 I 7, thc EPA proposed to repeal the Clean Power Plan and on August 2 I , 201 8, proposed the Affordable Clean Energy (ACE) rule to replace the Clean Power Plan. The ACE rule sets forth a list of"candidate technologics" that states can use to reduce grccnhouse gas emissions at coal-lireled porver plants. The ACE rule was finalized.lune 19, 2019 replacing the Clean Power Plan. Clean Air Act Criteria Pollutants - National Ambient Air Quality Standards Thc Clean Air Act requires EPA to set National Ambient Air Quality Standards (NAAQS) tbr six criteria pollutants that have the potential of harming human health or the environment. The NAAQS are rigorously vctted by the scientific community, industry, public interest groups, and the gencral public, and establish the maximum allou,able concentration allowed for each "criteria" pollutant in outdoor air. The six pollutants arc carbon monoxide, lead, ground-level ozone, nitrogen dioxide (NOx), particulate matter (PM), and sulfur dioxide (SO:). Thc standards are set at a levcl that protects public health with an adequate margin ofsafcty. If an area is determined to be out olcompliance with an established NAAQS standard, the state is required to develop a statc l+ PACTTTCoRP 2019lRP CHAP I I,R J PI AN\IN{] E\VIRoN\,ILN I Federal Renewable Portfolio Standards Since 2010, there has been no significant activity in the development ol'a f'ederal rcnewable porttblio standard (RPS). Accordingly, PacifiCorp's 2019 IRP assumcs no federal RPS requirement over the course ofthe planning horizon. Federal Policy Update Carbon Emission Guidelines lbr Existing Sources - Clean Air Act $ lll(d) On August 3,2015, the EPA issued a final rule, relbrrcd to as the Clean Power Plan (CPP), regulating CO: emissions from existing powcr plants. P^crr,r(oRP-2019IRP Ct IAPTLR 3 - Pt-ANNIN(i ENVTR( )NNfl-.N I implementation plan for that area. And that plan must be approvcd by EPA. The plan is developed so that once implemented, the NAAQS ftrr the particular pollutant of concern will bc achieved. ln Octobsr 2015, EPA issued a final rule rnodifying the standards lor ground-level ozone fiom 75 pans per billion (ppb)to 70 ppb. On November 16,2017. thc EPA dcsignated allcounties rvhere PaciliCorp's coal facilities are located (Lincoln, Sweetwater, Converse and Campbell Counties in Wyoming; and Emery County in Utah) as "Attainment." On June 4,2018, the BPA designatcd Salt Lakc County and part of Utah County rvhcrc thc PaciliCorp Lake Side and Gadsby f'acilities arc located as "Marginal Nonattainment." A Marginal dcsignation is the least stringent classification firr a nonattainment area and does not require a frlrrnal State lmplementation PIan (SIP), however Utah has until 2021 to develop ways to meet the standard. Regional Haze EPA's regional haze rule, finalized in 1999, requires states to develop and implement plans to improve visibility in certain national park and wildcrncss areas. On June 15, 2005, EPA issued flnal amendments to its regional haze rule. These amendments apply to thc provisions of'the rcgional haze rule that require emission controls known as the Best Available Retrofit '['echnology (BART) tbr industrial facilities meeting ce(ain rcgulatory criteria with emissions that have the potential to affect visibility. These pollutants include fine PM, NOx, SO:, ccrtain volatile organic compounds, and ammonia. The 2005 amendments included final guidelines, known as IIART guidclincs, fbr statcs to use in determining which lacilities must install controls and the type of controls the facilities must use. States were given until December 2007 to develop their implementation plans, in u'hich states rvere responsible for identifying the facilitics that would havc to rcduce emissions under BART guidclines, as well as establishing BART emissions limits for those fhcilitics. States are also required to pcriodically update or revise their implementation plans to reflect current visibility data and the effectiveness of the state's long-term stratcgy lbr achicving reasonable progrcss to*'ard visibility goals. On December 14,2016, EPA issued a final rule setting tbrth revised and clarifoing requirements lbr pcriodic updates in state implementation plans. States are cuncntly required to submit thc next periodic update by July 3l , 2021 . The regional haze rule is intended to achieve natural visibility conditions by 2064 in specific National Parks and Wildemess Areas, many ot'r.r,hich are losated in Utah and Wyoming where PacifiCorp operates generating units, as well as Arizona whcrc PacifiCorp owns but docs not opcrate a coal unit, and in Colorado and Montana where PacifiCorp has partial ownership in generating units operated by others, but are noncthclcss subject 1() the regional haze rule. On December 20, 2018, the EPA preparcd a tinal guidance document to support states with the technical aspects of developing reginal haze state implementation plans for the sccond implementation period of the Reginal Haze Program. 45 ln April 2017, the EPA Administrator signed a final action to reclassify the Salt Lake City and Pr<lvo PM:.s nonattainment area from Moderate to Serious. PacifiCorp's Lake Side and Gadsby facilities were identified as major sources subject to Utah's serious nonattainment area SIP fbr PM:.s and PM:.s precursors. On April 27,2017, PaciliCorp submitted a best-available control measurc technology analysis for Lake Side and Gadsby to the Utah Division of Air Quality for review. On January 2,2019, the Utah Air Quality Board adopted source specific emission limits and operating praotices in the SIP in which incorporated the current emission and operating limits for the Lake Side and Cadsby facilities. P^c[,rCoRr, 20l9lRP (]Ii,\P I I.,R 3' PL.\NNI\G I]NVIRONI!{ENT Utah Regional Haze ln May 2011, the sttrte of Utah issucd a regional haze state implementation plan (SIP) requiring the installation of'S0:, NO, and PM controls on Hunter Units I and 2 and Lluntington Units 1 and 2. [n Dcccmbcr 2012, the EPA approved the SO: portion olthe Utah regional hazc SIP and disapproved the NOx and PM portions. EPA's approval of the SO: SIP was appcalcd to f'ederal circuit court. In addition, PacifiCorp arrd the state of Utah appealed EPA's disapproval ofthe NOx and PM SIP. PaciliCorp and the state's appeals rvere dismisscd. In June 2015, the state of Utah submitted a rcviscd SIP to EPA lirr approval u'ith an updatcd llARf analysis incorporating a rcquirement lor PacifiCorp to retire Carbon Units I and 2, recognizing NOx controls prcviously installed on Hunter LJnit 3, and concluding that no incremental controls (beyond thosc included in the May 201 I SIP and alrcady installed) u,ere required at the Huntcr and Huntington units. On .lune l, 2016, EPA issued a final rule to partially approve and partially disapprove the Utah's regional haze SIP and propose a I'ederal implementation plan (trlP). The final rule requires thc installation of selective satalylic reduction (SCR) controls at four of PacifiCorp's units in Utah: Hunter Units I and 2, and Huntington Units I and 2. On Septembcr 2,2016, PacifiCorp filed petitions tbr administrative and judicial revieu, of EPA's final rulc and requested a stay ol'the cf-ftctive date olthe final rule. Unless the EPA's FIP is staycd or reversed, the controls are requircd to be installed by August 4, 202 I . On October 28,2016. PacifiCorp filed a motion lor stay with the l0'h Circuit Court. EPA sent lettcrs to Utah and PacifiCorp on July 14,2017, indicating its intent to reconsider its FIP. EPA also filed a motion rvith the l0'h Circuit Court ofAppeals to hold the litigation in abcyancc pending the rule's reconsideration. On September ll,ZOl7, the lOth Circuit Court granted the petition for stay and the request for abatement. Thc compliance deadline of the FIP and the litigation were stayed indellnitely pending EPA's reconsideration, and EPA was requircd to t'ile status repor1s with the Court. The EPA Iiled its lirst status report on December 13,2017. The report stated that EPA was working rvith Utah to develop additional information in support ol'its rcconsideration. The report stated that once the technical analyses (CAMx air quality modeling) had been fully developcd, the EPA would procced rvith rulemaking. Final ('AMx modeling reporls were dclivered by PacifiCorp to Utah on September 21,2018. On March 6, 2019, Utah Division of Air Quality stall'presented a revised Utah Regional Haze SIP, bascd on the new modeling, to the Utah Air Quality Board. The Utah Air Quality Board voted in favor ol sending the revised SIP out for public comment. On March I l, 2019 EPA filed its latest status report rvherein EPA indicated that it was rvorking with Utah to incorporate the results ol'the analysis. On April I , 201 9, the SIP revision rvas rclcased for a 45-day public comment period, u'hich closed on May 15, 2019. On June 24,2019, the Utah Air Quality Board unanimously voted to approve the Utah Regional Haze SIP Revision which incorporatcs and adopts the tlAR l Altemative into Utah's Rcgional Hazc SlP. Thc llAR't Alternative niakes the shutdor.vn o1'PaciliCorp's Clarbon Plant enforceable under the SIP and removes the requircmcnt to install SCR on [[unter Units 1 & 2, arrd Huntington Units I & 2. Thc statc's flnal rulc was published in the Utah Bulletin on July 15, 2019 and had an cffcctivc datc of August t5,2019.'lhe Utah Division of Air Quality submittcd the SIP Revision to the EPA for revieu on July 3,2019. On September 9,2019, thc EPA provided a status report on Utah Regional Haze to the U.S. l0'r'Circuit Court of Appeals. The update statcd that EPA is reviewing Utah's proposcd SIP Revision, which rvas submitted by the statc on July 3,2019. 16 l',\( rr rf oRP l0l 9 lRI)CHAPTER 3 PL,\\NrNG ENVTRo\NrL."r Howcver, the EPA also stated that it u'as rvaiting on Utah to submit an additional minor rcvision to the SIP to address cerlain recordkeeping and reporting requirements. -l'he additional modification relates to particulate matter (PM) cmissions and exceedance reporling. rvhich rvas a conditional requirement lrom EPA's 2016 partial approval of thc SIP. The minor revision was proposcd to the Utah Air Quality Board on September 4, 201 9 and rvas issued tbr public comment on Octobcr l, 2019. A draft ofthe revision was scnt to EPA lur concurrent revierv on October 2, 2019. The state anticipates getting final approval from thc Utah Air Quality Board during its Novcmber board meeting and fbrmally submitting the minor revision to EPA in December 2019. The Westcrn Regional Air Partnership (WRAP) is currently developing the modeling that the statc rvill use for the implementation ofthe second planning pcriod. Utah will use a'Q/d' screening of l0 kt detennine which sources will be subject to the rule. Thc state is expecting to notify the cftcctsd sources soon and will require the sources to conduct a four-factor analysis. It is expected that thc Hunter and Huntington facilitics u,ill be subject to the rule. Wyomins Rcgional Haze On January 10, 2014, EPA issued a final action in Wyoming rcquiring installation of the follorving NOx and PM controls at PacifiCorp lhcilities: o Naughton Unit 3 by Decembcr 31, 2014: SCR equiprnent and a baghouseo Jim Bridgcr Unit 3 by December 3 I , 20 I 5: SCR equipmento Jim Bridgcr Unit 4 by December 3 I , 2016: SCR equiprrento J im Bridger Unit 2 by December 31,2021: SCR cquipmentr Jim Uridger Unit I by f)ecenrber 31,2022: SCR cquipment r Dave Johnston Unit 3: SCR rvithin five years or a commitmcnt to shut down in 2027. Wyodak: SCR equipment within Iive years Wyodak - Different aspects of EPA's final aclion rvcrc appealed by a nurnber of entities. PaciliCorp appealed EPA's action requiring SCR at Wyodak. PacifiCorp succcssfully requested a stay oIEPA's action as it pertains to Wyodak pcnding resolution ofthe appeals. Naughkrn - In its 2014 rule, EPA indicated suppon for the conversion ofthc Naughton Unit 3 to natural gas and statcd that it rvould cxpcditc consideral.ion ol the gas conversion once the state ol Wyorning submitted the requisite SIP amendmcnt. Wyoming submitted its Regional Haze SIP rcvision regarding Naughton Unit 3 to EPA on Novernber 28, 2017. On March 7, 201 7. Wyoming issued PaciliCorp a pcrmit rvhich allowcd fbr adjusted emission limits upon Unit 3's conversion to natural gas; and allorved for operation of Unit 3 on coal through January 30, 2019. PaciliCorp ceased coal operation on Unit 3 on January 30. 2019 as required by the permit. EPA's final rulc approving Wyoming's SIP revision for Naughton Unit 3 gas conversion was published in the Fetleral Register on March 21,2019, with an elTective date of April 22,2019, On May 24,2019, PacifiCorp providcd Wyoming with a noticc ol'commencement of construction for upgrades supporting Unit 3's conversion to natural gas, along with a noticc of initial startup on natural gas firing in accordance with statc pcnnits and EPA's approval of the Wyoming SlP. Jim Bridger - SCR nas installed on Jim Bridger Units 3 and 4 by the dates required in the 2014 final rule. On February 5,2019, PaciflCorp submitted to Wyoming an application and proposcd SIP revision which would institute plant-rvide variable average monthly-block pound per hour 41 1,,\crrrCoRP - l0lI lltP C ,\PTER 3 PI AN\tN(i l-l\vlRoN\{ENI NOx and SO: crnission limits, in addition to an annual combincd NOx and SO: limit, on all lbur Jim Bridger boilers in lieu of the recluircmcnt to install SCR on Units I and 2. Thc application demonstrates that the proposed limits arc morc cost effective, results in less overallcnvironmental impacts, and leads to bctter modeled visibility that SCR installation on Units I and 2. Wyoming is reviewing thc application in coordination rvith EPA. WRAP is currently developing the modcling that the state u,ill use for the implemcntation olthe second planning period. Wyoming has not determined which sources rvill be subjcct to the rule. Arizona Regional I laze The state olArizona issued a regional hazc SIP requiring, among other things, thc installation of SOz, NOx and PM controls on Cholla Unit 4, which is owned by PacifiCorp but operated by Arizona Public Scrvice. EPA approved irr part and disapprovcd in part the Arizona SIP and issued a FIP requiring the installation of SCR equipment on Cholla Unit 4. PacifiCorp Iiled an appcal regarding the FIP as i1 relates to Cholla Unit 4, and the Arizona Departmenl of Environmental Quality and other all'cctcd Arizona utilities filed separate appeals ol'the FIP as it relates to their interests. For thc Cholla FIP requirements, the court stayed thc appcals rvhile parties attempt to agree on an alternative compliance approach. In .luly 201 6, the EPA issucd a proposed rule to approve an altemative Arizona SIP, which includes converting Cholla 4 to a natural gas-fired unit or shutting thc unit down in 2025. EPA approved the revised SIP on March 27 ,2017 . WRAP is currcntly dcvcloping thc rnodeling that the state rvill use lbr the implcmentation of the second planning period. Arizona will usc a 'Q/d' scrccning of20 to detenrine rvlrich sourccs rvill be subject to the rule. The statc has notitled the effected facilities has is requiring thc facility to conduct a four-fbctor analysis by end ol' 201 9. Colorado Rcsional Hazc The Colorado regional haze SIP required SCR controls at Craig Unit 2 and Hayden Units I and 2. In addition, the SIP required thc installation of selective non-catalytic reduction (SNCR) technology at Craig Unit I by 2018. Environmental groups appealed EPA's action, and PacifiCorp intenened in support ofEPA. In July 2014, parlies to the litigation other than PaciliCorp entered into a settlement agreement that rcquires installation of SCR equipment at Craig Unit I in 2021. ln February 2015, the State ofColorado submitted a revised SIP to EPA for approval. As part ola lurther agreement between the owncrs of Ciraig Unit l, state and lederal agencies, and parties to previous scttlcmcnts, the owners of Craig agreed to retire Unit I by December 31, 2025, or convert the unit to natural gas by August 31,2023. The Colorado Air Quality Board approved the agreement on December I 5, 2016. Colorado submitted the corresponding SIP amendment to EPA Region 8 on May 17,2017. EPA approved the SIP onJuly 5,2018. WRAP is currently developing the modeling that the slatc will usc tbr the implernentation ol'the second plirnning pcriod. Colorado rvill usc a 'Q/d' screening of l0 to determine which sourccs w.ill bc subject to the rule. l'he state is expecting to notify the elI'ected lacility soon and will require the lacility to conduct a four-factor analysis by end ol20l9. 48 l)^crFIC0RP 2019 IRP CIlAP I IlR :J _ PI,A TNINC [rNV]RONMHN,I Mercury and Hazardous Air Pollutants The Mercury and Air Toxics Standards (MATS) became cfl'ective April 16, 2012. The MATS rule required that new and existing coal-fueled tbcilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources wcre required to comply with the new standards by April 16,2015. Ho*'ever, individual sources may havc been granted up to one additional year, at the discretion ofthe Title V permitting authority, to completc installation ofcontrols ur for transmission system reliability reasons. By April 2015, PacifiCorp had taken thc required actions to comply with MATS across its generation facilities. On April 25, 2016, the EPA published a Supplemental Finding that determined that it is appropriate and necessary to regulate under the MATS rule which addressed the Supreme Coun dccision. On February 7, 201 9, the EPA published a reconsideration ofthe Supplemental Finding in which it proposed to find that it is not appropriate and necessary to regulate hazardous air pollutants, reversing the Agency's prior determination. The comment period on the proposed rule closed on April 17,2019. PacifiCorp is awaiting EPA's final action. 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 wastcs under an amendment to the Resource Conservation and Recovery Act (RCRA); however, EPA issued a flnal rule in December 2014 to regulate CCRs for thc flrst time. Under the tinal rule, EPA will regulatc CCRs as non-hazardous waste under Subtitte D of RCRA and establish minimum nationwide standards for the disposal ofCCRs. The linal CCR Rule became elfective October 19,2015. Under the final rule, surface impoundments utilizcd fbr CCRs may need to close unless they can mect more stringent regulatory requirements. At thc time the rule u'as published in April 201 5, PacifiCorp operated l8 surface impoundments and seven landfills that contained ClCRs. Befbre the effective date in October 2015, nine surlhce impoundments and three landfills were eithcr closed or repurposed to no longer receive CCRs and hence are not subject to the linal rule. 'Ihc final CCR regulation was set up to be enlbrced by citizen suits; however, in September 2016, the Senatc passed, and in December 201 6 Presidcnt Obama signed, the Coal Combustion Residuals Regulatory lmprovemcnt Act, rvhich sets forth the process and standards fbr EPA approval (and rvithdrau,al) of a state's permitting program firr coal combustion residual units. A state may incorporate cither the requirements of the EPA rule into its permit program or other state rcquirements that, based on site-spccilic 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.r 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 entbrcement authorities. Beforc EPA can take enforcement action in an authorized state, EPA must consider any other actions against thc facility and determine ifan enforcement action by EPA "is likely to be necessary" to ensure the f'acility is operating in accordance with its permit rcquirements.o Authorizes EPA to operatc a permit program in lndian country.. Provides a permit shield for t-acilities that are operating in accordance \r'ith a state- or EPA-issued permit. 49 P^CIFICORP 20I9 IRP CIIAPI.F]IT 3 PI,ANNINC I]NVIRONMI.]N I . Preserves other lcgal authorities or regulatory determinations in eff'ect before enactment CCR Litieation On August 2l, 201 8 the U.S. Court of Appeals lor thc District of Columbia issued a decision in thc Utilin, Solid Wasle A(Iivities Group, el ol.. vs. Enrirorlnrcnlol Protection Aget?c.r'casc over the 2015 CCR Rulc. Specifically, the (irurt vacated and remandcd 40 CIiR $ 257.101(a) to EPA tbr additional consideration "consistent" with the Court's opinion. '[ he l0l(a) provision relates to the tirning of closure for unlined CCR impoundments. PacifiCorp is awaiting EPA's final action. Water Quality Standards C'ooling Wal.cr Intakc Structures Thc f'edcral Water Pollution Control Act ("Clean Water Act") establishes thc frameu,ork lbr maintaining and improving \\'ater quality in the Unitcd States through a program that regulales. among other things, discharges to and rvithdrarvals t'rom u,atenvays. Thc Clean Water Act rcquires that cooling water intake structures rctlcct the "best technology available lor minimizing adverse environmental impact" to aquatic organisms. In May 2014, EPA issued a final rule, effective October 2014, under r 3 l6(b) ofthe ('lean Water Act to regulate cooling rvatcr intakes at existing thcilities. The llnal rulc cstablished requirements lbr electric generating t'acilities that rvithdraw more than two million gallons per day, bascd on total design intakc capacity, of water fiom rvaters ol'the Unitcd States and use at least 25 percent of the rvithdrawn rvaler exclusivcly tbr cooling purposes. PacifiCorp's Davc Johnston generating Iacility withdrarvs more than trvo million gallons per day ol'rvater tiom walers ol the U.S. fbr once-through cooling applications. Jim Bridger, Naughton, Ciadsby, llunter, and Huntington generating lacilities currently usc closed-cycle cooling torvers and withdrarv more than two million but less than I 25 million gallons ol' rvater per day. Thc rulc includes impingemenl (i.e., when fish and othcr aquatic organisms are trapped against screens rvhen u,alcr is drarvn into a lircility's cooling system) mortality standards and entrainment (i.e., whcn organisms are drawn into the facility)standards. The standards will be set run a casc-by-case basis to be determincd through site-specilic studies and will he incorporated into cach t'acility's di scharge pcrmit. 50 Rulc-rcquired permit application rcquirements (PARs) havc been submitted to thc appropriate perrnitting authorities lbr thc Jim l3ridger, Naughton, Cadsby, Hunter and Huntingtor plants. As the five lacilitics utilize closed-cycle rccirculating cooling rvatcr systems (cooling towers) cxclusivcly tbr equipment cooling, it is cxpected that state agcncies rvill require no further action t'rom Pacifi('orp to comply rvith the rule-required standards. Because Davc Johnston utilizes onco-through cooling rvith rvithdrarval rates greatcr than 125 million gallons per day, thc lacility has been required to conducl more rigoruus permit application requirements. The Davc Johnston permit application rcquirements rvere submitted to the Wyoming Water Quality Division on May 31,2019. Thc application proposed that no modillcations to the intake structure were required; horvcver, upon review,ol'thc submittal the Water Quality Division may require the Iacility to conduct an impingemcnt characterization study. tf an irnpingement charactcrizalion study is required, thc llnal disposition of the Davc Johnston cooling watcr intake structure will not occur until the Watr-r Quality [)ivision has rcvicrved the study results. E,llluent [-irnit Ciuidelines EPA first issued ellluent guidelines lbr the Stcam Electric Porver Cencrating Point Source Category ( i.e.. the Stcam Electric e llluent guidelincs or "ELG" ) in I 974, rvith subscquent revisions in 1977 and 1982. On Novembcr 3,2015, the agency issued a flnal rule entitlcd Elfluent Lintitotions Guidelines arul Stundurtls Jbr the Ste am Eleclrit' Prmer Ge nerating Poinl Sourt'e Cotegon'. The revised rule addressed the follolving wastestreams produccd by steam-generation po*'er plants: ( l) llue gas desullirrization (*FGD") waste\ryater; (2) t1y ash transport wastewaterl (.i) bottom ash transport wastc$'atcrl (4) flue gas mercury control ("FGMC"') uastcu'ater ("Hg control rvaste"); (5) combustion residual lcachate (t)r "Leachate"): and (6) gasilication waslewalcr. Compliance u,ith the revised ELG is required by dates determined by the pcrmitting authority, r.r,hich must be as soon as possiblc beginning November l, 20 18, but no later than Dccember 3 I, 2023 (compliance deadlines are gencrally expected to be set at NPDES permit renewal dates). On Scptember 18,2017, EPA announced that it intcnds to conduct a rulemaking to revise the definitions of Best Availablc Technology Econornically Available ("BAT") elllucnt limitations, and Pretreatment Standards for lixisting Sources ("PSES") fbr cxisting sources for bottom ash transport water and llue gas desulfurization rvastcu'aler. EPA is postponing thc earliest compliance dates tbr the new. more stringent, BAT etJluent limitations and PSES lor both waste streams l'or a period oftwo years to Novembcr l, 2020. BAT effluent limitations and pretreatment standards lor all other wastestreams, or any ofthe othcr requirements in the 2015 Rule will not be revised during this rcconsideration. EPA's action to postponc compliance dates in the 2015 Rule is intended to presen/e the status quo tbr FGD waste$,ater and bottom ash transpod *,ater until EPA completes its next rulemaking. 2015 Tax Extender Legislation On December 18, 2015, President Obama signed tax extender lcgislation (H.R. 2029) that retroactively and prospectively extended certain expired and expiring i'edcral income tax deductions and credits. Bonus Derrreciation Filty perccnt bonus dcprcciation was extended for propcrty acquired and placed in sen'icc during 20 I 5, 20 I 6, and 20 I 7. []or property acquiretl and placed in sen,icc during 20 I 8. 40 percent of the eligible cost of thc propcrty qualilics l'or bonus depreciation. For property acquired and placcd in service during 2019, 30 percent olthc cligible cost ofthe propeny qualilies lor bonus depreciation. F'or property placed in service alier December 3 I , 20 I 9, there will he no bonus dcprcciation. rr rr There is an cxceplion lirr long-production-period property (generally propcrty with a construction period longer than one year and a cost exceeding $1 million). Costs incurred on long-production-pcriod propcny may qualify fbr bonus dcprcciation ifphysical construction has begun belbrc thc placcd-in-service date ofthe bonus phass-out. 5t P,\('r1 rC oRP 2019 IRP Clt^l,r r,R i - PLANNTN(; E\vrRoN\.fliN r On April 12,2019, the Fifih Circuit Court of Appeals vacated the pofiions of thc rulc thal set BAT fbr combustion residual leachate and legacy \4'astewater, and rcmanded those sections to thc EPA for rcconsideration. PacifiCorp is awaiting EPA's linal action. Production Tax C'redit ( Wind) P^( rfr(l)RP - 2019 IRP 'Ihe 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 belbre January l, 2020. as tb[lows: o 2015 - 1007n retroactiveo 2016 - 100% (construction begins belbre January 1,2017)o 2017 - 80% (construction begins belbre January l,2018)o 2018 - 607o (construction begins beltrre January 1,2019)c 2019 - 40o/o (construction begins belbre January 1,2020) Production Tax Credit (Geothermal and Hydro) The PTC for geothermal and hydro were granted a two-year extension as follows (no phase-out period was adopted): . 2015 - 100% retroactiveo 2016 - 100% (construction begins before January 1,2017) 30% Enersv Investment Tax Credit (Wind) The investment tax crcdit (l'IC) has heen extcndcd and phased out lbr wind property f'or which construction begins before January l, 2020, as follorvs: o 2015 - 30%o retroactiveo 2016 - 30ok (construction begins before January 1.2017). 2017 24% (construction begins belirre January l, 2018)r 2018 l8% (construction begins betbre January 1,2019). 2019 - 1270 (construction bcgins belore January 1,2020) E ner Invcstmcnt I'ax C'redit Solar The ITCI has been extended and steps down fbr solar property lbr which construction begins before January l, 2022, as lbllows:. 2015 - 300/o retroactive o 20[6 30% (construction begins befbre January l, 2017)t 2Ol7 - 30% (construction begins bctbre January l,2018)o 2018 - 30% (construction begins before January 1,2019)o 2019 - 30%o (construction begins before January I , 2020)o 2020 - 260/o (construction begins be fore Jan mry I , 2021)o 2021 - 22% (construction begins before January l, 2022)o 2022 - l0% (construction begins on or afier January 1,2022) Californ ia Under the authority ol the Global Warming Solutions Act, the Clalifomia Air Resources Board (CARB) adopted a greenhouse gas cap-and-trade program in Ockrbcr 201l, with an effectivc date ofJanuary l, 2012; compliancc obligations rvere imposed on rcgulated entities beginning in 2013. The first auction ofgrcenhouse gas allou,ances was held in California in November 2012, and the 52 ClAl,t r,lr J Pt ,\NNrN(; EN VrrtoNMr,N I P^CIFICoRP _ 20 I9 IRP CHAPTER 3 PLAN\-ING ENVIR0NVFTNT second auction in February 2013. PacifiCorp is required to sell, through the auction process, its directly allocatcd allowances and purchase the required amount of allou,ances necessary to meet its cornpliance obligations. In 2002, Califomia established a RPS requiring investor-owned utilities to increase procurement from eligible renewable energy resources. Califomia's RPS requirements have bccn accelerated and expanded a number of times since its inception. Most recently, in September 2018, Govemor Jerry Brown signed into law the 100 Pcrccnl Clean Energy Act of20l8, Senate Bill (SB) 100, which requires utilities to procure 60 perccnt ol their electricity from renewables by 2030 and enabled all the state's agencies to work toward a longer-term planning target fbr 100 percent of Califomia's electricity to come liom renewable and zero-carbon resources by Decembcr 3 l, 2045. Oregon In 2007, the C)regon Legislature passed House Bill (HB) 3543 - Global Warming Actions, which establishes grcenhouse gas reduction goals for the state that: (t) end the growth of Oregon greenhouse gas emissions by 2010; (2) reduce greenhouse gas levels to ten percent below 1990 levels by 2020; and (3) reduce greenhouse gas levels to a1 |east 75 percent below 1990 levels by 2050. ln 2009, thc legislature passcd SB l0l, which requircs the Public Utitity Commission of Oregon (OPUC) to submit a report to thc legislature before Novcmber I ol-each even-numbered year regarding the estimated rate impacts for Oregon's regulated electric and natural gas companies ol'meeting the greenhouse gas reduction goals ol'ten percent below 1990 levels by 2020 and 15 percent below 2005 lcvcls by 2020. The OPUC submitted its most recent report November I , 2014. In 2007, Oregon cnacted SB 838 cstablishing an RPS requircmcnt in Oregon. Under SB 838, utilities are required to deliver 25 percent of their electricity from renewable resouroes by 2025. On March 8, 2016, Govemor Kate Brown signed SB I 547-8, the Clean E,lectricity and Coal Transition Plan, into law. SB 1547-8 extends and expands the Oregon RPS requirement to 50 percent ofelectricity from renewable rcsources by 2040 and requires that coal-l'ueled resources are eliminated liom Oregon's allocation of electricity by January l, 2030. The increaso in thc RPS requirements under SB 1547-8 is staged-27 percent by 2025, 35 percent by 2030, 45 percent by 2035, and 50 percent by 2040. The bill changes the renewable energy certificate (REC) lit'c to live years, rvhile allowing RELIs gencratcd liom the effective datc ofthe bill passage until the end of 2022 fr<tm new long-term reneu'able projccts to have unlimited life. Thc bill also includes provisions to create a community solar program in Orcgon and encourage greater reliance on electricity for transportation. J-) ln May 2014, CARB approved the lirst update to the Assembly Bill (AB) 32 Climate Change scoping plan, which detlned Califbrnia's climate change priorities lbr the next five years and set the groundwork fbr post-2020 climate goals. In April 2015, Govcmor Bro*,n issued an executivc order to establish a mid-term reduction targct lbr Califomia of40 perccnt below 1990 levels by 2030. CARB has subsequently been directed to update the AB 32 scoping plan to rellect the nerv interim 2030 target and previously established 2050 targct. Washington In November 2006, Washington voters approved Initiative 937 (l-937\, thc Washington Energy Independence Act, which imposes targets for energy conservation and the usc of eligible PA( I.rCoRP-2019IRP Cr T PTER 3 PT.ANNTN(; ENVTRoNMINT renewable resourccs on electric utilities. Under l-937, utilities must supply l5 percent of thcir energy liom rcnervable resources by 2020. Utililies nlust also sct and meet energy convcrsation targels starting in 2010. ln 2008, the Washington Legislature approved thc Climate Change Framework E2SHB 2815, which establishes thc following state grecnhouse gas emissions rcduction limits: (l) reducc emissions to I990 levels by 2020: (2) reduce emissions to 25 pcrcent below 1990 levels by 2035; and (3) by 2050, reduce emissions to 50 percent below 1990 levels or 70 percent belorv Washington's forecasted emissions in 2050. In July 2015, Governor Inslee relcased an executive order that directed the Washington Department of Ecology to develop new rules to reduce carbon emissions in the statc. In December 2017, Washington's Superior Coun concluded that the Department of Ecology did not have the authority to impose thc Clean Air Rule without legislative approval. As a result, the Department ofEcology has suspended the rule's compliance requirements. Utah In March 2008, Utah enacted thc 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. lt sets out a goal for utilities to use eligible renewable resources to account [br 20 percent ofthcir 2025 adjusted retail electric sales. On March 10,2016, the Utah legislature passed SB ll5-The Sustainable Transportation and Energy Plan (STEP). The bill supports plans for electric vehicle inlrastructurc and clean coal research in Utah and authorizes the development of a renewable energy tariff for nerv Utah customer loads. The legislation establishcs a five-year pilot program to provide mandated funding tbr clectric vehicle infrastructure and clean coal research, and discretionary tunding for solar development, utility-scalc 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 mcchanism to manage risks and provide planning flexibility associated with environmental compliance or other ecnnomic impairments that may afl'ect PacitiCorp's coal-fueled resources in the future. The def'errals of variable power supply costs went into effect in June 2016, and implementation and approval ofthe other programs was completed by January l, 2017. Wyoming On March 8, 2019, Wyoming Senate File 0159 was passed into law. SF 0159 limits the recovcry costs for the retirement of coal lircd electric generation facilities, provides a process lbr the sale In 2019, the Washington Legislature approved the Clcan Energy Translbrmation Act (CETA) rvhich requires utilitics to eliminate coal-lired resources from Washington rates by December 31, 2025, be carbon neutral by January l, 2030, and establishes a targct of 100 percent of its electricity liom rcnervable and non-emitting rcsources by 2045. Rulemaking by state agencies, including the WUTC and the Washington Dcpartment of Commerce commenced in July 2019. PacifiCoryr is participating in rulemaking proceedings and will pcrtbrm an analysis ol'the portfblio effects ol'thc new requirements under CETA in a Supplemcnt to the 201 9 IRP on or before March 3 l, 2019. 54 PACTITCoRP 20l9lRP CHAPTER 3 PLANNTNC ENVTRONMLTN r of an otherwisc rctiring coal fired clcclric generation facility, exempts a person purchasing an otheru,ise retiring coal fired electric generation facility fiom regulation as a public utility; requires purchase of electricity generated lionr purchased retiring coal lired electric generation thcility (as specified in linal bill); and providcs an cli'ective date. Cost recovery associated with electric generation built tu replace a retiring coal tircd generation facility shall not be allowed by the commission unless thc commission has determined that the public utility made a good faith cltort to sell the facility to anolhcr person prior to its retirement and that thc public utility did not rcfuse a reasonable offer to purchase the lacility or the commission determines that, if a reasonablc oflbr was received, the sale was not completed for a reason beyond the reasonable control ofthe public utility. Under SF 0159 clcctric public utilitics, other than cooperative electric utilities, shall be obligated to purchase electricity generated from a coal llred electric generation facility purchased under agreement approved by the commission, provided the otherwise retiring coal llrcd electric generation facility of1-ers to sell some or all ofthe electricity liom the f'acility to an electric public utility, the elcctricity is sold at a price that is no greater than the purchasing electric utility's avoided cost, the electricity is sold under a power purchase agreement, and thc commission approves a one hundred percent cost recovery in ratcs fbr the cost ofthe power purchasc agreement and the agreement is one hundred percent allocated to the public utility's Wyoming customers unless otheruisc agreed to by the public utility. Greenhouse Gas Emission Perlbrmance Standards Califomia, Orcgon and Washington have all adopted greenhouse gas emission performance standards applicable to alI electricity generated in the state or delivered from outsidc the state that is no higher than the greenhouse gas emission levels ofa state-olthe-art combined cycle natural gas generation lhcility. The standards I'or Oregon and Calilbrnia are currently set at 1,100 [b CO:/N1Wh, which is defined as a mctric measure used to compare the emissions liom various greenhouse gases based on their global rvarming potcntial. In September 2018, the Washington Departmenl ol'Commerce issued a new rule lou,ering the emissions perfbrmance standard to 925 lb COr/MWh. An RPS requires a retail seller ofelectricity to include in its resource portfolio a ccrtain amount of electricity from renewable energy resources, such as wind, geothermal and solar energy. The retailer can satisly this obligation by using renewable energy liom its own lacilities, purchasing renervable energy from another supplier's facilities, using Renewable Energy Credits (RECls) that certifu renewable energy has been generated, or a combination olall ofthese. RPS policies are currently implemented at the state level and vary considerahly irr their renervable targets (pcrccntagcs), targct dates, rcsource/technology eligibility, applicability ol'cxisting plants and oontracts, arrangements for enforcement and penalties, and use of RECs. In PacifiCorp's service territory, Calitbmia, Oregon, and Washington havc cach adopted a mandatory RPS, and Utah has adopted a RPS goal. Each of these states' legislation and requirements are summarized in Table 3.1 , with additional discussion below. 55 Renewable Portfolio Standards Iable 3.1 - State RPS R uirements California SB 2 (lX) created multi-year RPS compliance periods, which were expanded by SB 100. The Caliltrmia Public Utilities Commission approved compliancc periods and corresponding RPS procurcment requirements, which are shown in Table 3.2. 'table 3.2 - California Com liance Period Re uirements Compliance Period I (201l-2013) rr Ad.justments for gsncrated or purchased t'rom qualifying zero carbon emissions and carbon capture sequestration and DSM.ri wu'rv.leginfo.ca.gov/pub/ I l- l2ft,ill/son/sb 0001-0050/sbxl 2 bill 201 10412 chaptcrcd.pdl- r6 legintir.lcgislaturc.ca.gov/faces,/billNavClGnt.xhtml?bill idL0l5l0l60SB350 Califomia Oregon Washington Utah Lcgislalion . Senale Bill 1078 (2002). Asscmbly Bill200 (2005). Senatc Ilill 107 (2006). Senatc Bill2 First Extraordinary Session (201 l). Scnatc Billl50 (2015). Senrtc Bill I00 (2018) . Senate Bill838 Oregon Renc*ahle !:nerg)' Act (2007)r House Bill3039 (2009). Housc Bill 1547-8 (2016) . Senate Eill202 (2008) Requircment or Goal . 20q; h] l)ccember i l,l0ll. 159, b) Decembc. il.:(ll6. i-l% br Deccmber I l. :0lll. 14% h) l)ccember i l,:024. 52% b) Decembcr:i l,2i)27 . 609n b) Dec€mber ll,:010 and bclond. Planning rargel ol- 10{)'/o rcncwahlc and carbon-lice b) 20.1i* B,rscd on ihc .euil load lr'. x thrc€-ye.rr compliance pl':riod . 59,, b) Deccmhcr ll l. :01 I. I 5% bl Decembcr I I . l0 I 5. 209; hy l)rcemh(r 31. :020. 27% by l-rcc\inrbcr ll, 2025. 159/0 by Dcccnrber I l, 2030. 45o/" b)' t)ecembcr.ll. 20i5. 509t b) l)cccmbcr II. 2040* Bnsed on (hc rctail load for that !ear (;oalof20o/o by 2015 ( must be cosl eilcctivc Annuai targcts arc adiusledri retail salcs lor thc calendar .._ear 16 monrhs befbre thc larget ) ear Compliaoce Period Procurement Quantit\ Rcquirement Calculation (21 .7% * 2014 Rctail Sales) + (23.3% * 201 5 Retail Salcs) + (25% * 2016 Retail Sales) PAfIIIC0RP-20l9lRP ('llApl LR i - PLANNI\(i ENVTRoNNfl N I Califomia originally cstablished its RPS program with passage ofSB 1078 in 2002. Scveral bills that have sincc been passed into law kr amend thc program. ln the 201 I First Extraordinary Special Session, the Califomia Legislature passed SB 2 (lX) to increase Califomia's RPS to 33 percent by 2020.r5 SB 2 (lX) also expanded the RPS requirements to all retail sellers o['electricity and publicly owned utilities. In October 20 15, SB 350, the C lean Energy and Pollution Reduction Act, was signed into law.l6 SB 350 established a greenhouse gas reduction target of40 percent bclow 1990 levcls by 2030 and 80 percent below 1990 levels by 2050 and expanded the state's renewables portfolio standard to 50 pcrcent by 2030. In September 2018, the signing of SB 100, the Clean Energy Act of20l8, further expanded and accelerated the Califomia RPS to 60 percent by 2030 and directed the state's agencies to plan tbr a longer-term goal of t00 percent of total retail sales ofelectricity in Califbmia to come from eligible renewable and zero-carbon resources by December 3 l, 2045. . lnitiative Measure No. 937 (2006). SB 5400 (2013). SB sl l6 (2019) . lo'" b) Juruary l,:012. !)0./o br Januan t. ?016. l5% by January l, 2020 and bijyond. I0(l% csrhon neutral b) l0l0. llannin_{ larget of l00qi, r.net\able aM rcn-cmitling b) 1045 + Annral larPels are bascd on thc average of Lhc Lrtilit)'s load for lhe (20yo * 2Ol I Retail Sales) + (20% * 2012 Retail Sales) + (2lo/o * 2013 Retail Sales) Conrpliancc Pcriod 2 (2{) 14-2016) 56 ('ontpliancc t'criod I (l0l 7-1010) (21tyo * 2Ol7 Rctail Sales) i (lq9lo *:018 Rctail Salcs)i (31?i, * 2019 Rctail Salcs) + (33% * 2020 Relail Salcs) C ornpliance I'criod .l (l(121 -2014)(35.8% * 2tl2l Rctail Sales) + (38,5% * 2022 Rctail Salcs) + (11 .3yo * 2023 Retail Salcs) + (.14% * 2024 Retail Sales) Compliancc I'criod 5 (2025-2027)l47yo * 2025 Retail Salcs) + (50% * 2026 Retail Salcs) + (52o/b * 2027 Retail Sales) Compliance Pcriod 6 (1028-2010)(54.7% * 2028 Retail Salcs) + (i7.3% * 2029 Retail Salcs) + (60% * 2030 Retail Sales) SB 2 (lX) cstablishcd ncw "portfblio conl.ent categories" fbr RPS procurement, which dclineated the type of rcncwable product that may he used for compliance and also set minimum and maximurn limits on certain procuremcnt content categories that can bc used fbr compliance. Porrfolio Content Category I includes eligible renervablc cnergy and RECs that mecl qither of'the [bllorving critcria: Have a lirst point of interconnection rvith a Califbmia balancing authority, havc a lirst point of intcrconncction with distribution lacilities used to scrve end users rvithin a Calilbmia balancing authority area, or arc scheduled from the eligiblc rcnervable energy resource into a California balancing authority without substituting electricity from anothcr source;r7 or Have an agreement to dynamically transfbr electricity to a Califomia balancing authority. Portfolio Contcnt Catcgory 2 includcs lirmed and shaped cligible renervable energy resourcc electricity products providing incremcntal electricity and scheduled into a Calili)mia balancing authorily. Portlolio Content Category 3 includcs cligible reneu,able energy resourcc electricity products, or any fraction ol'tlre electricity, including unbundled rcnewable energy credits that do not qualily under the critcria ol Porttblio Content Category I or Porttblio Content Category 2. rB Additionally, the C'alifomia Public Utilities Clommission established the balanced portlolio requiremenls li.)r contracls executed al'ter June l, 2010. Thc balanced portfolio requircmcnts set minimum and maximum levels tbr thc Procurement Content Category products that may be used in each cornpliance period as shon'n in'l'ablc 3.3. i'- The use ofanothcr source to provide real-timc ancillary sen ices required to maintain an hourly or subJrourly impon schedule inro a Califirmia balancing authority is permitled. but only (hc liaction ofthe schedule actually generated by the eligible rencrvable energy resource rvill count tou,ard this portfolio contenl category. rr A REC can be sold either "bundled" with the underlying encrgy or "unhundled" as a separa(e commodity tiom the energy itsclf ink) a scparatc REC trading market. 57 PA(rHCoRP 2019 IRP Crr^p]t:R 3 - PLA\\rN( i FINVrRo\r'rE\T ( ornpliance Period I (201l-201..i)Category I - Minimum of 500/o of Requirement Category 3 - Maximum of 25% of Requirement Compliance Period 2 (2014-2016)Category I Minimum of 65% of Requirement Category i Maximum of J 5% of Requirernent Compliance Period 3 (2017-2020) Compliance Period 4 (2021-20?4) Cotrtpliance Period 5 (2025-2027) Compliance Period 6 (2028-2030) Clategory I Minimum of 7504 of Requirement Catcgory 3 - Maxirlum ol l0% of Requirement Table 3.3 - California Balanced Portfolio Re uirements In Dccember 201 l, the Califbrnia Public Utilities Commission (CPUC) conlirmed that multi- jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits in the three portfolio content catcgories. PacifiCorp is requircd to file annual compliancc reports with the CPUC and annual procurement reporls with the Califomia Energy Commission (CEC). Neithcr SB 350 nor SI) 100 changed the portfolio content categories for eligible renewable cnergy resources or the porlfblio balancing requirements exemption provided to PaciliCorp. For utilities subject to the portlblio balancing requirements, thc CPUC extended the compliance period 3 requirements through 2030. The Iull California RPS statute is listcd under Public Utilities Code Section 399.11-399.32. Additional inforrnation on the Califbrnia RPS can be hrund on thc CPUC and CEC websites. Qualitying renervahle resources include solar thermal electric, photovoltaic, landfill gas, wind, biomass, geothermal, municipal solid waste, energy storage, anaerobio digcstion, small hydroelectric, tidal cnergy, wave energy, ocean thcrmal, biodiesel, and fuel cells using renewable fucls. Renervable resources must bc certified as eligible lbr thc Califomia RPS by the CEC and tracked in the Westcm Rcnervable L.nergy Generation Intbrmation System (WREGIS). Oregon Oregon established the Oregon RPS with passagc of SB 838 in 2007. The law, called the Oregon Rencwable Energy Act, rr'as adoptcd in June 2007 and providcs a comprehensive renewable energy policy for the state.le Subjcct to ce(ain exemptions and cost limitations established in the Oregon Rene*'able Encrgy Act, PacifiCorp and othcr qualifliing electric utilities must meet a target ofat lcast25 percent renewahle energyby2025. In March 2016, the Lcgislature passed SB 1547,:0 also referred to as Oregon's Clcan Electricity and Coal Transition Act. In addition to requiring Oregon to transition off coal by 2030, the neu, law doubled Oregon's RPS requirements, which are to bc staged at 27 percent by 2025,35 percent by 2030,45 percent by 2035, and 50 percent by 2040 and beyond. Other components of SB I547 include: o Development of a community solar program with at least l0 percent of the program capacity rescrvcd lbr low-income customers. re wwu',leg.state.or.us/07reg/rneaspdt/sb{)lt{)0.dir/sb0838.en.pdf r0 olis.lcg. state.or.us/lizl201 6R I /Dou,n loads/MeasureDocumcnL/S B I 547/lrnrolled PA( I,r(lmP 2019 lRP CImPTIR ] _ PL^NNING ENVIRONMLN.T California RPS Compliance Period Balanced Portlirlio Requirement 58 P.\( rr r(i)r.rP l0l9lRP A requirement that by 2025, at lcast eight percent ofthc aggregate electric capacity ofthe state's investor-owned utilities must come fiom small-scale rencwable projects under 20 mega\Yatts. Creares nerv eligibility fbr pre-1995 biomass plants and associaled thermal co-generation. Under the previous law, pre- 1995 hiomass rvas not cligible until 2026. Direction to thc state's investur-owned utilitics to propose plans encouraging greater reliance on electricity in all modcs ol'transpoftation, in order to reduce carbon emissions. Removal ofthe Oregon Solar Initiative mandate.:r SB 1547 also modified the Oregon REC banking rules as follorvs: o RECIs generated befbre March 8, 2016, have an unlimitcd lif'e. o RECs generatcd during thc first I'ive years for long{crm projects corning online bctwccn March 8,2016, and December 31,2022, have an unlirnited lif'c.o RECIs generated on or after March 8, 2016, frorn resources that came online before March 8,2016, expire five years beyond the year the REC was gcncrated. o RECs generated beyond the first five ycars fbr long-term projects coming online between March 8, 2016, and December 3 I , 2022, expirc fivc years beyond the year thc REC is generated.o RECs generated fiom projccts coming online alier Dccember 31, 2022, expire tive ycars beyond the year the REC is generated. o Banked RECs can be surrendered in any compliance year regardlcss ofvintage (eliminatcs thc "tirsGin, tlrst-out" provision undcr SB 838). To qualily as eligible, thc RECs must be lrom a resourcc cerlilied as Oregon RPS eligiblc by the C)regon Depanment of Energy and trackcd in WREGIS. Qualilying renewable energy sources can be located anyrvhere in thc United States portion ofthe Westcm Electrisity Coordinating Council geographic area, and a limited amount o1'unbundled renewable encrgy crcdits can be used toward the annual compliance obligation. Eligible rencrvable rcsources include electricity generated fiom rvind, solar photovoltaic, solar thermal, r'ave, tidal, ocean thermal, geothermal, certain types of biomass and biogas, municipal solid waste, and hydrogen power stations using anhydrous ammonia. Eleotricity gcncratcd by a hydroelectric I'acility is eligiblc if the lacility is not located in any fbderally protected areas designated by thc Pacific Northwest Electric Power and Conservation Planning Council as ol'July 23, 1999, or any arca protected under the l'ederal Wild and Scenic Rivers Act, P.L. 90-542. or the Oregon Scenic Wateru'ays Act. ORS 390.805 to 390.9251 or if thc electricity is attributable to elficiency upgrades madc to the lacility on or after January l. 1995, and up to 50 averagc megawatts of'electrioity per year gcnerated by a certified low-impact hydroelectric facility owned by an electric utility and up to 40 average megawatts ofelectricity per year ggncraled by certilied low-impact hydroelectric f'acilities not or.r,ned by electric utilitics. l In 2009, Oregon passed llouse Bill 30i9, also callcd the C)regon Solar lnitiativc. rcquiring that on or belbre January l, 2020, thc total s()lar photovoltaic generating nameplatc capacity nrust be at least 20 megawatts liom all eicctric companies in the state. 'l he Public Utility (irmmission of Oregon determincd that PacitiCorp's sharc of the Oregon Solar lnitiative rvas 8.7 nregarvatts. CII l,lt tr -i Pr.,^\\rN(; ll\vrRoNVr,Nr 59 Pi\('Il,rCORP ]0lt) IRP CI I,\PTI.]R J Pl,ANNIN(j I]NVIIIONN{ENI PacifiCorp liles an annual RPS compliancc rcport by June I of evcry year and a rencrvable implementation plan on or belore January I ofeven-numbered ycars, unless otheru'ise dirccted by the Public Utility Commission ol'Orcgon. These compliance rcpofts and implementation plans are available on Pacifi Corp's websitc.22 The full Oregon RPS statute is listed in Oregon Revised Statutes (ORS) Chaptcr 469,{ 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 Cihapter 860 Division 084 for the solar photovoltaic program. Thc Oregon Department of Energy rules are undcr OAR Chapter 330 Division 160. Utah ln March 2008, Utah's govemor signed Utah SB 202, the Energy Resourcc and Carbon Emission Reduction Initiative.rr-l'he Energy Rcsource and Carbon Ernission Reduction Initiativs is codified in Utah Code'Iitle 54 Chapter 17. Among other things, this law provides that, bcginning in the year 2025,20 percent ofadjusted retail electric salcs ofall Utah utilities bc supplied by reneu,ablc energy if it is cost cl-fbctive. Retail electric salcs will be adjusted by dcducting the amount ol generation f-rom sources that produce zcro or reduced carbon emissions and for sales avoided as a rcsult ofenergy efficiency and demand side management programs. Qualilying rencwable energy sources can be located anyu'here in the Westem Electricity Coordinating Council areas, and unbundled renervable energy credits can be uscd for up to 20 percent of the annual qualifuing electricity targct. Eligible rencwable resourses includc clectricity from a f'acility or upgrade that bccomes opcrational on or after January l. 1995, that derives its energy f'rom wind, solar photovoltaic, solar thermal electric, wave, tidal or ocean thermal, certain types of biomass and biomass products, landlilt gas or municipal solid wastc, gcothermal, waste gas and waste heat capture or rccovery, and efficiency upgrades to hydroelectric facilities if'the upgrade occurred afler January l, 1995. Up to 50 average megawatts from a certified low-impact hydro facility and in-state geothermal and hydro gcneration rvithout regard to operational online date may also be used to*,ard thc target. To assist solar development in Utah, solar facilities located in Utah receive credit lbr 2.4 kilorvatt- hours ofqualilying clcctricity for each kWh ofgcncration. Under the Carbon Reduction Initiative, PacifiCorp is required to Iile a progress report by January I ofeach of the years 2010,2015,2020 and 2024. Follorving PacifiCorp's Decembcr 3t,2009 progress report, the Utah Division of Public Utilities' report to the Legislature stated: "Given PaciliCorp's projections of its loads and qualifying electricity fbr 2025, PacifiCorp is wcll positioned to meet a target ol'20 perccnt renewable energy by 2025." PacitiCorp tiled its most recent progrcss report on December 31, 2014. -l'his report shoncd that the company is positioncd to meet its 20 percent target requircment of apprtiximatcly 5.2 million mega\vatt-hours of renervable energy in 2025 l'rom existing company-orvned and contracted rcnclvable energy sources. rr w wrv.pacifi cpou,er.net/ORrps:r le.utah.gov/-200[i/bills/sbillenr/sb0202,pdf 60 P^c[,r(l)RP 2019 IRP C APTER 3 PI.A\NlN(i EN v rR( )\N.llr\t' Washington In November 2006, Washington voters approved,l-937, a ballot mcasure establishing the Energy Independence Act, which is an RPS and energy efficiency requircment applied to qualifoing electric utilities, including PacifiCorp.2a The law rcquires that qualifying utilities procure at least three percent of retail sales from eligible renervable resources or RECs by January I , 2012 through 2015; nine percent of retail salcs by January l,2016 through 2019; and l5 percent of retail sales by January l, 2020, and every year thcreafter. Eligible renewable resources includc clectricity produced fiom rvater, wind, solar energy, geothermal energy, landfill gas, wave, ocean, or tidal powert gas from sewage treatment facilities, biodisscl fuel with limitation, and biomass energy based on organic byproducts of the pulp and wood manulacturing process, animal u'aste, solid organic fuels irom u'ood, tbrest, or field residues, or dedicated energy crops. Qualifying renewable energy sources must be located in thc Paciflc Northwest or delivered into Washington on a real-time basis without shaping, storage, or integration services. The only hydroelectric rcsource eligible for compliancc is electricity associated with ctflcicncy upgradcs to hydroelectric facilitics. Utilities may use eligible rencwable rcsources, RECs, or a combination of both to meet the RPS requircment. PaciliCorp is required to file an annual RPS compliance report by Junc I oi every year with the WU'|C demonstrating compliance with the Energy lndependence Act. PacifiCorp's compliance reports are availablc on PacifiClorp's wsbsite.25 The WUTC adopted final rules to implement the initiative; the rules are listed in thc Revised Code of Washington (RCW) 19.285 and the Washington Administrative Code (WAC) 480-109. Undcr SB 5 1 I 6, passed in 201 9, Washington utilities are required to be carbon ncutral by January l, 2030 and institute a planning target ofone hundred percent clean electricity by 2045. Thc bill cstablishes four-year compliance periods beginning January l, 2030 and requires utilities to use electricity from renewable resources and non-cmitting electric generation in an amount equal to 100 percent ol'the retail electric load over each compliance period. Through December 31,2044, an electric utility may satisfy up to 20 percent of its compliancc obligation with an alternative compliance option such as the purchase ofunbundled RECs. The electric transpo(ation market is in an emerging state,26 and plug-in electric vehicles currently comprise a negligible share of PacifiCorp's load. This rapidly evolving market represents a potential driver of lulure load growth and those impacts managed proactively, providc an opportunity to increase the efficicncy of the electrical system and provide benefits for all 6l ln 2027, the legislation requires a commission rcport to the Utah Legislature, rvhich may contain any recommendation fbr penalties or other action for ['ailure to meet the 2025 targct. The legislation requires that any rccommcndation lor a penalty must provide that the penalty funds be used l'or demand side management programs lor the customers of the utility paying the penalty. Transportation Electrification } u,rvw.secstatc.wa.gov/clcctions/initiatives/tex l937.pdf :5 www.pacifi cpower,net/report 16 As ol-Junc 2019, thc market share ofplug-in electric vehiclcs rvas t\!o percent: rvwu,.nada.org/WorkArea/DotrnloadAssct.aspx?id:2 | 47485 8563 l',\(.lr,r(i)RP l0l9 IRI)(lHAp I FtR 3 - PLANNINc ENVTRoNMIIN I PacifiCorp customers. In addition, increased adoption of electric transportation has the ability to improve air quality, reduce greenhouse gas emissions, improve public health and safety, and create financial benelits fbr drivers, which can be a particular benelit fbr lorv and moderate income populations. To help manage and undcrstand the potential luturc load growth impacts ofelcctric transportation PacifiCorp is invcsting $26 million to support EV fast chargers along key corridors, devclop '*'orkplace charging programs, research nerv rate designs and implcment time-of-use pricing pilots, creatc partnerships for smart mobility programs and develop opportunities lbr customers in our rural communities. Our investments include a 54 million partnership award from the U.S. Department of Energy to research and develop elcctric transportation and $3 million as part ol'thc Oregon Clean Fucls Program. Givcn the emerging state of clectric transportation a forecast explicitly identifying the load associated rvith electric transponation on PacifiCorp's system is cunently unavailable. Electric vehicle load is, however, reflected in the Company's load lbrecast. PacifiCorp continucs to activcly engage with local, regional, and national stakeholders and participate in statc regulatory processes that can inlirrm futurc planning and load lbrecasting efforts. The issues involved in relicensing hydroelectric facilities are multitaceted. They involve numerous tbderal and state environmcntal laws and regulations, and the participation of numerous stakeholders including agencies, Native American tribes, non-governmental organizations, and local communities and govemmcnts. The valuc ofrelicensing hydroeleclric fhcilities is continued availability of energy, capacity, and ancillary services associated with hydroelectric generation. Hydroelectric projccts can often provide unique opcrational flexibility because thcy can be called upon to meet peak customcr demands almost instantaneously and back up intermittent renewable resources such as wind. ln addition to operational flexibility, hydroelectric generation does not have the emissions concems of thermal generation and can also ol'ten providc impodant ancillary services, such as spinning reservc and voltage support, to enhancc the reliability ofthe transmission system. On September 27, 2019, the FERC issued a new license order for the Prospect No. 3 Hydroelectric Projcct, a 7.2 MW project located in southem Oregon. The licensc period is 40 years. Conditions ofthe license are consistent with thc Commission's previous environmental analysis. Pursuant to the new license, PaciliCorp will implement increascd minimum flows downstrcam of the diversion dam, rcplace the project's rvood-stave llorvlinc and sag-pipe, upgrade and construct new wildlit'c crossings over the walerway, and prepare and implement various monitoring and management plans. With the exception of the Klamath Rivcr and Weber hydroelectric projects, all of PacifiCorp's applicable generating tacilities now operate under contcmporary licenses from thc FERC. tn 2019, PaciliCorp initiated the FERC relicensing proccss fbr the Cutler Hydroclectric Project. This 30 MW project is located in Utah and has a 30-year license period that ends March 2024. Under a 2010 settlement agrccmcnt, amended in 2016, the 169 MW Klamath Hydroclcctric Project is anticipated to opcrato under its existing license until project operations ceasc in 2021 r.r,ith the 62 Relicensing P^( rfrCoRP-l0l9lRP CHApIITR 3 PI-ANNINC LNVIRoNMLN r The I:ERC hydroelectric relicensing process can bc cxtremely political and often controversial. The process itself requircs that thc project's impacts on thc surrounding environment and natural resources, such as fish and wildlif'c, bc scientifically evaluatcd, lbllorved by developrncnt ol' proposals and alternatives to mitigatc those impacts. Stakeholdcr consultation is conductcd throughout the process. Il'resolution of issues cannot be reached in this process, litigation often ensues, u'hich can bc costly and time-consuming. The usual alternativc to relicensing is decommissioning. Both choiccs. however, can involve signilicant costs. F-ERC has sole jurisdiction under the Federal Power Act t<l issue new opcrating licenses for non- federal hydroelectric projects on navigable waterways, I'ederal lands, and under other criteria. FERC must find that the project is in the broad public intcrcst. This requires weighing, with "equal consideration," the impacts ofthe project on fish and u,ildlife, cultural resources, recreation, land use, and aesthetics against the project's energy production benetlts. Because some of the responsible state and f'ederal agencies have the ability to place mandatory conditions in the license, FERC is not always in a position to balance the energy and cnvironmental equation. For example, the National Oceanic and Atmosphcric Administration Irisheries agency and the U.S. Fish and Wildlilb Service have the authority in the relicensing process to requirc installation offish passage facilities (fish laddcrs and screens) and to specifu thcir design. This is oftcn the largest single capital investment that will be considcred in relicensing and can significantly impact project economics. Also, because a rnyriad ofothcr state and federal laws comc into play in relicensing, most notably the Endangered Species Act and thc Clean Water Act, agcncies' interests may compete or conllict rvith each other, leading to potcntially contrary or additivc liccnsing requirements. PacifiCorp has generally taken a proactive approach towards achieving the best possiblc relicensing outcome fbr its customers by cngaging in negotiations with stakeholders to resolve complcx reliccnsing issues. In some cases settlcmcnt agreements are achieved rvhich are submitted to FERC lor incorporation into a new license. [r[:RC] welcomes license applications that reflect broad stakeholder involvenrent or that incorpurate measures agrccd upon through multi- party settlement agrccmcnts. History demonstrates that with such support, [rERC generally accepts proposed nerv license terms and conditions rellected in settlemcnt agreements. Potential Impact Rclicensing hydroelectric facilities involves significant proccss costs. The FERC reliccnsing process takes a minimum ol five years and may take longer, depending on the characteristics of the project, Ihc numbcr of' stakeholders, and issr.rcs that arise during the proccss. As of Decembcr 31, 2016, PacifiCorp had incurcd approxinrately $16 million in costs for license implernentation and ongoing hydroeiectric relicensing, rvhich are included in construction rvork- in-progress on PacifiCorp's Consolidatcd Balance Sheet. As currcnt or upcorring relicensing and settlemcnt elforts continue lor the Weber, Cutlcr and other hydroelectric projects, additional process costs are being or will be incurred that rvill nced to be recovered from customcrs. llydroclectric relicensing costs have and rvill continue to ha\,e a signilicant impact on overall hydroelcctric generation cosl. Such costs include capital investrnents and related opcrations and maintenance costs associated with fish passage facilities, recrcational lhcilities, wildlife protection, water quality, cultural and flood managcmcnl measures. Project opcrational and florv-related changes, such as increased in-stream llow requiremcnts to pr()tcct aquatic resourccs. can also 63 decommissioning of thc project. The assumed date of Klamath project removal in the IRP is January I , 2021 . 'l'he 3.85 M W Weber project is currently in the FERC relicensing proccss. P^CIIICoRP 20I9 IRP CII,,\pIiR 3 PT.ANNTN(; [iNVIRoNN,fliN I directly result in lost gcncration. The majority of these relicensing and settlement cosls relatc 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 scttlement commitments are incorporated in the projection of existing hydroelectric resources discussed in Chapter 5. PacifiCorp's Approach to Hydroelectric Relicensing PaciliCorp continues to managc the hydroelectric relicensing process by pursuing interest-based rcsolutions or negotiatcd settlements as part of rclicensing. PaciliCorp believes this proactive approach, rvhich 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 agrecments with licensing stakcholders to decommission projects where that has heen the most cost-effective outcomc for customers. Current rate designs in Utah havc evolved over time based on orders and dircction from the Public Sen'ice Commission of Utah and ssttlement agrecments between parties during general rate cases. Most recently, currcnt rales and rate design changes were adopted in Docket No. l3-035-184. The goals for ratc design are (generally) to reflect the cost to scne customers and to provide price signals to encourage economically efficient usage. This is consistent with resource planning goals that balancc consideration ofcosts, risk, and long-run public policy goals. PacifiCorp curently has a number of rate design elements that take into consideration these objectives, in particular, rate designs that rellect cost differences for energy or demand during differcnt time periods and that support thc goals ofacquiring cost-eU'cctive energy efficiency. Residential Rate Design Rcsidential rates in Utah are comprised ofa custumer chargc and energy charges. The customer charge is a monthly chargc that provides limited rccovery of customer-rclated costs incurred to serve customcrs regardless of usage. All other remaining costs arc recovered through volumetric- based energy charges. Energy chargcs for residenlial customcrs are designed rvith an inclining-tier rate structure so high usagc during a billing month is charged a higher ratc. This gives customers a price signal to cncourage reduced consumption. Additionally, energy charges are dill'ercntiated by season with higher rates in the summcr rvhen the costs to servc are higher. Residential customers also have an option lbr time-of-day rates. Time-ol'-day ratcs have a surcharge lbr usage during thc on-peak periods and a credit for usage during thc otf-peak periods. This rate structure provides an additional price signal to encourage customers to use less energy during the daily on-pcak periods when energy costs are highcr. Currently, less than onc pcrcent of customcrs have opted to participate in the time-of-day rate option. 64 Utah Rate Design Information Changes in residential rate dcsign that might lacilitate IRP objcctives include a criticaI peak pricing program or an expansion of time-of'-use rates. Thcsc types of rate designs are discussed in morc detail in Volume l, Chapter 6 (Resourcc Options). As part ol'the STEP legislation enacted in SB ll5, the company developed a pilot time-of-use program to cncourage off-peak charging of electric vehicles fbr rcsidential customers. The results of this pilot may infbrm future rate design P^crrrCoRP - 2019 IRP CIIApTER 3 - PLAtiNtNG ENVt RoNtllt-.Nt offerings. Any changes in standard residential rate design or institution oloptional rate options to support energy efficiency or time-differentiated usage should be balanced with the recovery of Iixed 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 privatc distributed generation, rates have begun to evolve to address the change in usage requirernents and ensure appropriate cost rccovery liom these customers. A deeper consideration ol'the implications ofcurrent rates and ratc dcsigns is ncccssary to addrcss growing issues with privatc generation and ensure the appropriate price signals are set for the changing circumstances. As a result ofa scttlement in Docket No. l4-035- I 14, new customer generators in Utah receive expon credits that are valued at a diflbrent rate than rctail rates as part of a transition program. Commercial and Industrial Rate Design Commercial and industrial rates in Utah include customer charges, facilitics charges, poncr chargcs (lirr usage over l5 kW) and cncrgy charges. As with residential rates, customer chargcs and lacilities charges are generally intended to rccover costs that do not vary r,r'ith energy usage. Power charges are applied to a customer's monthly dcmand on a kW basis and are intended to recover the costs associated with demand or capaoity needs. Energy charges arc applicd to thc customer's metered usagc on a kWh basis. All commercial and industrial rates employ seasonal variations in power and/or energy charges with highcr rates in the summer 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 difterentiated hy on-peak and off-peak periods tbr both powcr and encrgy charges. For commercial and industrial customers with load less than 1,000 kW, the company offers two optional time-of-day rates-one that ditTerentiatcs energy rates lbr on- and 611:'peak usage, and one that dift'erentiates power charges by on- and off-peak usagc. Currcntly, about l9 percent olthe eligible customers arc on the energy time-of-day option and less than one percent arc on the power time-of-day option. Irrigation Rate Design Irrigation rates in Utah are comprised ofan annual customer chargc, a monthly cuslomer charge, a scasonal power charge, and energy charges. The annual and monthly customer charges providc some recovery of customer-related costs incurrcd to serve customers regardless ofusage. All other remaining costs are recovered through a seasonal power chargc and energy charges. The power charge is for the irrigation season only and is designed to recover demand-related costs and to encourage inigation customers to control and reduce power consumption. Energy charges for irrigation customers are designed with two options. One is a time-of-day program with higher ratcs fbr on-peak consumption tnun 1-o.6ft--pcak consumption. Irrigation customers also have an option to participatc in a third-party operated lrrigation Load Control Program. Customers are oll'ered a tinancial incentive to participate in the program and give the company the right to interrupt service to the participating customers when energy costs arc higher. PacifiCorp and the CAISO launched the EIM Novembcr 1,2014. The EIM is a voluntary market and the first westem energy market outside of Califomia. The EIM covers eight states in the United States of America and one province in Canada-British Columbia, Califomia, Nevada, Arizona, 65 Energy Imbalance Market PACrr,rCoRP 20l9lRP CHATTER 3 - PLAr.rNrNc ENVTR0NMENT Idaho, Oregorr, Utah, Washington, and Wyoming-and uses CAISO advanced markct systems to dispatch the least-cost rcsources every five minutes. Since the launch of the ElM, NV Energy joined the markct Dccember 1, 2015; Puget Sound Energy and Arizona Public Service joined October l, 2016t Portland General Electric joined Octobcr l, 2017; Idaho Power and Porverex joined April 4,2018; Balancing Authority of Northcm California./Sacramento Municipal Utility District Phase I joined April 3, 20 I 8. Entities scheduled to join the EIM include Salt River Project and Seattle (lity Light in April 2020; and Los Angeles Department of Power and Water, NorthWcstem Encrgy, 'l'urlock Irrigation District, BANC Phase 2 and Public Service Company ol' Nov Mexico in 202 1; and Tucson Electric Porver, Avista, Tacoma Porver and Bonneville Power Administration in 2022. PaciliCorp continucs to work with the CAISO, existing and prospective EIM entities, and stakcholdcrs to enhance market functionality and support markct growth. Figure 3,6 - Energy lmbalance Markct Expansion P Sqottle Ciry Lighr Tocomo Powcr I Pordond Gcnerol Elechic L lrrigoli Dirtri cl Solt Rivcr Project Power The EIM has produced significant monctary benefits ($736 million total footprint-wide benefits as of July 31, 2019), quantified in the lollowing categories: (l) more efficient dispatch, both inter- and intra-regional, by automating dispatch every l5 minutes and every five minutes within and across the EIM footprint; (2) reduced renewable energy curtailment by allowing balancing authority areas to export or reducc imports ofrenewable generation that would otherwisc need to 66 [os oI & T I I T I II fE t, \ I r\ N t [*I 7:]t' Poworcx l)^( r r('( )RP l0l9lRP CIIAPTLR 3 - Pl-ANNTNG ENVTRoNMENT be curtailed; and (3) reduoed need for flexibility reserves in all EIM balanoing authority areas, also referrcd to as diversity benefits, which reduces cost by aggregating load, wind, and solar variability and forecast errors ofthc EIM tbotprint. A significant contributor to EIM benefits are transfcrs across balancing authority areas, providing access to lower-cost supply, rvhile factoring in the cost of'compliance rvith greenhousc gas emissions regulations whcn energy is transf'erred into the CAIS0 balancing authority area to serve California load. The transfer volumes arc therelbre a good indicator of a portion of the benefits atlributed to the EIM. Transfers can take place in both the llve and l5-minute market dispatch intcrvals. After development and expansion of thc EIM in the west, a natural next qucstion is - are there continued opportunities to increase economic efficicncy and renervable integration bcyond the scope ol'EIM but short ol'a Iully regional independent system operator? PacifiCorp believcs the anslver may be yes, but scvcral itcms that are critical to its succcss rvill need creative solutions; resourcc sufficicncy, transmission utilization, voluntary nature and govcmance. Currently, the benefits of an extended day-ahead market (EDAM) in the rvest have not been asscssed and the markct design has not yct been developed. The concept of cxtending day-ahead market services are included in thc CAISO's 2019 Drali Policy Initiatives Roadmap, which has an EDAM stakeholder initiative which entered the tirst stage of policy development Octobcr 10, 2019, with the issuance of an Issue Paper by the CAISO. The EDAM stakeholder initiative rvill tacklc questions such as transmission utilization, grid management charges, govemance and regulatory considerations in an open forum to reach consensus on a viable EDAM conccpt. PacifiCorp issued and will issue multiple requests for proposals (RFP) to secure resources or transact on various energy and environmental attribute products. Tahle 3.4 summarizes rcccnt RFP activities. Tahle 3.{ - PaciliC ,s uest tbr Activitics I)urchase renervable energl credits tbr Oregon Schedule 272 participation C Ioscd August 2017 Septemher 201 7l0l 7 Rcncwablc Energ), (lrcdits RFP Purchase new or repowered wind renewable energy Closed September 201 7 November 201 8201 7 Renewable RFP Purchase solar renewable energy Closcd November 201 7 March 20 I 8201 7 Solar RFP November 201 7 Novcmbcr 20 I 7201 7 Market Resource RFP Purchase firm powcr lor PacifiCorp's "vcstcmbalancing authority Closed Orgoing July' 201 8 On hold pcnding final program rules 20 l8 Oregon Cornmunity Solar RFP Purchase solar energy or Oregon Community Solar August 2018 Septcmhcr 201 8201 8 Renewable Iincrgy Credits Rl'P Purchase renewable energy credits fbr Oregon Schedule 272 participation ( losetl 6l Recent Resource Procurement Activities lssucd CompletedI{FP RFP ()bjective Status 20 l9R Utah RFP Purchase neu' renewable encrgy for specitic customers under Utah Schedule 32 or 34 0ngoing March 201 9 Ongoing Renewable energy credits (Sale)[xcess s],stem RECs Ongoing Based on specific nccd Ongoing 2019 Capacity and Energy Suppl_v RFP Purchase capacity and energy suPPly Ongoing June 4, 2019 Ongoing Renc*'able energy credits (Purchase)0ngoin_u Based on specific need 0ngoing Rcncrvable energy' credits (Purchase) Based on specific need Washington compliance needs Ongoing 0ngoing Rcncwahle energy credits ( Purchasc) Based on specilic needCalifornia compliance needs Ongoing Ongoing Sh0rt-tcrm Market (Sales)51'stcm balancing Ongoing Based on specitic need Ongoing Demand Side Management (DSM) Resources In 2018, through competitive procurement processes, the company selected vendors to continue and adaptively manage the successlul, cost-eflbctive delivery of its two largest Energy Efficiency programs: wattsmart Homes and wattsmart Business. PacifiCorp also compctitively procured for Demand Response programs: Oregon lrrigation Load Control and Home Energy Reports. These delivery contracts supporl the detivery designs of existing programs.2T 2017 Renewable Energy Credits RFP PacifiCorp issued a 2017 Oregon Schedulc 272 REC RFP in August 201 7 secking cost-competitive bids under Oregon Schedulc 272 fbr individually negotiated arrangcments for unbundled RECs lrom l'acilitics in Oregon and Utah. As a result of discussions with customers, no transactions were completed pursuant to this RFP. 2017 Renewable RFP PacifiClorp issued a Renewable RFP in Scptember 2017 seeking cost-compctitive bids for up to 1,270 MW of wind encrgy interconnecting with or delivering to PacifiCorp's Wyoming system and any additional wind energy located outside ol'Wyoming that will reduce system costs and provide net benefits for cuslomers. As a rcsult ofthe RFP, PacifiCorp has contracted to conslruct antVor procure three ncu' wind projects - TB Flats I and II, Ekola Flats, and Cedar Springs - totaling l, 150 MW. 2017 Solar RFP PacifiCorp issued a 2017 Solar Resource RFP in Novembcr 2017 seeking cost-competitivc bids for solar energy interconnecting rvith or dclivcring to PacifiCorp's system that will reduce system 17 Program infbrmation tbr Rocky Mountain Power can be found at enerqwision2020.com/and programs for Pacific Porvcr can be lound at rvww.oacificoower.net/about/innovation-environmcnl,/energy-vision-2020.htm1. 68 PACII.ICoRP 20I9 IRP CHAP I I.jR 3 _ PLANNING ENVIRoNMI-]NI Rf.P RFP Objcrtive Status lssucd Completed Orcgon compliance needs PA( rCoRP 2019 IRP CIhPT[R 3 - Pr-ANNING ENVTRoNMENT costs and provide net benelits lbr customers. At the conclusion of the linal shortlist evaluation process, PacifiCorp decided not to select any ofthe bids under this RFP. 2017 Market Resource RFP PaciliCorp issued a 2017 Market Resource RFP in November 2017 seeking firm physical power delivcred to PacifiCorp's wcstern balancing authority area for the timc pcriod 2018 through 2020. No transactions were completed as a result of this RFP. 2018 Renewable Energy Credits RFP PaciliCorp issued a 201 7 Orcgon Schcdule 272 REC RFP in August 201 8 sceking cost-competitive bids undcr Oregon Schedule 272 fbr individually negotiated arrangements tbr unbundled RECs t'rom facilities u.ithin Pacific Power and Rocky Mountain Porver service territories. As a rcsult ol discussions u'ith cuslomers, no transactions were completed as a result ol'this RFP. 2019 Renewable RFP - Utah PaciliCorp issued a Renewable RFP in March 2019 on behalfofa sclect group of customers seeking cost-competitivc bids tbr rcncrvable projects constructed in Utah meeting the critcria established by the participating customers to meet thcir annual energy requirements. Projects must interconnect or be capable ol'delivery to PacifiCorp's system. Customers will contract lor the project otrtput through Utah's Schcdule 32 or 34.7e RFP is in progress with a target completion date in December 2019. Renewable Energy Credits RFP (Sale) On an ongoing basis, and based on availability, PacifiCorp issues short-term RFPs to sell RECs thal are not required to be held anrVor retired for meeting rcgulatory requirements, such as state RPS compliance obligations. Renewable Energy Credits RFP (Purchase) On an ongoing basis, and based on availability, PacifiCorp issues short{erm RFPs to purchase RECs lbr PacifiCorp's Oregon, Washington and/or California state rcncwable portlblio standard compl iance obligations. :8 Scc Public Utiliry Commission ofC)rcgon, Community Solar Program lmplementation, Docket No- UM more information. re This Utah schedule information for Rocky Mountain Pou'er can be found at: $w\-l.rockymountainpower.neVabouVratcs-rcgulation/utah-rates-tariffs.html 1930, tbr 69 2018 Oregon Community Solar RFP PacifiCorp issued a 2018 Orcgon Community Solar RFP in July 201 8 seeking cost-competitive bids tbr individual projccts up to 3.0 MW of ne*, greenfield, altcrnating current (AC) solar photovoltaic resources directly interconnecting with PacifiCorp's distribution or transmission system and located in PacifiCorp's Oregon service territory. The RFP is currently on hold whilc Oregon Community Solar Program rules, guidelines and timclincs are I'urthered clarified and established within Public Utility Commission of Oregon proceedings.rs PACrr.rCoRP - 2019 IRP CI{nPIIIR J PI- NNI\G ENVIRoN]\II.\ I 70 PA(' ,rC(nf - l0l9 IRP CII^PTER.1 TRANsIu,IIssIo\ CHRprpn 4 - TnaxsMISSroN a Cu,trrnn HTGHLTGHTS PacifiCorp's planned transmission projccts will facilitate a transitioning rcsource portfblio and will comply with reliability requirements, rvhile providing sufficient flexibility neccssary to ensure cxisting and future resources can meet customer demand cost effectively and reliably. Givcn the long lead timc needed to site, permit and construct major nerv transmission lines, these projccts need to be planned in advance. PacifiCorp's transmission planning and benellts evaluation efforts adherc to regulatory and compliance requirements and respond to commission and stakeholder requests for a robust evaluation process and clear criteria lirr evaluating transmission additions. PacitiCorp requests acknowledgement ol'its plan to construct thc Acolus to Mona (Clover substation) Gateway South 500 kilovolt (kV) transmission line based on customer beneflts and the inclusion of this segment in the 2019 PacifiCorp lntegrated Resource Plan (tRP) prcl'crred portfolio. While construction ol'the balance of'luture Energy Gatcway segments (i.e., Gateway West, and Boardman to Hcmingway) is bcyond the scope of acknowledgcmcnt lbr this IRP, these segments are expected to deliver future bcnefits fbr our customers and for thc region. Thus, continued permitting of these segments is warantcd to ensure that PacifiCorp is wcll positioned to advancc these projecls at the appropriate time. a PacifiCorp's bulk transmission network is designed to reliably transport electric energy from a broad array of generation resources (owncd or contracted generation including market purchases) to load centers. There are many benefits associated with a robust transmission network, some of which are set lorth below: l. Reliable delivery of diverse energy supply to continuously changing customer demands under a *,ide 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 dispatch ofresourccs within PacifiCorp's diverse system. 4. Economic transfer of electric power to and liom other systems as facilitated by the company's participation in thc market, which reduces net powcr costs and provides opportunities to maintain resource adequacy at a reasonable cost. 5. Access to some ol'the nation's best wind and solar resources, which provides opportunities to develop geographically diverse low-cost renewable assets. 6. Protection against market disruptions where limitcd transmission can otherwise constrain energy supply. 7. Ability to meet obligations and requirements of PacifiCorp's Open Access Transmission Tariff(OATT). PacifiCorp's transmission netrvork is highly integated with other transmission systems in thc wcst and provides the critical inlrastructure needed to serye our customers cost ellectively and reliably. Consequently, PacifiCorp's transmission network is a critical componcnt of the IRP process. 7l Introduction P^( I rCoRP f0l9lRP C APTLR 4 -TRANsMIssr()\ PacifiCorp has a long history ofproviding reliable service in meeting thc bulk transmission needs of the region. This valucd asset rvill beconre even more critical as the regional resourcc mix transitions to accommodalc increasing levels of variable gcncration from renervahle resourccs lhat *ill be uscd to serve growing energy needs of'PaciliCorp's customers. Open Access Transmission Tariff PacifiCorp provides open acccss transmission and interconnection service in accordance with its OATT, as approved by the Federal Energy Regulatory Commission (F'ERC). Under the OATT, PaciliCorp plans and builds its transmission system to mcet the needs ul'trvo difTerent types of transmission customers: network customcrs and point-to-point customcrs. The OATT also obligates PacifiCorp to expand its systcm as needed to grant requests fbr gcnerator interconnection service. For nctwork customers, PacifiCorp uses tcn-ycar load-and-resource (L&R) lbrccasts supplied by the customer, as well as network transmission service requests to tacilitate development ol transmission plans. Each ycar, PacifiCorp solicits L&R data fiom cach of its network customcrs to determine f'uture L&R requirements fur all transmission network customers. The bulk of PacifiCorp's network customer needs comes fiom the company's Energy Supply Management (ESM) function, which supplies energy and capacity for PacifiCorp's rctail customers. Other network customers include Utah Associated Municipal Power Systcms, Utah Municipal Powcr Agency, Deseret Power Electric Cooperative (including Moon Lake Electric Association), Bonneville Power Administration (BPA), Basin Electric Pou,er Cooperativc, Black liills Power, Tri-State Generation & 'l'ransmission, the United Slates Dcpartment of the Interior Burcau of Rcclamation, and the Westem Area Powcr Administration. PaciliCorp uses its customers' L&R forecasts and bcst available information, including transmission service requests, as one lhctor to determine the need and timing fbr investments in the transmission system. If customer L&R fbrecasts change signilicantly, PacifiCorp may consider altemative deployment scenarios or schedules for transmission system investments, as appropriate. In accordance with FERC guidelines, PacitiCiorp is able to reserve transmission network capacity based on these da1a. PaciflClorp's experience, however, is that the lcngthy planning, permitting and construction timeline required to deliver significant transmission investments, as well as thc typical useful life of these facilities, is well beyond the l0-year timeframe of L&R tbrecasts.r A 20-year planning horizon and ability to reserve transmission capacity to meet existing and foreoasted necd over that timeliame is more consistent with the time rcquired to plan for and build largc-scale transmission projects, and PacifiCorp supports clear regulatory ackno*,ledgcmcnt of this reality and corresponding policy guidance. For poinrto-point transmission service, thc OATT requires PacifiClorp kr grant service on existing transmission infrastructure using cxisting capacity or to build transmission system infrastructure as required to providc thc requested sen,ice. The required action is determined with each point-to- I For example, PacitiCorp's application to hegin thc Lnvironmental Impact Statement (EIS) process for the Cateway Wcst scgmcnt ofits Energy Cateway Transmission Expansion Project was lilcd rvith the Bureau ofLand Managcmcnt (BLM) in 2007. A panial Record ofDecision (ROD) was received in late April 2013, and a supplemental ROD was receivcd in January 2017- l2 Regulatory Requirements PACI,ICORP 20l9lRP CHAPTFTR 4 - TRA\-sMIsstoN point transmission service request through FERCi-approved study processes that identify the transrnission fhcilities needed to grant thc request. Requests lor generator interconnection service can also drive the need for transmission network upgrades. Similar to the process for point-to-point requests, the OATT contains study proccdures to determine the facilities needed to grant a request for new generator intcrconnection service. Reliability Standards PacifiCorp is required to meet mandatory FERC, North Amcrican Electric Reliability Corporation (NERC), and Westcm Electricity Coordinating Council (WECC) reliability standards and planning requirements. The operation of PacifiCorp's transmission system also responds to requests issued by Peak Reliability as the NERC Reliability Coordinator. lleginning in 2020, Peak Reliability will be disbanded and the California Indcpcndent System Operator (CAISO) will providc the Reliability Coordinator f'unction for PacifiCorp. Thc company conducts annual system assessments to confirm rninimum levels of system perfilrmance during a wide range ol'operating conditions, from serving loads rvith all system elements in service to extreme conditions where portions olthe system are out of'service. Factored into thesc assessments are load growth forccasts, operating history, scasonal performance, resource additions or removals, new transmission asset additions, and the largest transmission and generation contingencies. Bascd on these analyses, PaciliCorp identifies any potential system deficiencies and determines thc infrastruclure improvements needed to reliably meet customer loads. NERC planning standards define reliability of the interconnected bulk elcctric system in terms of adcquacy and security. Adequacy is the electric system's ability to rneet aggregatc clectrical demand for customers at all times. Seourity is the clectric system's ability to withstand sudden disturbances or unanticipated loss of systcm elements. lncreasing transmission capacity oflen requires redundant f'acilities in order to meet NERC reliability criteria. This chapter providcs: o Justification supporting acknowledgement of PaciliCorp's plan to construct Gateway South.. Support for PacifiCorp's plan to continue permitting the balance ol Gateway West and Boardman to Hemming*'ay;e Key background inlbrmation on the evolution of'the Energy Gateway Transmission Expansion Plan; and. An overview ofPacifiCorp's invcstments in recent sho(-term systcm improvements that have improved reliability, helped to maximizc eflicient use of the existing system, and cnabled the company to def'er the need to invest in larger-scale transmission infrastructure. The Wallula to McNary transmission project was energized at the end of January 2019 and the transmission customer began taking transmission servicc February 1,2019. The project meets the requirement to provide the requested transmission service in accordancc with the OATT and improves reliability of load served from the Wallula substation. '73 Wallula to NlcNary U P^crr,r( (mP 2019 IRP Crr,\Prr,R4 TR^Nsrutssto\ In 201 8 PacifiCorp received the necessary state regulatory approvals, stale and local permits. and private rights-of-\vay to construct the Aeolus{o-Bridger/Anticline sub-segment D.2 ol'Gatcrvay West. Construction bcgan in April 2019 and will be complcted and placed in servicc by the end of 2020. The 2019 PacifiCorp IRP preferred portfolio includes thc Aeolus+o-Mona (Clover substation) transmission segment (Energy Gateway South or Scgment F-). This segment is included in the prelened portfolio as a component ofthe least-cost, least-risk plan. The 500 kV transmission scgment extends 416 miles betwccn the planned (as part ol (iatcway West sub-segment D.2) Aeolus substation near Medicinc Bow, Wyoming, and the existing Clover substation located near Mona, Utah. PacifiCiorp, with stakeholder involvcment, has pursued pcrmitting of the Energy Gateway South transmission project since 2008. ln May 2016 the Bureau of Land Management (BLM) releascd its final Environmental Impact Statement (EIS) and issued their Record o[' Decision (ROD) in December of the same ycar. ln May 2018 the U.S. Forest Service issucd its ROD, completing the permitting on f'cderal lands and providing a right-of-rvay grant fbr federal properties. Factors Supporting Acknowledgement Acknowledgment of the Aeolus-to-Mona transmission segment is supported by the extensive analysis that led to the inclusion ofthe transmission line in the 2019 IRP preferred portlblio. This transmission segment will allow PacifiCorp to implement system improvements, supports the full capacity rating for Gateway South and Wcst and enables the addition ol'incremental Wyoming wind resources to support customer needs and deliver value fbr customers in the most cost- elfectivo way. Timing of construction is driven by the phasc-out schedule of federal production tax credits (PTCs), particularly the 2023 in-scrvice requirements for 40 percent PTCI eligibility, and potential risk associated with thc termination ofthe BLM permit lbr non-use. In addition to 14 Aeolus to Bridger/Anticline U Request for of Aeolus to Mona I-everaging transmission modeling improvements implemcntcd in the 2019IRP, the Acolus-to- Mona transmission segment rvas made availablc as a transmission upgradc that could be endogenously selected by thc Systcm Optimizer (SO) model-the modcling tool used to develop a broad spcctrum ofresource portfolios during the portfblio-development phase ofthe lRP. In the initial phase of the portfolio-developmcnt process, PacifiCorp produccd 35 unique resource portfolios to evaluate how the type, timing, location, and volume of nerv resourccs and transmission upgrades changed in response to difl'crcnt planning assumptions (i.e., coal retirements, market prices, carbon dioxidc (CO:) prices). The Aeolus-to-Mona transnrission segment was endogenously selected by the SO model to comc online by the end of2023 in 34 out ol'thcsc 35 resource portfolios, and rvas selected to come online by the end of 2023 in all subsequent resource portli)lios developcd to refine cost-and-risk analysis 1br top-performing cases. Based on the IRP analysis, the Aeolus-to-Mona transmission segment will be placed into sen'ice by thc cnd of 2023, subject to completion of local permitting and private rights-of-way acquisitions. To align development of thc Aeolus-to-Mona transmission segment rvith additional renervable generation projccts that will further decarbonize PacitlCorp's portfolio and to provide full linc rating capacity on Gate*,ay West and South, thc company requests the Aeolus-to-Mona transmission segment be ackno',1'ledged in this IRP. PACTITC0RP 20l9lRP C APIIR 4 - TRANS\4rssroN supporting rene\\,ablc rcsource additions in PacifiCorp's generation ponfolio, qualifying thcm fbr P'l'Cs, thc ncw transmission segnrent will incrcasc transflr capability out of eastern Wyoming. The addition of the Aeolus-to-Muna transmission segment further improves the reliability of PacitiCorp's transmission system in the lbllowing ways: Provides a parallel path to the Gateway West - Sub-segmcnt D.2 Project (Aeolus-to- Bridger/Anticline 500 kV line) improving the reliability ofthe 230 kV transmission system in Wyoming fbr the loss of either 500 kV line. Strcngthens thc PacifiCorp transmission system (increased lault duty) by interconnccting the geographically diverse areas ofeastcm Wyoming and southem Utah together, allowing additional generation resources to be connected. lmprovcs grid rcliabitity by providing better operational control ofthe backbone transmission system by interconnecting two areas ofthe PacifiCorp transmission system that are abundant in t*.o different forms olrenewable resources, spccifically rvind rioh eastem Wyoming rvith the solar rich area of southern Utah. Provides anticipated improvements in eastern Utah rcliability by providing a potential future high voltage source and power delivery option to mest thc projected oil expansion and corresponding load growth (Ashley, Vemal). Improves the southem Utah transmission system reliability by providing congestion reliefon the 345 kV lines during outagc conditions. Supports PaciliCorp's NERC TPL-001-4 Lransmission system reliability etlbrts, u'hich are necessary to improve grid retiability perfbrmance. Assists PacifiCorp in meeting its OATT obligations to interconnect new generation. Completion of'ths new transmission scgment realizes the full 1,700 MW rating of (iateway South allowing thc addition of up to I ,920 MW of renewable resources added to the system. Connecting into the Mona/C'lover market hub provides additional flcxibility in the use of least-cost resources from eastem Wyoming or southem Utah k) serve customer load. PacifiCorp's preferred portfolio includes nearly 11,000 MW ol'new wind and solar resources expected to come online in the 2020-2038 timeframe, which ret'lects a least-cost, least-risk mix of resources that rcquircs incremental intiaslructure investment to serve PacifiCorp's cuslomcrs cost eflectively and reliably. In addition to the Windstar-to-Populus line (Energy Gatcway Segment D), the Gateway West transmission project also includes the Populus-to-Hemingway transmission scgment (Energy Gateway Segment E). In a luture tRP, PacifiCorp will support a request for acknowledgement to construct the balance olGateway West. While PacifiCorp is not requesting acknowledgement of a plan to construct these segments in this lRP, the company will continue to permit the projects. Windstar to Populus (Segment D) The Windstar-to-Populus transmission project consists ofthree key sub-segments: 15 Gateway West - Continued Permitting I'rcr|rcoRr l0l9 lli P CHAP r r.rR .l - TRA\SMISSIoN D l-A single-circuit 230-kV line that will run approximately 75 miles betwccn the existing Windstar substation in castem Wyoming and the Aeolus substation that is currently under construction ncar Medicine Bow, Wyoming, which includes a loop-in to the existing Shirley Ilasin 230-kV substation; D2-A single-circuit 500-kV linc that is currently under construction running approximately 140 miles tiom the Aeolus substation (under l-igure 4.1 - Segment D construction) to a new annex substation (Anticline, also currently under construction) near the existing Bridger substation in western Wyoming; and Populus to Hemingway (Segment E) Figure 4.2 - Segment E N H.mln a C r7 W Y O M I N G a Srldtcr l he Populus-to-Hemingway transmission project consists of two single-circuit 500-kV lines that run approximately 500 miles betwccn the Populus substalion in castcm Idaho to the Hemingway substation in westem ldaho. Hldpolnt E GA T Boan C.d* The Gatervay West projcct rvould enable PaciliCorp to morc efficiently dispatch system rcsourccs. improre performance ol' the lransmission system (i.e., reduce line losses), improve reliability, and enable access to a diverse range ofnew resource altematives over the long term. Under the National Environmental Policy Act, the BLM has completed the EIS fbr thc Gateway West project. Thc BLM released its tinal EIS on April 26,2013, tbllorved by the ROD on November 14,2013, providing a right-of-rvay grant lbr all of Segment D and most ol'Segment E olthe project. The BLM chose to det'cr its dccision on the rvestem-most portion olScgment E of the project locatcd in ldaho in order to perform additional review of the Morley Nelson Snake River Birds of Prey Conservation Area. Specifically, the scctions of Gateway West that werc deferred for a later ROD include the sections of Segmcnt E from Midpoint to Hemingway and Cedar Hill kr Hemingway. A ROD fbr these final sections of Segment E was issued on January 19,2017 and a right-of-way grant was issued on August 8,2018. 76 D3-A single-circuit 500-kV line running approximately 200 miles betrveen the nevv' annex substation (Anticline, under construction) and the Populus substation in southeast Idaho. IDAHO Plan to Continue Permitting - Gateway West The Gateway West transmission projects continue to o{ler bencfits under multiple, future resource scenarios. To ensure that PacifiCorp is wcll positioncd to advance the projects, it is prudcnt for PacifiCorp to continue to permit thc balance of Gateway West 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 meel these requirements and rvill continuc to meet regularly with the Bureau ofLand Management to rcvicw progrcss. PACIFICoRP-20I9IRP CHAPTFR 4 TRANsvrssroN PacifiCorp continucs to participatc in thc project under the Joint Funding Pcrmitting Agreenrent u,ith ldaho Power and BPA. In accordance rvith this agreement. PacifiClorp is responsiblc tbr its share of the costs assooiated rvith I'ederal and state permitting activ ities. Idaho Powcr's 2019 IRP identifies the Boardman-to-Hemingrvay transmission line (82H) as a prelerred resource to meet its capacity needs, reflccling a need lirr the project in 2026 to avoid a delicit in load-serving oapability in peak-load periods. Given the status of ongoing permitting activities and the construction pcriod. Idaho Power expects the in-scrvicc date lor the transmission line to be in 2026 or bcyond. Permitting Update 'fhe BLM released its ROD lbr B2H on November 17.2017. 'Ihe ROD allows BLM tu grant right- of-way to Idaho Porver for the construction, operation, and maintenance of the B2H Project on BlM-administered land. The approved route is thc agency-preferred alternative identillcd in the final EIS and proposed land-use plan amendments. For all lands crossed in Oregon, ldaho Power must receive a site certiflcatc fiom the Energy Facility Siting Council (EFSC ) prior to constructing and operating the proposed transmission line. The Oregon Department of Energy (ODOE) serve as stalf members to EFSC tacilitating the revic'w ofthc site certilicate application process. ODOE an<l EFSC both revicw Idaho Porver's application to ensure compliance with state energy tacility siting standards The U.S. Forest Service (USFS) issued a separate ROD on Novcmber 9, 2018 for lands administercd by thc USFS bascd on thc analysis in the final EIS.'l-he USFS ROD approvcs the issuance of a special-use authorization for a portion of the project that crosses the Wallowa- Whitman National Forest. The U.S. Department of the Navy issued a ROD on Septernber 25,2019 in support ol'construction of a portion of the B2H project on 7.1 rnilcs of the Naval Weapons Systems I'raining Facility in Boardman, Oregon. Benefits The existing transmission path between the Pacific Northwest and Intermountain West regions is fully used during key operating periods, including winter peak periods in the Pacifio Northwest and summcr pcak in the lntermountain West. PaciliCorp has invested in the permitting of the B2H project because ofthe strategic value ofconnecting the two regions. As a potential owner in the project, PaciliCorp rvould bc able to use its bidirectional capacity to incrcase reliability and to enable more efficient use of existing and future resources lor its customers. The following lists additional 82H benefits: o Customers: PaciliCorp continucs t() invest to meet customers' nceds, making only critical investments now to ensure future reliability, security, and safety.'l'he B2H project will bolster reliability, security, and safety for PacifiCorp customers as the regional supply mix transitions. . Renewables: The B2H projcct has been identified as a strategic project that can lacilitate the transfer of geographically diverse rencwable resources, in addition to other resources, across PacifiCorp's two balancing authority areas. Transmission line infrastructure, like 11 Plan to Continue Permitting - Boardman to Hemingway P^crHC()R? 20l9lRP CHAPI I-tR 4 - TRANSMISSloN B2H, is nccded to maintain a robust electrical grid rvhile integrating clean, rencrvable encrgy rcsources across the Pacillc Northwest and Mountain west states. Regional Benefit: PacifiCorp, as a member ol'thc rcgional planning entity Northern Tier Transmission Group (NTTG), supports the inclusion of B2H in the NTTC regional plan. From a regional perspective, thc B2H project is a cost-ell'ectivc investment that rvill provide regional solutions to identified regional needs. Balancing Area Operating Efficiencies: PacifiCorp operates and controls trvo balancing areas. Aller the addition of 82I{ and portions of'Gateway Wcst. more transmission capacity will exist between PacifiCorp's two balancing arcas, providing the ability to incrcase operating efficiencies. B2H rvill providc PacifiCorp 300 MW ol'additional west-to-east capability and 600 MW oleast-to-west capability to move resources between PacifiCorp's two balancing authority areas. Regional Resource Adequacy: PacifiCorp is participating in the ongoing effort to evaluate and develop a regional resource adequacy program with othcr utilities that are members of the North\\,est Porver Pool. The B2H projcct is anticipated to provide incremcntal transmission infrastructure that lvill broaden acccss to a more diverse resource base. which will provide opportunities to rcducc the cost of maintaining adequatc rcsource supplies in the region. Grid Reliability and Resiliency: The Midpoint-to-Summcr Lake 500-kV transmission line is thc only line connecting PaciliCorp's east and west control areas. The loss of this line has the potential to reduce transfbrs by 1,090 MW. When B2H is built, the ner.v transmission line will provide redundancy by adding an additional 1,000 MW ofcapacity between thc Hemingr.r,ay substation and the Pacilic Northvvest. 'l'his additional asset rvould mitigate the impaot rvhen the cxisting line is lost. Oregon and Washington Renewable Portfolio Standards and Other State Legislation: Neu, legislation and rules for recently passed legislation arc being developed to meet statc- specitlc policy objectives that are expcctcd to drive the need lor additional renervable resouroes. As these laws are enacted and rules are developed, PacifiCorp will evaluate how the B2H lransmission line can help lacilitate meeting state policy objectives by providing incremental access to geographically diversc renewable resources and other flexible capacity resources lhat will be needed to maintain reliability. PacifiCorp believes that inveslmcnt in transmission infrastructure projects, Iikc B2H and other Energy Gatervay segmenls, are necessary to integratc and balance intermittent renewablc resources cost effectively and reliably. EIM: PaciliCorp was a leader in implementing the westem cncrgy imbalance market (EIM). Thc real-time market helps optimize the electric grid, which lowers costs, enhanccs reliability, and more effbctively integrates resourccs. PacifiCorp believes the B2H project couJd help advance thc objcctives ofthe EIM and has the potential ofbcnefitting PacifiCorp customcrs and the broader region. a Next Steps Given the extensivc list of benefits noted above, PaciliCorp is committed to participating in the B2H project in accordance with the terms of'the Joint Funding Permitting Agreement through the final Oregon Department ol' Energy Facilities Siting Council's permitting process and will continue to evaluatc the benetlts to PacifiCorp's customers prior to commitment ofentering into a projcct construction agreement. Additionally, PacifiCorp will continue to revierv possible bencfits 78 PA('rrr( oRr - l0l9 IRP CIAP rr..R 4 TRt\sNltssto\ of'the project as it continues to participatc in project development activities, including moving forward with preliminary oonstruction and construction agreement negotiations. Introduction Given the long-lead time required to successf'ully site, permit and construct major nerv 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 cflbrts that are ongoing and have been conducted multiple times over a period ofscvcral years. The purpose of this section is to provide important background information on the transmission planning eflorts that led to PacifiCorp's proposal of the Energy Gateway Transmission Expansion Plan. Background Until PacifiCorp's announcement of Energy Gateway in 2007, its transmission planning efforts traditionally centered on new resource additions identiticd in the IRP. With timelines ofscven to ten years or more rcquircd to site, permit, and build transmission, this traditional planning approach was proving to be problematic, leading to a perpetual state of transmission planning and new transmission capacity not being available in time to be viable for meeting customer needs. The existing transmission system has been at capacity for sevcral years, and nerv capability is ncccssary to enable ne\,r' resource development. The Encrgy Gatervay Transmission Expansion Plan, formally announced in May 2007, has origins in numerous local and rcgional transmission planning eftbrts discussed further below. Energy Gateway was designed to ensure a reliable, adequate system capable of mccting current and future customcr needs. Importantly, given the changing rcsource picture, its design supports multiple future rcsource sccnarios by connecting resource-rich arcas and major load centers across PacifiCorp's multi-state service area. ln addition, the ahility to use thesc rcsource-rich areas helps position PacifiCorp to meet curent state renervablc portl'olio requirements. Please rel'er to the regional maps olrvind, solar, biomass, and geothermal potcntial available on PacifiCorp's Encrgy Gateway project rvebsite to see an ovcrlay ol'the Energy Cateway projcct and rener,''able resource potential.l Energy Gateway has since becn included in all relevant local, regional and interconneotion-wide lransmission studies. Planning Initiatives Energy Gatervay is the result ofrobust local and regional transmission planning eflorts. PacifiClorp has participated in numerous transmission planning initiatives, both leading up to and sincc Energy Gateway's announcement. Stakeholdcr involvement has played an important role in each ofthese initiatives, including participation from statc and f'ederal regulators, government agencies, private and public energy providers, independent developers, consumer advocates, renervablc cncrgy groups, policy think tanks, environmental groups, and elected officials. These studies have shown a critical need to alleviate transmission congestion and move constraincd energy resources to regional load centers thnrughout the west, and include: : wrru'.pacilicorp.com-/transmissior/transmission-projects/energy-gate$'ay.html 19 P CIFIC()RP_20I9IRP C APTER4 TR.,\NSMIssroN N o rthwest Truns mis s io n Ass essment Committee ( N TAC) The NTAC was the sub-regional transmission planning group reprcsenting the northwest region, preceding Northem Ticr Transmission Group and ColumbiaGrid. The NTAC developed long-term transmission options for resources located within the provinccs of llritish Columbia and Alberta, and the states of'Montana, Washington, and C)regon to serve Pacific Northwcst loads and northem Califbmia. Rocky Moantain Area Transmission Study Recommended transmission cxpansions overlap signilicantly with Energy Gateway confi guration, including: o Bridger system expansion similar to Gateway West. o Southeast Idaho to southwest Utah expansion akin to Cateway Central and Sigurd to Red Butte. o lmproved cast-u est conncctivity similar to Energy Gatervay Segment H altemativcs. Western Governots' Association Transmission Task Force Report Examined the transmission needcd to deliver the largely remotc generation resources contemplated by the Clean and Diversifi ed Energy Advisory Committee. This ellbrt built upon the transrnission previously modeled by the Seams Steering Group-Westem Interconnection, and included transmission necessary to support a range of resource scenarios, including high efficiency, high renewables and high coal scenarios. Again, tbr PacifiCorp's system, thc transmission expansion that supported these scenarios closely resembled Energy Gateway's conliguration. Western Regional Transmission Expansion Purtnership (WRTE P) The WRTEP was a group ol'six utilities working rvith four westem governors' ofJices to evaluate the proposcd Frontier Transmission Line. Thc Frontier Line was proposcd to connect Califbmia and Nevada to Wyoming's Powder River Basin through Utah. The utilities involved rvere PaciliCorp, Ncvada Power, Pacific Gas & Elcctric, San Diego Gas & Electric, Southem Califbmia Edison, and Sierra Paciflc Powcr. Norlhern Tier Trunsmission Group Transmission Planning Rcporls 'The analyses presented in this Report suggest that well- considered transmission upgrades, capable of giving LSEs greater access to lower cost Beneration and enhancing fuel diversity, are cost-effective for consumers under a variety of reasonable assumptions about natural gas prices." 80 "The Task Force observes that transmission investments typically continue to provide value even as network conditions change. For example, transmission originally built to the site of a now obsolete power plant continues to be used since a new power plant is often constructed at the same location." In the 2016-201 7 NTTG Drali Regional Transmission Plan, sub segmcnts of Energy Gateway (both Gateway West and Gateway South) were listed as necessary to prov ide acceptable system perlirrmance. The study also established that the amount of new Wyoming wind gencration that is added over time can impact the transmission system reliability rvest of Wyoming, Additionally thrcc interregional projects were included in the study Southwest tnter-tie Project (SWIP North, Cross Tie and TransWest Express), u,hich showed that all three projects relied on Encrgy Gateway to attain their lull transler capability rating. WECC/Reliahility Assessment Committee (RAC) Annuul Reports and l;l/estern I nlercon nection T ra ns miss ion Puth Utiliiation Studies These analyses measure the historical use of transmission paths in thc wcst to provide insight into where congestion is occurring and assess the cost of that oongestion. '['he Energy Gatervay segmenls were included in the analyses that support these studies, allcviating several points olsignificant congestion on the systcm, including Path l9 (Bridger West) and Path 20 (Path C). Energy Gateway Conliguration To address constraints identified on PaciliCorp's transmission systcm, as well as meeting system rcliability requirernents discussed funher belorv, the recommended bulk electric lransmission additions took on a consistent fbotprint, which is now knorvn as Energy Gate\,r.ay. This expansion plan establishcs a triangle of reliability that spans Utah, Idaho and Wyoming with paths extending into Oregon and Washington, and contemplates geographically diverse resourcc locations based on environmental constraints, economic generation rcsources, and federal and state cnergy policies. Since Energy Cateu'ay's initial announcement in 2007, this series ofprojects has continued to be vetted through multiple public transmission planning forums at the local, regional and Western lnterconnection level. In accordance with the local planning requirements in PacifiCorp's OATT, Attachment K, PacifiCorp has conducted numerous public meetings on Energy Gateway and transmission planning in general. Meeting notices and materials are postcd publicly on PacifiCorp's Attachment K Open Access Same-time lnformation System (OASIS) site. PacifiCorp is also a membcr of NTTC and WECC's RAC. These groups continually evaluate PacitiCorp's transmission plan in their efforts to develop and refine the optimal regional and interconncction-wide plans. Please refer to PacillCorp's OASIS site for informatinn and materials related to these public processes.l I rvww.oatioasis.com/ppw/index.html "After analyzing the steady-state perf ormance of stressed conditioned casPs, a rigorqus contingency analysis com m enced.., the[ NTTG'5 Technical Committee &termined additional f acilities would be needed to meet the reli abi lity criteria..,," P,\crrrCoRP - 2019 IRP CHAPTER 4 - TRANSMrssroN 8t "Path 19 [Bridgerl 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." PACTITCoRP 20l9lRP CllAPt LR.l TR\Nsivtssl{ )\ Additionally, an extensive I8-month stakeholdcr process on Gateway Wcst and Gater.vay South was conducled. This stakeholder process was conducted in aocordance with WECC Regional Planning Projcct Revierv guidelincs and FERC OATT planning principles, and was uscd to establish need, assess benelits to the region, vet altematives, and eliminate duplication ofprojects. Meeting materials and rclated reports can be lbund on PacifiCorp's Energy Gateway OASIS site. Energy Gateway's Continued Evolution The Energy Gateway Transmission Expansion Plan is the product of years ol'ongoing local and regional transmission planning efforts with signilicant customer and stakeholder involvement. Since its announcemcnt in May 2007, Energy Gatcway's scope and scale have continued to evolve to meet the future needs of PacifiCorp customers and the requiremcnts 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-thc current system and help dcfbr, to some degree, the need for larger capital investments likc Energy Gateway (see thc following section titled "Efforts to Maximize Existing Systcm Capability"). The IRP process, as compared to transmission planning, can result in frequent changes in the lcast-cost. least-risk resourcc plan driven by changcs in the planning environment (i.e., market conditions, cost and pertbrmance of new resourcc technologies, etc.). Near-term fluctuations in the resourcc plan do not always support the longer-term developmcnt needs of transmission infrastructurc, or the ability to invest in transmission assets in time to meet customer needs. Together, however, the IRP and transmission planning proccsses complement each other by helping PacifiCorp optimize the Iiming of its transrnission and resource investments to delivcr cost-et-fective and reliablc cnergy to our customers. Whilc the core tenets for Energy Oatcway's design have not changed, the project conliguration and timing continue to be reviewed and modilied to coincide with the latest mandatory transmission system reliability standards and perlbrmance requirements, annual system reliability assessments, input from several years of federal and state permitting processes, and changcs in generation resource planning and our customers' Iirrecasted demand for energy. As originally announced in May 2007, Energy Gateway consistcd ofa combination ofsingle- and double-circuit 230-kV,345-kV and 500-kV lines connccting Wyoming, Idaho, Utah, Oregon and Nevada. In response to regulatory and industry input regarding potential regional benefits of "upsizing" the project capacity (lbr cxample, maximized usc of energy c<lrridors, reduccd environmental impacts and improved economies ol'scale), PacifiCorp included in its original plan the potential fbr doubling the project's capacity to accommodate third-party and equity partnership intcrests. During late 2007 and early 2008, PacifiCorp received in cxcess of6,000 MW ofrequcsts for incremental transmission scrvice across the Energy Gatcway footprint, which supported the upsized contiguration. PacifiCorp identified the costs required for this upsized system and offered transmission service contracts to qucuc customers. These queue customers, however, were unable to commit due to the upfiont costs and lack of lirm contracts with end-use oustomers to take delivery of f'uture gcneration, and withdrew their rcqucsts. ln parallel, PaciliCorp pursued several potential pannerships with other transmission developers and entities with transmission proposals in the lntermountain Region. Duc to the significant upfront costs inherent in transmission investments, firm partncrship commitments also lailed to materialize, leading PacifiCorp to pursue the current contiguration with the intent oionly dcveloping system capacity suf'licient to meet the long-term needs of its customers. 8l I',\( [ r('oRP f0l9ll.ll'CHAPT'|tt .l - T RA N sr'r r:i:i t( )N ln 2010, PacifiCiorp entered into mcmorandums of understanding to explore potcntial joint- devclopment opportunities with ldaho Power Company on its lloardman{o-Herningway projcct and with Portland (icneral Electric Company (P(iE) on its Cascade Crossing project. One ofthe key purposes of Energy Gatcrvay is to better integratc PaciliCorp's east and west balancing authority areas, and Gatervay Segmcnt H liom u,estern ldaho into southem Oregon rvas originally proposed to satisfy this need. However, recognizing the potential mutual benefits and valuc lirr customcrs of'jointly developing transmission, PacifiCorp has pursued thcse potential partnership opportunities as a potcntial lorvcr-cost altemative. ln 201 l, PacifiCorp announced the indetinitc postponement ofthc Catcway South 50C)-kV segmcnt benvce-n the Mona suhstation in central Utah and Crystal substation in Ncvada. This extension oi Gateway South, likc thc double-circuit configuration discussed above, rvas a component of the upsized system to address regional needs il' supported by qucue customers or partnerships. Horvcver, despite significant third-party interest in the Gatervay South segment to Nevada, thcre rvas a lack of financial commitment needed to support the upsized configuration. In 2012, PacifiCorp determincd that one new 230-kV line betrveen the Windstar and Aeolus substations and a rebuild of the existing 230-kV line were l'casible, and that the second ncu, proposcd 230-kV line and proposed 500-kV linc planned between Windstar and Aeolus u'ould bc eliminated. This dccision resultcd liom PacifiCorp's ongoing I'ocus on meeting cuslomer needs, taking stakeholder feedback and land-use limitations into consideration, and finding thc best balance between cost and risk lor customers. In January 2012, PacifiCorp signed the Boardman to Hemingway Permitting Agreement with Idaho Porver Company and llPA that provides for the PaciliCorp's participation through the permitting phase ol' the project. 'lhc Boardman-to- Hemingrvay project was pursued as an altemative to PacifiCorp's originally proposed transmission segment liom eastem Idaho into southern Oregon (Hemingway to Captain Jack). Idaho Power leads the pcrmitting ctlbrts on the Boardman-to-I{cmingrvay project, and PacifrCorp continues to support these activities under the conditions of the l]oardman to Hemingr.r,ay Transmission Projcct Joint Permit Funding Agreement. 'fhe proposcd line provides additional connectivity betrvccn PacifiCorp's wcst and east balancing authority arcas and supports the full projcctcd line rating for thc Gateway projects at fulI build out. Pacillcorp plans to continue to support the project undcr the Pcrmit Funding Agreement and will assess ncxt steps post-permitting based on customer need and possible benelits. In January 2013, PacifiCorp began discussions rvith PGE regarding changes to its Cascade Crossing transmission project and potential opporlunilies lor joint developmcnt or lirm capacity rights on PacitiCorp's Orcgon system. PacifiClorp turthcr notes that it had a mcmorandum of undcrstanding with PGE for the development ol'Cascade Crossing thal was tenninated by its own terms. PacitiCorp had continucd to evaluate potential partnership oppodunities u'ith PCE once it announced its intention to pursue ('ascade Cirossing rvith BPA. Horvcl'er. because PCE decided to end discussions rvith BPA and instead pursue olhcr options, PacifiC'orp is not actively pursuing this opportunity. PacifiCorp continues lo look to panner with third parties on transmission devclopment as oppor{un ities arise. In May 2013, PacifiCorp completcd the Mona-to-Oquirrh projcct. In November 2013, the B LM issucd a partial ROD providing a right-ot--rvay grant lor all olSegrnent D and most ofSegment E ofEnergy Gateway. The agency chose to defer its dccision on the westem-most portion ofSegment E, ol'the project located in Idaho in order to perform additional rcvicw ofthe Morley Nelson Snakc Rivcr Birds of Prey Conservation Area. Spccifically, the sections of Gateway West that were t3l PACIl.rcoRr,-?019IItP CHAr,r l,R .l TIi,^NsN{rssroN defened tbr a later ROD include the sections of'Segment E from Midpoint lo Hemingway and Cedar Hill to l{emingway. ln May 2015, the Sigurd-to-Red Butte project was completed and placed in service. ln December 2016, the BLM issucd its ROD and right-of:way grant f'<rr the Gatcway South project. ln January 2017, thc BLM issued its ROD and right-of-way grant, previously del'erred as part of the November 2013 partial ROD, lbr thc sections of Segment E from Midpoint to Hemingway and Cedar Hill to Hemingway. Finally, the timing of Energy Gateway segmcnts is regularly asscssed 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 def'erring in-service dates as needed due to permitting schcdules, moderated load grofih, changing customer needs, and system retiabitity improvemcnts. PaciliCorp rvill continue to adjust the timing and conliguration of its proposed transmission investments based on its ongoing assessment of the systcm's ability to meet customer needs, its compliance with mandatory reliability standards, and the stipulations in its project permits. ure.l.3 - En Gatewa Transmission Ex ansion Plan 'lhis mup is lbr gcncral retircncc only and rellecN current plans. 11 may not rcflcci lhc tlnal ft)utes, conslru(lion sequencc or c\act line conliguralion WASHINGTON r MONTANA ph"T N IDAHO G Y E MING 'r i"g f t-z uo o\,CALIFORNIA NEVADA COLORADO ARIZONA N E W t4 E X t C O Pacillcorp retall service area New transmisrion liner: - 500 kV minimum volrat. - 345 kV minimum volu8e 230 kV minimum volhte a Exirrint subs(ation O New lubstarion 84 c.pt ln l.cl a $ sltuda rd(uro,r Segmeot & Name Description Approxim{te !Iile{ge Stafus and Scheduled ln-Scr! icc (A) Wallula-McNary 230 kV, single circuit 30 mi . Status: Construction complete. ln scrvice: .lanuary 2019 (B) Populus-Terminal 345 kV. double circuit 135 mi . Status: completed e Placed in scn,icc: November 2010 (c) Mona-OqtLinh ()quinh-Tcrninal 500 kV single circuitj,l5 kV double circuit -i;15 kV double circuit l(X) lni l,l mi . Status: completed. Placed in-service: Mav 2013 . Status: rights-of'-way acquisition undeuayr Scheduled in service: 2024 (Dl) Windstar-Aeolus Neu, 230 kV single circuit Re-built 230 kV single circuit 75 rni o Status: permitting undcru,ay. Schcduled in service: 1023 earlicst (D2) Aeolus- Bridger/Anticline 500 kV single circuit 140 mi . Status: under construction o Scheduled in scrricc: 2020 (D3) Bridger/Anticline- Populus 500 kV singlc circuit 200 rni o Status: permitting undcnvay. Schcduled in sen'ice: 2024 earlicst (E) Populus-Hemingway 500 kV single circuit 500 lni . Status: permitting under\rayr Scheduled in servicc: 2024 earliest (F) Aeolus-Mona -5 00 kV single circuit 4(X) mi . Status: pcrmitting underu'ay. Scheduled in service: 2023 ((; ) Sigurd-Red lhtle 3,15 kV singlc circuit 170 mi . Status: complctcdr Placcd in senice: May 2015 (H) Boardman- Ilemingway 500 kV single circuit 190 mi . Status: pursuing.ioint-developmcnt and/or firm capacity opportunities *'ith project sponsors . Scheduled in service: sponsor driven PA( ll,rCoRP f0l9 IRP (' APTER4 Ilr^\sMrs:iroN ln addition to investing in the Encrgy Gateway transmission projects, PacifiCorp continues to make other system improvements that have helped maximize eflicient use of the existing transmission system and det'er the need lor larger-scale, longer-term infrastructure 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 cfliciency through other smaller-scale, incremental projects. System-wide, PacifiCorp has instituted more than 155 grid operating procedures and l7 special protection schemes to rnaximize thc cxisting system capability ,,vhile managing systcm risk. In addition, PacifiCorp has been an active participant in the EIM sincc November 2014. The EIM provides for more eflcicnt dispatch ol' participating resources in real-tirne through an automated systcm that dispatches generation across the EIM footprint (collectively, EIM Area), which currently includes: 85 Efforts to Maximize Existing System Capability r PacifiCorp east and wesl balancing authority areas . NV Energy. Puget Sound Energy. Arizona Public Service o Portland General Electric P^( I,r('oRP l0l 9 tRI'CI TAPTIR 4 - TR ANsMrssroN o Idaho Power Company. Powerex Corporation in the BC Hydro balancing authority areao Balancing Authority of Northcm Califomia with its member the Sacramento Municipal Utility Districto CAISO balancing authority area (collectively, EIM Area) Entities scheduled to join the EIM includc Seattle City Light, Los Angeles Department of Water and Power, and Salt River Project (April 2020), NorthWcstern Energy (April 2021), and Public Service of Ncw Mexico (April 2021 pending state commission approval). r Installed backup 345-kV bus differential relays at Jim Bridger substation located in Wyoming o Project driver was to correct NERC Standard TPL-001-4 Category P5 deficiency identified in PacifiCorp's 2015 NERC TPL Assessment resulting from a fault plus relay lailure to operate evenl. o Bencfits include mitigating the risk of thermal overloads and voltage issues in the surrounding area resulting from the thilure of the primary 345-kV bus differential rclay protection to operate, and the resolution ofthe NERC Standard TPL-001-4 Category P5 deticiency. 2. Goshen Idaho Area Reconstructed the Goshen-Jclferson l6l-kV line locatcd in Idaho o Project driver was projected load growth at Jefferson substation that requircd increasing the capacity of'the l6l-kV line and eliminating existing clearance issues on the l6l-kV linc from Goshen-to-Jeff-crson substation. o Benefits include supporting projected load growth in the arca by increasing the capacity of thc l6l -kV transmission line and eliminating line clearance issues rvhich allows operation ofthc line at full capacity. Installed a new remedial action schsme (RAS) in the (ioshen/Rigby area ofldaho o Project driver *,as thc risk of losing the 345-kV source at Goshcn Substation that would result in thermal overload and severe low voltage conditions on other underlying transmission lines in the Goshen/Rigby area. The prcvious protcction scheme would havc tripped all load and generation in the area which was anticipated to bc up to 700 MW and 650 MW, respectivcly. o Benefits includc shedding less load and generation than the previous RAS (load up to 450 MW and generation up to 80 MW) to prcvent multiple thcrmal overload and low voltagc conditions and improved the restoration process by 86 By broadening the pool of lower-cost resourccs that can be accessed to balancc load system requirements, reliability is enhanced and system costs are reduced across the entirc EIM Area. In addition, thc automated system is able to identify and use available transmission capacity to transf'er the dispatched resourccs, enabling more efficicnt use ofthe available transrnission system. Transmission System Improvements Placed In-Service Since the 20l7IRP PacifiCorp East (PACE) Control Area l. Central Wyoming Area PA( lf rCoRP 2019 IRP (IHAP'rr:R,l TR^Nsrurssro\ making it less complicated than the previous protection scheme rvhich dropped all load and generation in the area. . Purchased a spare 345- I 6l kV transformer for Coshen substation in ldaho o Primary drivcr is to protcct against experiencing a singlc contingency event (N- l) for the failure ofonc olthc 700 megavolt-arnpere (MVA), 345-16l kV transfirrmers at Goshen substation that would cause thermal overload on the remaining lransfbrmer during heavy summer load pcriods and could result in ths load shcdding olup to 250 MW ofload in the arca fbr cxtended periods ol timc sincc therc werc no system spare transformers al this voltage class and capacity. o Llenefits include mitigating thc risk ol'thermal overload on the remaining 700 MVA, 345- 161 kV transformer and not having to shed up to 250 MW of load tbr cxtcndcd pcriods ol time during heavy summer loading conditions. r Installed shunt capacitors at Rigby and Sugarmill substations located in ldaho o Primary driver was 10 correct NERC Standard TPL-001-4 Category Pl-2 dcticiency identified in PaciliCorp's 2016 NERC 'IPL Asscssment and the 2016 Goshen Area Study resulling in low voltage issues caused by the loss ofa I (r I -kV line (N- I ). o Benclits include improving the voltage protilc undcr normal and outage conditions, resolving low voltage and voltage deviation issues, rcducing load shedding risk under normal opcrating conditions, mitigating consequential load loss ol' up to 150 MW, improving reliability to the Rigby-Sugarmill area customers, and rcsolution ol'NERC TPL-001-4 Category Pl-2 dcficiency. Southcast ldaho Area o Rcplaced an existing bus tie oil brcaker \.r'ith a SF6 breaker and added a circuit switchcr in series with the breaker at the 'l reasurcton 138-kV substation located in Idaho o Project driver u'as to correct NERC Standard TPL-001-4 Category P2-4 deliciency identilied in Pacifi(iorp's 2015 NERC TPL Assessment resulting from a potential stuck brcakcr cvent that prevents the bus tie to operate to clear a f'ault. The P2-4 contingency event that would result in thermal overloads bcyond the cmergency rating ofseveral ll8 kV lines in that arca. o Bcnetlts include mitigating the risk of thermal overloads and voltage issues, eliminating the potential loss ofload at the Treasureton substation ofup to 465 MW, and resolution of the NERCI 'lPL-001-4 Clategory P2-4 deliciency. Ogden Utah Area r Energized one circuit ofthe 230-kV Bcn Lomond-to-Panish line as a three-tenninal 138-kV linc liom Ben Lomond to Syracuse and Parrish locatcd in Utah o Projcct drivcr was to correct the NERC Standard l PL-003 Category C3 deficiency that u,as identified in PacitiCorp's 2013 NERC TPL Assessment that caused by lhe loss of any two bulk transmission clcmcnts under peak load conditions. 4 87 P^crr,rCoRP 20l9lRP (lltAP I tR 4 - Ttu\NS\ltsslo\ o Bencllts includc mitigating the risk of thermal overloads and voltage issues, mitigating the potential load shedding ol'up to 180 MW in the Ogden area, and the resolution ofthe NERC TPL-003 Category C3 deficiency. o lnstalled a sccond 700 MVA 345/138 kV translirrmer at Svracusc substation located in Utah o Project driver was to oorrect NERC Standard TPL-001 -4 Category P I , P6 and P7 defisienoies identitlcd in PacifiCorp's 2015 NERC TPL Asscssments resulting in a singlc contingency event (N-l) and multiplc contingency events (P6 and P7). o Benefits include mitigating the risk ol'thermal ovcrloads and low voltage issues, eliminating the risk ol'preemptive load shedding up to 30 MW, improving transmission reliability fbr customcrs in the Ogden area, and resolution ofthe NERC TPL-001-4 Catcgory Pl deficiencies and resolvcs nearly half the numbor of identified NERC TPL-001-4 Category P6 and P7 deficiencies (Operating procedures are in place to address the non-resolved P6 and P7 deficiencies that lvere not corrected by the implementation olthis projcct). o Installed a new RAS at El Monte substation and line closing for Riverdale-Gordon Avenue-Parrish 138-kV lincs in Utah o Pr<rject driver was to correct NERC Standard TPL-001-4 Category P2, P6 and P7 dcticiencies identified in PacifiCorp's 2016 NERC TPL Assessment that could cause thermal overload issues on multiplc 138-kV lines in the Ogden area. o llenefits inch-rde mitigating the risk ofthermal overloads, improving reliability to thc 138-kV system, optimizing the load shed lcvcls of the new RAS, and resolving NERC TPL-001 -4 Category P2, P6 and P7 deficiencies. Salt Lake Valley Area o Replaced breakers identificd as ovcr-dutied with higher-capability brcakcrs at MidVallcy substation in Utah o Project driver w,as to correct NERC Standard TPL-001-4 Requirernent R2.3 deficiencies identiflcd in PacitiCorp's 2015 NERC TPL Assessment rcsulting in thc identification of three 138-kV over-dutied brcakcrs at MidVallev substation. o Benefits include elirrinating the risk of over-dutied breakers failing undcr fault interruption conditions that pose safety and reliability risks, and the resolution olthe NL.RC 1'PL-001-4 Requirement R2.3 deficiencics. Park City Utah Area . Constructed a 138-kV line fiorn Crovdon substntion to Silvcr Creek substation located in t ltah o Proiect drivcrs rvcrc projected load grorvth and reliability improvemcnts which requircd an additional 138-kV source into the Park City area. o Benefits are the additional a 138-kV sourcc into the area, additional capacity to address projected load grorvth, and improved transmission reliability. 7. Utah Valley Arca n8 l 6 P,\crflCoRP-2019IRP o Installed backup bus diffcrcntial relays at Camp Williams substation located in Utah o Project driver was to correct NERC Standard T'PL-001-4 Category P5 deficiency identified in PacifiCorp's 201 5 NERC TP[- Assessment rcsulting lrom a I'ault plus relay l'ailure to operalc cvent. o Benellts include mitigating the risk of thermal ovcrloads and voltage issues in the surrounding arca rcsulting liom the failure of thc primary 345-kV bus differential relay protection to opcrate and the resolution ofthe NERC Standard TPI--001-4 Category P5 deficiency. o lnstalled a new bay with a breaker and halfscheme at Spanish F'ork substation located in Utah o Projcct driver was to correct NERC Standard TPL-003 Category C2 deficiency idcntiflcd in PaciliCorp's 2013 NERC TPL Assessmcnt fbr a potential stuck breaker event that prevcnts the bus-tie breaker to operate to clear a fault. o Benefits include mitigating the risk ol'thermal overloads and voltagc issues, and eliminating the potential loss ofthc entire Spanish 138-kV substation load o1' up to 270 MW, and resolution of thc NERC TPL-003 Category C2 deficicncy. 8. Southu'est Utah Area o Encrgized the Red llutte-St. Cicorge 345-kV line at 138 kV locatcd in Utah o Project driver was to correct NERCI Standard TPL-001-4 Category P6 and P7 deliciencies identilied in PacifiCorp's 2015 NERC TPI- Assessment resulting in multiplc contingcncy events (N- l - I and N-2 ) that would impact I 38-kV lines betu,een Red Butte/Central and St. George substations during heavy summer load ctlnditions. o Benelits include adding a fourth Central/Red Butte to St. George 138-kV line that increased capacity into St. George substation, improved 138-kV reliability in the area, eliminated the need fbr prccmptive loading shedding under an N-l- I outage condition up to I 70 MW, and rcsolved the NERC Standard TPL-001- 4 Catcgory P6 and P7 deliciencies. 9. L,ast Utah Area o Installcd 3.6 megavolt-ampcrc-reactive (MVAr) capacitor banks at Macser and Vemal substations located in Utah o Project driver u'as to correct NERC Standard TPL-001-4 Category Pl and P2 deficiencies identified in PacifiCorp's 2016 NERC TPL Assessment resulting fbr thc loss of a I 3 8-kV line (P I ) and for circuit brcak/bus Iaults (P2) that result in lorv voltage in the Vernal area. o Benefits include mitigating the risk ol'low voltage issues and resolution ofthe NERC Standard TPL-001-4 Category Pl and P2 delicicncies. PacifiCorp West (PACW) Control Area I . Yakima Washington Area . Rebuilt the I I 5-kV main and transfer bus into a breaker and half scheme at the Union Gap substation in Washingkrn C APTTR 4 - TR,\NstvtssroN E9 Cll\PIr.]R4 TRA\s\rrsstoN o Project driver was to correct NERC Standard TPL-003 Category C delicicncics identified in PaciliCorp's 2013 NERC 'l'PL Assessrnent lbr a I 15 kV bus section lault or breakcr tailure with protection system lailurc. o Benellts include mitigating the risk of thermal overloads and voltage issues. eliminating the risk of shedding up k) 500 MW ol load, and resolution ol'the NERC 'f PL-003 Category C deliciencics. r Replaced conductor on the Moxee-Hopland section of the Moxee-Union Gap I l5-kV line located in Washington o Project driver was to correct NERC Standard TPI--001-4 Catcgory Pl deficiency identilied in PacifiCorp's 2015 NERC TPL Assessmcnt resulting Iiom a single contingcncy event (N- I ) for the loss ol a 230-kV transmission linc. o Bcncfits include mitigating the risk ol'thermal overloads. increasing capacity of the ll5-kV line, improving transmission reliability, and resolution of the NERC TPL-001 -4 Catcgory P I deficiency. Portland Oregon Area o Rebuilt the 230-kV portion ol'thc Troutdale substation, located in Oregon, into a six hreaker ring bus configuration o Project drivcr rvas to correct NERCI Standard TPL-002 deficiency for the loss ofa single 230 kV line and NERC Standard TPL-003 for multiple oontingcncy (N- I - I and N-2) outagcs to 230-kV lincs that were identilied in the PacifiCorp's 201 I NERC TPL Assessrnent. o Benefits include mitigating the risk ol thcrmal overloads, eliminating thc risk ofshedding load in prcparation ofthe second contingency fbr an N-l-l outage, and rcsolution ofthe NERC TPL-002 and TPL-003 dcticiencies. r Converted portions of Portland, Oregon area transmission network to I l5 kV tiom 57 kV and 69 kV o Project drivers are projccted load grouth, needed additional capacity, and transmission reliability improvement needs in the Portland area. o Benefits include the elimination of portions of the old 57-kV and 69-kV systcms, increasing thc ll5-kV network, adding additional capacity to address projcctcd load grouth and reliability improvement to thc transmission network. 3. (lrant Pass Orcgon Area o Replaced thrcc 230-l l5 kV 125 MVA transf'ormers rvith two 230-l l5 kV 250 MVA transformers at Grants Pass substation in C)rcgon o Project driver was to correct NERC Standard TPL-002 deliciency fbr thc loss of'a single 230-kV linc and NERC Standard TPL-003 deficiencics for multiple contingency (N-l-l and N-2) outages to 23O-kV lincs that rvere identilied in PacifiCorp's 2013 NERC TPL Asscssmcnt. o Benelits include mitigating the risk of thermal overloads, eliminating the risk ofshcdding load in preparation ofthe second oontingency fbr an N-1-l outage, and resolution ofthe NE.RC TPL-002 and TPL-003 deficiencies. 4. Klamath Falls Oregon Area 90 2 PA( rlr(:oRp-l0l9IRP PAC|r'rCoRP 2019 IRP CITAPTtiR 4 - TRA\svrssroN . Constructed the new Snorv Goosc 500-230 kV substation locatcd in Oregon o Project driver was to correct NERC Standard TPL-001-l Catcgory B deliciency lbr the single contingency of the loss of thc existing 500-230 kV transfbrmer and TPL-003 Catcgory (l deficiencies lor multiple N- I - 1 and N-2 outages that were identified in PaciliCorp's 2012 r'r-ER(' 'f PL Asscssment. o Benefits include mitigating the risk of'thermal overloads and vohage issues, eliminates the risk ofshedding load in preparation of the sccond contingency Ibr an N- I - l outage, and resolves thc NERC TPL-001- I Clategory B and TPL- 003 Catcgory C deliciencies. 5. Yreka California Area o Replaced the existing I l5-69 kV transfomer at Wccd substation with a 50 MVA load tap changer (LTC) unit located in Caliibrnia o Project driver nas to improve 69-kV voltage regulation by changing out an old I l5-69 kV translormer at Weed Junction substation that had its no-load tap changer locked in place due to the high risk ol'causing internal transfbrmer faull ifopcrated. Thc ncw replacement I l-5-69 kV LTC transfonner was installcd at the nearby Weed substation. o Benefits include improved voltage control ofthe local 69-kV system, improved translbrmer reliability, and ability to usc load drop compensation to improve transmission voltagc prolile. Planned Transmission System Improvements PacifiCorp East (PACE) Control Area l. Central Wyoming Area . Upgrade the 345-230 #2 translbrmer at Jim Bridgcr substation in Wyoming o Project driver is to corrcct NERC Standard 1'PL-001-4 Category Pl and P3 deliciencies identified in PacifiCorp's 201 7 NERC TPL Assessmcnt resulting for a 345-kV or 230-kV bus fault (P I ) and fbr the loss of a generator and both J im Bridger 345-230 kV transfbrmers # I and #3 (P3) that will results in thermal overload of existing Jim Bridger 345-230 kV #2 transformer. o Bcncfits includc mitigating the risk ofthcrmal overloads and resolution ofthe NL,RC TPL-001-4 Catcgory Pl and P3 deficiencies. 2. Goshen ldaho Area . Install a third 345-l6l kV transfonner at Goshcn substation located in ldaho o Project driver is to correct NERC Standard TPL-001-4 Category Pl (N-l) deficienoy identified in Pacif'rCorp's 2016 Goshen Area Study rcsulting in thermal overload ol' the remaining 345-l6l kV translormer at Cioshen substation. o Benefits include mitigating the risk of'thermal overloads and rcsolution ofthe NERC Standard TPL-001 -4 Category P I dcticiency. e Install a new l6l-kV line liom Goshen to Sugarmill and then lrom Sugarrnill to Rigby substations located in ldaho 9l P^( l r(l)RP 2019 lRP CIAP ll R.l Tlr,\Ns \t t\\l( )\ 92 o Project driver is to address thc single contingency (N-l) and multiple contingency (N- l- I ) issues prcscnt in the Sugarmill-Rigby area and the large amount of load shcdding risk identified in thc 2016 Coshen Area Planning Study that proposcd adding a new l6l-kV linc fiom Goshen to Sugarmill and then fiom Sugarmill to Rigby substation to allow a looped conliguration during hcavy summer load conditions. o Bcnefits include mitigating thc risk of thermal overloads and voltage issues, and eliminating thc loss of up to 150 MW ol'load lbr N- l outages and up kr 300 MW lbr N- l- I outages. o Rebuild and oonvert an cxisting 69-kV line to I 6l -kV to cstablish a new I 6l -kV sourcc at Rexburg substation in ldaho o Project driver is to improve 69-kV capacity and voltage regulation sencd lrom Rigby substation by converting an existing 69-kV line to l6l kV to create a l6l-kV source at Rexburg substation through a new l6l-69 kV transformer installation. Thc project also will include a new six breaker 69-kV ring bus at Rexburg substation that includes terminating two existing 69-kV lines and one ncw 69-kV line. o Bcnefits include establishing a ncrv l6l-kV source in thc arca, providing additional 69-kV capacity, improving 69-kV voltage regulation and reliability to customers scrvcd from the 69-kV system. 3. Salt Lake Valley Area o Install a nerv circuit srvitcher in series with the bus-tic circuit breaker at 90th South substation located in Utah o Project driver is to correct NERC Standard TPL-001-4 Category P2-4 dcficiency identified in PacitiCorp's 2017 NERC'IPL Assessment fbr a bus tie breaker intemal lirult event that results in the loss of the entirc 90rl' South 138- kV substation. o Bcnctits include mitigating the risk of thermal overloads and voltage issues, and eliminating the potential loss ofload at the entire g0th South 138-kV South subslation lbr a bus tie failure event. and resolution of the NERC TPL-001-4 Catcgory P2-4 defi ciency. 4. Park City Utah Area . Install a 9-mile, 138-kV transmission line betwccn Midway and Jordancllc substations in Utah o Project drivers arc projected load grorvth and rcliability improvements w'hich rcquired ofextension ofthe I 38-kV line tiom Jordanelle-to-Midway substation. o Llenefits are the established new 138-kV loop, additional capacity to address projected load growth and improved transmission reliability. 5. Utah Valley Area . Upgrade the 345-138 kV transformer at Spanish Fork substation located in Utah o Projcct driver is to correct NERC Standard TPL-0C)l-4 Category P1 and P3 deticiencies identified in PacifiCorp's 2017 NER(l TPL Assessmcnt resulting liom an outagc ofSpanish Fork 345-138 kV translbrmer #4 (N-l) and multiple P^clr.rCoRP l0l9 IRP C ,^P I ItR -l Tt{,\NsvtsstoN double contingency outages (N-l-l) that result in lhermal overloads on numcrous subslation transformers and lransmission lines. o Bencflts include mitigating the risk ofthcmral overloads and low voltage issues, additional capacity to address projected load growth, irnproved transmission reliability and resolution oi the NERC -IPL-001-4 Category Pl and P3 deficiencies. 6. East Utah Area . Construct the new Naples 138-12.5 kV substation located in Utah o Project driver is to correct NERC Standard TPL-001-4 Catcgory P6 deficiencies identificd in PaciliCorp's 2016 NERC TPL Assessment resulting in multiple double contingencics causing low 138-kV system voltages in the Vcrnal area. o Benefits include mitigating the risk of lou voltage issues and resolution ofthe NERC Standard TPL-001-4 Category P6 deficiencics. 7. Utah & Idaho- Upgrade Program Backup Bus Differential Relays r Install backup bus differential relays at various substations located in Utah and ldaho o Project driver is to corect thc NERC Standard TPL-001-4 Category P5-5 dcficicncies identilled in PacifiCorp's 2015 NERC TPL Assessmcnts resulting in multiple contingcncies Ibr faults plus bus difI'erential relays failurc to operate that cause delayed fault clcaring due to the failurc ol'a non-redundant relay installation. o Bcnctits include rnitigating the risk ofdelayed clearing of all transrnission line connected to specific buses that would lcad to thermal overloads and voltage issues, ensuring that critical dill'erential bus protcction has the required relay redundancy, improving reliability to the impacted substations and their connected transmission lines, and resolution ol'the NERCI 1'PL-001-4 Category P5-5 del'ic iencies. 8. Utah, ldaho & Wyoming - Upgrade Program Replace Over-duticd Circuit Breakers . Replace breakers identified as over-dutied with higher-capability breakers in various substations located in ldaho, Utah, and Wyoming o Project driver is to correct NERC Standard TPL-001-4 Requircmcnt R2.3 deficiencies identiflcd in PaciliCorp's 201 5-201 8 NERC TPL Assessmcnt resulting in the identification of l3 over-dutied breakers. o Benefits include eliminating the risk ofover-dutied breakers failing under tault interruption conditions that posc sat'ety and reliability risks, and the resolution of the NERCI TPL-001-4 Requirement R2.3 dellciencies PacifiCorp West (PACW) Control Area [. Yakima Washington Area . Construst a new 230-kV transmission line frorn 13PA's Vantage substation to PacifiCorp's Pomona Heights substation locatcd in Washington o Project driver is to correct the NERC Standard TPL-002 deficiency identificd in PacitiCorp's 201 I TPL Asscssment for the loss ofa single 230-kV line. 9l I'^( l|rCoRP-20l9IRP ( rr'\P |riR .l I R,\Ns\rrssroN 9+ o Benefits include mitigating the risk ofthermal overloads and lorv voltagc issues, adding additional capacity to address projected load growrh, improving transmission reliability and resolution ofthc NERC TPI--002 dellcicncies. . Construct a new I l5-kV transmission line liom Outlook substation to Punkin Center substation located in Washington o Project driver is to correct N ERC Standard TPL-001-4 Category Pl deficiencies identified in the 20 l6 NERC l'PL Assessment tbr single contingency (N- I ) outages on the 230-kV system serving the Yakima Upper Valley. o Benellts include mitigating the risk ol'thcrmal overloads, resolving an existing capacity limitation on the I l5-kV line, improving transl'er capabitity betrveen the Upper Valley and the Lowcr Valley system, and rcsolution of the NERC TPL-001-4 Category Pl deficicncy. 2. Walla Walla Washington Area o Rcplace the existing I 15-69 kV, 20 MVA transformer with a I 15-69 kV, 50 MVA transformer at Dry Gulch substation located in Washington o Project driver is to correct NERC Standard TPL-001-4 Category P2 dcficiency identilicd in PacifiCorp's 20 I 5 NERC TPL Assessnrent lbr a I l5-kV bus fault at Dry Culch substation. o Benefits include having 69-kV capacity and voltage rcgulation capability to operate in a normal opcn conliguration to eliminate thcrmal overloads and lorv voltage conditions, eliminating the 69-kV loop in parallel u,ith thc 230-kV and 500-kV main grid system that impacted the 69-kV system for outages on thc main grid systcm, rernoving the Tucannon 69-kV line from the WECC Path 6 dcfinition, and resolving the NERC TPL-001-4 P2 delicicncy. 3. Albany/Con'allis Oregon Area o Rcplace conductor on the ll5-kV line between Hazelwood substation and BPA's Albany substalion and construct a new I I 5-kV ring bus at I lazehvood substation all located in 0rcgon o Project driver is to ctirrect NERC Standard TPI--001-4 Catcgory P6 defioiencies for an outage on the transformers at Fry substation and reduce load loss exposurc from various other N-l-l contingencies. o Benet'its include rnitigating thc risk of thennal overloads and voltage issues, improving transmission reliability, reducing the complexity ol' operating procedures fbr remaining N-l-l contingencies and resolution o1'a number of NERC TPL-001-4 Category P6 deficiencies. 4. Medlbrd Orcgon Area . Construct one new 500-230 kV substation called Sams Valley locatcd in Oregon o Project driver is kr corrcct NERC Standard TPL-002 tbr the loss ofa single 230- kV line and NERC Standard 'IPl.-003 lirr the N-l-l and N-2 outages to 230- kV lincs that were identified in PacifiCorp's 2010 NERC TPL Asscssment, and to provide a second 500-kV source to address load growth in the Southem Oregon region. P^( [.rCoRI, 20l9lRP CHAPTT,R 4 - TRANSI{tssloN o Benefits include adding a sccond source of500-kV capacity, adding a nen'230- kV linc, improving reliability of thc 230-kV netrvork, mitigatcs the risk of thermal ovcrloads and lou, voltage, mitigatcs the risk ol shedding load in preparation of the second contingency for N-l-l outages, and resolves thc NERC TPL-002 and TPL-003 dcticicncies. . Expand the RAS at Meridian substation located in Oregon o Project driver is to expand the existing RAS to cover threc additional N-l-l contingencics on the southem Oregon 500-kV system and trip additional load as identified in the 201 5 Meridian Area Load Tripping Assessment and the 20 I 7 NERC TPL Assessment. o Benefit ol'expanding the RAS will bc to avoid relying on thc Southern Oregon Under-Voltagc Load Shedding scheme as the primary mitigation for double contingencies on the 500-kV system. 5. Yreka Califomia Area o Install an additional I l5-69 kV translbrmer at Yreka substation located in California o Project driver is to correct low voltage conditions undcr normal operating conditions during heavy summer loading periods due to inadequate vohage regulation on the 69-kV system served from Yrcka substation, as identified in the 2013 Yreka-Mt Shasta Area Study. o Benefits include the ability to providc 69-kV voltage regulation by the new I l5- 69 kV transfbrmers load tap changer, allorvs thc use ol'load drop compensation feature to further improvc lhe transmission voltagc protile over the lon-e term, and making the exiting non-LTC transfbrmer available as an installed spare firr immediate servicc rcstoration rr'hen needed. 6. Oregon - Upgrade Program - Replace Over-dutied Circuit Brcakers . Replace breakers identified as ovcr-dutied rvith higher-capability breakers at Lone Pine Substation in Orcg0n o Project drivcr is to correct NERCI Standard TPL-001-4 Requirement R2.3 deficiencies identified in PacifiCorp's 2015-2018 NERC TPL Assessment resulting in the identification ofthrcc over-dutied I l5-kV breakers. o Benefits includc eliminating the risk of ovcr-dutied I l5-kV breakers failing under fault interruption conditions that pose salety and rcliability risks, and tlie resolution ol'the NERCI TPL-0L) I -4 Requirement R2.3 deficiencies. Thcse investmerrts help maximize the existing system's capability, irnprove PaciliCorp's ability to serve growing customcr loads, improve reliability, increase lransf'er capacity across WECC Paths, reduce the risk of voltage collapsc and maintain compliancc rvith NERC and WECC rcliability standards. 95 P,\( I,rCoRP l0l9 lltl'(lU,\P ll,R .l I Rl\srlssroN 96 CsaprEn 5 - Loeo eNp RESoURCE Bar-RNcs PACI,TC()RP 20l9lRP CIIAPTER 5 - LoAD AND RtsouRCE BAT.AN( rl CuaprEn HTGHLTGHTS o On both a capacity and energy basis, PacifiCorp calculatcs load and resource balances from existing resources, Ibrecasted loads and sales, and reservc rcquirements. The capacity balance compares existing rcsourcc capability at the time ofthe coincidcnt system summer and winter pcak periods. o For capacity expansion planning, PacifiCorp uses a l3 percent target planning rescrvc rnargin (PRM) applied to the company's obligation, which is calculated as projected load lcss private generation, less energy elliciency savings (Class 2 dcmand-side management (DSM)), and less intcrruptible load. o A 2018 Private Generation Long-Tcrm Rcsource Assessment (2019-2038) study preparcd by Navigant Consulting, Inc. produced estimates on private generation penetration levels specific to PacifiCorp's six-state territory. The study providcd cxpected penetration levels by resource type, along with high and low penetration sensitivitics. PacifiCorp's 2019 IRP load and resourcc balance trcats base case private generation penetration lcvels as a reduction in load. o After accounting for load reductions from private generation and energy efficiency savings liom the preferred portlolio, PaciliCorp's system coincident pcak load is lirrecasted to grou, at a compound annual growth rate of'0. l0 percent over the period 2019 through 2038 (0.64 percent without incremental energy efficiency from the prel'erred portfblio). On an energy basis, PacifiCorp expects system-R'ide average load grorvth of 0.06 percent per year from 2019 through 2038 (0.73 pcrcent w-ithout incremental energy efficiency savings liom the preferred portfolio). o After accounting lor the l3 percent target PRM, load growth. coal unit retirements from the prelerred portfolio, and afler incorporating future energy cflicicncy savings from the pref'erred portfolio, PacitiCorp's system is capacity deficient ovcr the summer peak throughout the twenty-year planning period and is capacity deficient over the winter peak beginning 2024. e When accounting ltrr these same f?rctors and the [eve[ of potcntial market purchases, fnrnt office transactions (FOTs), assumcd in the 2019 lntegrated Resource Plan (lRP), PacifiCorp's system is capacity deficient over the summer peak beginning 2028 and is capacity deficient over the winter peak beginning 2029. 'l'his chaptcr prcscnts PacillCorp's asscssmcnt of its load and resource balance. PacifiCorp's long- term load forecasts (both energy and coincident peak load) fbr each state and the system as a rl,hole are summarized in Volumc II, Appcndix A (Load Forecast Details). -l'he summary-lcvel system coincident peak is presented first, followed by a profile ofPacifiCorp's existing resources. Finally, load and resource balances lirr capacity and energy are prescntcd. Thsse balances are composed of a ycar-by-year comparison of projccted loads against the existing resource basc, with and without available FO'l's, assumed coal unit retircments and incremental new energy efficiency savings tiom the 2019 IRP prel'erred portfolio, before adding ncrv gcnsrating resources. 97 Introduction PACTFTCoRP-20l9IRP CIIAPTLR 5 - LoAD AND Rr-.s(nlRCF: BAI.ANCI System Coincident Peak Load Forecast Table 5.1 - Forecasted System Summer Coincident Peak Load in Megawatts, Before Energy EI'Iicienc and Private Ce ncration Ntw 2026 Existing Resources On a system coincident basis, PacifiCorp is a summer-peaking utility. For the tbrecasted 2019 summer coincident peak, PacifiCorp owns or contracts for resources to meet expected system summer peak capacity. Note that capacity ratings in the Ibllowing tablcs provide resource capacity value at namcplate, rounded to the nearest megawatt. Thermal Plants Table 5.2 lists PacifiCorp's existing coal-f'uclcd plants and Table 5.3 lists existing natural-gas- fueled plants. End ollife year dates reflect those assumed in the prcl'cred portfolio. Table 5.2 - Coal-Fueled Plants Plant PaciliCorp Percentage Shrre (%) Statc Dnd of Life Year Nameplat€ Capacity (Mw) Choll:r..1 100 Arizona 1020 Colstrip i Montana 0 ColstriP,l Mon(ana 2027 Craig 1 l9 2025 It1 Craig l (irlorado 1026 It Dave Johnston I t00 Dave Jolrnsk)n l l0t)Wyoming 100 Wyorning 202i 220 Dave Johnslon 4 t00 l0_3 0 .ll :0i0 tirah I0.ll 2019 2020 2021 2023 2t21 2025 2027 202t2022 Svstem t0,28.1 10,,125 l(),51q t0,78ti 10,91.1 I t,0t2 I t.057 I 1,149 | 1,26t 2029 2030 2{r-11 2012 2031 2034 2035 2036 2031 203It Svstem I 1,362 I 1.469 I t,u.t4 12,078 98 The system coincident peak load is the annual maximum hourly load on the system. The 2019 IRP relies on PacifiCorp's September 2018 load forecast. Table 5.1 shows the annual summer coincident pcak load stated in megawatts (MW) as rcported in the capacity load and rcsource balance, before any load reductions fiom energy ctlciency and private generation. The system summer peak load grows at a compound growth rate (CAGR) of 0.90 perccnt over the period 2019 through 2038. t0.671 r r.575 I 1.696 I 1,809 I I,723 I 1.9,16 I 2, t93 I .l87 l(i 74 t0 14 ( olorado l9 Wyoming 2017 99 2021 106 Davc Johnslon 3 Wyoming 2021 330 Llayden I l.l ( olorado Havdcn 2 tl Colorado Hunter I g-l -ln 100 t,tah 20,11 11l,Hunter 3 Utah 2036 .159Huntington I t00 Utah 2036 .l-it)H untington l 61 l0ll 354Jim Bridgcr I Wyoming 67 Wyonring 2 02li 359.lim lltidgcr I 61 Wyoming 20i7 i49Jim Bridger 3 61 Wyoming 2017 i53.lim Bridger 4 100 Wyoming 1025 156Naughton I Naughtun 2 t00 Wyoming l0l5 201 I00 2019 0Naughton 3*Wyoming 80 Wyoming 2019 2(rllWyodak 5.638TOTz\1, - Coal P,\cIlCoRP 20l9 IRP CIIApf[R 5 - L(r\l) ,,\Nr) RlisotrR( r, B,^r NC|, lluntcr l 60 Utah 2012 269 * Naughton 3 coal gcneration cnded January 30,2019. The preferred portfolio converts Naughton 3 to gas in 2020 through 2029. Tablc 5.3 - ),,Jatural-Cas- Fueled Plants Renewable Resources Wind PaciliCorp either owns or purchases under contract 3,908 MW of wind resources. Table 5.4 shows existing wind thcilities owned by PacifiCorp, while Table 5.5 shows existing wind power purchase agreements. 100 Washington 20,1i -l9lChchalis l(x)10.15 5J5Cunant Creek :032Cadsbl" I 100 Utuh 69100Utirh2012Cadsby 2 2032 t05(hdsbv 3 100 Utirh .10l(x)UrahCadsbl-.1 2012 -l(l100Cadsby 5 20tl ,10(irdsby (:100 2016 231Henniston1000rcgon 104"t 55ttakc Side 100 l(x)l-tllh 1054 (>]{Lakc Sidc 2 2,tt 2 lTO'lAL - ltlatural (ias 99 t00 Natural Gas -fuelcd PacifiCorp PercentaBe Share (%\ Statc As s unred End of Life Yerr NameCate Capacity (MW) Utah Utah Utah Utah PACII.ICORP 20I9 IRP CIIAPTER 5 LoAI) ANI) RFjSoIJRCE BALANCE Table 5.4 - Owned Wind Resources + Net total capacity for Foote Crcek I is 40 MW. ** Wind facility not pan ofEV 2020- In service December 31,2020*** EV 2020 in service by December 31, 2020. Table 5.5 - Non-Owned Wind Resources Foolc (-rcck I *.il Leaning.lunipcr OR t0l Goodnoe Hills East Wind 94 Marengo l.l0 Marengo II 7t) Clenrock Wind I 99 Clenrock Wind III _i9 Rolling IIills Wind 99 Seven Mile Hill Wind 99 Seven Mile Uill Wind Il l0 I Iigh Plains 99 McFadden Ridge I 19 Dunlap I llt Prvor Mountain **M',l't.l0 Cedar Springs II***100 Ekola Flats ***250 TB Flats ***.5 00 TO'l AL * Owncd wind 111) Cedar Springs Wind ***PPA 200 Ccdar Springs Ill *PPA D0 Combinc Hills oR PPA ,ll PPA t1 Rock Rivqr I PPA 50 Stateline wind ORiWA PPA 175 l-hree lluttes Wind Po\rcr (Dukc)PPA 99.0 Top of the World PPA 100 Wolverine Creek ID PPA 65 Chopin ()!IO F ootc ('rcck Il ()f 2 Footc ('rcck Ill Q[.l5 Latigo Wind UT Ql' Mariah Wind OR ( )t-t0 Mcadow Creck Project - Five Pine ID ()tl .10.0 Meadow Creek Project - Nonh Point Il.)QF 80 Monticcllo Wind UT ()F 79 N{ountain Wind Porver I QF 6l lVlountain Wind Porver Il QF 8t) Orchard Wind QF .10 Oregon Wind Farms I & II QF 65oR Orern |am ilv Wind QFOR Pioneer Wind Park I QF 80 Porver County Wind Park Nonh lL)OF ll l0c) tltilit\ -Ownrd Wind Proiects State Capacil\'(MW) Power Purchase.{grecmcnts / Exchangcs State PPA or OF Capacitv (MW) Footc Crcck lV 60 10.0 Spanish Fork Wind Park 2 ut'QF l9 Three Mile Canyon QF t0 u1'3Toole Army Depot QF 0.2Small QF QI. TOTAL - Purchased Wind 1,686 P^crflCORP-20l9lRP CHAPTER 5 - LoAD ^ND RESoIJRC}- BAI-AN(.}. Porvcr Wind Prrk Soutlr [)QF li i Wind facility not pan of F-V 2020. Nerv since 201 7 IRP Update** EV 20f0 in sen'ice by Dcccmbcr i1,2020. Solar PacifiCorp has a total ol'61 solar projects under contract representing 1,759 MW of nameplate capacity. OI'thesc, scvcn projects totaling 559 MW are new since the 2017 IRP Update. Table 5.6 - Non-Owned Solar Resources PPA OR )Bllck Cap PPA UT 2Utah Solar PV Program PPA OR 5 PPA OR t0Oregon Solar Inccntivc Projccts (OSIP) PPA UT 99Nlillbrd * PPA UT 100Ilunter * PPA UT ti0Sigurd * PPA UT 58Cove Mountain * PPA UT t22( o!e lvlountdin ll * PPA OR l0Prineville * PPA OR 60lVlillican * Sntall Solar Qr-UT 0.5 Qr-OR l0 Bear Creek Solar Center Ql.OR l0 Beryl Solar Q!UT 8Black Cap Solar ll Ql.oR qBlv Solar Center Qr.oR Ql.Buckhorn Solar UT Qr.lCedar Valley Solar UT QF l0(ihiloquin Solar OR QF OR l0Collicr Solar QF OR l0Elbc Solar Center QF UT tt0Entcrprise Solar QF UT 80Escalante Solar I 80Escalante Solar II Qr' 80Escalante Solar lll Qr-T,IT (ll'I[]rvauna Solar oR QF OR[]rvauna Solar 2 QF Li ISunF Solar XVll Project l-3 QF It0Granite Mountain - East QF UT 50Granitc Mountain - Wcst QF UTCranite Peak Solar QF IITGreenville Solar QF t,rT 8t)lron Springs QI-LTT l0l Power Purchuse Agrecments / Exchanges PPA or QF Statc CaDacity (MW) otd Mill Adams Solar Center UT L' I Laho Solar Villirrd Ir lirt Solar Qr,UT \.lillirrd Sollr l QI.UT Norucst Lnergy 2 (NefI)QI.OR l0 NorNcst linergy 4 (Bonanza)QI.OR 6 Norucst llncrgy 7 (Lagle I'oint)QF OR l0 Norwcst Flnorgy 9 Pendleton QF OR 6 OR Solur l, LLC (,Agate llay)()F OR l0 OR Solur 3. LLC (Turkey IIill)()F OR l0 OR Solar 5. LLC (Menill)QF OR l{ OR Solar 6. LLC (Lakevieu)oF oR l0 OR Solar 7, LLC (Jacksonville)OF OR l0 OR Solar li, LLC (Dairy)oF OR l0 OF Ll I 50 Pavant Solar ll LLC OF UI 50 Pavanl Solar III LLC QF LT l0 Quichapa Solar l- 3 QF UT 9 Sage lSolar QF l0 Sagr: ll Solar OF l0 Sagc Ill Solar oF'1,3 South l\'liltbrd Solar QF UT Swcct$.atcr Solar QF ,!0 Three Pcaks Solar QF UT ll0 Tunthlcwccd Solar QF oR l0 Utah l{cd llills Renervable Park QI.UT 80 oF oR li 1.759 Merrill Solar QF OR l0 * Ne\ since 2017 IRP Update Geothermal PacifiCorp owns and operatcs thc Blundell geothermal plant in Utah, which uses naturally crealed steam to gcncrate electricity. The plant has a net generation capacity of 34 MW. Blundell is a fully renewable, zero-discharge lacilily. Thc bottoming cycle. \r,hich increased the output by ll MW, was completed at lhc cnd of 2007. 'l'he Oregon Institute ol'Technology added a ner.r' small qualitying facility (QF) using geothermal technologies k) produce renewable power for the campus that is rated at 0.28 MW. PacifiCorp has a six-year power purchase agrcemcnt with a 3.65 MW QF geothcrmal projcct ncar Lakeview, Oregon, which became operational September 2016. Biomass/Biogas PaciliCorp has biomass/biogas agreements with l9 projects totaling approximately 100 MW of namcplatc capacity. At least one project is located in each statc in PacifiCorp's serv'ice territory. Renewables Net Metering lnstallation rates for net metering facilities have been relativcly consistent lor the last ferv ycars in the Pacific Porver States. While in the Rocky Mountain Polver states the net metering installation rates have declined approximatcly 40 percent from the peak installed in 201 7. Table 5.7 provides a brcakdorvn ofnet metered capacity and customer counts liom data collected on September 30, 2019. t02 P^crr rC (mP l0l 9 IRP CH,\p l r-R 5 - Lo,\D AND RESotrRCt BAl AN( r: TOTAL - Purchased Solar Pavarlt Solar Woodline Solar PACIIICoRP 20I9IRP CltAprER 5 - LoAr) ANr) RHSoURCE BALANCI 401,71,8 873 884 899 1,,1,57\ameplate (kW) 99.06%0.22%o.22%0.22%0.28%Capacity (pcrccntagc ol total) 47 ,761 198 4 20 58\ umber of customcrs 99.4t%o.42%o.oto/o o.o4%0.72%Customer (percentage of total) Tablc 5.7 - Net ]Vlctcrin Customcrs and ('a acities I (ia-s includes: biofuel, wastc gas, and fuel cells: Mixed includes projects with multiple technologies, onc project is solar and biogas and the others are solar and rvind Hydroelectric Generation PaciliCorp owns 1,135 MW ol hydroelectric generation capacity and purchases the output from 89 MW of other hydroclcctric resourccs. I These resources provide operational benefits such as flexible generation, spinning reserves and voltagc control. PacifiCorp-owned hydroelcctric plants are located in Califomia, Idaho, Montana, Oregon, Washington, Wyoming, and Utah. The amount of clcctricity PacifiCorp is ablc to gcnerate or purchase lrom hydroclcctric plants is dependent upon a number of factors, including thc watcr content ofsnow pack accumulations in thc mountains upstreanl ol'its hydroelectric lacilities and the amount of' precipitation that falls in its watershed. Opcrational limitations ofthe hydroelectric facilities are af'flctsd by varying water levels, licensing requirements for fish and aquatic habitat, and flood control, which lead to load and resource balance capacity values that are dif'ferent from net facility capacity ratings. Hydroelectric purchases are categorized into two $oups, as shown in Table 5.8, which shows 2019 capacity. Table 5.8 - H lectric Contracts Table 5.9 provides the capacity for each of PacifiCorp's owned hydroelectric generation facilities in 2019. Hvdroelectric 192 Qualif'-ving lacilities I lydroelectric u8 Total Contracted Hvdroclectric Resou rccs 280 rPacifiCorp's 201 8 l0-K shows I ,135 MW of Net |acility Capacity. l0l Fuel Solar Wind Gasl/Hvdro MiredI/ Hydroclcctric Contrncts bv Load and Resrlurce Balance Catesory NamcDlate CaDacitv (Mw) Wcst Bie Fork \47 .l Klamath - Dispatch CA 56 Klamath F lat CA ll Klamath Shape OR t6 Lcrvis l)ispatch 425 Lervis Shapc 94 Rogue OR 3t Small West llydrol cA/owwA Umpqua - Flat oR t5 Umpqua - Shape OR ti9 Bear Rivcr - Dispatch ID/UT 60 l3ear River Shape ID/UT :0 Small l-ast I ly-dror ID/UT/WY ll TO'l AL - Hvdroelectric before Contracts 916 Plus Hydroelectric Contracts It0 'I OTAL - Hvdroelectric with Contracts 1,20.1 Tahle 5.9 - PacifiCo Owned droelectric Generation Facilities -Ca acities r/CowlitzCountyPUDownsSwittNo.2,andisoperatedincoordinationwiththeothcrprojectsbyPacifiCorp 'z' Includes Bend, Fall Crcck, and Wallowa Fallsr' Includcs Ashton, Paris, Pioneer, Weber, Stairs. Granitc, Snakc Cresk, Olmstead, Fountain Green, Vcyo, Sand Cove, Viva Naughton, and Gunlock Hydroelectric Relicensing Impacts on Generation Table 5. l0 lists the estimatcd impacts to average annual hydro generation tiom expected Fcdcral Energy [{egulatory Commission (FERC) orders and relisensing scttlement commitments. PacifiCorp assumes that the Klamath hydroelectric Iacilities rvill be decommissioncd in accordance rvith the Klamath Hydroelectric Settlement Agreement in the year 2022 and that other projects currently in relicensing will reccive new operating licenses, but that additional operating reslrictions will bc imposed in new licenses, such as highcr bypass flow requirements, that will reduce generation available from these lircilities. Table 5.t0 - Estimated lmpact of FERC License Renewals and Relicensing Scttlement Commitments on H droelectric Gencration Demand-Side I\Ianagement For resource planning purposes, PacifiCorp classifies DSM resources into four categories, diffcrentiated by two primary characteristics: reliability and customer choioe. These resourccs are captured through programmatic ellbrts that promotc etlicient electricity use through various intervention strategies, aimcd at changing energy use during peak periods (load control), timing (pricc rcsponse and load shifting), intensity (energy ellicicncy), or behaviors (education and information). The four categories includc: 104 l0I 9-1020 9.485 11,116 (rlll,000 (rli9, I l6 PACrllcoRp-20l9lRP CIIAPTER 5 _ LoAI) AND IGSOLIRCI BALANCE Plart State(s)CaDrcitr'(NIW) Flast Yeani lncremcntal Lost Gcneration (MWh)Cumulativc Lost Generatior (MWh) 102I -1036 PA( lllCoRP 2019 IRP Class I DSM (Demand Response) -Rs56u1ss5 from fully dispatchable or scheduled firm capacity product offerings/programs: Demand Rcsponse programs are those fbr which oapacity savings occur as a result ol'active company control or advanoed scheduling. Once customers agree to participate in thcsc programs, the timirrg and persistencc of thc load reduction is involuntary on their part within thc agreed upon lirrits and parameters of the program. Program e'xamples include residential and snrall commercial central air conditioncr load control programs that are dispatchable, and irrigation load management and interruptible or curtailment programs lrvhich may be dispatchable or schedulcd frrm, depending on the particular program design or cvcnt noticing requirements). Sar,ings arc typically only sustained for the duration ofthe evcnt and there may also be retum energy associated with thc program. CILAprt,R 5 - LoAt) ANI) RtisouRCE BALAN'cl a Class 2 DSM (Energy Elficiency) -Rcsources from non-dispatchable, firm encrgy and capacitl product offerings/programs: Encrgy Efliciency programs are energy and related capacity savings which are achieved through fhcilitation ol' technological advancenrcnts in c-quipmcnt, appliances, structures, or repeatablc and prcdictable voluntary actions on a customer's part to managc thc energy use at their husiness or homc. Thcsc programs generally provide financial incenlivcs or services to customers to improve the elficiency ol'existing or neu residential or commercial buildings through: (l) the installation of morc clllcicnt cquipment, such as lighting, motors. air conditioners, or appliances; (2) increasing building cflicicncy, such as improved insulation levels or windorvs; or (3) behavioral nrodifications, such as strategic energy n'ranagement efforts at husiness or honrc energy reports lirr residential customers. Thc savings are considered firm o\cr thc lif'c ol'the improvement or cust()mrr xction. Class 3 DSM (Price Response and Load Shifting) -Resources from price-responsive energy and capacity product offerings/programs: Price rcsponsc and load shilting programs scck to achieve short-duration (hour by hour) energy and capacity savings fiom actions taken by customers voluntarily, bascd on a financial incentive or signal. As a result of their voluntary nature, participation tends to be low and savings are less predictable, making thcsc resources less suitablc to incorporate into resource planning, at lcast until their size and custorner behavior profile providc sufllcient inlirnnation needed to model and plan firr a reliable and predictable impact. The impacts ofthcsc resources may not be explicitly considered in the resourcc planning process; however, they are captured naturally in long-term load grou,th pattems and forecasts. Program examples include time-of-use pricing plans, critical peak pricing plans, and invened block tarifl'dcsigns. Savings are typically only sustained for thc duration ol'the incentive offering and, in many cascs, loads tend to be shifted rather than being avoided. Class 4 DSM (Education and lnlbrmation) -Non-incented behavioral-based savings achieved through broad energy education and communication ef'lbrts: Education and lnlbrmation programs promotc rcductions in energy or capacity usage through broad-bascd energy education and communication etlbrts. Thc program objectives are to help customers better understand how to manage their energy usage through no-cost actions such as conscrvativc thcrmostat setlings and nrming o11'appliances, equipment and lights u'hen not in use. 'l hese programs are also used to increasc customer awareness ofadditional actions they might takc 1o save energy and the service and financial tools available Io assist lhem. Thcsc programs help foster an undcrstanding and appreciation of rvhy utilities seek 105 PAC II.ICoRP 20I9IRP CIIAP'I T.:R 5 LoADAND RISOURC}, Bi\I,A\(.}, customer pafticipation in othcr programs. Similar to price responsc and load shifting resources, the irrpacts of these prograrns may not be explicitly considered in the resource planning process; horvever, they are captured naturally in long-term load growth pattcms and tbrecasts. Program exanrples include company brochures rvith energy savings tips, customer newsletters lircusing on cncrgy efficiency, case studies of customer energy eflciency projects, and public cducation and awareness programs. PacifiCorp has been opcrating successful DSM programs since the late 1970s. While the company's DSM fbcus has remained strong over this timc, since the 2001 rvestem energy crisis, PacifiCorp's DSM pursuits have expandcd to neu' heights in terms ol'investment level, state presence, breadth of DSM resourccs pursued and resource planning considerations. Work continues on the expansion of cost-effective program portlblios and savings opportunities in all states while at thc samc time adapting programs and mcasurc baselines to refleot the impacts of advancing state and federal energy codes and standards. ln Oregon, PacifiCorp continucs to rvork closely rvith the Energy Trust of-C)regon to hclp identify additional resourcc opportunities, improve delivery and communication coordination, ensure adequate Iunding, and provide company support in pursuit of DSM rcsource targets. Tablc 5.1 I summarizes PacifiCorp's existing DSM programs, their assumed impact, and how they are treated for purposes ol'incremcntal rcsource planning. Note that sincc incremental energy efficiency is determincd as an outcome of resource portlirlio modeling and is characterized as a new resourcc in the pret-erred portflolio, existing energy ctlicicncy in-l'able 5.1 I is shorvn as having zero MW.: lior a summary of current DSM program of-fbrings in each state, ref'er to Volume Il, Appendix D (Demand-Side Managcmcnt Resources). r Thc historical ct}'ects ofprcvious Ciass 2 DSM savings are backed out ofthe load lirrccast before the modeling for new Class 2 DSM. t06 P^crFrCoRP-20l9lRP CHApTER 5 - LoAD AND RESoURCE BALANCTi -table 5.11 - Existin DSM Resource Summa Assumes six percent Ii)r f,lanning reserves in addilion to rcali/cd irrigation load curtailment in ldaho and titah of 170 \'fW and l0 Mw, respecti!el). with a additional I Ntw tiom thc orcgon pilol through 20?0.} Due to the timing of the 2019 IRP load tbrecast, there is a small amounl (81 NfW) ofexisting Class 2 Ds\4 in Table 5. | 4 ( System Capaciq I-oads and Resources without Resource Additions). Private Generation For the 2019 IRP, PacifiClorp contracted with Navigant Consulting Inc. (Navigant) to update the assessrnent of private generation (PG) penetration performed lbr thc 2017 IRP rvith new market and incentive devclopmcnts. Thc study provided a lirrecast ofadoption for each privatc gcncration resource in each ofthe six states serued by PacifiCorp. Specific technokrgies studied included solar photovoltaic, small-scale wind, small-scale hydro, and combined hcat and power (CHP) Ibr both reciprocating engincs and micro-turbincs. Navigant estimates approximately 1.3 gigarvatts (GW) of PG capacity rvill be installed in PacifiCorp's territory liom 2019-2038 in the base case scenario. As shorvn in Figurc 5.1, the low and high scenarios pnrject a cumulative installed capacity of 0.60 CW and 2.3 GW by 2038, respcctively. The main drivcrs between the dill'erent scenarios include variation in technology costs, system performance, and electricity rate assumptions. As in the 2017 IRP, the Navigant study identifies expected levels of customer-sited private generation, which is applied as a reduction to Paciflcorp's tbrecasted load for IRP modeling purposes. 122 MW summer peak Ycs Rcsidcntial/small commercial air conditioner load contrul 205 MW summer peak|YesIrrigarion load management I Interruptiblc contracts 177 MW Year-round availability No. ('lass f DSM programs are modclcd as rcsourcc options in the portfolio development process and includcd in thc pret'ened poftfolio. 1 PacifiCorp and Energy Trust of Orcgon pnrgrams 0 \4wl No. Historical savings from customer responses to pricing signals are reflected in the load lbrecast. Time-based pricing 98 MW summcr peak 55- 149 GWh (capacity impacts arc unavailable due to lack of information on end usc loads bcing saved No. Historical savings from CUStomer response to pricing structure is reflected in load forecast. Inverted rate pricing ,l Energy education Encrgy and capacity impacts are not available/mcasurcd No. Hiskrrical savings liom customer panicipation are refl ected in thc k)ad fbrecast. 107 Encrgy Savings or Capacit,' at Ccncrator lncludcd as Existing Resources for 2019-2038 Period l'rogranr Class Dcscription Yes. -1 PACTTTC0RP 2019lRP CrlAprER 5 - LoAr) ANr) RESoTJRC[ tsALANCE Figure 5.1 Private Gcneration N'larke t Pcnetration (IIW..rt ), 2019-2038 () 3E : o- (J : -g E o a. PaciliCorp obtains the remainder of its capacity and encrgy requirements through long-term firm contracts, short-term firm contracts, and spot market purchases. Figure 5.2 presents thc contract capacity in place lbr 2020 through 2038. As shown, major capacity reductions in wind purchases and QF contracts occur. For planning purposes, PacifiCorp assumes intcrruptible load contracts are extended through the end ofthc IRP study period. The renewable wind eontracts arc shown at their capacity contribulion lcvels. Fi re 5.2 - Contract Ca :l in the 2019 IRP Summer Load and Rcsource Balance - PurchaserWind IQFlSolar Ilnterruptible+Net PositionIdro ESale ,$," rs.tr{Pr{F rs," r{F r$," rd$ r$,- r{F "s," .\,sf 1,$r{r "*-"*F r*"r*l r*- 2,500 2,000 1,500 1,000 500 0 -500 -1,000 r08 Power Purchase Contracts C Apt uR 5 LoAr) A\r) RF sor.R( ri BAl. NCIl Capacity and Energy Balance Overview Thc purpose o{-the load and resourcc balance is to compare annual obligations with thc annual capability ol PacifiCorp's existing resources, without new generating resource additions. 'l'his is done with two views ofthe system, the capacity balancc and energy balance. Thc capacity balance compares generating capability at time of system summer pcak load hours. It is a kcy part ofthe load and resource balancc because it helps guide the timing and severity of potential future resource need. The capacity balance is inherently captured in the IRP models for any give scenario. For reporting purposes, the capacity balance summarized in this chapter is developed by first reducing the hourly system load by hourly private generation projections to determine the net system coincident pcak load fbr each of the first ten years (2019-2028) of the planning horizon. lntem.rptible load programs, existing load reduction DSM programs, and nerv load reduction DSM programs from the preferred portfolio at thc time ofthe net system coincident peak are f'urther netted liom the peak load lorecast to compute the annual peak-hour obligation. Then the annual flrm capacity availability ofthe existing resources, reflecting assumed coal unit retirements fiom the preferred portfolio, is determincd. The annual resource deficit or surplus is then computed by multiplying the obligation by the target PRM and then subtracting the result from existing resources. This view is presented with an account rvithout and with uncommitted FOTs. Thc energy balance shows the average monthly on-peak and off-peak surplus or deficit ol'energy over thc lirst ten years of the planning horizon (2019-2028). The average obligation (load lcss existing DSM programs, new DSM programs f-rom thc pref'erred portfblio, and projected private gcneration) is computed and subtracted liom the average existing resourcc availability lbr each month and time-ol'-day period. Thc usef'ulness ol'the energy balance is limited becausc it docs not address thc cost ofthe available energy. The cconomics ol'adding resources to the system to meet both oapacity and energy needs are addressed during the resourcc portfolio development process described in Chapter 7 (Modeling and Porttblio Evaluation Approach). Load and Resource Balance Components The capacity and energy balances make usc of the same load and resource components in their calculations. The main component categories consist ol the tbllowing: resources, obligation, reserves, position, and available FOTs. Under the calculations, there are negative values in the table in both the resourcc and obligation sections. This is consistent rvith how resource categories are represented in portfolio modcling. The resource categories include resources by typc-thcrmal, hydroelectric, renewable, QFs, purchases, existing demand response, sales, and non-owned reserves. Categorics in thc ohligation section include load (net of private generation), intcrruptible contracts, existing energy efficiency, and new energy efficiency from the preferred porttblio. l(x) P^(rr,r(oRP-l0l9IRP Load and Resource Balance P^CIFICoRP 20I9IRP Cll^pll.tt 5 L0AD ^NI) Rt,sol R(r:Br\1.1\(i I Please ret'er to Volunre ll. Appendix N (Caprcity Contribution Study) il0 Existing Resources A description of each of the resource catcgorics follows: Thcrmal This category includes all thenral plants that are wholly orvncd or partially owned hy PacifiCorp. The capacity balance counts these plants at their expected availability (after derating lbr fbrccd outages and maintcnancc) during sumrner or rvinter hours u'ilh loss ol- load events in the final capacity thctor mcthodology analysis.i The energy balance also counts them at expected availability. but includes all hours in the year. This includes thc cxisting fleet of coal-fueled units, and six natural-gas- lueled plants. Thcsc thcrmal rcsourccs account for roughly two thirds ol'the Iirm capacity availablc in thc PacifiCorp system. []vdroelectric This category includes all hydroelcctric gcneration resources operated in the PaciliCorp systcm, as well as a number of contracts providing capacity and energy from various counlcrpartics. The capacity balancc counts these resources at their expected availability (aftcr dcrating tbr forced outages and maintenance) during summer or rvinter hours rvith loss of load events in the final capacity lactor methodology analysis. Thc cncrgy associated with stream flow is estimated and shaped by tlre hydroelcctric dispatch t'rom the Vista Decision Support System modcl. Also accountcd for arc cnergy impacts of hydro relicensing requirenrents, such as higher bypass flows that reduce generation. Over 90 percent ol'the hydroelectric capacity is on the west side of the PacifiCorp system. Renervable This category is cornprised of'geothermal and variable (rvind and solar) renervable energy capacity. The capacity balance counts the geothermal plant using the samc mcthodology applied to thermal resources. The capacity contribution o1'rvind and solar rcsources, represented as a percentage ol' resource capacity, is a mcasure ofthe ability lor these resources to reliably meet dcmand. During the 2019 IRP, PacifiCorp identified that capacity contribution valucs lbr wind and solar rvould vary based on the penelration lcvcls ofthcse resources, as rvell as the composition ol'the rcst ofa portfblio. To account tbr these eft'ects, PacifiCorp perfirrmed a reliability analysis on every portfolio that rvas developed to ensure that the combination ofrcsources achieved a targeted level ol'reliability. For thc purposc ofrcporting the capacity contribution ofrvind and solar rcsourccs in thc load and rcsource balance, PacifiC'orp first calculated the contribution of all other rcsources in the portfolio, using the methodologies dcscribed in this scction. The remaining capacity in the load and resource balance, up to PacifiCorp's thirtecn percent planning reserve rnargin, is attributable to wind and solar. This remaining capacity was allocated to each wind and solar resourcc based on the u,ind and solar penetration analysis and the final capacity fhctor methodology arralysis, as discussed in Volume II, Appendix N (Ciapacity Contribution Study). The resulting capacity contribution valucs tbr rvind and solar lor the purpose of the load and resource balancc arc sho\\,n in Figure 5.3 (summer) and Figure 5.4 (rvinter) belorv. P.\( rr,rc( )RP f0l9 IRP CltApfltR 5 - Lo,\t) A\l) Rr.rsotiRCti ll^t.ANCI Figurc 5..3 - Summcr Pcak Capacity Contribution Values lbr Wind and Solar tfi% 9tr/o 8U/o 7Wo 6U/o SU/o 4tr/i 3U/o 2U/o LU/o o% 2019 7077 2073 2025 2027 2029 2031 2033 203s 7037 - Summer Wind -Summer Solar Note: Marginal benefits are lower than shorvn; rclcr to Volume II, Appendix N (Capacity Contribution Study) Figure 5.4 - Winter Peak Capacity Contribution Values lbr Wind and Solar t6% 9U/o 8096 7UA 6U/o SUA 4tr/o 3U/o ZV/. lU/o o% 2019 ZO27 2023 2025 2027 2029 2031 2033 2035 -winter wind - winter solar 2037 Note: Marginal benelits arc lo$er than shorm: rcl'cr to Volume ll. Appcndix N (Capacity Contribution Study) ilt Purchase 'fhis includes all major purchase contracts for lirm capacity and energy in thc Pacit'iCorp system.l The capacity balance counts these by the maximum contract availability at time ofsystern summer peak. The energy balance counls contracts at optimal economic model dispatch. Purchascs are considered finn and thus planning resen'es are not held tbr thern. Qualif ying Facilities All QFs that provide capacity and cnergy are included in this category. Wind and solar QFs are handled in the same manncr as non-QF renewable resources, as described above. Other QFs are handled in the same manner as other power purchases, the capacity balance counts them at maximum systcm summer peak availability and the energy balance counts them at optimal economic model dispatch. l)emand ResDonsc (Class I DSM ) Existing dcmand response program capacity is categorized as an increase to res()urce capacity. This is in line with the treatment of DSM capacity in the latcst version of the System Optimizer model that PacifiCorp uscs to select resources. Salcs This includes all oontracts tbr thc sale of firm capacity and cncrgy. The capacity balance counts these contracts by thc maximum obligation at timc oisystem summer peak and the energy balance counts them by cxpected rnodel dispatch. All salcs contracts are lirm and lhus planning reserves arc held for thern in the capacity vicu. Non-owned Reserves Non-ou'ned reserve capacity is categorized as a decreasc to resource capacity to represent the capacity required to provide reserves fbr load and generation that are in PacifiCorp's balancing authority area (BAA) but not uscd to serue the company's rctail load. There are a number of wholesale ouslomers that operate in the PaciliCorp control areas that purchasc operating reserves. The annual rcserve obligation is about thrce MW in the rvest BAA and 38 MW in the east BAA. The non-orvned reserves do not contribute to the energy obligation because the requircmcnt is for capacity only, Obligation The obligation is thc total electricity demand that PacitiCorp must serve. consisting olforecasted retail load lcss private generation, existing cncrgy efficiency, new energy efficiency from the prefened poftfolio, and intcrruptiblc contracts. 'l-he following are descriptions ol'each of these comp0nents: Load Net of Private Generation The largest componcnt ofthe obligation is retail load. In the 20l9IRP, the hourly rctail load at a location is flrst reduced by hourly privatc gcneration at the sarne location. The systerl coincident peak is detennined by summing the net loads tirr all locations (topology bubbles rvith loads) and then linding thc highest hourly systern load by ycar. Loads repofted by east and wcst []AAs thus rcflcct loads at the time of PaciliCorp's coincidcnt system summer peak. The energy balancc I PaciliCorp has curtailment contracts for approximately 172 MW on peak capacity that arc trcarcd as lirm purchases, PacitiCorp has the right to cunail thc customer's load as needed lbr economic purposes. .[ he customer in tum may or may not pay markcl-based rates fbr energy used during a curtailment period. lr2 P^0HCORP-2019IRP (lltAp I tiR 5 - LOAD ,^.ND RFtsol JR( 1, BALANCL P,\crr,rcoRP 2019 IRP CIIAp tR 5 - LoAD ANI) Rt.:sotjRCE B.\LANCII Figure 5.5 - Energy Efficiency Peak Contribution in Summer Capacity Load and Resource Balance (reduction to load) (200) (4oo) l600) luro) (r,mo) (1,200) (r,4oo).% ,r+ .% 'r+ 'r+ "% t+ ++ % % % ++ .% .E ."+ .% 'r+ tr, % Interruptible Contracts PacifiCorp has intcrruptiblc contracts lbr approximately 177 MW of load interruption capability beginning in 2019. These contracts allow the use of 177 MW of capacity firr meeting reserve requirements. Both thc capacity balance and energy balance counl these resollrces at the level of full load interruption on the executed hours. Interruptible resources dircctly curtail load and thus full planning reservcs are no1 held I'rrr the load thal may be curtailed. As rvith demand rcsponse, this resource is categorized as a dccrcase to the peak load. Planning Reserves Planning reserves represent an incrcmcntal planning requiremenl, applied as an increase to the obligation to ensure that there will be sufficicnt capacity available on the system to manage uncertain cvents (i.c., weather, outages) and known requirements (i.e., operating reserves). 0 ,rtlll lll counts the load on rnonthly basis by on-peak un6 611'-peak hours. Thc net load is simply referred to as load in the context ofload and resources balances and ponfolio selection and evaluation. Encrey Efficiency (Class 2 DSM) An adjustment is made to load to remove the projccted embedded energy efliciency as a reduction to load. Due to timing issues with the vintage ofthe load forecast, there is a levcl of20l8 Energy Efficiency that is not incorporated in the lbrecast. The 2018 cnergy efficiency forecast (8 I MW) has been accounted for by adding an existing energy efficiency resource in the load and resourcc balance. The energy el'liciency line also includes thc selected energy efficiency liom the 2019 tRP preferred portfblio. Figure 5.5 shows the energy efliciency lbr the east and wcst control areas in the 201 9 IRP preferred portfolio, P^crFrCoRP 20l9lRP Position The position is the rcsource surplus or delicit atier subtracting obligation plus rcquired reserves from total resourccs. While similar, the position calculation is slightly diflerent for the capacily and cncrgy viervs ofthe load and resource balance. Thus, the position calculation firr each ofthe views will be presented in their respective sections. Existing Resources: Therrnal + Hydro + Renewable + Fim Purohascs + Qualifying Facilities + [xisting Demand Response Firm Sales - Non-owned Rcscrves Thc peak load, intenuptible contracts, existing Energy Efficiency, and new Energy Eflicicncy from the preferred portfbtio are netted together lbr each ofthe annual system summcr and winter peaks, as applicablc, to compute the annual peak obligation: Obligation: [.oad Interruptiblc Contracts - Neu,and Existing Energy Efficiency Planning Reserves: Obligation x PRM Finally, the annual capacity position is dcrived by adding the compuled reserves to the obligalion, and then subtracting this amount fiom existing resources, including available FOTs, as shown in the I'ollowing fbrmula: Capacity Position: (Existing Resources + Available FOTs) - (Obligation + Rcserves) Capacity Balance Results Table 5.12 and Table 5.13 show the annual capacity balances and component line items fbr the summer peak and wintcr peak, respectively, using a targct PRM of l3 percent to calculate the planning resen'e amount. Balances lbr PacifiCorp's system as well as thc cast and rvest control areas are shorvn. While east and u,est control area balances arc broken out separately, thc PacifiCorp system is planned for and dispatched on a system basis. Also note that nerv QF wind and solar projects listed earlier in thc chaptcr arc rcpofted under the QF line item rather than the renewables line item. CIIAPI.I.]R 5 LOAD AND RLSoURCE B,\I,AN(.I: Capacity Balance Determination Methodology 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 resources is determined for each ofthese annual system summer and winter peak periods, as applicable, and summed as follows: The amount of rescrves to be added to the obligation is then calculated. This is accomplished by the net system obligation calculated above multiplied by the l3 percent target PRM adopted tbr the 201 9 IRP. The tbrmula for this calculation is: ll4 P^cr,rCoRP ?019 IRP CHAPTER 5 LoAD A\t) Rt.solrR( 1, BAt.ANcE Table 5.12 -- Summcr Peak - System Capacity Loads and Resources without Resource Additionsr/ ,020 !0?l 2022 1023 202{ 2025 2026 7021 2018 2019 5.961 242 891 l2rl 7Jr0 J.614 843 :15 323 (t7it 7545 5.61,t 11 Et9 2r5 323 7560 5.611 14 E66 215 665 t2:l 1,567 5.61r 7i :I5 617 lzl J,6l.t 906 lt5 323 l l.l8l 7,44t t.:t, .7l E98 ll5 621 t2l ,,1:lt i.l.l0 71 ll, 620 :ttl 7,124 :l..lEl 11 817 lt5 .t2l 6,r95 ,1.481 ?,t ?IE I 15 3tl 6,767lirt trisrioa R.so! r.er 7.039 (125) It11) Irlr) 6,592 7.t08 6.S?2 7,18t rl?l) r:l I ) 6,593 7.,105 6,68I 7..till rl88) ll77) 6.68' 7.5',).1 tl0l) 6,6{4 PlerninS ltc*r e\ ( I ldt)l{el $17 Ersl Oblit.lio! + llca(ntv Fr3l PoBitiotr Av.il.bl. ftonl Om.. Ttonrtdiotrr ;.47 t 0 ?.{s0 9S l0q 7.5t.t 5.1 tt7)(8s) 309 7,52E ,,511 t09 7.568 (1,.1001 Clas I D$,t 2,0tE 570 l8l I 390 3 ( t65t (lr 3J21 t.0.lE J?O :!79 I 292 (16n t-l I .,,126 2,0.tE 570 I 285 0 r:l r 3,07E 2.0.t8 570 :E9 I 278 0 lll I 3,07,1 |,136 570 289 I 2?8 0 rlr 2,102 1,736 570 198 I 219 (801 tl) 23O2 t.716 570 102 I 278 0 r.l I ,ro5 l,?36 570 100 I 246 0 (80) (l) 2,77t I.J9E 570 271 I 243 0 2,604 1.26! 570 :,r0 I 2Jl 0 tTli) 1l) W.rr Erisritrs R.tour... :).1E7 rllr 0 r8l) .1,2E5 3..1.1I {ll') 0 !,310 3.{86 rl9) 0 rlll) !,325 (.rl) 0 1,32d t,529 0 rlEl) .1,101 3_570 0 t?0t) 3,32.t t.597 t.ll) 0(ll:) l,!tr :1.616 0 l,l2l 1.657 0 1,321 1.68.1 0 J-!21 Planning Re*rrci i Iiqbr 110 ltl Iil r]l lll 1ll rtl W.sl Otlig.liutr + llcrcnts W.rl Poriliotr vrilrble Fronl O fli.. Tr.nr!.liori 1.7t2 r,ls9 -1.r57 t.159 1.756 -r.710 1,t50 I,l5't,!59 1,753 {98t1 1.159 (t.tltl ,.t59 I l.a27l I,t s0 Tohl R.root.es Ohlitfiion R.3.n.r Oblig.tiotr + R.i.n.r Stsr.m Poritiotr r0..137 9.E76 1.t07 I l lEi t0.6:18 9,918 l.lll I l.l3 t r0.6.11 |,.1l7 I t,170 r0,1.17 l.lt I I l..r0l t0.290 t0,005 1,314 I1,128 ( I.0i8 ) t.J l9 I l.l8.l l.t: l I l.l0r5 8,491 t.ltl I l.llr rl.8: i r A{il.bl. front Otfi.. Tltni..rioni 1,466 1,468 t,{68 1,46t I,d68 Utr.oDdiri.d l1OT! ro re€t ftm{i.in8 Need 146 519 592 6.10 956 N.lsurpl!! (D.n.iD 0 0 0 0 (l lr I h. lncr8' Ii|licienct line inclu&s sleorcd llner$ Efficie..r_ from rhc l0l9IRP prelerdd no hlir). 1,468 1,018 I,.168 t.rIr 1,.t68 l.185 0 l..l6li l..lri8 il5 t.lt8 I l.l8 t r l.1l,i ) 0.881 1. t08 It.l90 P^CIFIC0RP 2OI9IRP CIIAPTER 5 L()Ar) AND IltrsouRCE BALAN( 11 Table 5.12 (cont.) - Summer Peak System Capacity Loads and Resources without Resource Additionsr/ 2010 2(l-r,2031 2033 203.1 20.tS 20.!6 20.!7 20!E Qualifyins Facihics Clsss I DS\,{ Sllct 4,t42 14 723 ll5 595 l2l 0 6,036 4. t69 106 U5 321 0 5,952 ,r.169 lt5 5lt7 .]]l 0 5.90E 1.818 71 725 lt5 555 123 0 (15 ) 5,S96 3.818 14 726 ll5 516 .t2l 0 s,571 l.El8 71 ?:l lt5 5t6 t2l 0 5.575 ].E3E 71 177 lt5 503 t23 0 (15 ) 5,556 2,9lt{ llt llt .l t.l 0 4,126 2,98{ 691 r 15 120 321 0 1,279ftst Fristing Rc\ourcct 6.700 7.E30 il6t) 6.711 r.9tJ ,l$1, 6.751 8.0t,8,104 rSlilr 6,8r I 8.:E0 tl?l) 6,416 Ene.E/ Elllcicn(t PltrnringReservc\ ( l:l'h) &rl Oblig.liotr + R.3.ncs E$l Posilio. Ar:ilrblc lrooI Omce Trrnu.lio!s ?,59:t { t.5i?} !09 7.609 t09 7,652 it.'rlrl 309 7.665 10, 7.655 r!.0.8) -!09 7.6E1 (2.t09) 309 1,720 (!. r 61) 309 1,161 .!09 7,r91 tl.5ll I 109 QElify irg F.cilil i.s 1,26t 5?0 l.l9 I 22E 0 rl) t.rrJ 1.265 5?0 259 I 229 0 {l) 2,244 1.265 570 2:lE I 211 0 l78r rlt 2,226 t,265 I t:3 2,2115 1.265 570 266 I 22J 0 2,2,r5 t,265 J70 265 I 721 0 tl I 2,244 1,265 570 110 I 211 0 rl.l ) 2,291 1.053 570 275 I 201 0 ll.l) 2,073 4ll 5?0 210 I l0r 0 r:lr I _1I t,a27Wcrt ff,istirg Rcrouftes 1.709 0 t_I4 l,?.li ( 101) rttt) fJl0 1.77:l 0 LlE9 :i,801 t.265 ].7EE o .1,25,1 l.E t4 ( l9l) 1t l.tll 3.8,t1 (ll6r 0 !,210 LlrS t .!,201 l_9 tl 0 (118) I,tE,t l'hnnrc tu*^r\.! ( li",)ltl lio .rt1 [.].1lr)Il7 lt7 .11.1 Wcrr ObliBatiotr + ll.i.nrs 3.7ts Writ Porllloo rl.tl:r Ar:ihbl. ]ionl Om.. 'li.tr3..iion3 I,l!9 -1,7,10 (1,{97) I,159 .!.?t7 t,689 t.t59 Lls9 I,t59 1.t 59 1.62? !,t59 1,621 (t.s.lll) 1,159 rl.lllr t.159 Toral Rciotrr.cr ()tligrrion Rc{crrc( O blig,tion + R.crrks S!rt.m l'niriotr 8.t70 t0.0t.1 t.ll5 I l.l.l9 10.024 1.126 I t.350 rj-l5l) E.134 10.040 t.ltE I t.l6E ( i.:lr, 7,81I 10,018 l..l:7 r r.155 t0,008 I.l?,t ll.]12 7.ll l9 10.01 I t.32r l1.135 ?.E51 10,0t l r_l?6 I I -.i.t7 t.:t l0 I l.]87 5.706 I0.060 l.ll I I l.t9l -Av!il.bl. fronl Officc lt.n$!(lions l,{68 1,468 1,,168 1,t68 tln.ohmilr.dl(,Titom.crr€m.iflilai\_eed 1.,168 1..168 1..168 I.46ll rirt Surplus (lr.licil) ,L.rlr-'r il6ihr ll.166) r:.r)lh, I thelnerE lllli.i.nq linr includ.s *lc(rcd tn.rg, Effi.ien.\ l-rom lhe l0l9lRl, frrttredpurltolio. l,,t6E 1l rJl I t,.l6E l,il68 l,46ll (:.{)l7 r l.{6r,t,t6E 1.468 rl.l l7) il6 l PACI.TCoRP-20l9lRP CIIAPII.R 5 LoADAND RI]SOI-IRCL BALA\CI- Table 5.13 - Winter Peak System Capacity Loads and Rcsources without Resource Additionsr/ 2120 ,0ll :0::l0t.l 201.1 :0!5 7076 I 27 :01[ 6.020 54 1!; 8,258 5.691 1,762 5.6r2 J.l 1,59t 128 .t65 0 7,8!5 t.692 tl8 7,75a ?,0.12 5,697 54 1.0:0 ll5 lll 0 7.011 I t5 llr 6,687 54 1,009 I t5 1lr 5l 1.0 t0 I t5 ! 1:t 0 (li ) 6,027 4.545 5,1 I l5 116 5.931hrr F-r i\rinq R€$urces 5.7.t1 rl) 5.176 5,807 5,196 5,889 5.29E 4.105 5,119 PlanninE R*^cJ (ll9t);tl rt1 r:8 [rrl ()hlitrri0n t Re3.n-c$ last Position NEilsblc rronl O fti.c Trlrso.tio.r 6.062 !.61t 6,t2-l 6.lltt .t 6.011 I l0l) 109 2.040 672 I I.ll 0 3,369 t.040 l5l I l0: 3,008 2,040 tll I (l) 2921 2.040 670 I 3A 0 1.9t:l 1,728 610 ll7 I 15 0 rilr 2,a21 l.?18 ll7 I 15 2,517 r.?2E llE I 77 (l) l.7tE 610 ll8 1,590 t]7 I {t r$l) 2-!60 1.258 670 116 I 33 0 178) 2,01E\ (\r li i\ ritr A llr\ou rc.!2,1109 3,416 0 JJ27 1,.158 :1.,199 1_519 r"r (0) ri)) 00 r0) Itntl l-lto -1,J50 l.l{7 rllrr .1.3r5 1,576 0 tl{r) l-lJ l 1.605 1l) 0 f,429 ll) -i.al5 t,?06 (l) ,317w.rl ohlig.rior P hning R.rn'es ( I l'/.) W.vl ObliB.llo. + Re..n 3 r]5 \\$l loririun .rr!il!ble lrrnn r () IIir. 'Lrnrrctionr t.t59 t.771 t.785 -i.?i2 1766t (,16.1) (L691 I,t59 I,t50 1,159 rr,It2) 1.t 59 t,t59 Tot.l R.r.ur.cr Ohlie.li.n R.t.nrs (rbliq.iion i R.3enca Stn.o Poiiraotr l t.6:? 8,61 t.t50 9.82t et_1 8.125 1.157 9.881 86.t l0_671 8_741 1.160 9.901 E.6l 9.114 r.145 8.182 8,645 l.l] 7 9.79: 7,949 8,666 I,t50 9.81i lt-86?) Arall.bl. tiotrr Ofna t.rs,ctiotrs l..t6E l..t6t 1,.168 1,,168 Un.ornill.d lrO'I3 to Er.r Eoriring Ne.d 0 0 0 0 Nrr surplur (Delicit) 1.a06 el: 86,1 169 l/ The EDer-lr tillicisn(). lnrc inllutrs elccrcd Encrgv Llli.icne! liun lhu:019 IRP preaetr€d porinni. t.{61 655 t.168 1,168 l1 rl: 7tl |,721 !.7 4,762(t.21?) {t,z_r7)1.159 l,t a9 PA(llr(loRP-2019IRP C[Ap lt:R 5 LoAr) ANr) Rt,souRCE B,\I.AN( t-. Table 5.13 (cont.) - Winter Peak System Capacity Loads and Resources without Resource Additionsr/ ( Jlrnlr \.r: 20-10 10-11 !011 lo:rl !0-r.l !0:15 1016 Ioa, 20la 4.119 54 891 ll5 :l:6 5,5'0 -1.119 54 846 llt ll0 0 0 5,519 t,015 lr5 :E4 0 s3,ll ll5 Itl 0 sJ30 15r 5..,!3 1,908 5.4 1,0.15ni 227 5,309 1.054 ll5 26 .Jrt 1,073 lt5 t6 0 0 a,la,tlrl t.\i\.ine Rc\our..s E|ir ohli$riotr PlanninS R.srves ( l]%) rrrtOhllg.tion + R.reFrr 710 ?t.l Frir Fo!itiotr ,, r.il.nl€ lm,t Olfi.. T...src.ior! 6,02t 109 !09 6,llJ 6,163 6,2t2 6.r.t9 t.:ili L t.0tl t.158 610 128 I 21 2t00! 1.258 ls5 I :e 0 2,011 L t.158 610 t59 I o 2,0.t6 l.lt8 160 I l5 2.01{ I,014 I 74 0 I,EIE I :J \t r\r ti i\r itr r Rr\our.c! 1.75t 1.781 -r.tr6 .!.155 3.E l6 3,369 l;3.r 1.901 0 J,,100 1,913 !,1t5 f,,131 Pl.nning l!$..: rllq"r lJl I I.r wcrl Oblisrlion + Rsrerks W(!i Po\irion .\.il!bl. Fro!l Ofli.t'lrntr1.clion! f,rar J,?91 1.159 r,159 .1,608 1,t59 !.82r t.ls9 !.85' {!.0.1t I r.r59 1,877 I,159 lnrrl R€ionr..r ()hliA.iion R(!errrs Oblirrlion + R.!.rlEJ Sl!l(m I'urilio. 7.607 8.670 t.150 0,820 ( t.l11) 7.511 8,681 l,l5: 7,3?l 8.7J2 1.t 58 (:.517) 3_771 l t6l 9,916 rl.57l) lt,8 t6 7.t{l 3.81J l.t7t 10,00t 6.llt It.39l 1.179 t0.07t I,185 10.126 At.ihbl. fmrtolficc I nyrclioni l.{6a l.r5a l,r6a l.{68 1,.168 ljn..odirl.d mrr to D..t rcrri.i!! I..'l l.{611 1.468 l-163 1.t68 1.t68 lr Th. rners/ affici.ncv line incldcs *lccrcd Enere Elliuicn.] liom thc 201., IRP pr.tiied lonlolio. r,l6i t..168 1.t68 ll8 I,.t6t rl..l7ll P^crr,r( oRP - 2019 IRP CHApr r,R 5 LOAD AND RES0URCE BAr-.{NCr Figure 5.6 through Figure 5.9 are graphic represcntations ol-the above tables for annual capacity position for the summer system, winter system, east control area, and west control area. 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 I[, Appendix J (Westem Resource Adequacy Evaluation). Fi ure 5.6 - Summer S stem C ac Position Trend r1,000 12,000 10,m0 &000 5,m0 4m0 40m 0 7020 2071 2C22 mB 20U 2025 2026 2027 m2a 2029 2030 2031 2032 203 2034 2035 2036 2037 2038 E- Wril f,rl$tlDg Resoorc?s I f,ort Erlsthg Rrsoul.cr$ f'rcoEeltlcd trOT's lo mtct rclnrlohg l\.cd +Obllg.tloo + 139/0 Phooltrg Rcs€n tl --.r- Obllg.lio[ ll9 f,.3t ExlstiEg Resources lvest Exlstlng Resources P^CIFICoRP 2OI9 IRP CHAPTER 5 - LoAl) AND REsouRC[. UALANCE Figure 5.7 - Winter System ('apacity Position Trend It.0lt0 It,000 llt.000 ,l.lt(xt {,000 2.000 West Existitrg Resources lt 2019 2020 20zl 2022 202t 20?.1 2[25 2026 2i21 202't 2029 20-10 203t 20]2 :o.t.t 203,t 20t5 2016 2037 20.',t8 Wesl Eristing Rcsourccs -l;osr [xisling Resourc€s Uncommittcd 1O'l''( lo mel rem!iniDs Necd -DOhlisrtion + l3ol, Plrnning Rc$ncs --+Ohligntion 120 last llxisting l{csourcer P^crr,rCoRP-l0l9lRP CI IAPTIR 5 _ LOAD A)JI) Rl.,sot ]R(.F, BAI,AN(.Ij re 5.8 - East Summer C Position Trcnd r0,mo 9,000 q000 7,0m 4000 3,000 4ofl) 3,000 10d) t,000 0 2020 2021 2022 mLt 2024 tO25 2026 2027 -E.st Erlsttrg R€sourms -a-Obllgrtlor + 13% Plrtrtriug RtBrla€t 2024 2029 10$ 2031 2032 2033 203{ 2035 1036 !0J? 20J6 f,rst - t'oconmltt.d fOT's lo mect lrErltrhSNced -*-Erst obllgrllor t2t Esst EristiDg Resources PACIFICoRP 20I9IRP CthprER 5 LoAD A\t) RtisouRCF- BALANCI 5.9 - West Summer (la Position Trendil 10,000 9,m0 E.000 7.000 6,000 .t.000 Jp00 2p00 1,000 0 zo20 2021 2022 2023 202! 2n2a 2t26 7021 -W.3t Erhthg R6onrcs {-ObllgidoD + l3olo Plrr ry Rrso\"r 202E 2029 2030 2031 2032 20J3 2()3.r '031 20J6 20J7 20JE lvrsl trcommln.d FOT'! to n.d r.mrtnhg l...d --rF lvest obllgetloD Energy Balance Determination Methodologr The energy balance shows the monthly on-peak and of[-peak surplus (deficit) ofenergy. The on- peak hours are weekdays and Saturdays fiom hour-ending 7:00 am to l0:00 pm; of1'-peak hours are all other hours. This is calculated using the formulas that follow. Please refcr to the section on load and resource balance components lirr details on how energy tbr each component is counted. Existing Resources: Thermal + tlydro + Existing Class I DSM * Rcncwable + Firm Purchases + QF + lnterruptible Contracts Sales The average obligation is computed using the following formula: Obligation = I-oad - Finr Salcs The energy position by month and tirne block is then computed as fbllows: 122 Energv Position: Existing Rcsourccs Obligation Operating Reserve Rctluircmcnts -ts=F-rt West ExlstlDg Resourca! PA( rI,rCoRP - 2019 IRP (.IIAPII-R 5 LOAI) AND RLSoLIRCI- BAI-A\(]} Energy Balance Results The capacity position shows how existing resources and loads, accounting for coal unit retirements and incremental energy efficiency savings f'rom the prefbrred portlblio, balance during thc coincident peak summer and winter. Outside of these peak periods, PaciliCorp economically dispatches its resources to meet changing load conditions taking into consideration prevailing market conditions. In those periods when variable costs ol'the system resourccs are less than the prevailing market price for power, PaciliCorp can dispatch resources that in aggregate cxceed then-current load obligations facilitating otf system sales that reducc customer costs. Conversely, at times when system resource costs fall below prevailing market prices, system balancing market purchascs can be used to meet then-current system load obligations to reduce customer costs. The economic dispatch of system resourccs is critical to how PacifiCorp manages net po\,'er costs. Figure 5.10 provides a snapshot ofhow existing system resources could be used to meet firrecasted load across on-peak and o1'-peak peri<lds given the assumptions about resource availability and v''holesale porver and natural gas priccs. At times, resources are economically dispatched above load levels facilitating net system balancing sales. At other times, economio conditions result in nct system balancing purchases, which occur more olten during on-peak pcriods. Figure 5.10 also shows how much energy is available fiom existing resources at any given point in time. Those periods where all available resourcc energy I'alls below forecasted loads are highlighted in rcd, and indicate short energy positions without the addition of incremental resourccs to the portfolio. F ure 5.10 - S stem Avera e Monthl line Positions rg .q ^S ^S ^\ ^\ ra a"L ^1 aa a[ aL a5 "5 "b ^b ^1 ^1 .t ^$\c$" \.)Y'\d$'" \.1'" 1*"' 1or'"t6r'--tgt'\dr " \$\"\dI " \$v" ''dr" 1sY" '6cr" 9Y" 1.$"' 1+\" t4r"' 1s\'" - Etre{gy at or Below Load r Net BalaDcilg Sale -Net Balalrcillg hEchase r Energy Short&ll Energy Availablc -Load 0 5.000 .1.000 3.000 2.000 1.000 {q .s ^s "$ r\ r\ r"L n^. r5 r1 rL atr .1 .5 .b ^b ^1 ^1 ^$ ^$1+."' 1sY',41'" 1+\" \+s." \$\'" \dr"" 1.\\" fo+ " 1+l'" tos '*r''\of " \$Y'\6s. " \$Y'16l'" 1o\'"1O " 1tl'"r E[er'gy at or Balow Load rNer Bala0cing Sale INet Balancint Puchaser Etrer?y shonftll Energy Available -Load o 1.000 J.000 4.000 F 3.000uo zmo 123 On-Peak Energp' Balance Off-Peak Energl' Balance I)^( I r(l{mP l0l9IRP (.IIAP I I.,R 5 . LoAI) AND RESoI IR(.I., BAI,ANCIi t24 PACII.ICOIiP ]019 IRP CI IAP'TIR 6 _ REsoI,R(.I] OP,TIoNS Cuaprr,R 6 - RpsouRCE OprroNs CHaptRn Hrcur-rcurs o PaciliCorp developed resource aftributes and costs fbr expansion rcsources that reflect updatcd infbrmation fiom project experience, industry vendors, public meeting comments and studies.. Resource costs have been generally stable since the previous integrated resource plan (lRP) and cost increases have been modest to declining. The cost ofsolar photovoltaic modules and balance ofplant equipment decreased in 2018, continuing the downrvard cost trend of the past several years. Likewise, costs of wind turbines and batteries, and associated balance of plant costs, have shown a decline. o Geothermal power purchase agrcements (PPAs) are included as supply-side options in this IRP and updated to reflect current conditions. o Thc combustion turbine types, configurations, and siting locations are identified in the supply-side resourcc options table. Performance and costs have been updated.. Energy storage systems continue to be of interest to PacifiCorp, its stakeholders, and the industry at large. Options for advanced large batteries (15 megawatts (MW) and largcr), renewable (rvind and solar) plus storage, pumped hydro and comprcssed air energy storage arc included in this IRP. o For this IRP, PaciliCorp developed the capability fbr the System Optimizcr (SO) model to endogenously model transmission upgrades. o A 201 8 Long Term Ceneration Rcsource Assessment study that was conducted by Navigant Cionsulting, Inc. served as the basis lor updated resource characterizalions covering private generation. The dcmand-side resource information was converted into supply curves grouped into cost bundles by measurc or product type and competed against other resourcc altcmatives in IRP modeling. o PaciliCor? continued to apply cost reduction credits to energy efficicncy, reflecting risk mitigation bencfits, transmission and distribution invcstment deferral benefits, and a tcn percent market price credit for Washington and Oregon as aIlowed by the Northwest Power Act. This chapter provides background information on thc various resources considered in the IRP lor meeting future capacity and energy needs. Organized by major category, these resources consist of utility-scale supply-side generation, dcmand-side management (DSM) programs, transmission resources and market purchases. For each resource category, the chapter discusses the critcria for resource selection, presents the options and associated attributes, and describes the various technologies. In addition, Ibr supply-side resources, the chapter describes how PaciliCorp addressed long-term cost trends and uncertainty in deriving cost figures. The list of supply-side resource options rcllect the realities evidcnccd through pennitting, internally generated studies and extemally commissioncd studies undertaken to better undcrstand details of available gencration resourccs. Capital costs lbr some resource options have declined while others have remained stable compared to the 2017 IRP. Neu,wind resources rvere given 125 Introduction Supply-side Resources I'^( ll,rCoRP - ]0l() IRP ( ,1P r r,r{ 6 Rr,sot t{( t, Op oN\ particular attention after the 2017 IRP selected a combination ofrvind and transmission resources fbr investmenl that rvould provide value fbr PacitiCorp's customers. Encrgy storage options olat least one MW continuc to be of interest to PaciliCorp, its stakeholders, and the industry at large. PacifiCorp analyzed options lor large pumped hydro projer:ts and utility scale batteries. In rcsponse to stakeholdcr requests and utility industry trends, PaciliCorp studied multiple diflcrcnt battery cncrgy storage configurations and combined battery configurations collocated with u'ind and solar projects. Solar resourcc options examined 200 MW single axis tracking facilities to reflecl the industry trend oi larger utility-size photovoltaic (PV) systerns. A variety ofgas-fueled generating resources wcrc identified after consultation with major suppliers, large engineering-consulting lirm and stakeholders. The combustion turbine types and configurations idcntified for consideration in the 2019 IRP are the same as lhosc used in the 20l7lRP. Combustion turbine types and conligurations remained the same bccause the market continucd to improve the ability of'existing tcchnology to provide lirming for variable energy resources.'l'he capital and operating costs ofsimple and combined-cyclc gas turbine plants have rcmained relatively lorv in rccent years, with a flat to slightly dccrcasing cost trend. New coal-fueled and nuclear resources received minimal focus during this cycle due to ongoing environmental, economic, pennitting and sociopolitical obstacles. Derivation of Resource Attributes The supply-sidc rcsource options were developcd from a cornbination of resources. The process bcgan with the list of major generating resources lrom thc 2017 IRP. This resourcc list was rcvierved and rnodified kr reflcct stakeholder input, nerv tcchnology developments. environmental factors, cost dynamics and anticipated permitting rcquirements. Once ths basic list of resourccs was determined, the cost-and-perlbrmance attributes f<rr each rcsource i.vere estimatcd. The information sources used are listed belorv, lollowcd by a brief description on how they u,ere used in the development ofthe supply-side resource table (SSR), rvhich is uscd to develop inputs fbr IRP modeling: . Recsnt (20 I 8) third-party, cosGand-pcrfbrmance estimates;. Publicly available cost and pcrfbrmance estimates;o Actual PacifiCorp or electric utility industry installations, providing current constructionhaintenance costs and perlbrmance data rvith similar rcsource attributes;o Projcctcd PacifiCorp or electric utility industry installations, providing projected constructiorl/rnaintenance costs and performance data of similar or identical rcsource options; and. Recent requests lbr proposals (RFP) and requests tbr intbrmation (RFI). Rccent third-party engineering infbrmation from original equipment manufacturers wcrc used to develop capital, operating and maintenance costs, perfbrmance and operating characteristics and planned outagc cycle estirnates. Engineering-consultants or govemment agencies have access to this data based on prior research studics. academia, actual installations, and direct irrfbrmation exchanges rvith original equipment manufacturers. Examples olthis type ofelTort include the 2018 Black & Vcatch estimates prepared lirr simple cycle and combined cyclc options. F'or this IRP cycle, the energy storage ef-fbrt u'as pcrtbrmed by llums & Mcf)onnell and covers solar and wind resources. The Bums & McDonncll study builds upon prior cnergy storage studies, updates cost and technical infbrmation, and adds cornbined renewables plus energy storage resource options. t26 Crr^p r r.R 6 Rr.rsor rR( r, Op r ro\s PaciliCorp or industry installations providc a solid basis for capital/maintenance costs and opcrating lristories. Perlirnrance characteristics rvere adjusted to site-specific conditions idcntilied in the SSR. For instancc, the capacity ol'combustion turbinc based resources varies rvith clcvation and ambient tcmperature and, to a lcsscr exlent, relative humidity. Adjustments u'ere made tbr site-specitic clevations of actual plants to more generic. regional elcvations lirr f'uture resources. Examples of actual PacifiCorp installations used to develop the cost-and-pcrformance inhrrmation provided in the SSR include operation and maintenancc (O&M) costs firr PacifiCorp's Oadsby GE LM6000PC peaking units and thc Lakc Side 2 combined cyclc plant. Recent RFIs and RFPs also provide a useful source of cosl-and-performance data. ln thcse cases, original equipment manuf'acturers provided technology spccific inlbrmation. Examples of RFIs informing the SSR includc obtaining updated equipment pricing for rvind turbine equipment fiom original equipment suppliers and reviervs ol capital costs prepared by cngineering finns by engineer-procure-construct fi rms. Handling of Technology lmprovement Trends and Cost Uncertainties The capital cost uncertainty for some gcncration technologies is relativcly high. Various factors contrib e to this uncertainty, including the relativcly small number of facilities that havc been built, cspecially Ibr nerv and emerging technologies, as well as prolonged economic uncertainty. I)espite this uncertainty, the cost profilc bet\4'een the 2017 IRP and thc 2019 IRP has not changed significantly. For example, Figure 6.1 shows thc trend in North American carbon steel sheet prices ovcr the period from October 201 5 through June 201 8. The 201 7 IRP included the historic carbon steel pricing shown in Figurc 6.2. These ligures illustrate ncar-term changes in capital costs of generation resources. 127 P.\(rfrCoRP-2019IRP PA( rF rCoRP - 20l9lRP CHAPI.IR 6 _ RISoURCE OPIIoNS Figure 6.1 - World Carbon Steel Pricing by Type World Carbon Steel Pricint Averate Transaction Price (www.worldsteelprices.com) .+.Hot Rolled Coil +Structural S.ctions & 8.ams +Rebar So.40 50.35 so.3o S0.25 10.20 50.r5 so.ro ,*9cf *t' .."'" "".* J -.d *J *"' ..J ed oJ *C *J *d *t'" e."t"" -- 128 +a t,^crr,rCoRP 20l9lRP CtIAPTIR 6 - RtrsotiR( F. OP no\s Figure 6.2 - Historic Carbon Steel Pricing World Hot Rolled Coil Steel Prices {steelonthenet.com/steel'pri(es.html} l( s0 rs t015 ;\ 1r.01 lr.0! Jan 0l lan 0n lrn.05 Jr. r)6 ,an 07 ,dn €an-11 ran.12 ran.ll lan 1! lan 15 -lan 16 r.n.l7 ran 13 Priccs lbr solar PV modules and balance ofplant costs have come down since the 2017 IRP. Real prices are projected to continue to dccline based upon technological and manulaoturing improvements, but tariffs on Chinese.imports and high demand for PV modules ahead ofthe phasc out oflhe f'ederal investment tax credits (lTC) for solar projects crcates some degree ofuncertainty in the solar market. The 2019 IRP anticipates the cost of new solar projects to decline approximately five percent per year during next three years and then to decline at a ratc of approximately one percent per year beginning in year four. Some generation technologies, such as integratcd gasilication combined cycle (IGCC), havc shou,n significant cost uncertainty because only a few units have been built and operated. Recent experience rvith the significant cost overruns on IG('C projects such as Southem Company's Kemper Ciounty IGCC plant illustrate the difficulty in accurately estimating capilal costs ofthese resourcc options. As these technologies mature and more plants are constructed, the costs ol'such new technologies may decrease relative to more mature options suoh as pulverized coal and natural gas-fueled plants. The SSR does not include the potential for such capital cost reductions since the benefits are not expected to be realized until the nexl generation ofnew plants are built and operated. For example, construction and operating "experience curvc" benefits fbr IGCC plants are not expcctcd to bc available until after their commercial operation dates. As such, fulure IRPs will be better able to incorporate the potential benefits ol' I'uture cost reductions. Civen the current emphasis on construction and operating experience associated with renewable generation, PacifiCorp 129 s PAcrr.rcoRt,- 2019 IRP Cll^P r r,R 6 - l(fsoLrRCr, OPr roNS anticipates the cost benelits tbr thcse technologies til be available sooncr. The estimated capital costs are displayed in the SSR along with expected availability ofeach technology lor sommercial utilization. Figure 6.3 shows nominal year-by-year capital cost escalation rates lbr wind, solar, battery, wind+battery, solar+battery, and all other resources. Figure 6.3 - Nominal Year-by-Year Escalation for Resource Capital Costs 4.Oo,4 2.Oo/" O.O'/o -2.O% -4.O% -6.O./. -a.o% -70.o% -L2.O% -74.0% -16.O./. .,-J +Wind *Solar -t- Battery -a- Wind+Battery -a- Solar+Battery +AllOther Solar annual capital cost escalation rates are based on unweighted median scenarios from General Electric Renewable Energy, thc U.S. Energy Administration, and Bums and McDonnell-note, rates tbr 2019 and 2020 are adjusted to calibrate levelized costs to be consistent with pricing received in the 20175 RFP. Wind annual capital cost escalation rates are based on unweighted median scenarios fiom Energy+Environmental Economics, Gencral Electric Renewable Energy, Bcrkley Labs, ArcTechnica, the Olhce of Energy Efficiency & Renewable Energy Administration, and Burns and McDonncll-note, rates for 2019 an<l2020 are adjusted to calibrate levelized costs consistcnt with pricing received in the 201 7R RFP. Annual capital cost escalation rates tbr batteries are based on data from Bums and McDonncll. All other resources are assumed to escalate at 2.28 percent per year. Resource Options and Attributes Table 6.1 lists the cosland-performance attributes fbr supply-side resource options designated by generic, elevation-specific regions where resources could potentially be located: r Intemational organization for standardization (lSO) conditions (sea level and 59 degrees F); this is used as a reference lor certain modeling purposes.o I,500 feet elevation: eastern Oregon/Washington.o 3,000 feet elevation: southern/central Oregon.o 4,500 feet elevation: northem Utah, specifically Salt Lake/Utah/Tooele/Box Elder counties. ,-1 o I'ara-ar[-a-fr r30 '"*f "..pt"$"O"dP"$rdrd,"rd"d,"rd"etrdr"dP"dP"e""d"e""d"et Pi\crf rCoRP- 20l9lRP C Il,\t'tt:R 6 Rr,sol.rR( r.Opno\s . 5,050 feet elevation: central Utah, southcm Idaho, central Wyoming. e 6,500 feet elevation: southwestern Wyoming. Tablc 6.2 and Table 6.3 present the totai resource cost attributes fbr supply-side resource options, and are based on cstimatcs of the first-year, real-levelized costs for rcsources, stated in June 20 I 8 dollars. Similar to the approach taken in prcvious IRPs, it is not currently cnvisioned that new combined cycle resources could be economically permitted in northern Utah, spccitically Salt Lake/Utah/Davis/Box Elder counties due to state implementation plans for these countics regarding particulatc mancr of 2.5 microns and less (PM:.s). A Glossary of Terms and a Glossary olAcronyms tiom the SSR is surnnrarized in Tablc 6.4 and Table 6.5. r3l EE3e3!!EaiiE :EslAEgaiaEa 5 E rrrgRf-,4.r ,r,]u l:B.r!aaEaaSaE se aI;ll I:si FiiE zZat?t--=ie!, t,t'-l!'stDl!E?::t:tatd2a".2'!2zz ilfli-!:r:??ll 9* l-6t e Iar iU!,t 4e g €AEEIE *6l!Eg ; + i3EAi* ! ?,4 ^-, !, r,[.1:zn* :,:,.,- I ra a"-.p.! €P : !rrlF *;: B : r :E si :"-""1""""-"-"'"-' i!ei3eEeica:!irfiElrle;; rrE=IrEl!trt'i-t-'!EE!AEAEAAEA rr 5s r3: F.'tat cli;_;:?::rtlt ,9=gaaaIFS;a nE:?5!AsAr;9 Pgs:;PC"-!:s. Sils!xe;l3iiE !Ei;Eel!!i€i qEi4E:;x:is:8 ea9FE!::a9:! E1*iieiriql: rar:3?;39?ie F..EF; ?EIiF 'F' :fillrai=;'se:"sr"l!=lE!t"'""""""' aq 3 i3 a*at=24?4i..- :::t=a:tFnE.- 1A:=f;!!3€in 399399"q!:,8;-g !r ,.r ! !l a "', i.r i.t :i ;r: ia r ir11=;;!i?iii ,;ete9,i?9i?e i, L A t, 7,.-, a, it 7, 7, L tl :rn=A;t!4eat ,9 ?8-" ) 29=2, - r= =a:,.7\!td-,c .-. ,r1u :eE:.....t....,i6r:L.r..o55c L;Lr!!r-!L!!L:!Y.JdLJ8!31 -"v') ; 1a=r.i- =aj:"ni,!,i ii.t4i56E5d:5 ,3t!:)ai)iii J3J,!$dE3Ji,!E Ji,ESJ!i3i,33,i rarz=aarziza _28 r -i-ii,tlr,i: :;..l!, l r;;r; : E; i56 sss6i s EEti,!!E:lEt iEti!i!ti!iE ,!ls.(J33JSl3J 2 aia .!Afa !A') - .;-r=-*\ -: ttLL.<.<-.?+ :::r==+: ;i i aEATAS{A.S;i;tFF-FEFF-iirl!!:gE!Ei c9e!qe!4c9e3 F a a a\ I \o F o- o(, zlotrl 5l:l =l:l ild F O a.t 5l ! 3 :!i <la ! !2t?????t, I t2 I I ellt! t !t ltt?ztt!ltlltl!::lt!?tt?tt?e?z?l11!!! i:ia 6?:i :F! tiaal :.e9ii!!t388Ei8EeE!a-r:=E: !irr,tlttt.i a::::EAA:aaa:ttttSEt (l) U aa - L a a o, a! I I F iiilrj.rtLq/1iii 4 ,>i>r>Er.r.r -, -a -z - - - >;rir- a tiir l-ai ',i ',i ',i ,i ti ii i a, =,r a;ii5i2ii i) 1i rr.") rii?,,1=..;,2. i 1, ir'11; )i Zi i i ,.? zi zizi 11y2 i2 i':? '=' ie. i 4i_411, i ? a".'- .'.. ? . P.i a2iZ:2 i,,iZ-;i', aiii izi zi zizizi:- ;i ;-- ;'-i tiili, z ; z ;i r'.r:,? irir i ri > Z>i>e - - - - - - z'! i a i! 4 . 1 r \ ; :, ; -, r, . i . , ,aeil i ' i i r.'! - 7 2!. : ! a r -, ! ! 4 < i i i r't t "' 1 iii'^'"'" l')'' )'-..14..-: -: -: -;:',,|=: : - r i | ! ! ! !'r i:i:i:: i i 7 i, i,-i.=..- 1 | 7rr r r, I ; ; i iir!+;;iiii!iiiiiii: ;i,; ; ili:::1!111!:::::.)> ' ' ' > > : r ai e d i -;; ;;ii;i,,,"".!iiirs.;!iii!!ii!ii!j trtJ j i i i i i t t i i i i;;; i i i i i i, i i, 1! traaaaaarr.rr, .:,:i!:;.-l A'" ?,,:'. i a1 r,a?,e-1azi,a 4iliii:rtiattirtttti t z,.i;,,12 ritr c,:i-1r:=-l>ari -;2"i -.zi i -;1-)ia:leizi;riaa..ci1::tr+1r,tr:tt21Fitz1t1,.1E ai.r<.;r,<a'Fxt -;- ,t ^ i- ti ^ i. I ;i;;!;Ei;i;Ei!iatt::4ti:iafiittbtE!itit9td aaaaaaaarlr>ra i.rFFF ;il !!iE ! ! ! i! E i ii 9F.:i i iit-il! !.r qi'{ti} ii 3388883333:3!:3 I EE B,*aI !3 l 1i ".,j1 z ; c \o + a I d- = =1. - "t. ..1 Et" " -t" '1" 1-' =lo'l = !l YI,.,1 o:l q) U c) a a al I /.c /. 7J v. a(-, E 2!!Yi 9- ,9ri !,iz3< I _i:f ;i EE93 I^,i:i;j-CC;!:$i!i i;:!"3i g 3. g !3 6 "6 ;is! !!ia?qEEE 9 I i 4Z zr!;EaZZ: a i2r, =a1; ;i;..:9i:;iPigJ{{:i!l)ti!!trt :---;i33;41 -!5E5t,i, i9 :t II I l1 (.) 4) a a I al 4' F 7 c! ..' I\o .J & .J ir ::; a i, +;:6.1 4v:v:d ,Fzrn.i F it.224a:a33t33 g*q&989E8393 lqr'tn.'1_i---- tiaeZZ='i8==1t Oae =4, >jijieciSio3i FliT'-!i-z-.1 + <tF.iqi <irjF <j.i F,.i <i o ; F ,.1 ..i .,i ri .l .i .i .i .i =8!1:!138313 F:ShklElElE9l ja-ai.aii=5. i ; IJ. ii ii Aaa{,= tt iatiE. ==Ai1Et5tdi5Fr<i{i<ie€!€;<'j==ai4tdi!iaatFria€€oan€€5 l:iP"g:r:r9g; !l,a i.arcF 19.. 1 ==ii.Llr5;'t55rr€€o€G.sa€€ E8a3tE33:333:aiia'aa22iai l-!l!a!!3!=!< .:h'4i d >)aZ, a- a=a=i,i-,7t,,6 _ / a .- )j'.,iJJi;rrr- _:_ r!_ al1,.ee)!!9!\) ,.x ta /^ /*ititalit /:iv.!y9tr-!-- i=Eltct.c.c-zic 'ta&!!ae'J'Ja')'rZL.,!!Qt)i!Q, -, 7, -1 ::::ts:s .i!.-.i-i-r--:-i= i a c-c-c. a c-c- r'a J\-e!!!!ti!r .9 -! 3 .:1 ? I' t) U q) a) qJ a a li I !l) <l) Ial\o F / ? ; I t;:3 .Ei -n6i,i;F;rj.iFri .a iiv:.) *i +,.: +rF.i 33 n ;S=33='::::!:.....::::=r- :i:ooicjjico ;i;niC!€C€€6 -l'-11.!=r=====::=.=:==..:. .^,: vr -l 9t9 t ti sq J.:55.ii5.oi ;= 'itn. 338e3 8B3EE ee383 lSi:l alrl fZ3, en, v:iaq::.i;+!F.r: ==?,i:1:<t4xaY'<1114i.:.:r:Fi\\ .(, -;\: r' d;,r: -o-j =:agtaetSeSsFn<,;€.!€€ee€ q?-..7 .,i 3333t 8333 ? e?,9 -!55 :n =s,,2 i+-') z z2A7i 2 z=.=ititr-!it 1l'!.5i!:9--i"l : ir i=:;l::::f, i:.4iaQQ! - eiti.rt,!v9trt!Qt -E1? ::i!! FHE$? !?!?9 r,:i;:2'1.,' ,=== >,>>2 ,. ,., .. .; o. =o = =l3l:rl:l-lil U L a a U L q) F Iat F I o e -)c \c =(-, ee9qg3 a-4AAaa SEeeia;iIr:]!5 :;;ri ::'!i+! 8e333r qqqil€ 833883 3=:33: ; i_1 111 3a:333 i1'aiB F3;= 33:=:: 9.ii rlL. iiiaa;e=--..aaaaa 88883333 ,ja 4' ii 3i 3i 31 3i tr eeiairdi 33iri q 3.3:j f: ; t 5E5g9SS:i '!- 9 n7,"- a ',t;!!; iF, 2t".n ?;1.':a, /: -> 'l''-?a.2 1;-'i'.Ei =i= l la a =='.'a7 =iirtF,2. a-,.4-1 3azi1a i3, -. i,- = t - , r_'. =14.2! E 11_-.2/ ,< .t:-, z i nnt'_-= t1'-iit i a= a aa E!5!E! : /.2 _ _-.zrii7?1";2 si=t=,.22'-*Ez;i?z;iii=*;';72z:e?1ZxeF;F4>21::i: l a B E ?E 4 P;-s,-1 ; i i E E i i:A:,!yz.-.i.=-4,'!i 'i= ?- '.a ta ? t;2:.> -,t2"2 rA)a ti 5!:'-- ;i'aPJ .- 2'l n_;;iaarn; e.4":2Ei F- c-e. - ? @ ; Pl- o 6:: U t-, q) a a Lo I 4., tr F Ial\oo (!t- 7 c i I : = ,1 , :.-l ?"ai5: ! =Ei33qq l::i.-i1h!; 6:E{{ .'.;3:: riq: 9lii 7 a :,, ;,e19 a=!rq: shh!!3"?i i{ ? s ?'a.a 9.:rE? azl ?a?=az =aaaa:: I e. c-i ,Z I 7 ta :r* E; ir. a>aa ! = :{a :t *i; .ia4<<< tr3 't > | z 'Y 3n 24!1i<< , i i> i r'E o.aY;>aa !< B. 8 E o oU zaTi ,jji:criid '.j : :3::33!::!..jj-a..:: 99i$titt;i .i.i....irin. rir 3:: i =, i? iiii 3i ! i :! ii i:iii,i-: i : ! )..::::::::::]::::::::::=j: tdd t a'f $' i r'di d r'd;diid id idr' ; ;{E$AE'AE5T at:,3 irt :fi ,;; .Eq 'J:;r E :r xJS! :9l3Si1i3$S; 138: :.,., j j- - j j j - j j- - j.il' aaia6ira6 !a;31 "l 1 8e888388!8c!s I 1E' Cq4r*'qt4q* 4' dd& 4 €4qq, 6q,c cq4 r qqqcqE, I ,,->- ->a;z<i7ir,.,->lz -1ale -i .12r 2,12n z aaEl'a;?,2' ,)?=+,r.=,ar. =rai ):>iai!,zis.F,aEn< eail: :d- 1r -r-,, tai!13;14i ,i!!!f:!F!, .raJ,araaa 2 8 iL,; 9v: ^i-^!- ::::::;::i;::::; -;^:,:i' iii!::::: ! -. :i : B;; s :;: : :: ; : : ;:.' : :..r:q3: a:Bi - : t : : E - , ! : Z i i ". " I :iizi;z:ztizziizi;liiiiz;z;, ),., i 1'. ' / 3i: /1krr aiir;tii, = ;ii i2iiii|l =iI z 1 i7- z',izi ; e I : : : e / : a-t: ia i:^i, Zr, Zi; !!; ':ao21a;24 221 ,- ii?iaa,z..zi iei a !i! I l: 1 t z1-> - ; ; - ;2'-iil,.,.,:..,.n r:r , , I ii ai i a rr,,9 ,8, ? ;:.ro::a:!: ! ! ! !i i: : 1 -, ; - - - - -.i i I l.i. s t t t':--:-- r | 2 r a-'PF11 r, r, r : I i | 1 ;1+3;1i i:i; i: n::: ! t t- t,iiiil ! t"p,i !r{rXi. fri",5:,3s >>."2>t; L ,' ! ! I ? 33! =. , i!l!: ::ta o. 2i i1 .: U a a L I c.l Z i- _az t I =i =iJ a- cU c- a 'l=' I I I Ci q, oU t) t- q) o) a a (, I a.l cl o 9 = Elte:a*i8lrE ":Zl:: ;;az T !ir I qar-,6!B?.1;!.:,3 5=;3fiEP3+:ri F IGq6=-=ElE!A ttlF:tiF3:itfr!i a;:GssSca=8!8 ii+iiei+*d$i aF=€38it9313 *.dt*iddii{{ !i,1 i*+;;a+8i.ri.i.i! :"a t; iaPi*;,iali3;:l L,7,=? .NFet?,;l; ia=====aa=-= !r)?72.iq:i3;i 8:ii38ii5Gcr :::EIE!!E!EE 'L t;c2 il i , ):^-r, ')^ ,--AA.!r-2i = :. ='t --.- i' ?- t-,'i!-r.<<7a '6uar?Y?i-'-le E a.-r. -..-;- t i- ltt tEz ='-",i i'- i", J ,, a -. " .'.i'-i-:4..,n2!'li )l"E9!,r!:--r- ; i j Bo o t2t-e9r!99e\,? ;Z"i z z 1;'na i - !a!,dAa.:!]t-!-j a1!r-<<l< aAeol- 4l -tal-l ='lalllil 1l,l 3i3:,;!S3:Et'l ;:;a?a eSEt-!*E*q31 ;:3CGa;Pt*s?r?iii 9*83:t3Xtal t:t t *i+iitF$:tFE e!665 aE33= 3883€ 6.-5\5 i.iii 3333i 3;9 Sil 8ll t;3n3 *r9i-lliiEtl---€o..c9c9c 2 ciil;5 zCeareeE::=: aAe':=gE:3i8f, :i :i ti lii;55:i Ii ii Fi ii ail2z=z1ii=a =8 8E833 =:8::;etr;3;;sr9; ,i1 . ,1+r+a . ''-'.;'''1 )r,"tsp)ii-:, IE! isssssr;x )E!ti9)\r??!9 . n"l. :E;! ;!llE >222' i.; t; 'E i 1=1+'.:r.'.,..; ')r'a.9irrrrrr irElc. '9.7:i :::::Lc-erLUUr!:o9,Ej=",3".11!=? o U 6,) q) 0,) a a o F I a.t z . ! d = a d. i., t-$ t" =t q, c) U) a L3 ., F I 6t u z C o = .J I ,) +rl ;Er,3".,";t;=xxt9 a-rnn$E:rSElIt ; i.j t 5'iBl.J i'.aa1', ie-s*8 IeeEEq ! :: 1 3a3a ee€8 tEe8E= :::::.- a3==:a ==8583 483=:8 383-33 3e3433 :3:::33r esE9ar8r ,e !3*fr 1S:itEEi a11.Si=l'r:rEZEl IL: !: ."i i"l -.4,a11a n't, --rPa . Z?i 7r.; E iti -*-;".;::-i:; ;: J !- ""':-i;. 1aa'.4,i 9:rai) z j ,t:ii ina?:iE":t!,!?ni aaalni?42>>ed;i?'.i * r = t i'- i!Eititiiiit ! i4t:F.ieP.a<,i i=i:F 2-"a72ti >>4--t? an=;.r. tr:=!t1.ZEEEE az?aaa I a1-=iai9?ra' a raa3.a, . v ezi,a: a- a ?;z r; z s:a:_i?: =!2tta*> 4?ii-a c,a{i,}:; EEE E;:?5ar-i:! 3 l <f !d zj.E .ii : r ;- f EEr 7 ESi ET!h;Ei a a - I a-.1 Z C E i =(, o- a = 4ti-E 3;.;E !r5E+;;t aaa a 8.i 8 '39888:: 3.; ,1 3ne fl58-$€5ii t, i!i3 Fe3n8 P8a:,= *gg:r3 333€: ;8 ii 8 s::e a AJ rrdse == ==za,, t??.?8888633i a ;i ,2 ,\ a iti2 :): -. 1 l.:,5i a. a2 : i': )'- i: ta!a<<2 ,i?2t!'! i!r.-;-:i = 5;.. I I *"ral="""1 1,,",1 I i :r 1?' : ;, a -, '! ;|.4',:rii i?i!i 3 :::::a::a::::: 8rllE:8r888r888tSt-l- ata 83:38::3:: FPFPEFPIi::iiiFFFFFFFEiEF i?::!E:Eaaai tz==i;:3il8i8 E3388888888888348E4!ErEEa e ia ia 1i :in i1-iiraai;a: iii; i ii i:;;;d; d;;d,:;sl": ; di;i 33:tt88:83EB8a t- i. iz11aiz497Zaz;:24."! =Zai?,Za i?r'\ . >-;,1: >- t;,-itz,.iF,Z 2 'i:: ii-'j. ti Ii:ji:.31!i:,,..:',iiiiaiiiii.: , i : -.'.4 2. :.= <..... :. iE:iii.;r;i;r;i?-i:;;;;;;;;;; z .a3 "'P,:a!iF.r4!i i:; ? 2?i :7, == i;== _i< :i1?tZi.2t iizliSl:!i>"lit aaaaaa t!1g!r! 1E;5: ,ea221 ",,"',aaa>aaaa2 !i'! r l;i1 U t- <t a ,J) U F I a.l F z t :l l\o H ! I I a:ie1:l: PACrFrCoRr, 20l9lRP CHAPTF:R 6 RESoIIRCE OPTIoNS Additionally, total resource costs were prepared for threc natural gas-fired cornbined cycle combustion turhine resourcc options at an elevation of 5,050 feet at varying capacity lirctors to show how thcsc costs are affected by dispatch. Table 6.3 shows the total resource cost rcsults fbr this analysis. Table 6.3 - Total Resource Cost for various Ca F'actors S/MWh 20r8$ Table 6.4 - Glossa 100/"'78',%910/oCapacitv Factor CCCT Capacitr Factor Duct Fire too/o tlyo CCCT Dry "C/H", lxl s68. t5 $46.45 $i42.56 s75.9.1 $66.85 $16.20CCCT Dry "C,'11", Dl;, lxl s56.24 1;,10.30 $37.4sCCCT Dry "Ci I 1", 2x I s66. I r 1i58.66 $4 t.75CCCT Dry "C,'11". DF,2xl s61.02 I;42.68 $_39.39(l(lCT Dn, '.1,/HA.02"- |xI CCCT Drr '1iHA.02", Dl-. lxl s69.6i s6r.57 $13.2s CCCT Dry, 'llHA.02" 2Xl s5 t. l4 $3s.l,r CCCT Dry '!iHA.02', DF. 2xl ii6 t .6.1 s51.9 r s39.61 Primary fuel used tbr electricity generation or storage.Iruel Primary technology used for electricity generation or storage.Resource Elevation (af'sl)Average feet above sea level tbr thc proxy site for the given resource. Nct Capacity (MW) Clommcrcial Operation Ycar The resource availability year is thc carliest year the technology associatcd with the given generating resource is commercially available for procurement and installation. The total implementation tirne is the number ol' years necessary to implcmcnt all phases ol' resource dcvelopmcnt and construction: site selection, permitting, maintenance contracts, IRP approval, RFP pmcess, on'ner's engineering, construction, commissioning and grid interconnection. Average numbqr of years the resource is expected to be "used and useful," based on various factors such as manufircturcr's guarantees, fuel availability and environmental regulations. Design Life (years) Base Capital (lii kW) Total capital expenditure in dollars per kilowatt-hour (S/kW) fbr the development and construction ol'a resource including: direct costs (equipment, buildings, installation/ovemight constructi()n, commissioning, contractor fees/profit and contingency), owncr's costs (land, water rights, permitting, rights<rl'-rvay, design engineering, spare parts, project management, legalifi nancial support, grid intcrconnection costs, orvner's contingency), and financial costs (allorvance for tunds used during construction (AFUDC), capital surcharge, property taxes and escalation during construction, if applicable). 145 of Terms from the SSR Total Rcsource Cost ($/tU Wh) s37.57 Term Description For natural gas-fired generation resources, the Net Ciapacity is the net dependable capacity (net electrical output) for a given technology, at the given elevation, at the annual average ambient temperature in a "new and clcan" condition. PACTFTCoRP-2019IRP C PTER 6 RFsot R( u OProNs Var O&M ($iMWh) Includes real lcvelized variable operating costs such as combustion turbine maintcnancc, water costs, boiler water/circulating rvater treatmcnt chemicals, pollution control rcagcnts, equipment maintenance and fired hour f'ees in dollars per megawatt hour ($/MWh). Fixed O&M ($/kW- year) Includes labor costs, combustion turbine fixed maintenance fees, contractcd services lees, office equipment and training. Full Load Heat Rate HHV (lltu/kWh) Net efficiency of the resource to generate electricity lbr a givcn heat input in a "ncw and clean" condition on a higher heating value basis. EFOR (%)Estimated Equivalent Forced Outagc Rate, which incltLdes ltrrced outages and derates fbr a givcn rcsource at the given site. POR (%)Estimated Planned Outage Rate I'or a givcn resource at the given site. Water Consumcd (gallMwh) Average amount ofwater consumed by a resource for make-up, curling u'ater make-up, inlet conditioning and pollution control. SO: (lbs/MMBtu)Expected permitted level of sulfur dioxide (SOu ) emissions in pounds ofsullur dioxidc per million Lltu ofheat input. NOx (lbs/MMBtu)Expected permitted level ol' nitrogcn oxides (NO-) (expressed as NO:) in pounds ol'NOx pcr million Btu olheat input. I lg (lbs/TBtu)Expected permitted level of mercury cmissions in pounds per trillion Btu of heat input. CO: (lbsiMMBtu)Pounds olcarbon dioxide (CO:) emitted per million Btu ofheat input. Tahle 6.5 - (llossa of Acron Used in the S de Resou rces AFSI,Avcrage Feet (Above) Sea [.evel CAES Clompressed Air Energy Storage CCCT Clombined Cycle Combustion Turbine CCS Carbon Capture and Sequestration CF Capacity Factor CSP Concentrated Solar Pou'er DF Duct F iring IC lntemal Combustion I(;CC lntegrated Gasilication Combined Cyclc ISO lntemational Organization for Standardization (Tcmp : 59 F/ I 5 C, Pressure = 14.7 psia/1.013 bar) LiJon Lithium Ion NCM Nickel Cobalt Manganese (sub-chemistry of Li-lon) PPA Power Purchase Agreement PC CCS Pulverized Coal equipped u,ith Carbon Capture and Sequestration PHES Pumped I Iydro Energy Storage PV Poly-Si Photovoltaic modules constructed liom poly-crystalline silicon semiconductrlr rval'ers Recip Reciprocating Engine SCCT Simple Cycle Combustion Turbine SCPC Super-Critical Pulverized Coal 146 Term Description Acronyms Description CHAPTER 6 R[souRCE OPTToNS Resou rce Option Descriptions The following are brief descriptions ofeach ofthe resouroes listed in Table 6.1. Natural Gas, Simple Combined Cycle Turbine (SCCT) Aero x 3 - a resource based on three General Electric LM6000PF-Sprint simple cycle aero-derivative combustion turbines f'ueled on natural gas.'fhe scope rvould include selective catalytic reduction systems and oxidation catalysts to reduce NOx and carbon monoxide/volatile organic compounds (VOC) emissions. Natural Gas, lntercooled SCCT Aero x 2 - a resource based on two (ieneral Electric LMSI00PA+ simple cycle aero-derivative intercooled combustion turbine fueled on natural gas. Scope r.r,ould include selective catalytic reduction systems and oxidation catalysts to reduce NOx and carbon monoxide/VOC emissions. An air-cooled intercooler is assurned. Natural Gas, SCCT Frame "F" x I - a resource based on one General Electric 7FA.05 simple cycle frame type combustion turbine fueled on natural gas. Scope would include selectivc catalytic reduction systems and oxidation catalysts to reduce NOx and carbon monoxide/VO(l ernissions. Natural Gas, lnternal Combustion (lC) Recips x 6 a resource based on six Wansila I 8V50SG reciprocating engines fueled on natural gas. Scope would include selective catalytic rcduction systems and oxidation catalysts to reduce NOx and carbon monoxide/VOC emissions. Natural Gas, Combined Cycle Combustion Turbine (CCCT) Dry "G/H", lxl - a combined cycle resource based on one frame-type General Electric 7HA.0l combustion turbine, one 3- pressurc heat rccovcry steam gcncrator and one steam turbine. Scope would include selective catalyic reduction systems and oxidation catalysts to reduce NOx and carbon rnonoxidc/VoC cmissions. Steam lrorn the steam turbine is condensed in an air cooled condenser. Natural Gas, CCCT Dry "G/H", DF, lxl an option that can be added to a combined cycle plant to increase its capacity by the addition ofduct burncrs in the heat recovery steam generator. This increases the amount ofsteam generated in the heat recovcry sleam generator. The amount of duct firing is up to thc owner. Depcnding on the amount ofduct firing added, thc sizc ol'the steam turbine, steam turbine generator and associated fccd water, steanr condensing and cooling systems may need kr be increased. This description also applies to the lbllowing technologies that are listed on'l'able6.I:CCCTDry"C/H",DF,2xI;CCCTDry"J/HA.02',DF, IxI;CICCTDry"JIHA.0Z". DF,2xl. Natural Gas, CCCT Dry "C/H",2xl - a combincd cycle resource based on two f'rame-type Gcneral Electric 7HA.0l combustion turbines, two 3-pressurc hcat recovery steam generators and one steam turbine. Scope would includc selective oatalytic reduction systems and oxidation catalysts to reduce NOx and carbon monoxide/VOC cmissions. 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 hcat rccovery steam generator and one steam turbine. Scope would include selestive catalytic reduction systems and oxidation catalysts to reduce NOx and carbon monoxide/VOC cmissions. Steam liom the steam turbine is condensed in an air cooled condenser. 147 PA( rFrCoRP 20l9lRP P^( [,rCoRP - ]019 IRI'CUAP ll-.R 6 Rl sot R(,a OP ltoNs Natural Cas, CCCT Dry "J/HA.02",2xl - a combined cycle resource bascd on two liarne-type Mitsubishi M50lGAC combustion turbines (air-cooled), trvo 3-prcssure heat recovery steam general.ors and onc stcam turbine. Scope would include sclcctivc catalytic reduction systems and oxidation catalysls to reduce NOx and carbon monoxidc/VO(' ernissions. Steam liom thc steam turbine is condensed in an air cooled condcnscr. Coal, Super-critical Pulverized Coal (SCPC) with Carbon Capture and Sequestration (CCS) - conventional coal-tlred generation resource including a supercritical boiler (up rt 4000 psig) using pulverized coal with all emission controls including scrubber, fahric Iiltcrs (baghouse), mercury control, selective catalytic rcduction (SCR) and CCS to reduce carbon dioxide emissions by 90 percent. Coal, PC CCS retrofit at 500 MW - a rctrofit ofan existing conventional coal-flrcd boiler and steam turbine resource. Costs includc thc rcduction in plant output due to highcr auxiliary porver requirements and reduced stcam turbine output and would removc carbon dioxide by 90 percent and provide a marginal improvement in other emissions. Coal, IGCC with CCS - an advanced I(}CC rcsource to facilitate lorver cost carbon capture and sequestratiorl costs. An IGCC plant produces a synthetic I'uel gas fiom coal using an advanced oxygen blorvn gasilicr and burning the synthetic luel gas in a conventional combustion turbinc combincd cyclc porver facility. The IGCC rvould utilize the latest advanced combustion turbine technology and provide flr.rel gas clcanup to achieve ultra-lou emissions of sulfur dioxide, nitrogen oxides using selcctivc catalytic reduction systems, mercury i.rnd particulate. Carbon dioxide rvould be removed lrom the synthetic fircl gas befbre combustion thereby reducing carbon dioxide emissions by rrore than 90 pcrccnt. Wind,3.6 MW turbine 37 percent NCF WA/OR/ID a rvind resource based on 3.6 MW wind turbines located in Washington, Orcgon or ldaho rvith an estimalcd annual net capacity factnr of 37 perccnt. The scope u'ould include developing, permitting, cngineering, procuring cquipment and constructing a rvind larm. Wind,3.6 MW turbine 29 percent Nct Capacity Factor (NCF) UT - a u,ind resourcc based on 3.6 MW rvind turbines lticated in Utah with an estimated annual net carpacity f'actor ol29 percent. The scope would include developing. pennitting, enginccring. procuring cquiprncnt and constructing a *'ind f'arrn. Wind,3.6 MW turbine 43 percent NCF WY - a rvind resource based on 3.6 MW rvind turbines located in Wyoming rvith an estimated annual net capacity lactor of43 percent. The scope would include developing, permitting, enginccring. procuring cquipment and constructing a wind tarm. Solar, PV Single Axis Tracking in lD, OR, UT, WA, and WY with NCF between 26.0 and 32.5 percent depending upon location (1.46 MWdc/MWac) - a large utility scalc (50 MW or 200 MW) solar photovoltaic resourcc using crystalline silica solar panels in a single axis tracking system locatcd in southwestem Utah. Storage, Pumped Hydro Storage a rangc (400 - 1,200 MW) of pumped sbragc systcms using a combination ol'natural and constructed \\,ater storage combined with clcvation difference to 148 PA( rr,rCoRP 20l9lRP C Ap l l,R 6 RFrsotiR( r, Ott I0NS Storage, Lithium lon Battery a battery technology of lithium ion hatteries located closo to the load ccntcr. Based on currcnt commercial options such a system is rnodeled with an acquisition and implementation schedule ofone ycar. The recharge ratio fbr this storagc resource is 88 percent. Storage, Flow Battery a baltery lechnology based vanadium ReDOx or other tlo\\ battcry types. Based on current commercial options such a systenr is modeled rvith an acquisition and implementation schedule of one year. 'l hc rccharge ratio fi)r this storagc rcsource is 65 percent. Storage, CAES - compressed air energy storage (CAES) system consists of air storagc rcscrvoir replacing thc compressor on a convcntional gas turbine. 1'hc gas turbine exhaust pos,ers a pou'cr turbine prol'iding a simple cycle gas turbinc energy at lo"ver costs than a conventional gas turbine. g1]--peak energy is used to compress air into the storage reservoir. A systcm size of 320 MW is assumcd. The air storage reservoir is assumed to be solution mined to size. Natural gas is rcquired to generatc powcr. Although the rccharge ratio is difficult to scparate liom the fuel combustion a recharge ratio assumed for this storagc rcsource is 55 percent rvhich includes the luel required during the pos.er generation cycle. Nuclcar, Advanced Fission a laryc 2,234 MW nuclear resourcc rcflccts the current state-ot--the- art advanced nuclear plant and is modeled after the Westinghouse APl000 technology. The assumcd location lbr this resource is the proposed Bluc Castle site near Creen River, Utah rvhich is in devclopmcnt. It is cxpcctcd that thc resource rvould not bc available earlier than 2025. Nuclear, Small Modular Reactor - such systems hold the promise of being built ofli.sits and transportcd to a location at lower cost than traditional nuclcar I'acilities. A nominal 570 MW concept is included. [t is recognized that this concept is still in the design and licensing stage and is not commercially available requiring approximatcly l0 years for availability. Resource Types Renewables PacifiCorp retained Burns & McDonnell Engineering Company (BMcD) to evaluate various renervable energy resources in support olthc development ofthe 2C) I 9 IRP and associated resource acquisition portfolios and/or products. The 201 8 Rcncu'able Resources Assessment and Summary Tables (Assessment) (See Volume l[. Appcndix P) is screening-level in nature ant] includes a comparison of technical capabilities, capital costs, and O&M costs that are reprcsentative o[' renervablc cnergy and storagc technologies listed below. Thc Assessnrent contains preliminary infbrmation in support of the long-term power suppJy planning proccss. Any technologies of interest to PacifiCorp shall be lollorved by additional dctailed studies to further investigatc cach technology and its dircct application rvithin the orvner's long{crm plans. o Single Axis Tracking Solar e Onshore Wind. Encrgy Storagc o Purnped hydro energy storagc (PHES) l,+9 enablc a system capable ol'discharging the rated capacity lirr eight hours combincd with reoharging that capacity over l6 hours. Total development time is cstimated at six-to- l2 years due to various progress on permitting.'Ihe rechargc ratio lor this resource is 79 percent. Actual pumped hydro storage projects within PacifiCorp's territory rvere analyzed. P^( [,rCoRP - 20l9 lRP Clt^p iR 6 Rr,sorR( llOptloNs O CAES o Li-Ion Battery o Flow Batteryo Solar + Energy Storageo Wind + Energy Storage Each rcnewable resource is defined within the Assessment. Gcneral assumptions, tcchnology spccific assumptions and cost inclusions and exclusions are dcscribed within the Assessment. fhe follorving paragraphs discuss highlights from thc n ssessment. a comparison to prcvious IRP data and additional assessment performed by PacifiCorp. Co.s/s The follou,ing costs which were excluded fiom thc renewables sosts estimatcs were added by the PacifiCorp: o AFUDCo Escalation o Sales tax. Property taxes and insurance. Utility demand costs Solar The BMcD Assessment includes 5 MW, 50 MW, and 200 MW single axis tracking (SA1'), PV options evaluatcd at five locations within the PacifiCorp servises area. The 2019 dil'fers lrom previous IRP's in the lbllowing lvays: The number oflocations for solar developmcnt were expanded liom trvo states (OR & UT) to five states (lD, OR, UT, WA, and WY) to reflect cxpanding solar developmcnt activity within PacifiCorp's service territory. A 200 MW option rvas added for each ol'thc five locations based upon industry trends ot' building larger solar lacilitics. F ixed tilt PV and concentratcd solar are not included bascd to findings in the 201 7 IRP that SAT PV rcsources have lower costs and arc bctter suited to PaciliCorp's service territory than llxed tilt PV or concentratcd solar systems for the system sizcs considered. Solar costs (including forecasted costs) used kx the 2019 IRP are higher than those used in the 20 I 7 IRP Update, but are significantly lorver than those used in the 20 I 7 lRP. The increase from thc 2017 IRP Update is paaially duc to a different assumed design. Thc inverler krading ratio results in a higher base capital cost, but a lower levelized cost of energy (LCOE). ln addition to the differcnt dcsign basis trvo significant events have occurred u,ith respect to solar costs since the 2017 tRP. In late Septembcr 2017 the lntemational Trade Commission passed a finding of injury to US solar manufacturers. A significant increasc in solar prices in the US occurred lbllorving the ITC ruling. Solar costs have since rcsumed a declining trend, though at a rcduced rate ofdecline. On January 22, 2018, thc United States levied a 30 percent tariff on solar imports. The tariff covers both imported solar cells and solar modules. The taritf is expected to last fbr lbur years falling by five pcrcent annually, dropping to a l5 pcrccnt tariffin 2021. At the lime the tariff u,as levied solar prices brielly halted thcir decline from the peak price which occurred after the ITC nrling. Figure t50 PA( rFrCoRr 20l9lRP CIiAp I r.R 6 RIrs()l it{( t.: OF I roNS 6.4 shows a history of capital costs and a fbrccast used in the SSR for PV resources in Utah and Orcgon. The forecast data for the solar 2019 IRP PV costs were provided via NREL data on an annual basis. The decreasing slope starting in 2021 shows that NREL is expecting storage pricing to drop morc ovcr the next three ycars than the years after that. Figure 6.4 - History of SSR PV Cost & Forecast History of SSR PV Costs & Forecast Sr"9oo sl8oo aa E o E EO S1,7oo S 1,4o0 600 050 s s 2016 7017 2018 2019 2020 2021 2022 2023 Calendar Year 2024 1025 2025 2027 zva +2017 tRP UT +2017 IRP OR +2018 rRP UT +2018 tRP OR +2019 tRP UT +2019 tRP OR There was signilioant solar development activity in PaciliCorp's service territory bctween 2012 and 2018. Ovcr the course ofthose seven years,332 solar projccts with narneplates of l0 MW or greater have initiated generation intcrconnection requests rvith PacifiCorp. The total nameplate capacity of'those 330 projects is over 27,500 MW. There were 66 nerv renewablc gcneration projects greatcr than l0 MW that cntsrcd PacifiCorp's generation interconnection queue during 201 8; ol these 67 new projects, 5 I are solar, six are solar & battery storage, seven arc rvind, one is battery encrgy storage, and one is nuclear. The nameplate capacity ol'the 57 solar projects added in 2018 alone is over 7,300 MW. While many projects that have initiatcd generation interconnection studies over the past l7 years have not bccn built, the number and size ofthe 2018 interconnection solar projccts is testament to the tremendous solar development activity that is underway w ithin Pacifi Corp's service territory. Wind The 2017 IRP found wind energy to be one of the most cost effective new generation resources for PacifiCorp's customers and led to PacifiCorp's Energy Vision 2020 initiative. Energy Vision 2020 includes thrce new wind projccts, a new 500-kV transmission linc, and upgrades to existing t5t s1"3OO 51,20o S1,1oo Sl,ooo S9oo Al PA( I r('oRP-2019lRl,CIIAPTTR 6 _ [{ISoTIRCL- OP I,IO\s inliastructure to deliver the nerv wind gcneration to PacifiCorp's customers. l'he three nerv u,ind projccts rvill add I,150 MW ofncw wind porver to PaciliCorp's gcncration resources. Wind capital costs in the 2019 IRP are lou,cr than the cost estimates in thc 2017 tRP and rr,ill push the LCOE for neu, projects lorvcr. However, reductions in I'cdcral production tax credits (PTCs) will push the [.COE lbr ncw rvind projects built alier 2020 highcr, assuming there are no changcs to PTC policy. The BMcD Assessment includes 200 MW onshore wind generating facilities in the states of Idaho, Oregon, Utah, Washington, and Wyoming to rellect strong wind resources availablc u'ithin or near PaciliCorp's service areas. BMcD relied on publicly available data and proprictary computational programs to complete the net capacity factor characterization. (icncric project locations rverc selected by the corrpany based on viable wind project locations where there are Ihvorablc rvind profiles. Figure 6.5 shows a history of capital costs and a forecast used in thc SSR for wind resources in Wyoming and Oregon. Utility scalc wind farm costs have declincd significantly in reccnt ycars on a per MW nameplate basis duc in large part to substantial increases in the MW size ol'rvind turbines on thc market. Federal PTCs wcrc cxtcnded in December 201 5 and included a graduated phasc out structure that reduccs thc value ofthe credits lirr projects completcd after 2021 and eliminatcs P'l'Cs completely fbr projects completed after 2023. Thc PTC extension has led to incrcasing demand lor safe harbor and firllou-on wind turbine generators (wTGs) in the Unitcd States since 2016 as dcvelopers and on ners havc chosen to purchase sal'e harbor equipmcnt between 201 6 and 2019 to qualifu projeots that will be commercially operational no later than 2020 to 2023. Bums & McDonnell estimatcs the cost of rvind projects will rcmain mostly flat rvith cost decrcases ofless than live perccnt over the next ten years, rvhile other estimates indicate thc LCOE for rvind production could decline as much as 20 percent over the ncxt tcn years. While the wind industry has faced PTC clifl! in the past, it is dillicult to prcdict horv the ssheduled phasc out ofPTC benefits will impact the cost of tuturc rvind projects in the market ovcr the ncxt llvc to ten years. 152 Figure 6.5 - History of SSR Wind Costs & Forecast History of 55R Wind Costs & Forecast 51,700 s 1,600 s900 E o ao 't 500 ,lO0 300 200 100 S1, s 1,s 1,S S 1,ooo 2016 2077 2018 2019 2020 2027 2022 2023 Calendar Year 2024 2025 2026 2027 2024 + 2017 IRP WY ..-2017 IRP OR +2018 IRP WY + 2018 IRP OR +2019 IRP WY + 2019 IRP OR Capital Costs Capital cost cstimatcs lor wind rcsourccs in the IRP are bascd upon a combination olthe llurns & McDonnell study, communications rvith wind equipment and construction companies, and PacifiCorp's active wind construction projects. AII wind resources are specificd in 200 MW blocks, but the modcl can choose multiple blocks or a fractional amount ofa block. Wind Resource Capacity Factors andE[eray Shapes Resource options in the topology bubbles are assigned capacity lhctors based upon historic or expected project performance. Assigncd capacity factor values fbr \l'ind rcsources are 43 percent in Wyoming, 37 perccnt in Washington, Oregon and ldaho, and 29 percent in Utah. (iapacity tbctor is a separate modeled parameter from the capital cost, and is used to scale wind cncrgy shapes used by both the SO model and the Planning and Risk model (PaR). The hourly generation shapc rcflects average hourly wind variability. Thc hourly generation shape is repeated lbr each year ol the simulation. t53 CI IAPTER 6 - RL:s(n JRCr.r OPTToNSP^( rl,lCoRP 201 g IRP Wind Integration Costs To capture the costs of integrating u'ind into thc system, PacifiCiorp applied a value of S I . I l/MWh (in 201 8 dollars) fbr resource selection. To capture the costs ol' integrating solar into the system, PacifiCorp applied a value of $0.85/MWh (in 2018 dollars). Additional detailed inlbrmation can be found in PacifiCorp's 2019 flexible resen'e study (Volume II, Appendix F'). lntegration costs a a l l P^( rr r(oRP l0l9lRP CITAITER 6 RF.s(nrRCE oPTro\s werc incorporated into rvind capital costs based on a 30-year projcct life expectancy and gencration pcrfbrmance. and into solar capital costs based on a 25-vcar lif'e expectancy and generation perfornrance. Ceothermal Gcothermal resources can producc base-load energy and havc high reliability and availability. Horvever, geothermal rcsources have significantly highcr development cosls and cxploration risks than other rencuablc technologies such as s,ind and solar. PaciliCorp has commissioned several studics of geothermal options during the past ten years to detcrminc if additional sources ol production can be added to the company's generation porllblio in a cost effective manner. A 2010 study commissionecl hy PacitiCorp and completed hy Black & Veatch focused on gcothermal projects near to PacitiCorp's service territory that wcrc in advanced phases ol dcvelopment and could demonstralc commercial l'iability. PacifiCorp commissioned Black & Veatch to perlirrm additional analysis of geothermal projccts in the early stages ol'dcvelopment and a report was issued in 2012. An evaluation ofthc PacifiCorp's Rousevelt Hot Springs geothermal resource was comnrissioned in 2013. The geothermal capital costs in the 2019 supply side rcsource option are built on thc understanding gained fiorn thesc carlicr reports, publicaily available capital costs liom thc (icothermal Resources Council and publicly available prices lbr cnergy supplied under porvcr purchase agreernents. The cost recovcry mechanisms currently availablc to PacifiCorp as a regulated electric utility are not compatible rvith the inherent risks associated with the developmcnt of geothermal resourccs for porver generation. The primary risks of geothermal development are dry holes, rvell integrity and insuflicient resource adequacy (flou', temperaturc and pressure). These risks cannot be hrlly quantified until rvells are drilled and completed. The cost to validate total production capability of a geothermal resourcc can be as high as 35 percent of total project costs. Exploration test wells typically cost betrveen $500,000 and S I .5 million per well. Full production and injection wells cost between S4-5 rnillion per well. Variations in the permeability of subsurf'ace materials can determine whether rvclls in close proximity are commercially viable, lacking in pressure or tempcrature, or completely dry with no intcrconnectivity to a geothermal resource. As a regulatcd utility subject to the public utility commissions of six states, Pacitlcorp is not compensated nor incentivized to engagc in these inherently risky development efforts. 'I'o mitigate the llnancial risks of geothermal development, PacitiCorp rvould use an RFP process to obtain markct proposals for geothermal polvcr purchase agreements or build-ou,n-transl'er projcct agreement structures. Geothermal dcvclopcrs, extemal to PacifiCorp, have the flexibility to structure project pricing to includc all development risks. Through an RIrP process, PacifiCorp could choose the gcothcrmal project rvith the lorvest cost ofl-ered by the markct and avoid considcrable risk tbr the company and its customers. Several geothermal projects submittcd proposals in response to the 2016 Orcgon Renervables RFP, but nonc ofthe gerxhermal projccrs were selected as a new PacitiCorp generation source. In thc event PacitiCorp idcntitles a geothermal assct that appears to he economically attractive but also determincs that there is a signiticant possibility of developmcnt risk that the market rvill not cconomically absorb, PacifiC orp may approach statc rcgulators rvith estimates ofrcsource development costs and risks associated to obtain approval for a mechanism to addrcss risks such as dry holcs. Because public utility commissions typically do not allow recovr--ry ofexpenditures rvhich do not result in a dircct benefit to custonlers, and at least ons state has a statute that precludcs cost recovery ol'any assct 154 P^( rFrcor{I, 2019IRP C Ap I I.t{ 6 RE.s(x rR( r. Opl l()NS that is not considered to be "used arrd useful," obtaining a mechanism to recovcr gcothermal development costs may bc ditlcult. Energy Storage Thc BMcD Assessment discusses three energy storage rcsource options: l) PHES),2) CAES, and 3) battery shrage. Batlsry storage was also considered in combination with solar and wind. The addition of wind plus storage and solar plus storage created a largc number of'new resource options in the SSR. To mitigate the impact of thc additional information less cmphasis rvas placed on the various battery chemistries. Tu,o ofthe three pumped hydro projects included in both the 201 7 and 2019 IRP's shorved modcst capital cost declines rvhile onc shorved a modest cost increasc. The capital cost for CAES showed a 24 perccnt cost decrease. No forecasts havc been used for pumped hydro and CAES. Both technolcgies are expectcd to have a flat lorecast dcspite the recent movcment in costs. Figure 6.6 shows a history ofcapital costs and a forecast used in thc SSR fbr Li-lon and llow battcry resources. Battery costs are expected to continue t0 decline for the next ten years. Due to the complexity and maturity ol'the battery market, O&M costs continue to be an area olsome uncertainty. PacifiCorp currently has two battery projects undcr development, one in Utah and one in Oregon, which willprovide real markct data to validate or indicate ifan adjustment is needcd lbr O&M costs. Figure 6.6 - History ofSSR Battery Energy Storage System Costs & Forecast History of SSR Battery Ener8y Storage System Costs & Forecast S1,loo S1,2oo a t E E co a 91,1 00 al' S1,L}JO s9o0 s800 S/oo s600 ssoo 2015 2017 2018 2019 20ZO 202t 2022 2023 calendar Year 2024 2025 2026 2027 2028 t55 l +2017 IRP Li ion NCM +2017 IRP Flolv +2018|RP Li-ion NCM ..+-2018 IRP Flolv +2019 IRP Li ion NCM +2019 IRP Flolv P^(.lrrCoRP 20l9lRP C IAP r r,rr 6 Rr,s{)l R( li OpTIoNs Natural Gas Natural gas-fireled generating resources offer several important services that support thc safe and rcliable operation ofthe cnergy grid in an ecunomic manner.'l'hey include technologies that are capable ol'providing peaking, intennediate and basc generation. A variety of natural gas-lueled generating resources thal are and will continue to be available for a several years are includcd in the SSR. The variety of natural gas resources wcrc selected to provide fbr gcnerating performance and servicss essential to sal'e and rcliable operation of the cncrgy grid. Natural gas res()urccs gcncrale cost compclitivc po*cr while producing lon air cmissions. Natural gas-lueled rcsources are proven to be highly reliable and safb. Perlbrmance, cost and operating charactcristics for each resource were provided at elevations of 1,500, 3,000, 5,050 and 6,500 feet above mean sea level, rcprcsentative of geographic areas in which the resource could be located. Perftrrmancc, cost and operating characteristics rvere also provided at ISO conditions (zero feet above mcan sea level and 59'F) as a rct-erence. The essential services provided by the resource arc peaking, intermediate and base gcneration. 'l-hree simple cycle combustion turbine options and one rcciprocating engine option u,cre offered to provide pcaking gcncrating services. Peaking gcncrating sen'ices require thc ability to start and reach near f-ull output in less than ten minutes. Pcaking generating serviccs also require the ability in increase (rarnp up) and decreasc (ramp down) very quickly in rcsponse to sudden changcs in power demand as rvell as incrcases and decreases in produclion from intermittent powcr sources. Peaking generation provide the ability to meet pcak power dernand that exceed the capacity ol' intermediatc and base generation. Peak generation also provide reserves to meet system upsets. Options for peaking resourccs included in the supply side rcsources are: l) three each General Electric (GE) LM6000 PF aero-derivative simple cycle combustion turbines, 2) trvo cach GE LMS l00PA+ aero-derivatil'e simple cycle combustion turbines, j) one each (lE 7F frame simple cyclc combustion turhine, and 4) six cach Wasilla l8V50SG reciprocating internal combustion cngines. All of theso options are highty flexible and ellioient. Highcr heating value hcat rates for the rcsourcc rangcd lrom 9,204 Btu,,'kW-hr fbr thc LM6000 PF- to 8,279 Btu/kW-hr for the l8V50S(i engines. Installation ol'high lemperature oxidation catalysts lbr carbon monoxide (CO) control and an SCR systcm fbr NOx control rvould be availablc fbr these resources. Eight combincd cycle combustion turbine options were provided lilr intcrmediate and base gcnerating sen ice. Intermediate gencrating service requires resources that are able to elliciently operate at production rates u'cll below full production in compliancc with air emissions rcgulations for long periods ol timc. Intermediate generating service also require the ability to change production rates quickly. Intermediatc gcneration services pnrvide cost effective means o{' providing power demand that is greater than base load and lorver than peak demands. Base generating scrvicc requires a highly cost effective that is capable of operating at f'ull production fbr long periods of time. Base generation providcs fbr the minimum level of power demand over a day or longer period ol'time at a vcry low cost. 156 Options lor intermediate and base generation were based on tlvo size classes ofengines. The "GiH" size was reprcscntcd by a CE HA.01. The *J/HA.02" was rcpresented by the GE HA.02. Each cngine was aranged in a one combustion turbinc to one steam turbine ( lx I ) and a two combustion turbine to one steam turbine (2xl) contiguration to obtain four resourcc options. The combined cycle resources oflered high hcating value heat rates from 6,3 l7 to 6,374 Btu/kW-hr. Installation ol'oxidation catalysts for carbon monoxide (CO) control and SCR systems fbr nitrogen oxides l'.\crr,rCoRP 20l9lRP (llr^Pr,}.R f) RFsor ]RCF OP] ro\s (NOx) control is expectcd. All ofthe combined cycle options included dry cooling allowing them to be located in arcas with water resourcc concems. Duct Firing (DF) ol'thc combincd cycle is shown in the Supply Side Rcsourcc lirble. Duct liring is not a stand-alonc resource option, but is considcrcd to he an available option for any combincd cycle configuration and represents a lou,' cost option to add peaking capability at relatively high cfliciency and also a mechanism to recover lost pou,er generation capability at high ambient tempcratures. Duct tiring is shorvn in the Supply Side Resource table as a tixcd value lbr each combined cycle cornbination. ln practice the amount ol'duct firing is a design consideration rvhich is selected during the developrnent ofcornbined cycle gencrating lhcilities. Wrile equipment provi<led by specific manuf'acturcrs rvere used to li)r cost and performancc inl'ormation in the supply side resource table, more than onc manulircturer pmduces these type ol cquipment. The costs and pcrfbrmance used here is representative ofthc cost and perfolmance that would bc cxpcctcd f'rorn any ofthe manuthcturcrs. Final selection ofa manuthcturer's equipment rvould be made based on a bid process. New natural gas resources rvere assumed to bc installed at green-field sites on either thc east or rvest side of PacifiCorp's system. Greenfield developmcnt includes the costs ol high pressure natural gas laterals, clcctrical porver transmission lines, ambient air monitoring. pcrmitting, real estate, rights ofway and rvater rights. Rcsourccs additions a hro*'nfield site, such as an existing coal-fueled generating facility, are reduced to reflcct thc decreases costs. Coal Potential coal resources are shown in the SSI{ as supercritical pulverized coal (PC) boilers and ICCC, located in both Utah and Wyoming. Both resource types include carbon dioxide capture and compression needed for sequestration. Supercritical technology is considcrcd the standard design technology comparcd to subcritical technology for pulvcrized coal. Increasing coal costs make the added elficiency ofthe supercritical technology more cost-e ll'ective. Additionally, there is a greatcr competitive nrarketplace for large supcrcritical boilers than tbr large subcritical boilers. lncreasingly, largc boilcr manulhcturers only offer supercritical boilers in the 500-plus MW sizcs. Due to the increased efllciency ofsupcrcritical boilers, overall emission intensity rates are smalle-r than lirr sirnilarly sized subcritical units. Compared to subcritical boilers, supercritical boilers also havc bcttcr load Ibllorving capability, f'aster ramp ralcs. usc lcss \\,ater and requirc lcss steel lirr construction. I he costs shorvn in thc SSR lirr a supercritical PC fhcility reflect the cost oladding a ncu unit at an eristing site. Carbon Capture Thc requirement lbr CO: CCS represents a significant cost for both ncrv and existing coal resources. In ordcr tbr a coal-fueled gencraling thcility to meel the l-'ederal New' Sourcc Perlbrmance Standards lirr Creenhouse Gases (NSPS-GHG) carbon dioxide ernissions lirnit of I,100 lbs per mega\r'att-hour rvould require CO: capture and permancnt sr"-q ucstration. I Capital I This limir is still in cll'ccl and applies as it relates carbon capturc analysis tbr the 2019 Illl'. It should also be nolcd that on December 2018, EPA proposed revisions to the NS['S lbr GHG. Under thc proposcd rule. nervly constructed plant CO2 limits rvill bc based on the most emcicnt dcmonstrated steanr cycle in combination rvith the best opcrating practices. For large units, the BSER is proposed to be super-critical stcam conditions, alrd ifrevised the emission ratc would bc 1,9(X) pounds ofCO2 pcr mogawatt-hour on a gross output basis. for largc units, thc BSER 157 PA( r rcoRp - l0l9 IRP CHAP IT,R 6 RESoI]RCI] OPl]oNs costs do not include the 45Q tax credit lbr carbon dioxide sequestration or enhanced oil rccovery. Based on this requirement, only coal rcsource options that include carbon capture are included in the SSR. Tu,o rnajor utility-scale CCS retrolit projccts havc bccn recently constructed and havc cntered commercial operation on pulverized coal plants in Noth Amerioa. SaskPolvcr's I I5 MW (net) S 1.24 billion Boundary Dam project entered commercial operation in Octobcr 2014. In July 2016, the plant rcachcd a major milestone nfien it demonstratcd that over 1,100,000 tons ol'CO: had been capturcd. ln January 201 7, NRC's Petra Nova projcct rvent into conrmercial operalion. Both of thesc projects have CO: capture ratcs in cxccss of 90 percent; sequestration is accomplished through enhanced oil re"covery (EOR). lloth of these projects utilize aminc-based systems for carbon dioxide capturc. The Petra Nova project is especially meaningful in that the project entailed a retrofit ofan cxisting coal-tueled plant using amine based systcm and captures approximately 5,000 tons per day from the 240 MWh equivalcnt flue gas slipstream from NRG's W.A. Parish unit 8. Captured CO: is transportcd through an 8l-mile pipeline and used fbr EOR at thc West Ranch Oilfield, located on the Culf Cloast of 'l'exas. lt is the largest retrofit of a carbon capture technology of a pulvcrized coal plant in the rvorl<l. Petra Nova is 5(150 joint venture by NRG and JX Nippon. Thc United States DOE is provided up to $190 million in grants as parl of the Clean Coal Power lnitiative Program (CCPI), a cost-shared collaboration betueen the lbdcral government and private industry. Thc amine-based capture system utilizes Mitsubishi's proprietary KM CDR Process€r and uses its KS- I rM amine solvent. PacifiC orp continues to monitor CO: capture technologies for possible rctrollt application on its existing coal-fired rcsourccs, as well as their applicability lirr lirture lbssil t'ueled plants that could scn,c as cost-effective altematives t0 IGCC plants. An option to capture CO: at an existing coal- fired unit has been included in the SSR. Currently there are only a limited numbcr ol large-scale sequestration projccts in operation around the u,orld; most of thcsc have been installed in conjunction with enhanced oil recovery. Given the high capital cost of implementing CCS on coal fired generation (either on a retroflt basis or for neu, resources) CCS is not considcred a viable option bcfbrc 2025. Factors contributing to this position includc capital cost risk uncertainty, the availability of commercial sequeslration (non-EOR) sitcs. uncerrainty regarding long term liabilities lirr underground scqucstration, and the availability ol lederal lirnding to support such projects. To address the availability of commcrcial scquestration, three PacifiCorp powcr plants participated in l'ederally f'unded rcscarch to conduct a Phase I pre-l'easibility study ol carbon capture and storage. A grant from the U.S. DOE to the [Jniversity ol'Wyoming rvas used to assess the storagc of carbon dioxide in the Rock Springs Uplift, a gcologic tbnnation located adjacent to the Jim Bridger Plant in southwcst Wyoming. Similar funding was allocated to thc University of Utah to study thc l'casibility ol long-tenn carbon dioxide storage in thc San Ralhel Srvell near the Hunter and lluntington plants in central Utah. Both of projccts shorved that geological lbrmations cxist near the planls that may support carbon sequestration, though lurther study rvould be required. Neither sitc rvas sclccted by the U.S. DOE fbr advance study in the Phasc ll ofthe grant program. is proposed to be subcritical conditions, and il'rcviscd the emission rate would be 2,200 pounds ot CO: per mcgawatt-hour rcgardless ol'thc size ofthe unit. 158 P\( rFrCoRP l0l9llll'CIIAPir,R 6 Rlls() R( l OPlro\s PacifiCorp issued a request for expression of interest b potential carbon capturc, utilization, and storage (CCUS) counterparties on September 7,2018. The request fbcused on possiblc deployment of CCUS technologies at PacifiCorp's Dave Johnston gcnerating fbcility for potential enhanced oilrecovery (EOR). On February 28, 2019, a phase I feasibility study rvas received by each ofthe three interested parties selected to participate (Jupiter Oxygen, ION Clean Energy [previously Eco2Sourcel, and Glenrock Energy). On April 23,2019. the participants wcre notilled they may progress to phase [[ engagement ol front-end enginecring design (FEED) study at thcir discretion. None of thc participants receivcd DOE grant iunds to support their FEED studies. PacifiCorp remains open to a CCUS project rvith thc three parties ifthey secure funding in their own effons. An altcmativc kr supcrcritical pulverized-coal technology lbr coal-based generation is the application of I(JCC technology. A signilicant advantage tbr ICCC rvhen compared to pulverizcd coal with amine-based carbon capturc, is thc reduced cost ofcapturing CO: fiom the process. Only a limited number of IGCC plants have been built and operated around the rvorld. In the United States, these Iacilities have been demonstration projects. rcsulting in capital and opcrating costs that are signilicantly greater than thosc costs for conventional coal plants. These projects have been constructcd with significant f'edcral t'Lrnding- One large. utility-scale IGCC plant with carbon capture capability recently went into service. Southenr Company's 582 MW (nct) $6.8 billion Kempcr County project includes carhon capture (65 perccnt capture) and sequestration (fbr EOR). The plant produccd electric power using syngas in October of20l6. Lcaks caused the plant to miss the scheduled March 2017 cornpletion date. Kcmper power plant suspended coal gasilication in June 2017. The costs presented in the SSR tbr ncrv IGCC resources are based on 2007 studies ol'lGClC costs associated w,ith ellirrts to partner Pacifi('orp with the Wyoming Inlrastructure Authority (WIA) kr investigate thc actluisition of fbderal grant money to demonstrate rvestem IGCCI projects. A consortium of Japanese firms received ordcrs on December l,2016 for two 540 MW IGCC plants to be constructed in Japan based on Mitsubishi's IGCC teohnology that u.as tcstcd at the Nakoso Porver Station from 2007 through 2013. A number olcountries, including China,'Iurkey, Dubai, India, Kenya, Philippines, South Korea, Japan, and Malaysia have also announced plans to construct new conventional coal-lueled electric generating resources which will be monitored liom a cost and technology deploymcnt perspective. No new cost studies rvere perfirrnred I'ur coal-fueled gcncration options in 2018. Updatcd capital and O&M costs tbr coal-fuel gcncration options were based on cscalating costs used in the 2017 IRP. Coal Plant Efficiency Improvements []uel cfliciency gains lor exisling coal plants. rvhich arc manil'ested as lorver plant hcat ratcs, are realized by: ( l) continuous operations improvement, (2) rnonitoring the quality ofthe fuel supply, and (3) upgrading components ileconomically justilled. E,l'ficiency improvemcnts can result in a smaller cmissions lbotprint fbr a given level of plant capacity, or the same footprint u.hen plant capacity is incrcased. The efficicncy ol gencrating units, primarily measured by thc hcat rate (the ratio ofheat input to energy output) degrades gradually as componenls wear over time. During opcration, controllable process paramelers are adjusted to optimize the unit's power output compared to its heat input. Typical overhaul work that contribdes to improved efficiency includes (1) major equipment 159 P^( rC(mP f0l9lRP CIr^p n]r 6 Rr,s(x JRCr- Op ilo\s ovcrhauls of the steam generating equipment and oombustion/steam turbine generators, (2) overhauls ofthe cooling systems and (3) overhauls ol'the pollution control equipment. When economically justified, efficiency improvcments are obtained through major component upgradcs ofthe electricity generating cquipment. 'Ihe most notablc cxamples ofupgrades resulting in greater generating capacity arc steam turbine upgrades. Turbinc upgrades can consist ofadding additional rons ol'blades to the rearward section of the turbine shaft (generically known as a "dense pack" conliguration), but can also includc replacing existing blades, rcplacing end seals, and cnhancing seal packing media. Currcntly PacifiCorp has no plans to make any major steam turbine or generator upgrades over the next l0 years. Nuclear Paci{iCorp revisited two ofthe nuclear options presented in the 2017 fbr the 2019 IRP: l) 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 sitc. Blue Castle Holdings (BCIH) did not provide updated pricing, therefore costs wcre escalated by two years fiom the costs used in the 201 7 lRP. NuScale provided an update on their design, licensing and costs. NuScale's update resulted in a significant decline in the capital cost number for the Small Modular Reactor (SMR) resource option. In 2016 BCH provided a detailed cost analysis olthe Vogtle plant construction and eliminated unexpected costs rvhich would not apply to the Green River sitc such as geotechnical problcms encountered at the Vogtlc site. The Vogtle plant was a first of a kind (FOAK) plant but the Creen River plant would be an Nth ola kind (NOAK) plant based on the Vogtle plant AP 1000 design. PacifiCorp added a 3.7 percent delay cost to BCH's capital cost cstimate for potential unfbrcseen problems not encountered on the Vogtle project. Dctails of the BCH project can be found at wvw,bluecastleproject.com. NuScale is developing an advanced reactor design in the SMR category. Although it is an FOAK tcchnology, the design has inhercnt safery features which support reduced capital costs and operating cost estimatcs. PacifiCorp has a seat on the NuScale advisory board, however PacifiCorp has no monetary interest in NuScale or the SMR project being developed tbr the ldaho National Lab site. PacifiCorp added five perccnt contingency and ten perccnt dclay costs due to the project being FOAK. Details of NuScale's SMR can be f'ound at \ .\rlv.nuscalepower.com. PacifiClorp's capital cost estimates include a 10.36 percent owner's cost fbr thc BCI I and NuScale projects. Despite the cost improvements due to the leaming curvc associated with the AP-1000's previous installations orthe NuScale SMR's simplilicd design attributes, nuclear generation is still expected to have a high [,COE relative to other generation options. Resource Options and Attributes Sourcc of Demand-Side Management Resource Data PacitiCorp conducted a Conservation Potcntial Assessment (CPA) with fbr 2019-2038, which provided DSM resource opportunity estimates for the 2019 IRP. The study was conducted by 160 Demand-side Resouices PA( [ r('r)RP f0l9lRP ('tr,\Pl r,R 6- RLsol tr( I OPr roN\ Applicd Errergy Group (AEG) on behalf of the company. The CPA provided a broad cstimate ol' the sizc, type, location and cost ofdemand-side resources.l For the purpose ofintegrated rcsource planning, the DSM intbrmation from the CPA r,r'as convefted into supply curves by type of rcsource (i.e. energy-based energy efficiency and demand response) fbr modeling against compcting supply-sidc altematives. Demand-Side Management Supply Curves DSM resource supply curves are a compilation olpoint estimates showing thc rclationship betrveen ths- cumulative quantity and cost of resources, providing a representative look at how much ol'a particular resource can bc acquired at a particular price point. Resource modeling utilizing supply curves allows the selection of least-cost resources (e.9. products and quantities) based on each resource's competitiveness against alternativc resource options. Due to thc timing ofthe 2019 IRP planning and rnodeling, PaciliCorp had established, tirnded and begun acquiring 2019 DSM program acquisition targcts. To cnsurc that the 2019 IRP analysis is consistent rvith existing planned energy efficiency acquisition lcvcls (i.e., Class 2 DSM), expectcd DSM savings in each state were fixed for calendar year 2019. Beyond 2019, the model optimized DSM sclections. As u,ith supply-sidc rcsourccs, the devclopnrent of DSM supply curves requires specification of quantity, availability, and cost attributcs. Attributes specilic to DSM curvcs include: r Resource quantities available in each year either in terms of megawatts or megawatt-hours, rccognizing that somc resources may come from stock additions not yet built, and that clcctivc resourccs cannot all be acquired in thc llrst year ofthe planning pcriod; . Persistence of resource savings (e.g., cnergy elficierrcy equipment mcasure lives);. Seasonal availability and hours available (c.g., irrigation load control programs);o The hourly shape ol'the resource (e.g., load shapc ofthe resource); and o Lcvelized resource costs (e.g., dollars per kilowatt pcr year lbr energy efficiency, or dollars per mcgawatt-hour ovcr thc resourcc's lil'e lor demand responsc rcsources). Oncc developed, DSM supply curves are treated likc discrete supply-side resources in thc IRP modeling environmcnt. Demand Response: DSM Capacity Supply Cun'es The potential and costs fbr demand rcsponse resources were provided at the state level, rvith impacts specified separately for summer and wintcr pcak periods. Resource price diflcrcnces betwecn states fbr similar resources rellect dilferences irr each market, such as irrigation pump size and hours ol operation, as well as producl perlbrmance differences. For instance, residential air conditioning load control in Oregon is more cxpensive than Utah on a unitized or dollar-per- kilowatt-ycar basis duc to climatic ditfcrences that result in a lorver load impact per installed switch. Table 6.6 and Table 6.7 show the summary level demand response resource supply curve intbrmation, by control area. For additional detail on dcmand rcspunse resource assumptions uscd to develop these supply curvcs, scc Volume 3 ofthe 2019 CPA.I Potcntial shou'n is incremental to the existing DSM resources identified in Table 5.12. For existing program otfcrings, it is I The 2019 Conservation Potential Study is available on PacifiCorp's demand-side managcmcnt wch page rvrvw.paci ticorp.com/energy/integrated-resource-plan/support.html. r The CPA can bc tbund at: wu rv.pacilicorp.com/cnergy/integrated-resource-plan/support.htm l. r6l PACII.ICoRP 20I9IRP Table 6.6 - Demand Res nsc ram Attributes West Control Area Ice Line Stora Ancilla Sen,ices I For consistency in modcling, water heating potential for both scasons is included with the central air conditioning prcduc1. Table 6.7 - Demand Res onsc Pro ram Attributes fast Control Area Ancilla rv Scrvices (ti3) - $2I For consistency in modeling. rvater heating potcntial for both seasons is included with thc central air conditioning product. Energy Efficiency DSM, Energy Supply Curves Thc 2019 CPA provided the inlbrmation Io fully assess the potential contribution from DSM energy efficiency resources over thc IRP planning horizon. The CPA analysis accounts f'nr knorvn changes in building codcs, advancing equipment eliicicncy standards, market translbrmation, Summer Winter Product 20-Year Potential (Mw) Levelized Cost ($/kw-yr) 20-Year Potential (Mw) Levelized Cost ($/kW-vr) s7 - $27 l8 82 nla s30 - s9l DLC Cooling & WH - Res and C&l DLC Spacc Heating ltes & C&l 33 8.+ I s14 - S48 s3 l-ss4 $352 DLC Srnart Thermostat - Res DLC Smart Appliancc - Res 1 ti22 r DLC Elec Vehicle Charging - Res s773 DL('Irrigation 26 n/ir nla l'hird Party Conlracts 50 $55 - 556 4l s94 - S 100 3 nla 9 n/a n/a Summer Winter Product 20-Year Potential (Mw) Levelized Cost ($/kW-yr) 20-Year Potential (Mw) Levelized Cost ($/kW-vr) DLC Cooling & WH - Res and t'&l (s4) - $4e 20 DLC Spacc Hcating Res & C&I DLC Room AC - Res n/a $r8s ))s9 - sl8 ss - $s6 $77 - $28s 1 DLC Smart Appliance - Res s2l I $2228 ji696s6u6 8 5 sl4 - s44 nla DLC Elcc Vehiclc Char Third Party Contracts ing - Res DI-C I lon sl00-$t42il8s53 - 563 90 Ice Encrgy Storage 2 $i 143 n/a n/a t62 CrrAPrlR6 RrsorlR( 1, OP l lo\s assumed that the PacifiCorp could bcgin acquiring incremental potential in 2019. For resourccs representing nerv product oftbrings, it is assumed PaciliCorp could begin acquiring potcntial in 2020, accounting fbr thc time required for program design, regulatory approval. vendor sclcction, etc. $136-Sr57 n/a nla DLC Room AC - Res n/a 84 $2r0 1 l $763 l $37 - li40 s t34 nla sr4 - s20 64 stTl - s458 nla n/a nla DLC Smart Thcrmostat - Res 167 4t 4 l4 nla n/a 20 n/a P,\CII,ICoRP _ ]0I9IRP resource cost changcs, changes in building characteristics and statc-spccilic resource evaluation considerations (e.g. cost-eflectiveness critcria). DSM cnergy eliiciency resourse potential rvas assessed by state dorvn to the individual measurc and building lcvcls (e.g. spccific appliances, motors, lighting configurations for residential buildings, and small offices). The CPA provided DSM energy efficiency resourcc inlbrmation at the lbllowing granularity: . State: Washington, Califbmia. tdaho, Utah, Wyoming4. Measure: - 89 rcsidential measurss - I 30 commercial measures I I I industrial measures - 22 irrigation measures I I street lighting measures Facility types: Six residential lacility types 28 commcrcial f'acility types - 30 industrial facility typcs - I'rvo inigation facility type Four streel lighting types CHAPI l.R 6 Rl,sol rtt( t: OPTIo\s The 2019 CIPA levelized total resource costs ovcr the study period at PacifiCorp's cost of'capital, consistent rvith the treatment of supply-side resources. Costs include measure costs and a statc- specific addcr lbr program adminislrative costs for all statcs cxccpt Utah and ldaho. Clonsistent r.r,ith regulatory mandates, Utah and ldaho DSM energy efficiency resource costs wcre levelized using utility costs instead of total resource costs (i.c. incentive and a state specilic addcr fbr program administration costs). Thc technical potential for all DSM energy efliciency resources across all states except Oregon over the twenty-year CPA planning horizon totaled 12. I million MWh.6 The technical potential represents the total universe ofpossiblc savings belore adjustments for what is likcly to be realized (i.e. technical achievable potential). When the achievable assumptions describcd bclorv are considered the technical potential is reduced to a technical achievable potential I'or modeling consideration o19.6 million MWh tbr all five states. The technical achicvable potential for all six states for modeling consideration is 13.2 million MWh. The technical achievablc potential, represcnting available polential at all costs, is provided to thc IRP model for economic screening relative to supply-side altematives. Despite thc granularity of DSM cncrgy el)iciency resollrce information available, it rvas impractical to nrodel the resource supply curves at this lcvel ol dctail. The cornbination olmeasurcs r Orcgon's DSM potential $,as assessed in a s€parate study commissioncd by the Energy Trust ol'Oregon.i Facility typc includcs such anributcs a\ {\istrng or r)erv construclion. singlc or multi-lhmily. Facilily types are more lully desuibed in Chapter 4 olVolume ? ol'lhc 2019 CPA. 6 The identitled technical potential represents the cumulative impact ol't)SM mcasure installations in the 20'h year of the study period lbr Culilbmia. Idaho. Washingtun, Wyoming, and Utah. l his may dilTer l'rom thc sum of individual years' incremental impacts due to the introduction of improved codcs and standards over the study period. LTO provides Paciljcory rvith technical achievablc potcntial. 163 P,\( Il r( l)Rr, 20l9lRP CI IAPTTR 6 - RIisouR( li OP I ()Ns by building type and state generated ovcr 37,880 separate pemrutations or distinct measures that could be modeled using the supply cune methodology. To rcduce the resource options lbr consideration * ithout losing the ol'erall resource cluantity available or its relative cost, resollrccs were consolidatcd into bundles, using ranges ol' lcvelized costs to reducc thc number of combinations to a more manageable numbcr. Thc range ofmeasure costs in cach ofthe 27 bundles uscd in the development ol'thc DSM supply curves for the 2019 IRP are the same as those developed for the 20 I 7 lRP. Br.rndle dcvelopment began with the encrgy ctliciency technical potential idcntifled by the 2019 CPA. 'l'o account l'or the practical limits associated with acquiring all available resources in any given year, the technical potential by measure was adjusted to reflcct the amount that is realistically achievable over thc 20-year planning horizon. Consistcnt with the Northrvest Power and Conservation Council's aggressive regional planning assumptions, it rvas assumcd that 85 percent ol'thc tcchnical potential for discretionary (rctrofit) resources and on averagc up to 74 percent of' lost-oppomunity (new construction or equipment upgrade on Iailurc) could be achievable over the 20-year planning pcriod. T For Wyoming, the 2017 CPA applicd markct ramp rates on top ol'measurc ramp rates to rellect state-specific considerations aftecting acquisition rates, such as agc of programs. small and rural markets, and current dclivery intiastructure fbr the industrial market. 'fhis mechanism rvas uscd solely in the Wyoming industrial seck)r to rellect that program momentum is still building. Recent program accomplishments u,ithin this markct indicate that this trend has comc to an end, therelirre the "emerging" rnarket ramp ralc was removed fr<lm the 2019 CPA. For Oregon, the company does not assess potential for the Energy Trust ofOregon ( ETO). Neithcr PaciliCorp nor thc ET0 pertbrmed an econnmic screening of measures in the development ofthe DSM cncrgy efficiency supply curves used in thc dcvelopment of'the 2019 IRP, allowing resource opportunities to be economically scrcened against supply-side altcmatives in a consistent manncr across PacifiCorp's six states. 'fwenty-seven cost bundles were available across six states (including Oregon), which equates to 189 DSM energy ellicicncy resource supply curves. Table 6.9 shows the 20-year MWh potcntial fbr DSM energy efficiency cost bundles, designatcd by ranges of $/MWh. Tablc 6.10 shows the associated bundle price alter applying cost credits aflorded to DSM cnergy efficiency resources rvithin the model. Thcse cost credits include the firllowing: o A state-specific transmission and distribution investment def'enal cost crcdit (Table 6.8)o Stochastic risk reduction crcdit of $4.74lMWh8o Nofthrvest Pou,er Act l0-pcrccnt credit (Oregon and Washington rcsources only)e 7 Thc Northwest's achievability assurnptions include savings rcalized through improved codes and standards and market transformation, and thus. applying thcm lo identified technical potential rcprcscnts an aggressive view of what could bc achicvcd through utility DSM programs. 3 PaciliCorp developed this credit fronr two scts ol'production dispatch sirnulations ofa givcn resource portfolio. and each sct hi$ tNo runs \\'ith and *ithout DSM. One simulation is on dctcrministic basis and another on stochastic basis. Dilltrcnces in production costs belveen thc two scts ol'simulations determine the dollar pcr MWh stochastic risk reduction credit. D Thc lirrmula tbr calculating the $/MWh credit is: (Bundle pricc - ((First year MWh savings x nrdrkct valuc x l0%) + (|irst year MWh savings x T&D detcnal x lo%))/First year MWh savings. Thc levclizcd lbrward electricity price tbr thc Mid-Columbia markct is used as the proxy market value. I (r-1 PA( rFrCoR-P 2019 tRP CHAP I t.R 6 Rlis()t rRcE OPTto\s $4. t6Califbrnia $6.58 $ r 0.74 Oregon $4. r6 se.t0 $ r 3.36 Washington 54. l(r sil.79 $i 15.95 Idaho s4.16 sil.07 sts.22 [,rtah $4. t6 $9.02 sr3.l8 Wyoming $4. l6 $5.26 s9.41 Table 6.8 - State-s ecific Transmission and Distribution Credits The bundle pricc is the average levclizcd cost lor the group ofmcasures in the cost range, weighted by the potential of the measures. ln spccifying the bundle cost breakpoints, narrow cost ranges were defined for the lorver-cost resources to cnsure cost accuracy for the bundlcs considered more likely to be selected during the resource selection phase of the IRP. To capture the time-varying impacts of Energy Efficiency resourccs, cach bundle has an annual 8,760 hourly load shape specifying the portion ofthe maximum capacity availablc in any hour of the year. These shapes are created by spreading measurc-level annual energy savings over 8,760 load shapes, dif'ferentiated by state, scctor, market segment, and cnd use accounting lor the hourly variance of Energy Efficiency impacts by mcasure. These hourly impacts are thcn aggregated for all measures in a given bundle to create a single weightcd average load shape for that bundlc. 165 State Transmission Deferral Value ($i KW-year) Distribution Deferral Value ($/KW-year) Total <= l0 38,9 t 2 98,747 549.9t7 I ,41 8,505 210.292 394,1i I t0 - 20 I5,78 8 r09,045 7 6,449 llt,i99q oo)566,45 I i44,7I l 69.s02 68,27820-10 4,600 A1 ))R 693,9 | 7 30-40 3i,081 47 .387 6 t I,481 583,t73 166,070 25 t,490 40-50 I I,i5 l 24,007 {?? rq1 347 ,710 52,089 233,920 50-60 6,183 38,61 7 260.480 243,779 46,787 167,890 60 70 3,769 18,357 200, 163 126,e I 5 47 .964 7 4,670 70 80 7,788 8,17 3 168,229 187.482 29,400 30,877 80 90 )q5 l lt.i69 70,325 137 .014 24,985 t1.197 90 t00 4,346 14,246 I I,637 143,l5 I 23,308 4l,i59 100 1t0 4 l?R 7 .669 56,01 5 r 83,773 18,899 85,951 ll0 120 2,303 I 5, t95 39,623 136,567 14,302 20,700 l]0 l]0 15.688 25.4t9 13,8372,189 t3.926 86,346 r30 t40 I15,146 15,91510,391 7,160 93,739 6,266 140 - 150 7,600 4,996 62,573 t71,7 62 18,017 r 9,605 150 - t60 l,930 5,05 5 137,281 4i,708 13,759 9,608 160 - t70 |,947 9,360 33,284 46,478 10,014 6,732 170 - 180 2,458 2,396 7,) O{7 44.581 7,050 17,150 180 t90 t,723 r,843 15,798 I 1,791 r0,1i537 ,927 190 200 795 l,:r62 ) )0l1 20,928 4.69334,678 200 250 t4,14'7 1) lla ) o)d 56,428 44,598II5,84t 250 300 ,t.795 17,55510,007 8.i05 100,695 t9.324 300 400 t3,73t 4,220 I I,286I I,658 t70,t14 400 500 r,848 4,078 17,134 I1,6085 5,5 79 500 750 6,087 r0,509 46,965 l3 r,028 24,455 t2,672 750 1,000 \ 561 4,2 68 42,158 26.47 I 22,7',76 16.008 > I ,000 5.423 9,639 2l,631 r 10,459 23,582 ?9.420 CHAP I ER 6' RESoURCE OPI'IoNs Table 6.9 - 20-Ycar Cumulative llne Efficienc Potential b Cost Bundle NIWh 166 P,\( rr,r( oRP 2019IRI) Ilu ndle (lalifornia Idaho Oregon Utah Washington Wyoming ,1 Sqq 9,894 PA( rH(l)RP 2019 IRP ( ,^l,t I tt 6 Rr.s{)lr.r('r,OPIIo\\ Table 6.10 - Ene Efficien Ad usted Prices b Cost Rundle Distribution EIficiency PaciliCorp continues to evaluatc distribution encrgy el)iciency. 'l'he company's strcctlighl efficiency improvemcnts continue, rvith older mercury vapor, metal halide and incandescent company owned streetlights being replaccd with more efficient lights; high pressure sodiunr or light cmitting diode (LED) each year. The savings associated rvith this ongoing effort is cxpccted to be too small to lrarrant rcporling. PacitiCorp continues to develop its CYME CYMDIST(R) (porver florv soliware) investmcnt in ways that improve enginccring response time and, indirectly, distribution system el'ficiency. In the last biennial period, more than 300 large (Lcvel 2 and Level 3) distributed cncrgy resource (DER) applications were studied in CYME. This resulted in morc than 29 MW (nameplate) of approved <= l0 (.).00 0.00 0.00 0.0i)0.00 0.0i) t0 - 20 7.11 7.38 J./6 8.5 I 3.22 9.15 20-30 17.16 19.50 16.95 18.8i)l:t.09 19.8i) 30-40 30.89 26.09 2421 28.65 21.00 29.71) 37.37 30.92 36.97 32.09 3 8.6540-50 39.40 47.70 4'7.03 42.11 49. t050-60 4t\.22 56.1 I 55.1I 58.39 59.5860 70 5 {t.30 51.24 68.95 61.14 68.3 7 6t.77 68.3 I70-80 68.96 78.50 77 .7780-90 7 5.t9 75.41 71.98 77.34 86.9790 - 100 85.3 7 80.72 87.3 I 84. l4 89.22 97.72100-ll0 96.01 93.21 97.58 93.27 10t.60 il0- 120 106.63 106.27 t04.52 106. I l 102.29 t09.79 120 - 130 I16.57 I16.90 II1.8t 118.16 108.59 I t8.l9 130- 140 r28.80 128.48 |22.02 t26.21 122.26 I 29.5 I 140- 150 I36.45 t37.75 r 30.87 133.88 l3 I .34 137.11 150- 160 149.00 t49. l0 146.47 146.51 t4 t .99 145.73 156.75 I 55.37 150.50 158.40 t52.30 I 59.28160 - 170 170- 180 t67.97 167.t5 160.56 t67.95 I 63.07 l 68.15 180- 190 179.45 t75.72 174.23 177.40 110.44 I 78.5 r 190 - 200 I lt8.5l ft17.27 187.86 r 87.81 179.70 I 89.38 200 -250 226.03 203.75 221.72 2 I 3.95 209.13 225.45 250 - 300 272.36 272.99 266.1(t 264.04 260.89 2(t1.66 300 - 400 324.14 317.69 345.42 322.75 3 14.55 339.77 423.36 432.5t 402.40 .13 I .52 431.94 430.26400 - 500 655.21 6l 8.22 6l l.5t s83.68 5 76.48500 - 750 604.98 90-.r.i2 836.74 871.60 878.69 867.09 890.1 I750 - 1.000 4.1'70.84 3,473.6t I ,977.88 3,913.95 4,293.67 3,965.04> I ,000 167 Levelizcd Bundle Price aller Adjustmcnts ($/Mwh) Bundle California Idaho Oregon Utah Washington Wyoming 45.59 P^( lr,rCoRP-2019IRP C trAp rriR 6 Rr sol]l{(tiOptIoNs private generation across the company, Any energy savings resulting from these approvals across the service territory has not been determined. Neither ofthcse distribution energy cllicicncy rclated activities have becn modeled as potential resources in this IRP. As part of it 2019 lRP, PacifiCorp was successfully able to provide the SO model with the ability to view costs and transmission capability associated rvith certain transmission upgrades that thc modcl could incorporate along with new resource seleotions as it deemed optimal. This is an improvement liom previous lRPs, where transmission upgrades and associated costs had to be determined and accounted for posGportlblio development. New transmission modeling capabilitics include the endogenous consideration of l) new incremental transmission options ticd to resource selections, 2) existing transmission rights tied to ths use of post-retirement brownfield sites, and 3) incurporation ofcosts associated with these transmission options. Limitations of this approach include transmission options that interact with multiple or complex elcmcnts of the IRP transmission topology. Transmission options that are too complex to be captured by the modeling enhancements were therefore studied as sensitivity cases. Figure 6.7 illustrates the ne*'incremental transmission option modeling capability between two generic transmission areas in the IRP topology. Because the incremental transmission segment (shown in blue) is associated with new resource additions, the model selects thcm together, endogenously considering the upgrade cost in relation to the benefits of the new expansion resources. Figure 6.7 - IJndogenous Transmission Modeling Transmission Area "A"Transmission Area "B" Eristing tran5mission lncremental transmksbn ln many cases, transmission upgradcs do not add incremental transmission capacity to the system, but rather increase intcrconnqction capability. The upgrade cost in such cases is to accommodate additional capacity at a location, and the transmission topology itselfis unat-fccted. F'or example, additional transmission capacity or transmission reinforcements that arc confined to a transmission area incur an upgrade cost but would not add transnrission capacity to the larger system. A map of PacifiCorp's transmission system model topology is providcd in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). t68 Full up8rade Cost Existing Re5ource A1 l\lew ReSource A2 Ns Resource A3 Existing R6our(e Bl Eristing Rcsource 82 Transmission Resources I I Pcrlad r! (ltrr.hL ) b Alhny ae. Llo kl lld6oircin to:l AD6!} lEa t !l r.inI*..mnl AIEIJ.- arca lD RdschLry aBa 500 tV lnnsmksin Y.kitur rr.x lf, rL irinJ'ncrunr :010 YakiE .Ea to B..d .di 2i0 kv taBmasiM \\JlI] urln Jc.r ro YJlinr taerralq rmninN\$n lutS Vedford !rco ilxr.llo [v and ]r0 [v rciatlfr.mcnr Soud C. El a)(r'tJ ( ililmi, F-rurEr- Calesly segrum D :lA.rilit'poF ltr\ 50{ lv rraNnirsion litr) SoirEm ldrtn r.inlfrc.m.r EE.sy Garcqa_! r(loer D. I r widsbr - shr!) Blsh 1,10 kV lic ) l|l.l sdnhwgr \Yyoming !tod einfwe@nl tot6 Sepanrbn ol {huhle c iruuh 2i0 kv [.s, sdftru$ $,ldmhrrslhem t :hh arctrl0l li):r ti rp* Gdt $.t rtBnr r r^.d\ ( r*.r t{l) kv tBbmisim lixl t0] l(D]\dtEm lrlah 1r5lv thf@eme.r Uuhvdltt rrer l.l5'll8 kV and ll3 kv lrilrc ln(.tr'.trr IIhh V.lle) .r.r lli liS lv rcn LE{m€nl PA( rFrCoRP - 2019 IRP ('IAl,nitt 6 RLSoURCIi Op ] io\s Table 6,1 I - Transmission lnte tion O ns Location and Ca acl PacifiCorp and other utilities engage in purchases and sales of electricity on an ongoing basis to balance thc system and maximize the economic efficiency ol'por.r,er system operations. In addition to reflecting spot market purchase activity and existing long+erm purchase contracts in the IRP portfolio analysis, PacitiCorp modeled fiont office transactions (FOT). FO1's are proxy rr'sources, assumed to be firm, that represent procurcment activity made on an on-going for-u,ard basis to help the company cover short positions. As proxy resources, FO'ls represent a range ol'purchase transaction types. They are usually standard products, such as heavy load hour (HLH), light load hour (LLII), and supcr pcak (hours ending l3 through 20) and typically rely on standard enabling agreements as a contracting vchiclc. FOT prices are determined at the time of the transaction, usually via an cxchange or third party broker, and are based on the then-current forward markct price for power. An optimal mix ol'these purchases would includc a range ofvolumes and terms fbr these transactions. t69 Tablc 6. I I repofis the endogenous incremental transmission options includcd in the 20 | 9 IRP. Increment Market Purchases rtf(.rcd lnpohsr r.rtG, D.scrt,tio. nr lnl(sHlion P^crr,rCoRP - 2019 tRP Cr IAPTER 6 - RF.s(n JRCE C)PTroNS Solicitations for FOTs can be made years, quarters or months in advance, however, mosl 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. Scasonal transactions are typically delivered during quartcrs and can be available tiom onc to three years or more in advance. The terms, points oldclivery, and products will all vary by individual market point. Three FOT types rvere included lbr portfolio analysis in the 2019 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 PacitiCorp at a constant delivery ratc over all the hours of a year. 'l he HLH transaotions represent purchases received l6 hours per day, six days pcr rveek for July and December. Tablc 6.12 shows the FOT resourccs included in the IRP modcls, identifying the market hub, product type, annual megawatt capacity limit, and availability. PacifiCorp develops its FOT limits based upon its activc participation in w'holesale porver markets, its view ol-physical delivery constraints, market liquidity and market depth, and with consideration ol'regional resource supply (see Volumc II, Appendix J for an assessmcnt ol westem resource adcquacy). Prices lor FOT purchases arc associated rvith specific market hubs and are set to the relevant fonvard markct prices, tirne period, and location, plus appropriate wheeling charges, as applicablc. Additional discussion ol'how FOTs are modeled during thc rcsource portfblio development process of the IRP is includcd in Volume I, Chapter 7 (Modeling and Portfirlio Evaluation Approach). Table 6.12 - Maximum Available Front OIfice Transaction anti Market Hub Mitl-Colambia (Mid-C) Flat Annual ("7x24") or Heavy Load Hour ("6X 16") Heavy Load Hour ("6X I 6")3'7 5 400 375 .+00 California Oregon Border (COB) Flat Annual ("7x24") or Heavy Load Hour ("(rX 16") 250 250 Nevada Oregon Border (NOB) lleavy l-oad Hour ("6X 16") 100 100 Mons Heavy Load Hour ("6X 16") 300 300 170 Market Hub/Proxy FOT Product Type Available over Study Period Megarrvatt Limit and Availability (Mw) Summer (Iuly) Winter (December) PACTITCORP 20l9lRP CHAPI.F,R 7 - MODELING AN*D PORTTOLIo EVAI,I]A I'I0N N PPROACH CHlp'rsn HlGuLlcttrs The Integrated Resourcc Plan (lRP) modeling approach is used to assess thc comparative cost, risk, and reliability attributes of resource portlblios. The 2019 IRP modeling and evaluation approach consists ofthree basic steps uscd to select a pref'ened portfblio-coal studies, portfolio development, and Iinal portfolio screening. PacifiCorp uses the System Optimizer (SO) model to producc unique resource portfolios across a range ofdiflbrent planning cases. Informed by the public-input process, PacitiCorp ultimately produced over 50 diftercnt resource portfolios, informed by the coal studies summarized in Volume Il, Appendix R (Coal Studies). Each resource portfolio is unique rvith regard to the type, timing, location, and amount ofnerv rcsources that could be pursued to serve customers ovcr the ncxt 20 years. PacifiCorp uscs thc Planning and Risk model (PaR) to perform stochastic risk analysis of the portfolios produced by the SO model. For top-pcrtbrming resource portfolios, PaR studies were developed to evaluate cost and risk among thrcc natural gas price scenarios (low, medium, and high) and thrce carbon dioxide (CO:) price scenarios (zcro, medium, high). An additional price-policy scenario rvas developed to evaluate pcrtbrmance assuming a CO: price signal that aligns with the social cost ol'carbon. Taken together, there are lour distinct price-policy scenarios (medium gasimedium CO:, high gas/high CO:, lorv gaslzero CO:, and the social cost of carbon). The resulting cost and risk metrics are then used to compare portfolio alternatives and infbrm sclcction ol'the preferred portfolio. Taking into consideration stakeholder comments rcccivcd during the public-input process, PacifiCorp also developed eight sensitivity cases designed to highlight the impact of specific planning assumptions on fulure resource selections along rvith the associatcd impact on system costs and stochastic risks. Thesc scnsitivities are informative in nature and suppon development of an acquisition path analysis, but were not considered for selection ol'the prcf'erred portfblio. lnformed by comprehensive modcling, PacitiCorp's prelerred portfolio selection process involves evaluating cost and risk metrics reported from PaR, comparing resource portfblios on the basis ol' expected costs, low-probability high-cost outcomes, reliability, CO: emissions and other criteria. IRP modeling is used to asscss thc comparative cost, risk, and reliability attributcs of difl'crent resource porttblios, each meeting a target planning reserve murgin. These portfolio attributes form the basis of an overall quantitative portlirlio performance evaluation. The first section of this chapter describes the screening and evaluation processes lor portfolio selcction. Following sections summarize portlolio risk analyses, document kcy modeling assumptions, and dcscribe how this inlbrmation is used to select the preferred portfolio.-the last section of this chapter describes the cases examined at each modcling and evaluation step. The 111 CsaprnR 7 - MooSLING AND PoRTFoLIo EvaluauoN APPRoACH Introduction PACTFTCoRP - 2019 IRP CIhPTER 7 M0DEI.IN(i N ND PORI.T.oLIo EVALUATIoN APPRoACH results of Pacificorp's modeling and pofttblio analysis are summarized in Chaptcr 8 (Modeting and Portlblio Evaluation Approach). Figure 7.1 summarizes the three modeling and evaluation steps fbr the 2019 lRP, highlighted in green. The three stcps are (l) coal studies, (2) portlolio development, and (3) the final portfolio screening. Thc result ofthe final screening step is selection olthe prefened portfolio. re 7.1 - Portfolio Evaluation Ste s within the IRP Process Kc1 I'lannirg \srrrntptiorrr lrrrd I nccrtairrt u. l.oad & llc'oLtre. lllt lrtrtre Itcrorrrcc l'or t1i, Lirr I )L\ e [)l)r)].rll l'rclirrcti llortlirlio S('l('cliur (oal Studics llctilcrrrlrrt '\ssLrnrpl iorrs L arrrlidrlu Irlrtli)lio\ l\ft i,lio l)r\cl(rIllldrl 1 172 Modeling and Evaluation Steps llcliabilitr ( Lr't irrtri ll i.l \rr.rlr. . l'ort lirlio Scl(cron Act io r l'lirn Preferred Portfolio CIIAP IT-R 7 M0I)TI,IN(; AND PoRI I:oI-Io EVAI-I]A 1.1()N APPROACII For each modeling and cvaluation step, PaciliCorp developed unique resource portfolios, analyzed cost and stochastic risk metrics for each portfblio, and selected, based on comparative cost and risk metrics, the specific portfolios considercd in the next modeling and cvaluation step. The outcomcs ol-each can inlbrm the need lbr additional studies to test or refine assumptions in a subsequcnt screening analysis. The basic portfolio evaluations rvithin each step are highlighted in orange in Figure 7.I above and include: Resource Portfolio f)evelooment All IRP models are coniigured and loaded with the bcst available inl'ormation at the time a modcl run is produccd. This infbrmation is fed into the SO model. rvhich is used to produce resource portfolios rvith sufficient capacity to achieve a target planning rcserve margin. Each resource poftfolio is uniquely characterized by thc type, timing, location, and amount ol'new resources in PacifiCorp's system over time. Reliabilitv Assessmcnt The 2019 IRP adds a reliability asscssment phase to its portfolio processing, accounting fbr demonstrated reliability shortfalls driven by the replaccment of flexible, dispatchable rcsourccs with intermittent variable resources. The reliability assessment uses up to l6 PaR deterministic modcl runs to asscss hourl)' capacity shortfalls for years 2023 through 2038. 'Ihis information is then used in the SO model to optimize the selection ofadditional reliability resources. Cost irnd Risk Analysis Resource portfolios developed by the SO model are simulated in PaR to produce metrics that support comparative cost and risk analysis among the different resource portfolio altcrnatives. Stochastic risk modcling of resource portlolio alternatives is perlirrmed using Monte Carlo sampling of stochastic variables across the 20-year study horizon, which include load, natural gas and u,holesale electricity prices, hydro generation, and unplanned thermal outages. a Portlblio Selection The porttblio selection process is based upon modeling results tiom the resouroe portfolio development and cost and risk analysis steps. The screening criteria are based on thc present valuc revenue requirement (PVRR) ol system costs, asscssed across a range of price-policy scenarios on an expected-value basis and on an upper+ail stochastic risk basis. Portfirlios are ranked using a risk-adjusted PVRR metric, a metric that combines the expected valuc PVRR with upper-tail stochastic risk PVRR. The final selcction process considers cost-risk rankings, robustness of pcrtbrmance across pricing scenarios and other supplcmental modeling results, including reliability and CO: emissions data. Resource expansion plan modeling, pcrfbrmed with the SO rnodel, is used to produce resource portfblios rvith sufficient capacity to achieve a targct planning resene margin over the 20-ycar study horizon. Each rcsourcc portfblio is uniquely characterized by thc typc, timing, location, and amount of new resources in PacifiCorp's system over time. These resource portfblios rcllect a combination ofplanning assumptions such as resourcc rctirements, CO: prices, rvholesale power and natural gas prices, load growth net of'assumed privatc gcncration penetration levels, cost and performance attributes ofpotential transmission upgrades, and new and existing rcsource cost and 173 PACrr,rCoRP - 2019 IRP Resource Portfolio Development P^( rrrcoRP l0l9IRP cltAl,l 1.lt 7 N10l)lll l\(i A\t) PoRl I (]t Io llvAI tr,\ I t()\.API,RoA( t1 pcrformance data, including assumptions for new supply-sidc resources and incremental demand- side resources (DSM). Changes to these input variables cause changes to the resourcc mix, which influences system costs and risks. System Optimizer 'l'he SO rnodel operates by minimizing operaiing costs fbr existing and prospective ncw resources, subjcct to systcm load balance, reliability and othcr constraints. Over the 20-ycar planning horizon, it optimizcs rcsource additions subjcct to resource costs and capacity constraints (summer peak loads, rvinter peak loads, plus a targct planning resene margin fbr each load area represcntcd in the model). In the event that an early retirement ol'an existing generating res()urce is assumed for a given planning sccnario, the SO nrodel will sclcct additional resources as rcquired to meet summer and winter peak loads inclusive ofthc targct planning rescrve margin. To accomplish these optimization objectives, the SO modcl pcrforms a time-ol:day lcast-cost dispatch for existing and potential planned generation, while considering cost and perfbrmance ol' existing contracts and nerv DSM altematives rvithin PacifiCorp's transmission system. Resourcc dispatch is based on a representalivc-rvcek method. Time-ol:-day hourly blocks are simulatcd according to a user-specified day-type pattem representing an entire rveek. Each month is represented by one rveck, and the model scales output rcsults to the nurnber oldays in the month and then thc number of rnonths in the year. Dispatch also determines optimal electricity flons betwccn zone-s and includes spot markct transactions for system balancing.'l'he model minimizcs thc system PVRR, rvhich includes thc net present value cost of cxisting contracts, spot market purchase costs, spot market sale revenLies, generatiun costs (f'uel, fixed and variablc opcration and maintenance, decommissioning, cmissions, unserved energy, and unmet capacity), costs of DSM resources, anrortized capital costs for existing coarl resourccs and potential nerv rcsources, and costs fbr potcntial transrrission upgrades. T'he SO model is also uscd in developing the reliability portfolio for each case, recciving reliability requircments determined by the PaR model as dcscribed in Volume ll, Appendix R, Figure R.l (Coal Studies), applies tu all resourcc portfolio-development in thc 2019 IRP. Transmission System PacifiCorp uses a transrnission topology that captures major load ccnters, generation resources, and market hubs intc-rconnected via firm transmission paths. Transl'er capabilities across transmission paths are based upon the Iirm transmission rights ofPaciliCorp's merchant lunction, including transmission rights fiom PacifiCorp's transmission function and other regional transmission providers. Figure 7.2 shor.vs the 20 | 9 IRP transmission system model topology. t74 Sto 2019 tRP Transmission IRP Topology CIE ? ItrE CHAPTER 7 MoDII-lN(i ANr) PoR'r Fol to EvALuAIIoN AppRoA( Figure 7.2 - Transmission System Model 'I-opology I t rE9 Is II9fM Is ? lF.q coBIE lroE-:9 ?IE E Is IE _T ?.- I c-.,,.t-. QPd.hddsaeMa,i*ED cmt -rs/Exch..ses I JN \ S=Sumq. t rW br H=tleavy tdd HR L.LAI Loe *s Transmission Costs In developing resource portfblios fbr the 2019 IRP, PacitiCorp includes new modeling to endogenously select transmission options, in consideration of relevant costs and benefits. 'fhese costs arc influenced by the type, timing, location, and amount of new resources as well as any assumed resource retirements, as applicable, in any given portfolio. Additional details on endogenous transmission modeling are provided in Volume l, Chapter 6 (Resource Options). Resource Adequacy Resource adequacy is modeled in the portlblio-development process by cnsuring each portfolio meets a target planning rcserve margin. In its 2019 lRP, PacifiCorp continues to apply a I 3 percent target planning reserve margin. The planning reserve margin, rvhich influcnces the need lor new resourccs, is applied to PaciliCorp's coincident system peak load forecast net of of}'setting "load resources" such as energy ef'ficiency. Planning to achieve a l3 percent planning reserve margin ensures that PacifiCorp has sufficient resources to meet its peak [oad, rccognizing that there is a possibility lbr load fluctuation and extreme weather conditions, fluctuation ofvariable gcncration resources. a possibility tbr unplanncd resource outages, and reliability requirements to carry sulflcicnt contingency and regulating reserves. Volume I[, Appendix I (Planning Reserve Margin Study) summarizcs PacitiCorp's updated planning reservc margin study that supports selection ol a l3 percent target planning reserve margin in the 2019 IRP. 175 PACII.I(l)RP _ 20 I9 IRP New Resource Options Dispatchable l'hermal Resources Front office transactions (FO'fs) represent short-tcrm firm market purchascs for physical delivery of'power. PacitiCorp is active in the wcstcm rvholesale pow,er markets and routinely makes short- tcrm firm market purchases tbr physical deliveries on a lbru'ard basis (i.e., prompt month fonvard, balance ofmonth, day-ahcad, and hour-ahead). Thcsc transactions are used to balance PaciliCorp's systcm as market and systern conditions become more certzrin R'hcn the tirne between an ctl-ective transaction date and real timc delivery is reduced. Balance olmonth and day-ahead physical lirm market purchascs are mosl routinely acquircd through a broker or an exchange, such as the lntcrcontinental Exchange (lCE). Hour-ahead transactions can also be made through an cxchange. For these types of transactions, the broker or the exchange provides a oompctitive price. Non- brokered transactions can also be used to makc firm market purchases among a rvide rangc ol lonvard delivery periods. From a modcling perspective, it is not f-casible to incorporate all of the short-term lirm physical power products, which dill.:r by delivery pattem and delivcry period, that are available through brokers, exchangcs. and non-brokered transactions. Ilowever, considcring that PaciliCorp routinely uscs thcse types ol firm tr.rnsactions, u,hich obligate the scllcr to back the transaction with reserves when balancing its systcm, it is irnportant that thc capacity contribution of short- term firm market purchascs are accor,ulted lor in thc porttblio-developme nt process. I.or capaeity optimization modeling, short-tenn lirm tbrward transactions are rcpresented as FOTs and contigured in the SO rnodel uith cithcr an annual flat, summcr-on-peak (July), or u'intcr on-peak (December) delivery pattcm in every year ofthe trventy-ycar planning horizon. As configured in SO, FOTs contribute capacity torvard meeting thc 2019 IRP's l3 percent target planning rescrvc margin and supply systern energy consistent rvith the assumed FOT delivery pattem. Unlike FOTs, system balancing transactions do not contribute capacity toward meeting the l3 pcrccnt target planning reserve margin. System balancing transactions include hourly oftsystem sales and hourly off-system purchascs, representing nrarket activities that lninimize systcm energy costs as part ol'the cconomic dispatch of system resources, including encrgy from any FOTs includcd in a rcsource portlolio. 176 P^( r|rcoRP l{)l() IRP CIIApl1,R 7 l\,lur)r r r\(iANDPoR .or.lo EvAr.(r,\rioN AppRo^crr 'l he SO nrodel pcrtbrms tirne-ofl-day least cost dispatch ol'exisling and potential nerv thermal resources Io mcet load u'hile minimizing costs. Dispalch costs applicable to thermal resources include tuel costs, non-lirel variable operations & maintcnance (VOM) costs, and the cost ol' omissions, as applicablc. For existing and potential ncw dispatchable thcrmal resources, the So model uses generator-spccific inputs lbr fuel costs, VOM, heat rates, cmission rates, and any applicable pricc for emissions to establish the dispatch cost of each generating unit fbr each dispatch interval. Thermal resourccs are dispatched by least cost merit order. The powcr produced by these resources can he uscd to rneet load or to make olf:system sales at times when resourcc dispatch costs fhll below market prices. Converscly, at times when dispalch costs exceed market prices, ol1'-systcm purchases can displacc dispatchable thermal generation to minimizc system energy costs. Dispatch ol' thermal rssources reflects any applicable transmission constraints connecting generating rcsourccs rvith both load and markct bubbles as delined in the transmission topology for the modcl. Front Offi ce -l'ransactions PACTncoRP - ?019 lli.l' Energy Efliciency (Class 2 DSM) rcsources are characterized with supply curvcs that represent achievablc tcchnical potential of the resourcc by state. by year, and by measurcs spccific to PacifiCorp's sen,ice territory. For modeling purposes, thesc data are aggregated into cost bundles. Each cosl bundle of'the energy elficiency supply cun'cs spccilies the aggregate energy savings profile ol-all measures included within the cost bundle. Each cost bundle has both a sunrmer and winter capacity contribution bascd on aggregate energy savings during on-pcak hours in.luly and December aligning with periods rvhere PacifiCorp is most likely to exhibit capacity shortthlls. Demand Responsc (Class I DSM) rcsourccs, representing direct load control capacity resources, are also characterized rvith supply cun es rcprcscnting achievable technical potential by statc and by year for specific direct load sontrol program categories (i.c., air conditioning, irrigation, and commercial curtailment). The SO model evaluates demand rcsponsc resources by considering capacity contribution, cost, and opcrating characteristics. Operating charactcristics include variables such as total number of hours per year and hours per event that the demand response resource is available. Additional discussion ofDSM resourccs modeled in the 2019 IRP is included in Volume I, Chapter 6 (Rcsourcc Options) and in Volurne tl, Appcndix D (Demand-Side Management Rcsources). Wind and Solar Rcsources Ccrtain rvind and solar resources are dispatchable by the rnodcl up to fixed energy profiles that vary by day and month. The hxed cncrgy proliles lor wind and solar resources rcprcscnts the expected generation levels in rvhich half of the timc actual generation would fall below expected levels, and half of'the time actual generation would bc above expected levels assunring no curtailments. The capacity contribution of rvind and solar resources, rcprcscnled as a percentage of resource capacity, is a mcasure ofthe ability tbr these rcsources to reliably meet denrand over time. These values are dependent on the underlying portlolio, and are cxpcctcd to decline as the penetration of resourccs of thc samc type incrcascs. Forlhe purposes ofponfolio selection, PacitiCorp developed capacity-contribution values specific to the flve wind profiles and five solar profi les used tbr proxy resources. In addition, PacifiCorp developed contribution valucs fbr two levels of'wind and solar penetration. A "high" capacity-contribution block allowed for up to 2,000 MW of ncrv wind capacity and 1,000 MW of nerv solar capacity (roughly a 50 percent increase from the initial portfblio levels). Any additional rvind and solar capacity beyond thc first block uas assigned a "lorv" capacity-contribution value, calculated based on an additional 2,000 MW of ncrv rvind capacity and 1,000 MW of nerv solar capacity. PacifiCorp also developed capacity-contribution valucs fbr each ol'the wind and solar locations when combined with lithium-ion battcry storage CIIAPTER 7 _ MoI)I]I,I\(i A\I) PoRTFOI-Io EVAI-TIAI'IoN APPRo,^CII A description of [iO'l linrits assurred in the 2019 IRP is includsd in Volume I, Clhapter 6 (Resource Options). PacifiCorp's evaluation of resource adequacy in the westem power markets is summarized in Volume II, Appendix J (Western Resource Adcquacy Evaluation). Demand-Side Manaqement Thc SO model can sclecl incrcmcntal DSM resources during portfblio optimization development in each modcling and evaluation stcp. Sclcction of DSM resources is made from supply curves that define how much ofa DSM resource can be acquircd at a given cost. t11 P^crflCoRP 20lg IRP CtitprI,R 7 M(n)l,t.tN( i .,\Nr) PoR rror.io EVAI.r .\ lloN AppRo..\ct l Energy storage resources arc distinguished lrom other resources by thc follorving three attributes: . Energy takc gcneration or extraction ofenergy liom a storage reservoir;. Energy rcturn - energy used to fill (or charge) a storagc rcservoir; and. Storagc cyclc efficiency - an indicator of'the energy loss involved in storing and extracting cnergy ovcr the course ofthe take-retum cycle. Modeling energy storage resources requires specification ol'the size of the storage reservoir, defined in gigawatt-hours. 'Ihe SO model dispatches a storagc resource to optimize energy used by the resource subject to constraints such as storagc-cycle efficiency, the daily balancc of take and retum energy, and lirel costs (fbr cxample, the cost ofnatural gas lbr expanding air with gas turbine expanders). To detcrmine the least-cost resource expansion plan, the SO model accounts fbr conventional gcneration system perlirnnanoe and cost characteristics of the storage resourcc, including capital cost, size ol the storage and time to flll the storage, heat rate (il' fucl is used), operating and maintenance cost, minimum capacity, and maximum capacity. Bccausc they are energy-limited, an energy storage rcsourcg rnay not be able to cover the entirety ofan extended outage. For thc 20 l9 lRP, PacifiCorp calculated capacity contribution values based on the duration ofenergy storage. Volume II, Appendix N (Capacity Contribution Study) summarizes thc capacity contribution study and the resulting values for energy storagc. Capital Costs and End-Effects The SO model uscs annual capital recovery factors to convert capital dollars into real levelized revenue requirement costs to address end-efl'ects that arisc rvith capital-intensive projects thal have different lives and in-service dates. Al[ capital costs evaluated in the IRP are convcrted to real levelized revcnuc requirement costs. Use of real levelized revenue requirement costs is an established and preferred methodology lbr analyzing capital-intensive resource decisions among resource altematives that have uncqual lives and/or when it is not feasible to capturc operating costs and benctlts over the entire life of any given resource. To achieve this, the real levelized revenue requirement method spreads the retum of invcstment (book depreciation), rctum on investment (equity and debt), propcrty taxes and income taxes over the lile ofthc invqstment. The result is an annuity or annual payment that grorvs at inflation such that the PVRR is identical to the PVRR ofthe nominal annual requirement rvhen using lhc same nominal discount rate. For the 2019 IRP, the PVRR is calculated inclusive ofreal lcvclized capital revenue requircmcnt through the end ofthe 203ti planning period. Ceneral Assumptions Studv Period and Date flonventions PaciliCorp cxccutes its 2019 IRP models for a 2l-year period beginning January l, 2019 and ending December 3 l, 2038. Future IRP resources reflected in modcl simulations are given an in- service date ofJanuary 1't ofa given ycar, rvith the exception ofcoal unit natural gas conversions, t78 rvith a maximum output equal to 25 percent ol'the renewablc resource nameplate capacity and assuming a tbur-hour storage duration. Volumc II, Appendix N (Capacity Contribution Study) summarizes PacifiCorp's capacity contribution study and the resulting values. Energy Storaqe Resources P.\cr,lCoRP l0l9IRP CI I,\P IT,R 7 - MoI)},I,IN( i A\I) PoRTFOLIO EVAI T I IIoN APPRoACI{ which are given an in-servicc datc ol'June lst of a given year, recognizing thc dcsired need lbr these altcmativcs to be available during the summer peak load period. Inflation Rates 't'he 2019 IRP model simulations and cost data reflect PaciliC'orp's corporate inflation ratc schedule unless otheruise noted. A single annual escalation rate value of2.28 percent is assumed. The annual escalation rate rellects the average of annual inflation rate projections lirr the period 2019 through 2038, using PacifiCiorp's September 2018 inflation curve. PacifiCorp's inllation curve is a straight average offorecasts fbr the Cross Domestic Product inflator and the Consumcr Price Index. Discount Factor The discount rate used in presenl-value calculations is bascd on PacifiCorp's alier-tax weighted average cost ol'capital (WACC). The value used for the 2017 IRP is 6.92 pcrccnt. The use ofthe after-tax WACC complies with thc Public Utility Commission of Oregon's tRP guideline la, which requires that the after-tax WACIC be used to discounl all I'uture resource costs.r PVRR Iigures reported in the 20l9lRP are reported in January 1,2019 dollars. CO2 Price Scenarios PacitiCorp uses lbur diffbrent CO: pricc scenarios in the 2019 IRP zero, medium, high, and a price forecast that aligns rvith the social cost ofcarbon. The medium and high scenario are derived Iiom expert third-party multi-client 'trff+he-shelf' subscription services. Both of these scenarios apply a CO: price as a tax beginning 2025. PacifiCorp initially proposed using a medium CO: price forecast bcginning in 2030, consistent with the start year assumed by the third-party fbrecast reviewed, but in response to stakeholder interests, PacifiCorp agreed to align the start year in the medium case with the start year proposed firr the high case (2025). Figurc- 7.3 summarizes the CO: price assumptions used in the 2019 tRP (thc zero price, no CO: scenario is not shorvn). I Public Utility Comm ission of Oregon. Order No. 07-002, Docket No. U M I 056, January tl, 2007 179 S12o S11o Sroo seo S80 S7o 56o Sso S4o s30 S2o S1o so ".f "&"di"dP"dP"6F"dFd,"""d,s,""dF"sr""di."f"dP"e""d"e""dr "&""d,t ".p" +Medium +High +Societal Cost t.'ure 7.3 - COI Prices Modeled b Price-Polic Scenarios Wholesale Electricity and Natural Cas []orrvard Prices For 2019 IRP modeling purposes, eight electricity price tbrccasts were used: the ollicial lbrward price curve (OFPC) and seven scenarios. Unlike scenarios, which are altemativc spot price forecasts, the OFPC represents PacifiCorp's ofhcial quarterly outlook. The OFPC is compiled using market lbrwards, followed by a markct-to-fundamentals blending period that transitions to a pure f'undamentals-based forecast. At the time PaciliCorp's 2019 IRP modeling was initiated, the September 2018 OFPCI was the most current OFPC available. For both gas and electricity. starting with the prompt month, the front 36 months of the OFPC rellects market lbrw'ards at the close of a given trading day.2 As such, these 36 months are market fbrwards as ofSeptember 28, 201 8. The blending period (months 37 through 48) is calculated by averaging the month-on-month market forward from the prior year with the month<rn-month fundamentals-bascd price from the subsequent year. The I'undamentals portion ol'the natural gas OFPC retlects an expert third-party multi-client "of1--thc-shelf' price fbrecast. Thc fundamentals portion of the electricity OFPC reflects prices as forecast by AURORAxvpT (Aurora), a WECC-wide market model. Aurora uses the expert third-parly natural gas price forecast to produce a consistcnt clcctricity price forecast for market hubs in which PacifiCorp participates. PacifiCorp updates its natural gas price lbrecasts each quarter lor the OFPC and, as a corollary, the electricity OFPC is also updated. Scenarios pairing mcdium gas prices with altemative CO: price assumptions ret'lect OFPC tbrwards through October 2021 before transitioning to a pure Iundamentals forecast. Scenarios using high or low gas prices, regardless of'COz price assumptions, do not incorporate any markct fbrwards sincc sccnarios are designed to reflect an altemative view to that ofthe market. As such, the lorv and high natural gas price scenarios are purely fundamental lbrecasts. Low and high natural PACU.ICoRP-:019IRP ('lr,\pr r,R 7 \,1(n)r,l r\(i A\t) PoRTr.or-ro Ev^t tr,\ r roN nppR(r\( H r80 : The September 2018 OFPC prompt month is November 2018; Octobcr 2018 is "balance of month". r AURORAXMp is a proprietary production cost simulation model, developed by Energy Excmplar, LLC. P^c!.rcoRP-2019IRP gas price scenarios are also derived from expert third-party rlulti-client "ot}--the-shelf" subscription scrviccs. PacifiCorp's OFPC for electricity and each of its seven scenarios $,ere devcloped liom one of three (medium, low, high) underlying expert third-party nalural gas price forecasts in conjunction rvith onc of fbur CO: price sccnarios.a The September 20 I 8 OFPC does not assume any CO: policy or tax in conjunction rvith its medium gas price forecast. Ilow,ever, PacifiCorp's 2019 IRP "medium case" price forecast is not the OFPC but a scenario that couples medium gas rvith a medium CO: price, applied fbr lirrecasting purposes as a tax. Thus, the 2019 IRP mcdium case differs from that ofthe Scptembcr 201 8 OFPC by assuming a mcdium COz price starting in 2025. This medium CO: price serves as a proxy fbr a potential future CO: policy, whose implementation and design specifics are not known. Thc 2019 IRP rnedium CO: compliance assumption diflcrs liom that used in eithcr PacifiCorp's 2015 or 2017 lRPs. tn its 2015 IRP PaciliCorp's OFPC incorporated the U.S. Environmental Protection Agency's (L.PA's)s proposcd Clcan Power Plan ((:PP) rule to improve CO: emissions pcrtbrmance rates lor alfected poi.r,er plants..l'o reflect thc CPP in Aurora, PacifiCorp applied state emission ratc constraints in thc modcl. assuming energy eflicicncy goals assumed by EPA in its calculation of state emission rate targcts. Upon finalization of thc CPP, and in its 2017 IR-P, PaciliCorp's OFPC fbr electricity and each of its six scenarios were developcd fiom one o['three (low, medium, high) underlying expert third-party natural gas price lorecasts in conjunction rvith one of thrcc CO: compliance dcsigns tied to the C'PP. Ilut on March 28,2017, President 'Irump issued an Executive Order directing the EPA to revien'the C'PP and, ifappropriate, suspend, revise, or rescind the CPP, as rvell as related rules and agcncy actions. Thus, essentially rcndcring the CPP an artifact ol'the Obama Administration. On June 19. 2019 thc EPA issued its Aflordable Cllcan Energy (ACE) Rule replacing the CPP. ACE does not set (lO: emission cuts by state but, instead, allows states to determine elliciency irnprovements. Figure 7.4 summarizes the eight rvholcsale electricity price lbrecasts and three natural gas price lbrecasts used in the base and scenario cases fbr the 2019 IRP. rZero CC)r mcdiutn (iO] price, high COr pricc. and a social based cost ol COl ' EPA: Environmcntal l'rotection Agency. CHAPTF,R 7 MoD[LIN(; A\D PORl.foI-I() EVAI.II,\'I.I0N APPRonCII l8t P^( ll.rC()RP ]0l9lRP CIIAPTIR 7 - MODELIN(i ANI) PoR I FoLIo IvAI-LTATIoN AppR(]A(:H l're 7.4 - Nominal Wholesale Electrici and Natural Gas Price Scenarios s9 s8 Es7E)OGc<g;i $3 s1 $- -l\tediur + Low +Hid + r_.ro..l Grs Pd..r Erra U.b $rr rslo + lvtol.$le Ele.ldrltr Pri.es Arerxge olPrloVerdr md rlrd-C (Flrl) - 1r:1 11r:l !.1 ,.l a-r !!,J a 1i! a! I: I a -M8as_oco: -.>M8as Mco: -.-M8as-Hco:+HEtS_MCO: {-Hsas HCOI .-9-L8as (rol -:-Lfas Mco: +M!6s sco' i, s- $80 360 t{0 $20 s t:0 slm Planning and Risk PaR uscs the same common input assumptions described for SO model with additional data provided by the SO model results (e.g., the capacity expansion portfolio including reliability resource additions). While the SO model supplies a capacity view developing an optimized portlblio for each case, PaR is able to bring the advantages of stochastic-driven risk metrics to the evaluation of the studies while also capturing additional operational considerations that the SO model does not asscs (i.e., operating reserve requircments). While PaR cost-risk metrics are ultimately used in the prelened portfolio selection, the SO model results can be infomative, especially in their role as a magnitude and direction indicator to compare to PaR outcomes. The stochastic simulation in PaR produces a dispatch solution that accounts lbr 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, rvhich includc: load, wholesale electricity and natural gas prices, hydro generation, and thermal unit outages. Wind and solar generation is not modeled with stochastic paramctcrsl horvever, the incretnental reserve rcquircments associated with uncertainty and variability in wind generation, as determined in thc updated flexible reserve study, are capturcd in the stochastic simulations. 182 and Risk Analysis PaR is also used to perform the hourly deterministic reliability assessmenls lbr each case, as described in detail in Volume tl, Appendix R (Coal Studies). The PaR reliability assessmcnt inlbrms sclection of reliability resources in thc SO model. Figure R.l (Reliability Studies Methodology Process), presented in Volume Il, Appendix R (Coal Studies) applies to all resource portli)lio developmcnt in the 2019 IRP. Cost and Risk Analysis Once unique resource portfolios are developed using the SO model, additional modeling is perlirrmed to producc metrics that support oomparative cosl and risk analysis among the diflerent resource portfolio ahernatives. Stochastic risk modeling of resource portlblio alternatives is performed u'ith PaR. E l',\( I r('()RP l0l9 IRP Cr rAp rriR 7 - M()r)rir.r\G AND PoRTFoLro EvAl"u^ltoN AppRo^(.lt PaciliC'orp's updated flexible reserve study is provided in Volumc II, Appendix F (Flexible Rcscrvc Study). The stochastic parameters used in PaR lor the 2019 IRP are developed rvith a short-run rrrean reverting process, uhereby mean reversion rcprescnts a rate at which a disturbed virriable returns to its cxpected valuc. Stochastic variablcs may have log-nonnal or normal distribution as appropriatc. Thc log-normal distribution is otlcn usqd 1o describe prices because such distribution is bounded on the low end by zero and has a long, asymmctric "tail" reflecting the possibility that prices could be significantly higher tlran the average. Unlikc priccs, load generally does not have such skcwed distribution and is gcncrally better described by a normal distribution. Volatility and mean rcvcrsion parameters are used tbr modcling thc volatilities ofthe variables, while accounting t'rrr seasonal ef-fects. Conelation measures how much thc random variables tend to move together. Stochastic Model Parameter Estimation Stochastic parameters are developed with cconomstric modeling techniques. '['he 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 deflncs the short run volatility, whilc thc rcgression coef'ficient for the AR(l) variablc defincs the mean revcrsion parameter. Loads and commodity prices are mean-reverting in the short term. Iror 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 responscs arc the essence ol' mean rcversion. Thc mean reversion rate tclls hovn' last a f<rrecast rvill revert to its expectcd mcan lbllorving a shock. The short-run regression errors arc correlated seasonally to capture inter- variable effects from informational exchanges between markets, inter-regional impacts liom shocks to electricity demand and dcviations liom expected hydroelectric generation pcrfbrmance. The stochastic parameters are used to drive the stochastic processes of the following variables: . Representative natural gas prices firr PacifiCiorp's east and west balancing authority areas;. Electricity market priccs tbr Mid-C, COB, Four Comers, and Palo Verde;o Loads lbr Calitbmia, ldaho, Orcgon, Utah, Washington and Wyoming regions; and. Hydro gcncration. Volume II, Appendix H (Stochastic Parameters) discusses the methodology on hou'thc stochastic paramctcrs lbr the 20l9lRP were dcvclopcd. For unplanned thermal outages, PaciliCorp assumes a unitbrm distribution around an expected rate. For cxisting units, the expectcd unplanncd outage rates by unit are based on its historical perhrnnance during the 4-year period ending I)ecernber 201-5. For ne\\,rcsources. the unplanned outagc ratcs are as spccified tbr thosc rcsourccs as listed in the supply-side resource tablc in Volurne I, Chapter 6 (Resource Options). 'l able 7.1 through Table 7.8 sLrmmarize updated stochaslic parameters and scasonal pricc conclations lirr the 201 9 lRP. ilt.l Short-Term Volatility CA/OR without Portland Portland It)UT WA WV 0.021 0.028 0.045 0.042 0.035 ID UT 0.053 0.037 Short-Term Mean Reversion CA/OR without Portland Portland 0.050 WA WY Winter 2019 IRI' Spring 2019 IRP Summer 2019 IRP 0.1'77 0.363 0.595 0.341 0. t94 0.280 0.2 l3 0.157 0.23 5 0.261 l) \( I rCoRP-l0l9lRl'CHAPI F,R 7 _ M()I)I,I-INC AND PoRTFoLIo EVAI-I]A I.I()N APPRoACH Table 7.1 - Short-Term Load Stochastic Parameters 0.016 Spring 2019 IRP 0.035 t).01 8 Summer 201 9 IRP 0.042 0.01 6 Fall l0l 9 IRP 0.042 0.043 I 0.01 7 0.204 0.095 I;all 20l9lRP 0.2t8 0.249 I 0.203 l'able 7.2 - Short-Tcrm Gas Price Parameters Winter 2019 IRP 0. 120 S nn 2019 tRP Summer 20 l9 IRP F all 20l 9 lRP 0.092 0.265 0.102 0.105 Fall 2019 IRP 0.071 0.107 Tahlc 7.3 - Short-Term Electrici Price Parameters 0.092 0.075 0.098 Winter 2019 IRP 0.125 0. 140 Spring 2019 IRP 0.434 0.551 0.55 l 0.463 tJ.zl I Short-Term Volatility East Gas West Gas 0.1il 0.039 0.025 0.036 0.044 West GasShort-Term Mean Reversion 0.110 0.1 52 Summer 2019 IRP Winter 2019 IRP Spring 2019 IRP Short-Term Volatility Four Corners COB Mid- Columbia Palo Verde 0.098 0. 104 0.155 Winter 2019 IRP Spring 201 9 IRP Summer 201 9 IRP Fall 201 9 IRP 0. 102 0. 166 Short-Term Mean Reversion Four Corners COB NIid- Columbia Prrlo Verde 0.119 0.2I I t84 Fall 20l9lRP 0.3 70 0.257 0.219 0.41 5 Winter 20l 9 lRP 0.042 0.039 0.035 0.03 3 t).06-5 0.050 0.0-s l 0.039 0. t88 0. 153 0.1 8l 0.273 0.368 0.241 0254 0.257 0.242 0.06l 0.049 f,ast Gas 0. t34 0.261 0-475 0.300 0.213 0.141 0.t0l 0.1 03 0.il0 Summer 201 9 IRP 0.33 8 0.220 PA( rfrcoRP 20l9lRP Table 7.5 - S rrn Table 7.7 - Fall Season Price Correl:rtion Natural Gas East Four Comers COB Mid- Columbia Palo Verde Natural Gas West 0.629 1.000 COB 0.353 0.57(r 1.000 Mil - CotLmrbia 0.3 82 0.5 73 Pakr Verde 0.662 0.835 0.61 0 0.594 0.891 0.56'7 0.395 0.421 0.609 t.000 Natural Gas East Four Cornen COB Mid- Columbia Pakr Ve lde Natural Gas West 0.204 1.000 0.099 0.33 8 1.000 0.35 8 0.864 1.000Mid - Colunbia 0.069 Palo Verde 0.327 0.392 0.307 Natu-al Gas West 1.000 N atual Gas East Four Corners COB Mid- Columbia Palo Verde Natural Gas West N ahral Gas East r.000 Four Comers 0.052 1.000 COB -0.004 0.212 Mid - Colurnbia 0.024 0.848 1.000 Pakr Verde 0.506 1.000 Natural oas West 0.453 0.054 0.050 0.096 0.009 t.(x)0 N atural Gss East Four Cornen COB Mid- Columhia Palo \re rde Natural Gas West 1.000 0.r35 corl 0. 149 0.362 1.000 Mi{ - Cotumbia 0.t24 0.223 0.780 1.000 Palo Vcrde 0. 129 0.528 0.627 0.444 1.000 0.731 0.r00 0. 128 0. 133 0.066 1.000 185 ( I p tLR 7 Ivlotr,t.lN(i AND Poli U,ot.ro Lv,\r.r.A 1roN A ppt{o,^cll Table 7.4 - Winter Season Price Correlation Season Price Correlation Table 7.6 - Summer Season Price Correlation 1.000Natural Gas East Four Comers 0.942 1.000 t.000 N ahral (ias West t----_l Natural Gas East t.000 Fotn'C'omers corl 0.621 1.000 0.553 0.05 8 0.080 0.070 0.132 I -------r-----t I 1.000 0.290 -0.001 0.52 I 0.444 I -------r------ Natral Gas East Four Clomers 1.00t) N atural Gas West = f------T------- I,^CU ICoRP 20I9IRP CHAPI'I'R 7 _ MoD[LIN(j AND PoRlI.(II,I() EVALT]AIIoN APPRoACII Winter 20 l9 IRP 0.212 0.632 Spring 20 l9 IRI'0. 162 0.-501 Summer 2019 IRP 0. 168 L-5 l2 Fall 2019 tRP 0.10l 0.863 Table 7.8 - H ro Short-Tcrm Stochastic Figure 7.5 and Figure 7.6 show annual electricity prices at thc tjrst, loth, 25th, 5oth, 75th, 90th, and 99th percentiles fbr 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, diflerences between the first and 99th percentiles range from S21.64lMWh to $79.88/MWh during the 20-ycar study period. For Palo Vcrde electricity prices, the dift-erence between the lirst and 99th percentiles range liom $26.57lMWh to $99.34lMWh. t,'ure 7.5 - Simulated Annual Mid-C Electrici Market Prices 100.00 95.00 90.00 85.00 80.00 75.00 70.00 65.00 60.00 55.00 50.00 45.00 ,1o.00 35.00 30.00 25.00 20.oo +99rh +90th .-t- 75th -t+mean +25th + loth -lst -!. ^b -6 *1 -$1s, as, as' as, r:5' .q ^s ^\,ts' ",,$, "), f, ^a ^u ^h ^b ^^ ^$ ^q -s.r,s, ls, .us, ls, "r,s, -r,s, "rsv 1;sv as, Iti6 Short Term Volatilit\.'Short-Term Nlean Reversion P^( rfr('(nrP l0l9lRP C'IIAPTLR 7 _ M(NN.I,I\(i AND PORI'I:OI,IO ITVALTIATI0N APPR0A('I] F ure 7.6 - Simulated Annual Palo Verde Electrici Market Prices Figure 7.7 and Figure 7.8 shorv annual electricity prices at the first, l0'l', 25'l', 50tl', 75th, 90rh, and 991h pcrcentiles for west and east natural gas prices. For west natural gas prices, dilferences between thc first and 99'h percentilcs range liom S1.85/ Million British thcrmal units (MMBtu) to $7.22lMMBtu during the 20-year study pcriod. For east natural gas priccs, difl'erences between the first and 99!h percentiles range from $2.00/MMBtu to $7.64lMMBtu. F re 7.7 - Simulated Annual Western Natural Gas Market Prices 100.00 95.00 m.00 85.00 80,00 75.00 70.00 65.00 60.00 55.00 50.00 45.00 40.00 35.00 30.00 25.00 20.00 .q ^s ^\ ,,l'! ;\ ^u ^5 ^b A ^$ ^q *s ^\ {1, .3 ^u "5 ^b ^1 *$ 1s' "l,sv 1s,' 1s/ -rsv ns, "ls, rs, "l\"ts, ls, .ts, 1s, rs, "r,s, 1s, 1sr "rs, .l,s, ns/ +99th +90th +75th +mean +25th +10th --r-- lst 8.00 7.50 7.N 6.50 6.00 5.50 5.00 4.50 4.00 3.50 3.00 2.50 2.00 ,., "e".us,tr{P"-S.,$"*tr rs"r$ r{t""-f "s,""st rS"$ rs"r$ rs"d rs. +99th +90th +75th -+inr€an -x- 25th +loth -;-'lst 187 T- PACIr rCoRP - 2019 IRP CIIAPTER 7 MoI)I.I,IN(; AND PoRT[oLIo EVALU,{.TION N PPROACH Fi ur€ 7.8 - Simulated Annual f,astern Natural Gas Market Prices Figure 7.9 through Figurc 7.14 show annual loads by load area and for PaciliCorp's system at the Iirst, l0tr', 25'h, 50'l', 75'l',90rh, and 99'h pcrcentilcs based on a Monte Carlo simulation using short- term volatility and mean reversion parameters. For Idaho (Goshen) load, the annual dill'ercnccs between the first and 99tr' percentiles range from 192 gigawatt-hours (GWh) k) 348 GWh. For Utah load, the annual difference ranges liom 1,204 GWh to 2,772 GWh. For Wyoming load, the annual difference range liom 137 OWh to 271 GWh. For Orcgon/California load, annual ditlcrences rangc fiom 746 GWh to I,528 GWh. For Washington load, the annual dillbrcncc ranges from 3 I 5 GWh to 557 GWh. For PaciliCorp's systcm load, the annual difference ranges from 2,386 GWh to 4,354 CWh. ure 7.9 - Simulated Annual ldaho (ioshen Load .q ^S ^\ ^1 ;5 ^L ^i ^ro A ^$ ^q ^S ^\ ^1 $ ".0. "5 -b ^1 -$.rs' "rsv 1sv.us,.us, D" ns? 1s2 1sv 1sv 1sv ns, 1s, 1s, .rs, asr "rs, .rs, as/ .\rs, +99th + 90th +75th -l+mean -{(-25th +10th * lst 5 5 4 00 50 50 8.0 r 00_ 7.50 7.00 6.50 6.00 3.50 1.00 2.50 2.00 2.600 2.500 2.N0 2.300 F, 2-zoo 2.100 2.000 1.900 "$ "$ ^q as i {t ^3 "}. .5 -lr "$ -$"r,s,.r,s" rs" .u\, ,r), .us, "us, ,\/a, "r,\,.r,s, "!, r,s' rr r-- - +99th -I-90tb +75th -\+[rearr +251h +loth *-lst ^{o ^Sv"r\v.L\v /i, 1s" t.800 .9"S^\]],.rs' 1;s/ ,}s v 1\v r88 = F 37,000 36.000 35.0m 34.000 , r3-om() 32.000 31.000 30.000 29.000 ,.." drt ,$,' ,$ rs ,$ ,$ ,s" .|,s "$," ".sf ,s" ,et dl .si d|,$ ,e" ,$ ,s. +99th +90th +75th -X-rnean -F25th +loth *!-lst PA( rFrCoRP 2019 tRP CIIAp U.R 7 M(Dtil I\cA\DPoR ot.lo F:VALUATI0N AppRo^(lt Fi re 7.10 - Simulated Annual Utah Load ure 7.I I - Simulated Annual W llllll Load + 99th -+ 90th +75th -Euean +25t1 {b loth .*- lst 9..100 9.000 8.700 8.100 ^\, 8.400 +' 7.500 .q ^s ^\;L ^1 ^n^5 ^bA ^$as' 1se 1sv "Vs, "ts, *, "rsv 1sv lrsv 1\v *u 'vs'^,'',s" ,$ "..i" 189 7,800 +- P^CIFICoRP_20I9IRP CHAprlR 7 MoDEl,tN(; AND PoRTroLIo EvAr.tiA lloN AppRoACtl F ure7.12 - Simulatcd Annual O n/Calil'ornia Load ure 7.13 - Simulated Annual Washin n Load JJ, )- -,] I.>- --99rh ..f-90th +75ft -rhuleatr +25th {- loth -lst 00 12.000 t 1.500 11.000 10.5 00 10.000 _ , 13.000 -t2.5 s^\^\.n1s' 1sv 1s, "r\v ^U ^Lr ^ro A ^t, ^qn)' rS' .r,S' "rS' "rS' 1SP t ^svV aS,\rs' l,+.000 13.5 00 6.000 5.800 5.@0 5.,100 5.200 5.000 4.800 4.@0 4.400 4.200 .q ^s ^\ .ll :l ^L ^5 ^b .{\ ^q, ^q ^s .\ {t .1 -L "5 {ors' .vs, ls, "r,s, ls, .r,s" ,rlv 1s, "sv r,s, rs, ls, .vs, ls, .r,s, ls, .r,s, .vs, -a-99th -+90th +75th +nlear +25th +loth -|*" lst -rr) -'aL =7t- -: .-t_.D-(J a!',$. t90 PA( II,ICORP 20I9 IRP CIApt'l,R 7 Mot)F.t.tNC A\D Por{ rr or.ro Ev I t IAltoN ,AppRo^( Fi ure 7.14 - Simulated Annual S tem Load Figure 7.1 5 shows hydro generation at the flrst, I 0rh, 25'h. 50'l', 75th, 90'h, and 99'l' percentiles bascd on a Monte Carlo simulation using short-term volatility and mean reversion paramcters. PacifiClorp can dispatch its hydro generation on a limited basis to meet load and reserve obligations. The parameters developed for the hydro stochastic process approximate the volatility of hydro conditions as opposed to variations due to dispatch. The drop in 2021 is due to the assumed decommissioning olthe Klamath River projects. Annual differences in hydro gcneration between the first and 99rr' percentiles rangc fiom 253 GWh to 512 GWh. Fi re 7.15 - Simulated Annual H dro Generation -.F99th +90ti +75th + rean +25th +lorh -**lst 00 75.000 67.5 65,000 62.500 60.000 5 7.500 55.000 ^q 1s.:-"ts^r^5 ^b -1 ^$.rs, 1s, 1s, r,\, "r,s, r$, ls, rs, ",s, r,s, .q^s^\:'rA^u^l^bA^$ "l,s' "rs, 1s, 1rs/ 1s, 1$, .vs, n,! , "r,o, rs, 72.500 70.000 -q ^S ^\ .aL ;l, "!. ^5 ^lo A ^$ ^q "S +\ ^"\,.r,\' +s, ts, 1.s' "us' "ts' "r,s' "Ls' "ua' 1,s' 1,s' ns' 1s' .rs' +99th +mth +75th d{-(lc6tr .*-25th +loth +lst 3.,t00 4.400 4.200 4.000 - l8m - J.6oo 3.200 1.000 l9l :rF+ P^('ll,r('oRP ]019IRP CIL\pl ER 7 Nlot)t,t.t\G A,\"t) l'(n 'FUr.ro EvAI.( rA r()\ AtPIioA( rr Monte Carlo Simulation During model exccution. the PaR model makcs time-path-dependent Monte Carlo drarvs fbr cach sk)chastic variable based on input paramctcrs. 'fhe Monte Carlo drarvs are percentagc deviations Iiom the expected lonvard valuc of each variahle. Thc Monte C'arlo draws of the stochastic variables among all resourcc poftfolios modelcd are the sanre, which allows for a dircct comparison ol'stochastic results among all of the resource portlblios being analyzed. In the case ofnatural gas prices, electricity priccs, and regional loads, thc PaR model applics Monte Carlo draws on a daily basis. In thc casc ofhydroelectric gencration, Monte Carlo draws are applied on a wcckly basis. For the 2019 IRP. PaR is configured lo conduct 50 Monte Carlo itcrations for the 20-ycar study period. For cach ol the 50 Monte Carlo iterations, PaR gencrates a set of natural gas prices, elcctricity prices, loads, hydroclcctric generation and thcrmal outages. Then, thc model optimizes resource dispatch to minimize costs while meeting load and wholesalc sale obligations subjcct to operaling and physical constraints. In a 50-itcration sirnulation, the rcsource portlirlio is tlxed. 'l'he end rcsult ofthe Monte Carlo simulation is 50 production cost figures for the 2O-ycar study period rcllecting a rvide range olcost outcomes lor the portfblio. The expected values of the Monte Carlo simulation are the averagc result of all 50 iterations. Results fiom subsets ofthe 50 iterations are also summarized to capture 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 portfblio pcrformance, which are described below. Stochastic Portfolio Performance Measures Stochastic simulation results flor each uniquc resource portfolio arc summarized, enabling direct comparison among resource portlblio rcsults during the pref'ened portfolio selection process. The cost and risk skrchastic mcasures reported fiom PaR include: . Stochastic mean PVRR;o Risk-adjusted mcan PVRR;o Uppcr-tail Mean PVRR;r 51h and 95il' percentilc PVRR;. Average annual mean and upper{ail energy not served (ENS);o Loss ofload probability; ando Cumulative CO: emissions. Stochastic Mcan PVRR 'fhe stochastic mean PVRR is the average of system net variable operaling costs among 50 iterations, combined with the real levelized capital costs and fixed oosts taken from the SO model lbr any given resourse portlblio.6 The net variable cost liom stochastic simulations, expressed as a net present value, includcs system costs lor hrel, variable O&M, unit slart-up, market contracts, system balancing market purchases expenses and sales revenues, and ENS costs applicable rvhcn available resources fall short ol'load obligations. Capital costs fbr new and existing rcsources, taken from the SO model, arc calculated on an esoalated real-levelized basis. Othcr components in the stochastic mcan PVRR include fixed costs fbr ncw DSM resources in the ponfolio, also takcn liom thc SO model, and CO: emission costs fbr any scenarios that include a COr price assumption. " F ixed costs arc not all'ccled b) stochastic variablcs, and therclirrc. clo not changc across thc 50 l)al{ iterations t9l P^( rFrCoRP 20lg IRP Ctl^pt'tR 7 M(n)r1r rN(; A\D PoRTtiolto EvAt. i\ l.loN AppRoACtl Risk-Adiustcd PVRR Thc risk-adjusted PVRR incorporates the expectcd-value cost of low-probability, high cost outcomcs. This mL-asure is calculated as the PVRR ofstochastic mean system variablc costs plus [ive percent ol system variable costs tiom the 95th percentile. 'Ihc PVRR of'system lixed costs, Iaken from the SO model, are then added to this system variable cost metric. This metric expresses a lorv-probability portlblio cost outconle as a risk prcmium applied to the expcctcd (or mean) PVRR based on 50 Monte Carlo simulations fbr each resourcc portlblio. The rationalq bchind the risk-adjustcd PVRR is to havc a consolidated stochastic cost indicabr lor portfolio ranking, combining expected cost and high-end cost risk conoepts. Upper-Tail Mcan PVRR Thc upper-tail rnean PVRR is a measure of high-end stochastic cost risk.'['his measure is derived by identifying the Monte Carlo iterations with the three highcst production costs on a ncl presenl value basis. Thc portfolio's real levclizcd lixed costs, taken liom thc SO motlel, are added to these three production costs, and the arithmetic avcrage of'the resulting PVRRs is computed. 95th and 5th Pcrccntile PVRR The 5th and 95'l'percentile PVRRs are also reported liom the 50 Monte Carlo itorations. These measures capture the exlent ofupper-tail (high cost) and lorver-tail (low cost) stochastic outcomes. As described abovc, the 95th percentilc PVRR is used to derivc thc high-entl cost risk premium tbr Ihe risk-adjusted mean PVRR measure. Thc 5'h percentile PVRR is reported fbr inf'ormational purposcs. Production ( ost Standard l)eviat.ion To capture production cost volatility risk, PacifiCorp uses thc standard deviation ofthe stochastic production cost from the 50 Monte Carlo iterations. The production cost is expressed as a net present value ol'annual cosls over the period 2019 through 2038. This measure mects Oregon IRP guidelines to rcporl a stochastic mcasure that addresses thc variability of costs in addition to a measure addressing the severity ofbad outcomes. Averaqe and Uppcr- Iail Energy Nol Scrvcd Ce(ain iterations ol'a stochaslic sinrulation rvill have [.NS, a condition rvhere there arc insuftci!-nt resources, inclusive of system balancing purchases, available to mcet load or operating reserve rcquirements hecause olphysical conslraints. This occurs rvhen Monte Clarlo drau's ol'stoch:rstic variables rcsult in a load obligation that is higher than the capability ofthe available resources in the portfolio. I"or example, this rnight occur in Monte (larlo drarvs with large load shocks concurrent witlr a random unplanned plant outage event. Consequently, ENS, whcn avcraged across all 50 iterations, serves as a mcasurc ol'reliability that can bc comparetl among resource porttblios. PacifiCorp calculates an average annual value over the 2019 through 2038 planning horizon as rvcll as thc uppcr-tail ENS (average olthe threc itcrations u'ith the highest ENS). ln the 2019 IRP, ENS is nominally priced at $ 1,000/MWh. Loss of Load Probability 193 l'^(.lr,r(i)RP l0l9lRl'CHAP-II-,R 7 MODLLING A\D PORTFOI,IO FVAI.(IAIn\ APPROACII Loss of load probability (LOLP) rcports the probability and extcnt that available resources of a portfolio cannot scrve load during the peak-load period of July in the 20-year period. PacifiCorp repons I,OLP slatistics, rvhich are calculated liom ENS events that exceed threshold levels. Cunrul EmissionsIV Annual CO: emissions f'rom each portlirlio are rcportcd from PaR and summed lbr the twenty year planning period. Cornparison of total CO: cmissions is used to identify potcntial outliers anrong resource portfolios that rnight othsrwise be comparable rvith regard to expected cost, upper-tail cost risk. and/or ENS. Price assumptions firr each of thcsc scenarios are subject to shon-term volatility and mean reversion stochastic parameters u'hen used in PaR. Thc approach lor producing u'holesale electricity and natural gas price scenarios used fbr PaR simulations is identical to the approach uscd to develop price scenarios lor thc portfolio-developnrent proccss. Other PaR Modcling Methods and Assumptions Transmission Systcm Thc base transmission topology uscd fbr the SO model, shown in Figure 7.2, is identical to thc transmission topology used for PaR simulations. Any transmission upgrades selcctcd by the SO modcl that provide incremental translbr capability among bubbles in this topology are also included in PaR. Rcsource Adequacy l9.t Forward Price Curve Scenarios Top-perfbrming resource portfblios developed with the SO model during the porltblio- development process are analyzed in PaR *,ith up to Iour pricc-policy scenarios. The price curv'e scenarios are developcd fiom Pacifi(iorp's Septembcr 20 l8 OFP(:. PaR results using cach ofthese scenarios infbrm sclcction ofthe prel'ened portfblio. The rcsource poftfblio developed with the SO modcl, which tneets an assumcd l3 percent target planning reserve margin, is tixcd in all PaR simulations. With fixed resources, thc unit commitment and dispatch logic in PaR accounts lirr operating rcscn'e requirements. Thcse reserve recluircmcnts include contingency reserves, which arc calculated as 3 percent ol load and 3 percent olgcncration. ln addition, PaR rescrvr'rr.-quirements account for regulation reserves. PaciflCorp's regulation reserve assumptions are outlined in PacifiCorp's llcxiblc reserve study, providcd in Volume II, Appcndix F (Flexible Reserve Study), including PaR's use in the reliability assessment phase ol the portfolio-development proccss. Enerqy Storagc Resources Given the complexity ol Pacififiorp's system. the PaR modcl cxpcrienced difficultl optimizing the dispatch lor batter)' storage resources. 'l'o improl e upon this shortcorning in the PaR rnodcl, PacitiCorp developed and tcstcd a method to produce an optimized pcak-shaver'valley-fill profilc fbr these resourcc outsidc of PaR that is based on load net of wind, solar, energy elliciency resources, and private generttion rcsourccs in any given portfolio. Fixed liourly dispatch, charging, and opcrating reserves P^crIrcoRP-20l9lRP CHAp r r..R 7 - MoDELtNC AND PORTFoLIo EvAI.t 1A Iro\ AppRoACt I are entered as inputs Io PaR. This mcthodological enhance was presentcd and discussed with stakeholders at the March 2l , ZOl9 IRP public-input meeting. General Assumptions The general assumptions applied in the SO model for the study pcriod (20-years beginning 2019) annual inflation rates (2.28 percent), and discount rates (6.92 percent) arc also applied in PaR. Other Cost and Risk Considerations In addition to revierving stochastic PVRR, ENS, and CO: cmissions data from PaR, PacifiCorp considers othcr cost and risk mctrics in its comparative analysis of resource portlolios. 'fhese metrics include t'uel source diversity, and customer rate impacts. Customer Rate Impacts To derive a rate impact measure, PacifiCorp computes the percentage change in nominal annual revenue requirement from top performing resourcc porllblios (rvith lowest risk adjusted mean PVRRs) relative to a benchmark porllt)lio selected during thc linal preferred portfolio screening process. Annual rcvcnuc requircmcnt lbr these portfolios is based on the stochastic production cost results lrom PaR and capital costs reported by the SO model on a real levelized basis. The real levclized capital costs are adjusted to norninal dollars consistent \r'ith the timing of when new resources arc addcd to thc porttblio. While this approach providcs a reasonable representation of relative differences in projected total system rcvenue requirement among por-ttblios, it is not a prediction of future revenue requirement for rate-making purposes. Market Reliance To assess market reliance risk, PacifiCorp develops a scrics ol'portfolios designed to quantity the risk associated with relying on FOTs lbr a given portfolio. Thcsc studies apply a price scalar to market prices in the peak months ofJuly, August, and December. ln the SO modcl, FOTs include a premium to capture the risk ofprice spikes where the magnitude ofthese price spikcs arc based upon the variance between historical lbrr+'ard prices and actual prices from an historical period. This approach, which captures the severity and volume ol' potential high-price hours rvhile maintaining the shape ofthe undcrlying price curve. The final action in each modeling and evaluation step is portlblio selection. In the first step, to performing porttblios are identificd based on their relative perfbrmance with regard to mean system costs, risk-adjusted system costs, which account f'rrr upper tail stochastic risk, rcliability metrics and cumulative CO: emissittns. 195 Fuel Source Diversity PacifiCorp considcrs relative differences in resource mix among portfolios by cornparing the capacity ofnew rcsources in portfolios by resource type, differentiated by fuel source. PacifiCorp also provides a summary of fuel source diversity diflerences among top performing portf'olios based on fbreoasted generation levels of new resourccs in the portfolio. Generation share is reported among thcrmal resourccs, rcncwable resources, storagc rcsources, DSM resources and FOTs. Portfolio Selection P^cr C0RP 20l9lRP CHAP II]R 7 _ MoDELING ANI) P0R I }oLIo LVALT]ATIoN APPRoA(.H Additional refined analysis is perfurmed on thcse cases to ensure there relative cost and risk metrics are comparable by performing more granular reliability analysis that also better captures potential cost savings of combining battery storage resources with solar resources. Additional analysis can be perlirrmed to fu(her assess the relative differences among top-pcrforming portfolios. Within each step, each portfolio that is under examination is comparcd on the basis of cost-risk metrics, and the least-cost, least-risk portfolio is chosen. Risk mctrics examined include the mean PVRR, uppertail PVRR, risk-adjusted PVRR, mean ENS, upper-tail ENS, and cmissions. As noted above, markct rcliance risk was also evaluatcd and quantified. The comparisons ofoutcomes are detailed, rankcd and assessed in the next chaptcr. Due to the lengthy nature ofthe IRP cycle, the tinal step is the last opportunity to consider whether top-pcrtbrming portfolios merit additional study based on observations in the model results across all studies, additional sensitivitics, possible updates driven by recent events, and additional stakeholder leedback. Additional sensitivities may refine the portfolio selection based on portfolio optimization and cost and risk analysis steps. For the 2019 IRP this included additional analysis to assess market price risk, the impact ofrclying on new natural gas resources, and additional studics to assess incremental transmission investments that cannot be adequately captured in the improved endogenous transmission upgrade methodology discussed earlier in this chapter and in Chapter 6 (Resource Options). During the final screening process, thc rcsults of any further resource portfolio developments arc ranked by risk-adjusted mean PVRR, the primary rnetric used to idcntifu top performing porttblios. Portlolio rankings arc reported for the ltrur price-policy price curv'e scenarios. Resource porlfolios with thc lowest risk-adjusted mean PVRR receive the highest rank. Final screening also considcrs system cost PVRR data fiom thc SO rnodel and other comparativc portfolio analysis. At this stage, PaciliCorp reviews additional stochastic metrics tiom PaR looking to identily ilcxpected and ENS results and CO: emissions results can be used to differentiate portfblios that might be closcly ranked on a risk-adjusted mcan PVRR basis. Case de{initions spccily a combination ol-planning assumptions used to develop each unique resourcc portfolio analyzed in the 20 l9 IRP, organized here into major devclopment categorics: . Coal Studies. Portfblio Dcvclopment C ases o lnitial portfolio cascs o C-series cases o CP-scrics cases o [O'l' cases o Preferred Portfolic Selection 196 Final Evaluation and Preferred Portfolio Selection Case Definitions P^c[.rCoRP-2019IRP ('rrApI R 7 Mor)lit IN(] A\t) I,oR I t()t.lO LrV.^t.r.rAIoN AppR(xrll o No new gas cases o Energy Gateway Transmission cases o Dave Johnston wind altemative Sensitivity Cases Additional detail for all portlolios can be found in Volume tt, Appendix M (Casc Study Fact Sheets). Coal Studies The coal study cases are described in detail in Volume ll, Appcndix R (Coal Studies). Results from the coal studies informed the portfolio-development phase of thc 2019 IRP by driving coal retirement assumptions in the initial portfblio development step of the portfolio-dcvelopment process. Portfolio Development Cases Inlbrmed by the public-input process and lbcused on the retirement outcomes ofthe coal studies, these cases build diversity around varying key retircment dates, and implement modeling refinements to improve results and test evolving outcomes through thc IRP process. Initial Portfolio Cases As informed by the Coal Studies, the over halfofinitial portfblios explore variations in retirement timing for Jim Bridger Units I and 2 and Naughton Units I and 2. Thc initial portlblios also explore potentially significant interactions with additional retirement options including the potential to convert Naughton Unit 3 to natural gas, potential tradeol'ts to retire Gadsby steam units early, and the timing of other coal unit retirements that were not a tbcus of thq Coal Study (i.e., Cholla Unit 4 and jointly owred facilities where PacifiCorp is not the operator). The initial portfolios also consider how resource sclections change with price-policy assumptions that deviate from the medium natural gas price and medium CO: price assumptions uscd to develop many resource portfolios. Al[ ol the initial portlolios include the new reliability assessment phasc of portfblio dcvelopment that was incorporated in thc 2019 tRP cycle. Table 7.9 provides the initial portfi)lio definitions for this lRP. Additional information, including coal unit relirement assumptions, arc providcd lbr each case in Volume II, Appendix M (Ciase Study Fact Shccrs). 191 I,^( lr.rCORP-2019IRP CItApTER 7 MoDEt-tNG ANI) PoR trol,to EvAt-UAnoN AppRoACII Table 7.9 - Initial Porttblio Case Delinitions lnitial portfolio case refinements and additions rvere modeled on lhc basis of outcomes and stakeholder leedback throughout the 20l9lRP public-input proccss. This led to the developing assumptions fbr many cascs as a variant f'rom another case, lending itsell'to a "thmily trcc" structure as a means to describe the relationship among sases. Figurc 7.16 summarizes the case definitions in this family lree lirrmat. Notc, cascs P-70 through P-74 were developed in response to stakeholder interest to reaf'firm Coal Study tindings that early retirement ofunits at the Naughton and Jim Bridger plant were most likely to generate cost savings. These cases were higher cost than most ofthe other cases and were not evaluated as potential candidatcs tbr the preferred portfolio. The top rorv ol-cases in this ligurc represent "parent cases" from which all other cases were P-01 Coal Studv Benchmark P-02 Regional Haze Rcfcrence' P-0i Regional Haze lntertemporal P-04 Coal Srudy C-42 P-06 Gadsbv Alternative Case P-0'7 Gadsby Alternative Case P-06 P-08 Naughton 3 Small (ias Conversion P-03 P-09 P-03Naughton 3 Large Gas Conversion P-10 P-04Naughton 3 l,arge Gas Conversion P-t I P-09Cholla 4 Rctirement 2020 P- 12 P-06Cholla .l Rctircrncnt l0l-,! P-l3 Jirr Bridser I &2 SCRs P-11 P- 14 Naughton l&2 and Jim Bridgcr l-4 Rctirement 2022 P-09 P- 15 Retire All Coal bv 2030 P28 P-16 Jim Bridger I &2 Retiremcnt 2022, No CO:P04 P-t1 High CO:P-t 5 P- l8 Social Cost ofClarbon P-t 5 P- t9 Low Gas P-04 P-20 P-07High Gas P-28 P-l IColstrip 3&4 Retirement 2025 P-3 0 P-l INaughton l&2 Rctirc'rncnt 2022 t,-l l P-llNaughton I &2 Rctire'nrent 2025 P-3 2 P-07Naughton l&2 Retirement 2025 with Gadsby l-3 Retirement 2032 lr-31 P-l IJim Bridgcr l&l Rctirement 2022 P-3 4 P-llJim Bridger l&2 Retirernent 2022. with Gadsby l-3 Retirernent 2020) P-35 P-llJim Bridger J&4 Retirement 2022 P-.15 Jim Bridger I Retirement 2023 and Jim Bridger 2 Retirement 2038 P-l I t,-+6 P-31Jim Bridgcr 3&4 Retirernent 2025 P-5.1 Jim Bridger l&2 Retirement 2025, Jim Bridger 3 Retirement 2028, and Jim Bridger 4 Retirement 2032 P-.1 I P-54 Jim Bridger 2 Retirement 2024 P-31 t98 Case Description PaIent Case PA( rFrCoRP 20l9lRP CI IApT[R 7 - MoDLLIN(i ANr) PoR l fol.to EvALL:Al]oN AppRoAC derived. The text in each box of the family trcc describes what changed relative to the case fiom rvhich it was derived (i.e., case P-08 retains all attributes of case P-03, except case P-08 assumes a small gas conversation at Naughton Unit 3 in 2020). 1,'ure 7.16 - Initial Case Fami Tree C-Series Cases In the C-series, top-performing portfolios tiom the initial portfolio cases were examined with additional deterministic test years used to ascribe reliability resources covering 2023 through 2030, plus 2038. This provides a total ofnine years olhourly PaR reliability asscssmenl rather than the three years (2023,2030, and 2038) employed in the initial portfolio cases. Whcn reliability resourccs are added in the two-step portfblio dcvclopmcnt process adopted lor this tRP cyclc, incrcmcntal battery rcsources are routinely added to rcmcdy initial reliability shortlalls in each case. This indicates that if thc SO model were ahle k) assess the incremental reliability requirement in i1s fultlal resource portfolio, it would likcly pair batteries rvith any ofthe new solar rcsourccs it initially added to takc advantage ofcost savings fbr this combined resource altemative. Test runs perfbrmcd by the IRP modcling team conflrmed that ifstand-alonc solar rcsources were not allowed in the initial portfolio development case, that the SO model selected solar+battery combination resourcc options, and that when these ponfolios were analyzcd lbr rcliability (using the additional test years as described above) and run through the PaR rnodel, the overall systcm PVRR was lon'er. Consequently, for the five cases with the lowest system PVRR fiom the initial step ofthe porllolio- development process and fbr additional cases developed after stakeholdcr discussion at the September 2019 public-input meeting, PacifiCorp disabled stand-alone solar resources-in each casc, solar+battery is added to the portfolio and system costs rverc rcduccd. ln addition to the five top performing cases dcrive-d liom the initial portlirlios (P-llC, P-45C, P- 46C, P-53C and P-54C), tlrc C-series includes five additional cascs dcvcloped alter discussion at P{1 ?-1tPP5n n E ry@g t99 P^cr.rCoRP-2019IRP CIIApTER 7 Mot)t:t.tN(; AND PoRTroLIo EvALUATIoN AppRoACH thc Scptember 5-6, 2019 public-input mccting (P-36C, P-4612jC, P-47C, P-48C, P-53.123C). Table 7.10 provides the C-scrics portfolio definitions tirr this IRP. Figure 7.17 shou,s the Iamily tree relationship lbr thc C-scries of cases. Table 7.10 - C-Series Case Definitions re 7,l7 -C-Serics l'amily Trce CP-Series Cases In the CP-scries7, top-pertbrming portfolios inlormed by the C-series cases are examined with additional deterministic years covering 2023 through 2038. This provides a total of l6 years of hourly PaR reliability asssssmcnt, and fleshes out any granular variances driven by mapping results liom a singlc reliability test year to multiple simulation years in the back-end ofthe study period. Table 7.1 | provides thc CP-series portfolio definitions lbr this IRP. While the P-54C, P-54J23C, and P-3lC cases were not evaluated in the CP-series, thc I'amily tree relationships lor thc cases in the table below are unchanged from thc family tree relationships depioted lbr the C-series ofcases. 7 "CP" rcl'crs to -C-Prime". an expansion ofthe deterministic runs uscd lbr reliability assessment in thc C-Scrics cases. P-3IC Naughlon l-2 Rctire 2025 P-II P-J6C Jim tsridgcr l-2 Retire 2025 I'-.+6 P-45C Jim Bridger I & 2 Retire 2023 and 2038 P-31 P-46C]P-l IJim Bridger 3 & 4 Retire 2025 P-46J23C Jim Bridger 3 & 4 Retire 2023 P-.1(r P-47('Jim Bridger 3 & 4 Retire 2035 P-:15 P-48C Jim Bridger 3 & 4 Retirc 2013 P-;15 P.53C Jim Bridger I & 2 Retirc 2025, Jim Brideer 3-4 Retire 2028/2032 P--r I P-53J23C Jim Bridger I & 2 Retirc 2023 P-53 P-5.+C Jim tsridgcr 2 Retire 2024 P-31 200 Casc DescriDtion (Change from Parent Case)Pt]rrnt Case P45C .l81-2 RET 23, 28 P-31C RH lntertemp., NT3 Lg. GC, CH4 RET 20, NT1-2 RET P-46C JB34 RET 25 P-53C JBI.2 RET 25, JS3 RET 28, JB4 RET 32 P-54C IB2 RET 24 P-47C J83-4 RET 35 P-48C J83.4 RET 33 P-36C JBI.2 RET 25 P-46J23C I83.4 RET 23 P-53J23C J81.2 REI23 Jim Bridger l -2 Retire 2025 P-'16P.36CP Jim Bridger I -2 Retire 2023 and 2038 P-3 |P.45CP P-.16( t'Jim Bridgcr 3 & 4 Retire 2025 P-l I P-46J2-tC'P Jim Bridgcr 3 & 4 Retire 2021 P-46 P-47CP Jim Bridger 3 & 4 Retirc 2035 P-.1-s P-.18( P Jim Bridger 3 & 4 Retire 2033 P-45 P-53CP Jim Bridger I & 2 Retire 2025, Jim Bridger 3-4 Retire 2028/2032 P-3 l Table 7.1I - CP-Series Case Definitions Front OfIice Transaction (FOT) Portfolios PacifiCorp ran a series ofFOT studies designed to quantify the impact and risk ofmarket reliancc for a given portfblio. These cases use an escalating scalar to elevate market prices during the peak months ofJuly, August and December ofevery study year. As FOT prices are calculated as market price plus a premium, FOT prices are elevated with the market. The scalar targets a maximum escalation bascd on the largest difference bctrveen each month's highest Mid-C foru,ard price and the highest Mid-C historical price in the sample year ol20l8. This yiclds a maximum peak scalar ol'3.72 times higher than thc lbrward prioe curve in the month of August; 3.70 times higher in thc month of July; and I .77 times highcr in the month of December. The higher the original forward price in a givcn hour, the higher the scalar. This has the elibct of incrcasing both the severity and liequency ofhigh-pricc hours (increases upward volatility) while maintaining the shape ofthc undcrlying price curve. Figurc 7.18 illustrates the difl'erences between the undcrlying Iorward price curve (FPC) and thc escalating scaled pricc curvc in cach peak month in the sample ycar 2021. ure 7.18 - Sam le Year 2021 FOT MidC FPC and Scaled Price Curves O..€mber Av€Gg€ by Ho!r, Mai ra.td x1.77 Table Ll2lists the CP-series ol'oases rvhere lor which FOT scenarit.rs were developed to evaluate market-reliance risk. Auturt Aver.tc by Hour. Max F.clor x3.72 -.-ltA.,r_loA!,' JulyAve,ate by Hour, Max factor x1.70 P^( rl.rcoRP l()l I IRP CTIAPTER 7 - MODELIN(i ANI) PoR T}.oI-Io EVALUATIoN APPRoACH 201 Case Description (Change from Parcnt Casc)I'nrent Cnsc 'l'able 7.12 - Front Office Transaction FOT Case Definitions 2028-2029 Wyoming Wind Case ln rcvier,r,ing CP-series case results, PacifiCorp identified that 620 MW of Wyoming wind rcsources added to each portlirlio in the 2028-2029 timeframe, rvhich coincides with the assumed retirement of Dave Johnston, were being curtailed at relatively significant levels. Consequently, and considering it unreasonable to potentially includc highly curtailed new wind in a leading candidate for the preferred portfolio, PacillCorp produced an incremental portfblio as a variant of the least cost CP-series case (P-45CP) that eliminated the 620 MW of incremental Wyoming rvind coming online alier the retircment of Dave Johnston. This case is refbned to as P-45CNW. Preferred Portfolio Selection Cases Certain additional cases werc dcvcloped directly from the bp-perlbrming case (P-45CNW) based on analysis ol'portfblios fiom the initial cases through the CP-series of cases as described above to cvaluatc thc impacts of specific future scenarios not considered elsewhere, but which may be adopted into the preferred porttirlio if'the analysis warrants their inclusion. In thc 2019 IRP, there are two types of pref-erred portfolio selection cases: r No Gas portlolios . Gateway portfolios (excluding gateway south, which is modeled as an option in all cases) "No Gas" Cases PacifiCorp ran two cases as variants of P-45CNW to evaluate porttblio impacts ofexcluding new natural gas capacity tiom the portfolio. The first case, P-29 does not allow the model to selcct new natural gas resources (excluding the Naughton Unit 3 gas conversion). The second case, P-29PS is a variant of P-29 with lhe addition ofa 400 MW pumped storage project located in northeast Wyoming that comes online in 2028 following retiremcnt of the Dave Johnston plant. Table 7. I 3 provides the No-Gas case definitions Ior this IRP. Table 7.13 - No Gas Case Delinitions Gateway Cases PacifiCorp modcled four Energy Cateway transmission cases, expanding on scenarios defined in previous IRP cycles. The lull build-out of all Energy Gateway segments was pcrfbrmed in two cases (P-23 and P-25) to asscss the potential value in two difl'erent coal retirement scenarios. The Energy Gatcway cases developed for the 2019 IRP are summarized in Table 7.14 and Table 7.15. 2()2 P-45CP-FOT P-45CP with FO'l'price curve P-46CP-FOT P-46CP with FO'l' price curvc P-47CP-IiOT P-47CP with FO I price curvc P.48CP.FOT P-48CP with FOT price curve P-53C]P.FOT P-53C P rvith FC)T price curve P-29 P-45CNW, No Ncw Cas C)ption P-45CN W P.29 PS P-45CNW, No New Cas Option with pumped hydro storage P-4-5CN W PA( I.rCoRP-l0l9lRP CIIAPTIR 7 _ MoDLLING AND POR IT0I-IO EvAt,IJAl IoN APPRoACII Case Dcscription Case Description Parcnt Cnse P,\crHCoRP f 019 IRP CT[AI,TER 7 - MoDrir-rN(i ANr) PoRTFoLro EvALUATToN AppRoACH Table 7.14 - Additional Gatewa Case Delinitions P-45CNW l able 7.1 5 - (i:rtewa Se ent Definitions 500 kv single circuit * Note: Energy Gate\r'ay South Segment I is modcled as an option, and is selected in each Energy Gateway case summarized above. Sensitivity Case Definitions PacifiCorp initially identified 8 sensitivities based on prior IRP cyclc experience, stakeholder tbedback, and anticipated areas of interest. Each sensitivity is designed to highlight the impact of specific planning assumptions on luture resource selections along with the associated impact on system costs and stochastic risks. Thcse sensitivities were devcloped tbr inlbrmational purposes and serve to illustrate how the system behavcs under a variety of conditions which helps inform the acquisition path analysis presented in Volume l, Clhapter 9 (Action Plan). All sensitivities, as summarizcd in Tablc 7.16, r,l'crc run as a variant of case P-45CNW. Additional details on the sensitivity cases can be found in Volumc ll, Appendix M: Case Study Fact Shccts. 'fable 7.16 - Sensitivit Case Definitions Casc P-23 P-25 P-26 Base Case P-36CrNW (D3). (r)(Dl). (E). (F), (rr)(Di ). (E), (F ). (H) P.45CNW Segment Dcscription lncremental Capacity Approximate Mileage Build Year (D3) Bridger/Anticline - Populus 1700 Mw + PathC 1000 MW 202.s 1160 N4W 2025500 mi (F)+ Aeolus - Clover 500 kv single circuit 1700 Mw 290 mi 202b (;encraaionCas€Dc$riplior Losd Customer Preference S0 Mod€l CO2 Price ()ptimizcdl-01 s0l llir\.I ligh l.oad Optimi^d llN. s0l I in 2l) Hieh l].se ()ptimi^d 1las.I in 2o l.o.rd (;ro$lh s 0.1 Lo$ l'ri\rlc (;cncrrlior Op(irri/rd s-0i IhscI ligh l'rivate (;cncralion s-06 llish lliisc tln!(j s-07 s-08 No ( rstdtr!.r I'rclitncc llas<High (irstomcr li.r.c Uasc No hr8eted renewnbles OpliIri.,(d optimiTcd (hrin)i,/!(l Align first lhree Uas.' 203 P-.15CN W Scgmcnts*(F). (H) 500 kv single circuit 200 mi (E) Populus - Hemingway 500 kv single circuit 400 rni 2023 (H) Boardman - He mingway'600 Mw Ilisc lligh P^( rt,rCoRP 20l9lRP CHAPTL,R 7 . MoDELING ANI) P()RIF0LIo DVAI-LIATIoN APPRoA(]II Load Sensitivities PaciliCorp includcs three different load fbrecast sensitivities. The lorv load forecast sensitivity (S- 0l) rellccts pcssimistic economic grouth assumptions from IHS (ilobal Insight and lou,tJtah and Wyoming industrial loads. The high load forecast sensitivity (S-02) reflects optimistic cconomic grolvth assumptions liom IHS Global Insight and high Utah and Wyoming industrial loads. The low and high industrial load forecasts lircus on incrcased uncertainty in industrial loads fufiher out in time. To capture this uncertainty, PacifiCorp modeled 1,000 possiblc annual loads for each ycar based on the standard errcr ol'thc medium scenario regression equation. The lorv and high industrial load forecast is takcn fiom 5'l' and 95rh percentile. 204 The third load fbrccast sensitivity (S-03) is a l-in-20 (5 peroent probability) extreme weather scenario. The l-in-20 peak rveather sccnario is defined as the ycar for rvhich the peak has thc chance ofoccurring once in 20 ycars. '['his sensitivity is based on l-in-20 peak weather for July in each state. Figure 7.19 compares the low, high, and l-in-20 load sensitivities, net of base case private gencration levels, alongside the base casc load lorecast. PA( rf rcoRr 20l9lRP CIIAP] T]R 7 MOI)ELING AND PORTFoLIO EvAI,I;A IIoN APPROACI I Figure 7.19 - Load and Private Generation Sensitivitv Assumptions Coincitlent System Peak Load 3 E 13'sm 13.000 12,500 r2,om 11,500 1r,000 10.5m 10,0m 9,500 9,m0 ,$"r{rtrs.tr{PrdFr$}dFr$,"r$.$s,-"$r(,tl,strd}rdt"ssr$"r$r$. -.DBase +lin20 +Hi!& Load -tFlow L@d -r-Hi8h PC {-Low PG Svstem Energ-v Load 80,0m 7s,000 70.000 E 3 65,000 60,000 55,000 tr$ B" .$$,' ,,$ .uS d' rS ro" rS d,t ".f ,",,"^\ it, $ ^> -r? ^b $ *$.vs, as, i,s, .\rV n\, ,t\, 1\, 1v +Base --+-tin20 +HiFh Load +Low Load -High Po +LowPG 205 PA( lr |C0RP - 2019 tRP C APTER 7 Mot)F.t,lNGAND PoRTFoLIo EvAt lJAl,oN AppRoACII Private Generation Sensitivities Two private gcneration sensitivities arc analyzed. As compared to base private generation penetration lcvels that incorporated annual reductions in technology costs, the low private gencration sensitivity (S-04) rcflects lesser reductions in technology costs, reduccd technology performance levels, and lorver retail electricity ratcs. ln contrast, the high private generation sensitivity (S-05) reflects more aggressivc technology cost reduction assumptions, greater technology performance levels, and higher retail electricity rates. Figure 7.20 summarizes private generation penetration levels tbr the low and high sensitivities alongside the base case. Figure 7.20 - Private Generation Sensitivity Assumptions Business Plrn Sensitivity Case 5-06 complies with the Utah requiremcnt to perlorm a business plan sensitivity consistcnt with the commission's order in Dockct No. l5-035-04. C)ver lhe first three years, resourccs align with those assumcd in PacifiCorp's December 2018 Business Plan. Beyond the first three years of tho study period, unit retirement assumptions are aligned with thosc identified in the pret'erred portlolio. All other resourcc sclections are optimized within the SO model simulation. Customer Preference Sensitivities PacifiCorp includes two customer preference sensitivitics. The first sensitivity is a no customer pref'erence sensitivity (S-07) that assumes there are no customer pref'erencc resource requirements. Thc second sensitivity (S-08) is a high customer preference sensitivity that assumes proliferation of customer prel'erence rcsources at higher levels than anticipated with close to 9,300 GWh ol customer pref'crence resources being added by the end ofthe twenty-ycar planning period. Figure 7.21 illustrates the relative customer preference generation requirements for these sensitivities. zo6 .,,,,,,,r,,iiliiiilli -,;;;l ..,,,,,,,,illiiiillll...,,,rrmitaaiiiilil lj^( r,rCoRP 2Cll9 IRP (lUAP r r,R T MOD],l.tN( i A\r) PoR tl()l I() hvAt.Un oN APPROA( rr Figure 7.21 - Generation Requirements for Customer Preference Sensitivities | 0,000 9,000 4,000 7,000 6,000 5,000 J,000 3,000 2,000 I,000 0 .,"9 "s,""$,$"{F "$"{F "o"u""$,$," "{F "s," ",st r$ "$ r$ ""'r "s," "{r "s" - -No -lJase -ltigh East/West Split Pursuant to a requircmcnt by the Washington Utilities and Transportation Commission, PaciliCorp's IRP is to include a sensitivity that produces standalone resource portfblios lbr the west control area (WCA) compared to operation as part of PacitiCorp's integrated system. PacifiCorp u,ill incorporate this sensitivity as part of its 2019 IRP Update pursuant to the Washington Utilities and Transportation Commission's July 26, 2019 ordcr approving PacitiCorp's request for a waiver to WAC 480- | 00-238(4) in Docket UE- I 80259. 207 I,^crr,rCoRP l0l9 IRP CIIAP TiiR 7 MODI,I,IN(; ANI) P()RI.I OI,I0 F]VAI,I, I I()N APPROA( II 208 PACIt,r(oRP-2019IRP CHAp iR 8 - Mot)H.t\( i ANt) PoRTFot.to St,t lta-l.lo\ Rtst]t ts CseprsR 8 - MoopLrNG aNo PonrFot.ro SelscrroN REsulrs a a CH,rprnn H lGHt.lclt'ts Using a range of cost and risk metrics to evaluatc a wide range of resourcc portfolios, PacifiCorp selected a prefered portfblio rellecting a bold vision shared with our customcrs tbr a future where energy is delivered affbrdably, reliably and without greenhouse gas cmissions. The 2019 Integrated Resource Plan (lRP) prcterred pcrtfolio includes accelerated coal retircments and investment in transmission infrastructure that will facilitate adding over 6,400 megarvatt (MW) of new rcncwable resources by the cnd ol'2023, w'ith nearly I1,000 MW ofnew renewable resources ovcr the 20-year planning period through 2038.1 Near-term, by the end of 2023, the preferrcd portlolio includes nearly 3,000 MW of new solar resources, more than 3,500 MW of new wind resources, nearly 600 MW ol'battery storage capacity (all collocatcd with neu, solar resources), and over 700 MW of incrcmental energy efficiency and new direct load control resources.l To I'acilitate the delivery of new rener,l'able energy resources to PacifiCorp customers across the West, the preferred portfolio includes a 400-mile transmission line known as Gateway South, planned to come online by the end of2023, that will connect southeastem Wyoming and northem Utah. The preferred portfolio lirrther includes near-terrn transmission upgrades in Utah and Washington. Ongoing invcstmenl in transmission inliastructure in Idaho, Oregon, Utah, Washington, and Wyoming will facilitate continued and long-term groMh in new renewable resources. Energy efficiency continues to play a key role in PacifiCorp's resource mix. In addition to continued investment in energy efficiency programs, the pref'erred portlblio oontinues to show a role lbr direct load contml programs with total new capacity reaching 444 MW by the end ofthe planning period. Driven in part by ongoing cost prcssures on existing coal-fired t'acilities and dropping costs fbr new resource altematives, olthe 24 coal units currently serving PacifiCorp customers, the preferred porttblio includes retirement of 16 ofthe units by 2030 and 20 ofthc units by the end of the planning period in 2038. Coal unit retirements in the 20l9lRP preferred portfblio will reduce coal-flueled generation capacity by over 1,000 MW by the end ol 2023, nearly 1,500 MW by the end of 2O25, nearly 2,800 MW by 2030, and ncarly 4,500 Mw by 2038. In the 2019 IRP preferred portfolio, Naughton Unit 3 is convcrtcd to natural gas in 2020, providing a low-cost reliable rcsource lor meeting load and rcliability requirements. New natural gas peaking resources appear in the prel'erred portfolio starting in 2026, rvhich is outside the action-plan window and provides timc tbr PaciliCorp to continue to cvaluale rvhether non-emitting capacity rcsources can be used to supply the flexibility necessary to maintain system reliability into the future.'fhc prelbrred portlirlio shows an overall decline in reliance on rvholesalc market firm purchases in the 2019 IRP prct'cned portfolio relative to thc market purchases included in 209 I Resources acquired through customer partncrships, used for renewable portlblfu standard compliance, or for third- pany salcs ofren€wable attributes are included in the totalcapacity figures quoted, ? Id. P^crflCoRP 20l9lRP CHATI IrR 8 _ MoDELI\(i ANI) PoR-II.oLIo SLLECTION RF]SIJI,IS the 2017 IRP prcf'erred portfirlio. In particular, reliance on market purchases during summer pcak periods averages 366 MW per year over the 2020-2027 timeframe down 60 pcrcent from market purchascs identified in the 2017 IRP preferred portlirlio. Thc 2019 IRP prelened portfblio reflects PacifiCorp's on-going efforts to provide cost- effective clean-encrgy solutions lor our customcrs and accordingly reflects a continued trajectory of dcclining carbon dioxide (C0:) emissions. As compared to the 2017 lRP, projected carbon dioxide (CO:) cmissions in 2025, are dorvn sixtcen percent relative to thc 2017 IRP preferred portfblio. By 2030, average annual CO: cmissions are down 34 perccnt rclative to the 2017 IRP pref-erred portfolio, and down 35 percent in 2035. By thc end of the planning horizon, system C O: emissions arc projected to fhll lrom 43.1 million tons in 2019 lo 16.7 million tons in 2038-a 6l .3 pcrccnt reduction. This chapter reports modeling and performance evaluation results for the resource portfolios developed with a broad range of input assumptions using the System Optimizcr (SO) rnodel and the Planning and Risk rnodel (PaR). Using model data from the portfblio-development process and subscquent cost and risk analysis of unique portfolio altemativcs, PacifiCorp steps through its pref-erred portfolio selection process and presents the 2019 IRP preferred portlblio. The chapter is organized around the thrcc modeling and evaluation stcps identified in the previous chapter: (l) coa[ studies; (2) portfblio development; and (3) prefbrred portfolio selection. The final preferred portfolio selection is informed by all relevant case results and incorporates any refinements indicated by preceding results, recent relevant events and stakeholder feedback. This chapter also presents modeling results for additional 2019 IRP sensitivity cases that, while informative, were not considered for selection as thc preferred portfolio. Results ol resource portfblio cost and risk analysis liom each step are presented as PacifiCorp steps through thc fbllowing discussion olits portfblio evaluation processes. Stochastic modeling results from PaR are also summarizcd in Volume ll, Appendix L (Stochastic Simulation Results). The 2019 IRP included a thorough and robust economic analysis of PacifiCorp's coal units. The coal study analysis conducted in the 2019 IRP rvas initially prompted by thc Public Utility Commission ol Orcgon (OPUC) as set fbrth in its 2017 IRP acknowledgcment order, which administratively established certain modeling requirements. PacifiCorp met these requircments and then developed a more complete coal study. The coal study cUbrt is comprised of the following three key phases: . Phase Onc - Unit-by-unit coal studies.o Phase Trvo - Stacked coal studies.o Phase Three - Reliability coal studies. The three phases ofthe coal studies are detailed in Volume Il, Appendix R (Coal Studies). 2t0 I ntroduction Coal Studies P^cI rC()RP 2019 IRP CHAP]1-]R8 MoDLI,INC AND POR II,0I IO SELEC],IoN RIISI]I-Is Coal Studies Conclusions Each olthe coal study phases show that early retirement ol'certain coal units has potential to reducc overall system costs. ln particular, the coal studies showcd thal the greatest customer benelits were most likely to be realized rvith potential carly retirement ol coal units at the Naughton and Jim Bridger coal plants located in Wyoming. The portfblio-development process considcrs other planning factors not Iully evaluated in thc coal studics (i.e., Regional Haze compliance, altemative retirement dates tbrjointly orvned coal plants rvhere PacifiClorp is a minority orvner and not an operator, altemative timing of potential retirements rvhen accounting for incrcmental capacity to maintain reliability). Consistent with the findings lrom the coal study, more than half ol'the cases devcloped in the initial phase of the porttblio-development process evaluated varying combinations of rctirement dates for Naughton and Jim Bridger units. The following discussion begins with an examination of initial porlfollos exploring variations in retirement timing for the Jim Bridgcr I & 2 and Naughton I & 2 units. The initial portlblios also explore potentially significant interactions with additional retirement options including possible Naughton 3 gas conversion, Gadsby gas unit retirements, and the timing olCholla retirement. Following the initial portfolios, PacitiCorp refines top-perfbrming cases with two stagcs of additional reliability requirements, referred to as the C-series ofcases and the CP-series olcases. In the C-series ofcases, top-performing portlblios are examined with a more granular assessmcnt ofreliability requirements Ihrough the production olhourly deterministic Planning and Risk Model (PaR) studies cov ering 2023 through 2030, plus 2038. This provides a total of nine years o['hourly PaR reliability assessment rather than thc three years (2023, 2030, and 2038) used to develop thc initial portfblios. As described in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach), in addition to expanding the reliability assessmont step of portfolio development the C-series also removes proxy stand-alone solar resources from the resourcq options available to thc SO modcl, which lowers the present-value revenue rcquirement (PVRR) in all cases. Top-perfirrming portfolios lrom the Cl-serics of cases were further examined in the CP-series of cases with additional dctcrministic PaR studies covering2023 thror-rgh 2038. This provides a total of l6 years of hourly PaR reliability asscssment, and fleshes out any granular variances in thc back-cnd o 1'the study period. As discussed in Volume I, Chapter 7 (Modcling and Portfolio Evaluation Approach), PacifiCorp produced a variant of thc top-pertbrming CP-series casc to eliminate Wyoming wind resources that were added in the 2028-2029 timctiame. This case, along with other cases from the CP-scrics, rvere further analyzed to quantifu market reliance risk in a series of front otllce transaction ( F'O'I ) cases. Irinal selection cases rvere also developed to evaluate the impact of removing all ncx,natural gas resource from the top-performing ponfblio and to assess thc impact of adding additional Energy Gateway transmission segments to the top-perl'orming portfolio. 2ll Portfolio Development P^( U,lCoRP l0l9lRP (luAl,l l:R 8 - Motn,r.rNC ANr) P{)R I I ol.to SII.[(-r IoN Rr,sr [. r s I n itial Portfolio Development 'l he lollowing tables and figures present rcsource additions and systcm costs firr the initial portfblios. Additional information is provided for these cases in Volume ll, Appendix K (L]apacity Expansion Results Detail), including detaited resource portfblio results showing ncw resource capacity and changes to cxisting resource capacity by year. Summary portfblio results are also shou,n in the casc thct sheets presented in Volumc II, Appendix M (Casc Study Fact Sheets). Coal and Gas Resource Retirements Figure 8.1 summarizes thc cumulative nameplate coal and gas retirements by case over the near- term, mid-term, and long-term among the initial portfolio cases. Note, in reporting cumulativc capacity in this figure and in the similar tigures that follow, thc mid-term results includc capacity rctired in the near-tenn, and similarly, the long-term results include capacity retired in the near- term and in the mid-term. Unit-specific retirement dates for each case can bc tbund in Volume , Appendix M (Case Study Fact Sheets). By the end ofthe study pcriod, coal retirements are similar among nearly all cases (P- 15, P- l7 and P-18 are exceptions), rvith slight variations depcndcnt upon timing lbr Colstrip Units 3 and 4. Cases P-15, P-17, and P-18 assume all coal is retired by the end of2030. lly the end ol'thc study pcriod, gas retirements are the samc among all cases. Cases P-06, P- 17, P- I 2, P- 19, P-20, and P- 34 assume the gas-luelcd Gadsby Units l-3 retirc at thc cnd of 2020. Among thc t'ive cases with the lowest PVRR (cases P-31, P-45, P-46. P-53, and P-54), coal unit rctircments range fiom 667 MW to 1,023 MW through 2024 and range betu'een 2,091 MW and 2,lL)1 MW through thc end ol 2/J27. 212 Figurc 8.1 - lnitial Portfolios Coal and Gas Resource Retirements Summarv po1 942 orr ! c-rn fo-r, I c-ro !r'rz f e'ra f P1e I c-:o ! P28 I c.ro !e.l !o:z !o:: ! o3o I ,-35 I c+: ! p-46 I c-sr ! P-s4 I Plr Icrr lc+r f,-I o*I oor I ooa fros ! P_to rr.rr forz f p-r3 Ic.uf ,.rs I r.ro fp.17 Io-rsIp-rgI c-:o f cre l o:o fn.l fr.rz fr-r lo-* I crs fros f,*I,-s:I o-* I oro- ,11 II - - - EE - oor- orr- O,,E o-,rE o-tr- o*- o-tr- o-*- Coal/Gas Retirement 2019-2024 (MW) t Coal Gas t Coal/Gas Retirement 2019-2027 (MW) r Coal Gas Coal/Gas Retirement 201e-2037 (MW) rCoal 6asE - - I II - -- p{[ P42 P{3 P{t p-o9 P{6 Iror !P{s I P{s IercI n-rr !ru !p-\2 p-13 p,15 p,l6 p-t7 p-18 P19 P,?0 p-2a p,30 0 2,mo 4,mo 6,m0 8,m0 0 2,mo 4,mo 6,m0 8,mo 0 2,mo 4,000 6,000 8,m0 New Renewable and Storage Resources Figurc 8.2 reports the nameplatc capacity of new rene\r'ables and slorage resourcc additions for each initial case. Near-tenrr renewablc additiurs through 2024 range tiom 1.63:i MW to 5,475 MW. In all cascs but onc (case P-16, which climinates CO: price assumptions through the study period). thc SO model selects Energy Gateway South in 2024 (a proxy tbr year-end 2023) along rvith I ,920 M W of ncrv rl ind in easlern Wyoming. Excluding case P- 1 6. the minimum penetration ofnew renewable capacity is 3,290 MW through 2024 (a proxy lbr year-end 2023). Through the mid-term, rcnewable capacity grows up to 6,372 MW by 2027. Through 2027. new solar capacity rangcs between 1,370 MW and 4,452 MW-cases with morc carly coal retiremcnts have more solar capacity. Through 2038, thc total new renewable capacity rangcs between 5,574 MW and 10,71 I MW, and nelv battery storage capacity ranges bctwcen 1,903 MW and 4,558 MW. Arnong the flvs cases with the lowcr PVRR (cases P-31, P-45, P-46, P-53, and P-54), the total neu, renewable capacity ranges between 3,674 MW and 4.536 MW through 2027 and over 10,000 MW through 2038. 213 P^( [,rCoRP-]019IRP (lrrAp rriR li - Mot)l,l t$; A\D PoR ()r-io Sr:t l,(' I IoN Rrisr rl. rs CHAP,I},R 8 _ MoDELIN(i AND PoRIFoLIo ST:I.I-C I.IoN RESUL,I.S Figure 8.2 - Initial Portlblios New Renewable and Storage Resources Summary Renew/Storage Renew/Storage Renew/Storage 2019-2024 (MWl 202s-2027 (MW) 2028-2038 (MW) rwind r Solar r Solar+8at lWind+8at I Bat . Pumpsto ror fII IN\ ror!leo!ic{3!i po4 I Np{6 I Ioor!$ p.oe I iP{eIi cro! Ncrr ! |p,r, I No.r: ! i c.ra I Nors I Nlp-r6 I c-rz !\\\,18 I N\\\\I,r! !o.:o ! $p.:e I . o.ro I Ip:rIN P.' I NIn.r ! .\Ip.r4 I V c.rs ! SI o.os ! $cao ! (_N p.sr I N\ P,5{ I N N\V.\\\$il "Lr ;I*ir.W N\\\\I rrl ::1.::,,'), N\\\\U P,l5oro! U t Wind r Solar r Wind+Bat r 8at r Solar+Bat r Pump Sto . wind Solar rWind+8at r Bat r Sola.+Bat I Pump Sto p.r6 I "r, lN\ P{2 p{3 p{6 P47 F{8 p{9 P-t0 P,lt p-12 P-l3 P.14 P-15 p,18 p,t9 P-20 P-28 P,30 P-!! P.32 p-33 P-X4 P-35 P45 P-:'4 I\YIIrslIiIiIrNISINIiI\Y IN\IIISII"\IIrNININIVININIs.\IN\IN Pat P{2 P-01 p{a P"06 P4f P{8 P{9 P-10 P-t2 p,l3 P.IE P-19 P-20 P-28 P-:v, p-31 p.32 I M \\\\U IU ):1 \\NI r;.ffiffi N\\\\I*#Tff N\\\\lr'ffi1r9 N\\\V o-?1 p-35 Pls nre r;lii"{& \\\\V,r: ,itiii$ \\\V o 5,mo 10,0m 1t0m o 5,000 1o,om 11000 o s,mo 10,0m ltom Note: For $'ind or rencwable resources paircd with batlery, the capacity for the rerewable rcsource is shown in the graph. ]'he battery capaciry- paired with lhese resources is 25 percent ofthe reneu'ablc resource capacir_"_. Incremental Demand-Side Management (DSM) Figure 8.3 summarizes aggregated demand-side Management (DSM) selections by case. Selected volumes ol'DSM are relatively stable among all initial cases. Through 2024, Class 2 DSM (energy efliciency) selections rangc betlveen 763 MW (case P-19) and 965 MW (case P-18) and Class I DSM (demand response and direcGload control) ranges bctrveen ll MW and l9 MW. Through 2027, Class 2 DSM selections range between l,ll6 MW (case P-19) and 1,455 MW (case P-18) and Class I DSM ranges between 45 MW and 322 MW. More Class I DSM resources arc accelerated into the mid-term among those cases that have higher levels of accelerated coal and gas retirements (cases P-04, P- 10, P-14, P- 15, P- 16, P- 17 and P- 19). Through 2038, Class 2 DSM selections range between 2,005 MW (case P-19) and 2,603 MW (case P-18) and Class I DSM rangcs between 417 MW and 583 MW. 2t4 PA( I,rCoRP - 20l9IRP !\\\\il \\\\\\\\\I \\\\\\\U \\\\]il\\.\:\:U I N\\\\\I I \\\\\\\UR\\\\\\\ i\'\\L t\s\\\ N\\\\[ Figure 8.3 - Initial Portlblios Incremental DSM Summary DSM DSM 2019-2024 (MWl 2019-2027 (MW) 2 Class 1 i Class 2 Class 1 DSM 2019-2038 (MW) . Class 2 Class 1 -- --- E - - -- P{1 p{2 p{3 P4t P{6 p{6 P49 P-10 P-11 I Oass IIIIIIIIII P.,, Ip-n IIIIIIIIIIIIIIIIIII porE poz Ipo: Ep{. - "-Iroz f "{s - p{1 P47 P{3 p{6 P47 P-ll8 P{!} P-10 P-!1 p-12 p,13 p-15 P-16 c-t1 P,t8 P-19 P-20 P-28 P-30 p-31 P-t2 p-33 P-34 P-35 P'53 r o-gr- P49 P-10 p-12 p,t3 p-15 P16 P-t1 p,t8 P-19 p-20 p28 P-30 p-32 P-13 p.!1 p-5 P-53 - I - - P-,4 P-15 p-16 p-17 p,l8 P-19 P-20 P.IE P-30 P-31 P-32 P-33 P.A P-35 p45 p-53 P-54 E - - - Ii -- - - II - II -- o l,mo 2,mo 3,000 0 1,mo 2,000 3,m0 0 l,mo 2,@o 3,m0 New Natural Gas Resources Figure 8.4 summarizes cumulativc natural gas expansion resourccs lbr each initial portfolio. ln cases where Naughton Unit 3 converts to natural gas in 2020, it is assumed to retire at the end of 2029, so it does not show up in the results through 2038. Four cases (P-14, P-16, P-17, and P-19) include nelr' gas peaking capacity in 2023. Through 2038, nerl' peaking gas capacity ranges between 813 MW and 2,458 MW. Case P-15 includes ncw combined-cycle combustion turbinc (CCCT) gas capacity beginning 2027 through 2038, new CCCT capacity in this sase totals I ,541 MW. Three additional cases include CICCT capacity, albeit at reduced levels relativc to casc P- l 5 (cases P- I 6, P- I 7 and P- I 9). Among the Iive cases with thc lowest PVRR (cases P-3 I, P-45, P-46, P-53, and P-54), new peaking gas capacity is added in 2026 ( 185 MWFby 2038, new gas peaking capacity totals I,367 MW. 215 PACIIICoRP_20I9IRP CHApTER 8 - MoDILINC AND PoR tfot Io SELECTION IlEsLrLrs Figure 8.4 - Initial Portfolios New Natural Gas Resources Gas Gas 2019-2024 (MWl 2019-2027 (MW) rPeaker .CCCT GasConv. rPeaker r CCCT 6asConv Gas 2019-2038 (MW) I Peakpr I CCCT GasConv p{l p{5 p.1l rre ! oro I o rz ! p.I3 prg I p21 p28 pt3 p+r Ioo: fp-03 EP{4 Ip45 I P{6 - p{7a po8 Ipog Ip10 Ip'u Iprr Ip1iI P-1a Ip-15- p-ra I P.r5 Ip.ro I F-17 I p.18 prg I P-21 o-tt I p-28 p.l Ip-rz I P13 Pr7 f p-19 oas !p{6 I,-l: Ip54 I p-16 P'1s I p-19 pro I p27 I P28 Ip-ro Iprrl p12 IprI P3a Ip-rs Iott l P39 p+s Ip+o Ipsr I,,54 I 0 sm 1,m0 1,500 2,m0 0 5m l,mo 1,$o 2,m0 0 1,m0 2,m0 3,mo 4,m0 Notc: Scalc change in the 'through 2038' colLrmn due to P l5's addition ofCCCT resources. Summer Front Office Transactions (FOT) Figure 8.5 summarizes the average of FOTs for each initial portfblio during the summer peak. The summer FOT limit assumed fbr the 2019 IRP is I ,425 MW. Through the near-terrn, avcrage annual summer FOT purchases range between 543 MW (cases P-46 and P-53) and 1,031 MW (case P- l9). In the 2025-2027 timeframe, a period whcre there are resource-adequacy concerns in the rcgion, summer average annual FOT purchases range bet\4'ecn 168 MW (case P-31) and 1,290 MW (case P- l6Freliancc on the market grows in cascs with more acoeleratcd coal retirements. Over the long tcrm, the level of summer FOTs is rclatively stable among all cases, ranging betwcen 1,241 MW (Case P-13) and 1,362 MW (Case P-15). I,^CIIICORP 2(]I9IRP Clt I,l tilt 8 Motrit rN(i AND PoR 1I()t IO SIit [( t()NRl]sUt-ts I 216 P^c[,rCoRP 2019 IRP CHApTER 8 - MoDELtNC AND PoRTroLIo SELlc. oN REsUL ts Figure 8.5 - Initial Portlblios Summer Front Office Transactions Summary Average Annual Summer FOT 201e-2024 (MW) Average Annual Summer FOT 2O2s-2O27 lMWl rot !ro: !to: ! Average Annual Summer FOT 2028-2038 (MW) P'l)1 P-O2 p{3 p{6 P47 P{€ plo p,1t P,t2 P-I3 P-14 p-15 P-16 - I - P{1 P{2 P{3 P44 P{6 p{6 ?4t P-11 P.E P-13 P-14 p-15 p-16 p-17 P-1a P-19 P-20 P-24 P-lo P-31 p.32 P,t3 P-y P-35 P{:i P-53 P-54 P{4 F{6 PO6 po9 P-10 p,1l p-12 P-13 P-15 P-16 P.l7 P.18 P.19 P"20 P-28 P-:to P-31 P-32 P-33 P-9 ,-25 ,14 P-5, -- E -- - III - I II I - - P.r7 I - p-18 p-19 P-20 P-28 P-:lo P.31 P-t2 P-33 P-!rl p-35 P.4li P.5! I - III - - -- II - - - IIII IIIII 0 5m 1,000 1,500 0 s00 1,mo 1,500 0 500 1,000 1,500 Winter Front Office Transactions Figure 8.6 summarizes the average olFOTs fbr each initial portfblio during the winter peak. The winter FOT limit assumed for the 2019 IRP is 1,425 MW. Relative to the summer period, wintcr FOTs are much smaller among all cases and timelrames. Winter FOT purchases are also relatively stable among most cases through both the shon and mid-term. Over the long term, winter FOT purchases are reduced rvhen incremental capacity is added to the system-CCCT additions in P- I 5 and P- l9 significantly reduce wintcr FOT purchases. 217 Figure 8.6 - Initial Portfolios Winter Front Office Transactions Summary Average Annual Winter FOT 2019-2024 (MW) P{r Iroz !eor !P{4 I P{6 I eoz ! P{8 I P{e I P.rc Ic-rr !p-u I P-r! I e-u ! P-rs I e-ro ! P.17 I r-ra I P.D I P-20 I P-2s I P-30 I P-!r I r-rz !P-!! I p-3n I P-3J I P{5 I P.|6 I P-sr I P-s4 I Average Annual Winter FOT 202s-2027 (MW) ror f P{2 I P{3 I P44 I P{6 I P{7 I P{s IPOI r.ro ! P.t1 I P.U Ip-u Ic-u ! P.15 Ip-ro I P,17 I c-ra I P.19 Ip-m I P-28 I P-30 I o-rr ! Pi2 I c-ra ! Pi1 I P-35 IP{r I P..o I r-sa ! P.54 I Average Annual Winter FOT 2028-2038 (Mw) ear Ierz ! P{3 I P{4 I Po6 Ictt I P{s I P{e I r-ro ! P-r1 I r-rz !p-rr Ir-u ! P-u I P.$ I e-n f IIIIrIIIrIII P-18 P-19 P-20 P-24 p,30 P-31 p-?2 p-33 P-34 p,35 p.{5 p-53 0 5m 1,mo 1,$o o 500 1,m0 1,500 0 5m 1,m0 1,500 COz Emissions Figure 8.7 reports sumulative COr emissions lbr each initial porttblio. 'fotal CO: emissions through 2022 are very stablc, ranging between 162 and 164 million tons. Through 2027 . total COz emissions range between 318 and 353 million tons. Through 2038, total CO: cmissions range between 427 and 670 million tons. Among the five cases with the lowcst PVRR (cases P-3 l, P-45, P-46, P-53, and P-54), total CO: emissions through 2038 range between 560 and 588 million tons. 2t8 P^('rFrCoRP 20l9lRP CHAPTER 8 - MoDELING AND PoRt f(n ro SEr r-r( roN Rr.sllr. r s PA. rF'r(l)RP 20l9lRP CTIAPTER 8 M0DI]I-ING A\D POR IT0I,I0 SI:I,I (.I.IoN RESLILTS Figure 8.7 - Initial Portfolios COz Emissions Summary Emissions 2019-2024 (Million Tons) Emissions 2019-2027 (Million Tons) Em issions 2019-2038 (Million Tons) oarlooE ror fo*-,*I corf oo" Io-- c.ro fo.1rE,ttI,"- nra f "--,,UI r-uf,-ts-e-rrf,-:oEo-rtI o-roE ot, Io,, I,.,, Io*I c.:s fo*-,*I,,taI o,r I ,.1,-or2-,nr- ..). I,*- ,or- ,0"-,*E,.- orr-,,,- orr- ,ro- ,.rt- p{1 Pn2 p-t2 p-13 p-15 p-16 P-1S p-t9 p-20 p-24 p-30 p-lt P-12 P-33 p-34 p-15 P45 P,53 - ,,-,,,- ,rt- ,ro-l ,.rB- ,.ro-,rII or2- ,r,- ,"0- o.,t-p"sE 0"6- otr- o'- o .g .ve o& n8 o,e erB o .,8 "B te $e.re dl o \e .v& q8 v8 ',8 b8 Table 8.1 summarizes results for the initial portlolios, including the stochastic mcan PVRR, the risk-adjusted PVRlt, amount ol energy not servcd (ENS) as a percentage of load, and CO: emissions lirr ench case. 2t9 P^clFrCoRP l0l9lRP CnAprER 8 MoDrrt.tNG AND PoRTFoLro Stir.r:('rroN Rl-:stilTs Table 8.1 - Initial Portfolio Cost and Risk Results Summar Figure 8.8 summarizes the stochastic mean PVRR relationships among the initial portfblio cases in the "family tree" Iirrmat summarizcd in Volume l, Chapter 7 (Modeling and Portfblio Evaluation Approach). Dollar figures associated rvith eash case represcnt the increase in system PVRR relative to the lowest-cost case (case P-46). Note, that cases P-70 through P-74 rverc devcloped in response to stakeholder interesls to rcafllrm conclusions from the coal study, which indicate that potential early coal unit rctirements should be focused on Naughton and Jim Bridger units. Stochlrstic M."{n Risli Al.liusled ENS Alcragc l'crccnt ol Load ('O: lrnissi(nN RanhCasc PVRR ($m1 Change from Lowest Cost Porttblio ($m1 Ranl, PVRR ($m) Change from Lor,!est Cosl Ponfolio ($m1 Rrnk Average ENS, 20t9- 2038 % Load Changc tiom Lowcst ENS Portfolio Ita k Total c()2 Emissions. 2019-20llt (ThotA.lnd Tons) Change from Imission Ponfolio 6P1623,{l-r 0 :1. )5 l)0,012r/o 0.006"1,560,t99 t-t-\.1j90 P5l 23.-{68 57 0,0t2vo 0.00ftz,562,{t25 t-1.1,9155521.662 P.3I 21.18{12 0.0091{,0.002"1,l9 58ll,.l2l t6l,3l2 l91$21,6711 P.l5 l ll6 0.008,%0.001"1,l0 58_t.98|ts6.87221,122 0.009%l1 5ti.1,377 r57,267 t6P5l23,616 :0-r 2l,8tq : !.1 0.002% llPl0t1.655 l.l I 2.r.86.r :5e 0.009.,;u.1101",2l 571.707 t41,5e7 t:i.666 :51 7 2.1.87t :r,t,7 0.010q;2l i57.J89 |r0,i79 l02:l.6lt6 21i I t.1.888 lli l 0.008ci,ll 591,122 167,2t1 l8Pi0It,l0 ll.9.rl l0 0.010,,;t2 587.905 l6(),795 liPll2r,768 | 155 1,1 )1.916 170 l.]0.008%0.00lln s 5q6,9ll 169,1{11 l:Plz 13.678 t6.l I 24.8li6 :til It 0_008%0.0029,6 tl 579,167 t52,057 P t:l 24,016 f,0.1 24 a,l9 24 0_00u%0.00 t96 u 601,tq6 t77,286 P t.l 11,786 l7:ta 2i.000 :i9.1 0_0t5%0.0099;535,771 llrlr.66.+ l-+Ptl :1,750 II :.1.959 iiJ ll l)-(X)ll":i,0.(xrl,1i,l)581,S65 2411,760 I]2.1.910 tl 0.0099;111r:t0 597.855 170.7.15 8P0li(rl l1 tJ,9Sl lt{7 tl 0.01 l9;o.ll0.l'o 21 i67.90t Ito.79l l0Pil1i,809 jej ltl .l l9 0.007%0.00!9r 569.586 l1:,176 1,1)7 2t,8 r9 17 Jt7 I8 0.0079,i,5r11.581 r5,1.474 lll5,0ll P0l lt.8l:t8 25,0:l:l t1l t1 0.00tt_.;0.002'ln l2 595.728 l68.6 tg 2l 1,08 21.875 I9 2i,0r)2 Itib l9 0.009%lt3 595.956 168,11,1{r 720lol'ril Pt6 21.8lt9 )'76 :0 :-i.097 .+r) I l0 0.0070/0 0.000,1n 66q.q4l 242,r{34 5lrl ]15.lit 5r6 zt 0.007en 58i.907 lill,79ll t7 P:i1 2l.9ili 5t.l i5l:5.157 0.00liqr 0.00t,0 ll 568.111 l.ll,lll 2-1.000 5ll7 ti li.:2i 0.007qi,607,157 ltio,0.l7 2slIP0l2{. t06 721 0_006q;616,896 Pl7 2.{.r81 76S li..l00 0.057,4 0.05 t9i,175.jq0 189,786 .li.i.:t1l Pl5 21,285 871 2-\.516 rll 0.012%0.005%.172.-t69 .15..159 Pt8 :+,170 09arl25.601 0.lll%0. t01%.117. t l0 P0l 21,919 1,506 t6.lnl 1.577 0.0010,t6 l7lr.76l Pt0 25,I l8 t,705 26.in5 1.71r0 t).00794 0.000qn d)7.ti7 180.0.17 220 PacifiCorp identified the first five cases in the table (in bold) as top-performing cases selected lor more refined C-series analysis. I 26 2'l 712 3 3 {I 5 5 25 ?8 ,l :t65 7 .10(r J09 .1(,2 :lt) 6 l 11 l5 29 l6 16 lc ..1 27 21 :5 l8 l8 30 79 60J.Ii72 262q t0 i0 21 l'^crr,rCoRP -:019 IRP CIl prtrR 8 -MoDLt-tN(i ANt) PoR Itot.to SEI-ECTION RESULTS t re 8.8 - Relative Cost of Stochastic Mean to the Lowest-Cost Initial Case In the C-series ofcases, top-performing portfolios from thc initial set ol'porttblios, and additional portlblios produced in response to stakeholder interesl, receive an expanded reliability analysis. For each ofthese cases, PacifiCorp produced six additional deterministic hourly studies to ensure that each year is analyzed through 2030 (i.e., adding test years lbr 2024-2029). This improves the granularity at which reliability resources are applied and provides for a better comparison ofcost and risk metrics between these cases. As noted above, in addition to the five top performing cases dcrivcd f'rom the initial portlolios, the C-scries includes five additional cases developed after stakeholder discussion at thc September 5- 6, 2019 public-input meeting. Table 8.2 summarizes the llve additional C-series cases. Table 8.2 - Additional C-Series Cases To! Pe{ormin. ET EU EU EU, ] P.36C A variant of Clase P- l4 with Jim Bridger I -2 and Naughton I -2 retired at the end of 2025. P-46J23C A variant ofCase P-46 with Jim Bridger 3-4 retircd at thc cnd of2023. P-47C A variant ofCase P-45 with Jim Bridger 3-4 retired at the cnd of 203 5. P-48C A variant ofCase P-45 with Jirn Bridger 3-4 retircd at thc cnd of2033. P-5 3J23C A variant of Case P-51 with Jim Bridger I -2 retired at the end of 2023. 221 C-Series Portfolios As described in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach), in addition to cxpanding the reliability asscssmcnt step ol'portlolio development the C-series also rcmovcs proxy stand-alone solar resources 1'rorn the resourcc options available to the SO model. This allows the SO rnodel to efficiently combine renewables and storage rcsourccs in order 1o accrue combined cconomic benefits that would othcrwisc be lost. Case Description C-Series Portfolio Development Coal and Gas Resource Retirements Figure 8.9 summarizes cumulative nameplate coal and gas retirements for each C-series case over the near-term, mid-term, and long-tcrm. Note, in reporting cumulative capacity in this figure and the similar figures that fbllow, the mid-term results include capacity rctircd in the near-term, and similarly, the long-term results include capacity retired in the ncar-tcrm and in the mid-term. Unit- spccitic retirement dates for each case can be fbund in Volume Il, Appendix M (Case Study Fact Sheets). Through 2027, tolal coal rctircmcnts range between 2,091 MW (case P-3lC) and 3,499 MW (case P-36C). Through thc end of2037, total coal retirements approach 4,500 MW in each case. Figure 8.9 - C-Series Coal and Gas Retirements Summarl' P-31C P-36C p45C p.46C P$D3C P47C 9-1laC p-53C P-53123C p-54C P.3lC P-36C pa5c p{5c P.1tii2!c P17C p.aac p.53C P-53J23C P.51tC P-3tC P.36C P-45C p{6c P-46i23C P-4aC p-53C p,53,43C Coal/Gas Retirement 2019-2024 (MW) r Coal Gas Coal/Gas Retirement 2019-2027 (MW) Coal/Gas Retirement 2019-2037 (MW) a Coal Gas E --------- r Coal 6asIIIIIIIIII 0 2,000 4,mo 5,mo 8,mo 0 2,mo 4,m0 6,mo 8,m0 New Renewable and Storage Resources Figure 8.10 summarizes the nameplate capacity o['ner.l,renewables and storage resource additions for each C-series case. In all cases thc SO modcl selects Energy Cateway South in 2024 (a proxy lbr ycar-cnd 2023 ) along with I ,920 MW of new wind in eastem Wyoming. Through 2027 , new renewable capacity ranges between 3,992 MW (case P-3lC) and 4,645 MW (cases P-46J23C and P-53J23C). By the end ol'2038, ncw rcncwable capacity ranges between 8,905 MW (case P-36C) and 9,574 MW (cases P-46C, P-47C , P-48C, P-53C, P-53J23C and P-54C). New battery capacity ranges betrveen 518 MW and 729 MW through 2027 and over 3,100 MW by the end of2038. 222 PA( r rCoRP-l0l9lRP CHAPl LR tJ _ MODELINC AND PoRTI.OI-Io SEI,F]C'IIoN RHsI]I-1S E 0 2,m0 4,m0 6,m0 8,m0 Pi\r lr rC(mP f0l9lRP CITApTLR 8 - MoD[LrNC AND PoRTloLro SEL[cfloN RLsr]r- ts Figure 8.10 - C-series New Renewable and Storage Resources Sum Renedstorage Renew/Storage 2019-2024 (MWl 2019-2027 (MW) r Wind r Solar r Solar+8at r Wind r Solar ISolar+8at I Wi r Wind+Bat a Bat r Pump Sto rWind+Bat t Bat i Pump Sto r Wi P.3,cr :.::: = i.liiP'36c -!, t*c I P4scp+sc I e-oc fr P46cP46C I P-f6r23c I P''5123c I P$nlc pczc - crzc f P47c p-rsc I P'aac I P'4ac p-src I P-ssc I P-5lc c-s:nrc ;f P-s3n3c I P-53r?3c P,54c I P-54c I P-54c 0 5,m0 10,0m 15,0m 0 5,mo 19000 1t0m 0 5,m0 10,0m 15,0m Notc: lor wind or rcnervable resources paired with battcry, the capacity fbr thc reneu'able resource is shor,r,n in the graph. The battery capacity paired $'ith these resources is f5 percent ofthe renewable resource capacity. Incremental Demand-Side Management (DSM) Figure 8.ll summarizes aggregated DSM sclcctions by case. Selected volumes ol DSM are relativcly stablc among all C-series cases. On averagc, Class 2 DSM capacity totals 826 MW through 2024, 1,257 MW through 2027, and 2,299 MW through 2038. On averagc. Class I DSM capacity totals 29 MW through 2022,45 MW through 2027, and 485 MW through 2038. F'igure 8.1 I - C-Series lncremental DSM Summary P46r23C P47a ,*a- mary Renedstorage 2019-2038 (MW) nd ! Solar I Solar+Bat nd+Bat r 8at r Pump Sto - o 1,m0 2,000 3,m0 NSr[N\$NilISINSNNilreM$NNN -s$sNNI DSM 2019-2038 (MW) r Class 2 Class 1 a-rra- p-36C oor.- o*.- P llc p-35C p{5c p.t5c PSp3C p17C p.a8c P-5:tC P-t3r3C p-54C p-3tc P-36C p{5c P.46C P.4613C P47C p.48C p,53C p,53n3c P-54C P-5lC P-5:t.t2tc P,54C DSM 2019-2024 (MW) r Class 2 class 1 IIIIIIIIII DSM 2019-2027 (MW) r Class 2 Class 1IIf - IIIIIII o 1,m0 2,m0 3,mo II 0 1,m0 2,mo 3,mo New Natural Cas Resources Figure 8. | 2 summarizes cumulative natural gas expansion resources for each C-series portfolio. ln cases whcre Naughton 3 converts to natural gas, it is assumed to retire at the end ol'2029, so it does not show up in the results through 2038. Each case includes the large gas conversion of Naughton Unit 3 in 2020, and includes 185 MW ol'new peaking gas capacity in 2026. Case P-36C includes 1,356 MW ofnew peaking gas through thc cnd of2038; all other C-serics cascs includc I ,367 MW of new gas peaking gas capacity through the end of2038. None ofthese cases include nov gas CCCT capacity. 223 l]!l::!$l:::l:U\-\\\\\\\\\r PA( rFrCoRP 2019 tRP CIIApTER 8 Mot)t:t.lNG ANr) PoR rrju.ro SLI-tlc rIoN RESIiLTS ,31C , 364 D+5C P.18 4 p-5lc p 5lr23c p 54C P-31C P-:t6C P{5C p-a5c P.a6123C P47C P-aac P.53C P,53r23C P-54C P{5C P.t6C P46123C P47C P-4aC P-5lC P.5!A3C TrrrIIIIII Gas 2019-2038 (MW) I Peaker I CCCT Gas Conv P-31c - p.36c- ----1,m0 2,m0 1,m0 2,m0 P 54c - 0 1,m0 2,000 Front Office Transactions Figure 8.1 3 summarizes the average of FOTs for each C-Series portfolio during the summer and winter peak periods. The summer and r,r.inter FOT limit assumed firr the 2019 IRP is 1,425 MW. Market reliance is reduced in the 2025 to 2027 timeframe, coinciding with the addition of new transmission, new wind, and new solar+battery resources-on average, summer FOT purchases are 406 MW per year over this period. Longer-term, summer FOTs increase similarly among these cases, on avcragc ranging between I,310 MW and 1,361 MW each year lrom 2028-2038. Winter FOTs remain well below the volumes included in each portlblio to cover the summer peak period. 0 0 224 Figure 8,l2 - C-Series New Natural Cas Resource Gas Gas 2019-2024 (MWl 2019-2027 (MW) lPeaker rCCCT 6asConv. lPeake. ICCCT 6asConv. P,\( rl,rc(nP - 2019IRP CHApTER 8 - MODIL|NC ANr) P( )R r rol-ro SELucTtoN Rt,sr]1. rs Figurc 8,l3 - C-Series Front Office Transactions Summary P-31C P-35C P.4tic P.a5C P-46A3C P47a P.48C P-53C P-53J2lC P-54C r-atc !rrc !n+c !p..6c Ie+nrc ! PaTc I P{sc I P-s3c I e-srnrc !c-rc ! 0 P-3tC p-36C p{5c P{5123C P-53C p,5l12lc P-54C p-3lc P-36C P{5C P.l6C P$n3C p47C P'EC P-53C P-53123C p-54C P-53C P-53r3C P,54C Average Annual Summer FOT 2019-2024 (MW) IIIIIIIIII Average Annual Summer FOT 202s-2027 (MW) IIIIIIIIII 0 sm 1,m0 1,500 Average Annual Summer FOT 2028-2038 (MW) !.lIa p-36C Prsc- r*c- p{6,r23C P-.7c- o-o8c- o 5m 1,mo 1,500 Average Annual Winter FOT 2019-2024 (MW) 0 5m 1,m0 1,500 Average Annual Winter FOT 2028-2038 (MW) IIII!IIIII 0 5m 1,m0 1,500 Average Annual Winter FOT 202s-2027 (MW) c-rrc ! r-roc f P{5C P.46C P.46J23C P47C P4{lC p-53C P-5123C P-54C sm 1,000 1,500 o 500 1,m0 1,500 TI I TII I P-31C p-36C P45C p-15C p-46n3C P.4aC p-53C p-53123C P-5/tC CO: Emissions Figure 8.14 reports cumulative CO: emissions for each C-series portfolio. Total CO: emissions is similar among these cases through 2027. Through 2038, total COz emissions range between 550 million tons (case P-36C) and 588 million tons (case P-3lC). Figure 8.14 - C-Series COz Emissions Summary Emissions 2019-2024 (Million Tons) I - I -- T - I - I Emissions 2019-2027 (Million Tons) ---------- Emissions 2019-2038 (Million Tons) p-3lc p-36Cp-c5c- P-31C p,36C P45C p46ArC P-53C 9-5ln1C p-54C P.a6J2lC P{ac P-53C p-53J2rC - - \e n€ .re se o,,e b&o .e .u€ n,€ $& 0.,8 b8 o ."e ^,8 ,,& be qe (oe o 225 P^C II IC()RP 20I9IRP C Series Case Cost and Risk Summary Tlble 8.f - C Series Case Cost and Risk Results Summa PacifiCorp identitled the cases in bold in Tablc 8.3 as top-perfbrming cases selected fbr more relined analysis in the next step ollhc portfolio-development process (cases P-36C, P-46JC23C, P-47C, P-48C1, P-46C, P-45C, and P53C). While cases P36C does not perl'orm well on cost metrics relative to thc other cases, in responsc to stakeholder interests, PacitiCiorp insluded this case the list of top-performing C-series cases given its high ranking in total CO: emissions. Figure 8.15 summarizes the stochastic mcan PVRR relationships among the C-series cases in the "f'amily tree" firrmat summarized in Volume I, Chapter 7 (Modeling and Porttblio Evaluation Approach). Dollar ligurcs associated with each case represent the incrcase in system PVRR relativc to thc lowest-cost case (casc P-47C). Slochastic Mcan Ri|t[ Adjrlstcd tiNS Alerllre Percent of I -oad CO: lir)i\sionr Case PVRR ($m1 Change from Lo\resl Cost Porttolio ($m1 Itxnl PVRR (Slr), Change Lowest Cost Pontolio ($m;ltanl Average AIlnual F]NS, 2019- 2038 0/o of Average Load Changc from llNS Ponlolio Rank Toral CO2 F.missions, 2019"2038 ( fhousand Ions) Changc fiom Emission Pontblio RaDl Pl7(-:-!. t 98 s0 2J.-167 s0 0.012%[.llt2t'/o 573.0ti8 22.1r55 7 P{lt(23.721 s:-l 2.l,3rI \:1 0.0 | I .r,lt.00t,z,567,025 16.192 P{6('s80 .l 2J,t62 s95 -1 0.01I %0.00t,2, 7 5 3 560,? l0 { P{5('21.283 sli5 J tl,168 \llrl I 0.010%0.000,2,578.607 2lt-17{8 tt6,Izlc 2-1-1t 2 st t.l ,{,-{lJlt st2l 0.0 t l%551.673 -r,.t.10t.|020/r P5-',1( l 2-1,1t0 sr 12 2l.s:ll st6t 6 o.ll t.t,0.00t,2,.l 562,972 r2.739 5 Pr t('ll.37.l $ I 7t,1 21,562 $le5 8 0.010_0n 0.0(x)%588.111 l8.l{)l P5.l(t:t.l8l s l3,j 8 11.558 s l9l 7 0.0119.n 0.00:oo 6 58t.165 P5 rjli(?l,l9l sl9l 2.1.570 $20.i 0.0 [0,ll-lX)l9h 8 556.990 6.757 P.T6C 23,1.10 S23I 2l,6tJ s2l7 0.013%0.001.1,5s0,2-r3 0 226 CIl^pllllr8 Mot)t.].tN(i A\D PoR ()Lto SELIT( ItoNRr-sUt-ts I 2 9 l0 rl I to t0 llt I re 8.15 - Relative Cost of Stochastic Mean to the Lolvest-Cost C Series Casc ln thc CP-series ofcases, top-performing portfolios liom the C-series ofcases are further rctlncd. The CIP-scrics includcs thc additional solar+battery analysis, and to cnsure that there is no potential lor an inconsistent application of annual reliability requirements bcyond 2030, adds seven additional years (i.e., 2031-2037) of hourly deterministic analysis to the reliability assessment. This addition yields a total of l6 deterministic studies covcring the period 2023-2038. This reflnement further improves the granularity at which reliability resources are applied and therefore provides an improved comparison of cost and risk metrics between the top-performing cases. The rcsulting portfolios werc also evaluated among a range ofprice-policy scenarios. CP-Series Portfolio Development Coal and Gas Resource Retirements Figurc 8. l6 summarizes cumulative nameplate coal and gas relirements for each CP-series case over the near-term, mid-term, and long-tcrm. Note, in reporting cumulativc capacity in this ligure and thc similar figures that lollow, the mid-term results include uapacity retired in the ncar-term, and similarly, thc long-tcrm rcsults include capacity retired in thc near-term and in the rnid-term. Unirspecific retirement dates for each casc can be found in Volume tt, Appcndix M (Case Study Fact Sheets). Through 2027, aotal coal retirements rangc betu'een 2,441 MW (case P-45CP, P- 47CP, P-48CIP) and 3,499 MW (casc P-36CP). Through the end of 2037. tolal coal retirements approach 4,500 MW in each case. 227 Too Periormim P-36C P-45C P 46C P.45r23C P-48C P,53C S176m S 193m 580m 523m l42m5A5m SO @ Su4m ] P^clr,lcor{P l0l 9 lRP ClrAprER 8 - M0DILING AND PoR .ot.to SF.LECTIoN Rtisut.TS CP-Series Portfolios P-46C ,83-4 RET 25 P-45C ,81-2 RET 23,28 P-53C ,81,2 RET 25,I83 RET 28,I84 RET 32 P-36C ,81.2 RET 25 P-46J23C ,83.4 RET 23 P-47C J83.4 REI35 P-48C J83"4 REf 33 | stsrrl ,82 RET 24 t81-2 REr 23 P-31C NT3 tg. GC, CH4 RET 20, N-T1.2 RE] Figure 8.16 - CP-Series Coal and Cas Retirements Summary Coal/Gas Retirement CoaUGas Retirement 2019-2024 (MWl 2019-2027 (MW) r Coal Gas r Coal Gas e-:oce ! c+:ce ! r.mo ! c-lonrcc ! e<tce I r.*ce ! c-srcc ! 0 2,m0 4,000 6,000 8,000 p.36Cp p!6123Cp p,36Cp p.45CP p.a6cp P46l23CP P17CP P.4aCP P-53CP p45 o 2,m0 4,m0 6,m0 8,mo Coal/Gas Retirement 2019-2037 (MW) t Coal i6as -i) -tl --'1 - - - 0 2,m04,000 6,m08,000 IIIIIIIP4ACP P-5!CP New Renewable and Storage Resources Figure 8.l7 summarizes the nameplate capacity ofnew renewables and storage resource additions for each CP-series case. In all cases the SO model selects Encrgy Cateway South in 2024 (a proxy for year-end 2023\ along with 1,920 MW of nerv wind in eastem Wyoming. Through 2027, new renewable capacity ranges betrveen 3,339 MW (case P-47CP) and 4,409 MW (cases P-46CP and P-53CP). Ily the end of2038, nerv rcncwable capacity ranges bet*,een 9,512 MW (case P-45CIP) and 9,574 MW in the othcr four cases. Nerv battery capacity ranges between 587 MW and 729 MW through 2021 and over 3,300 MW by the end of2038. Figure 8.17 - CP-Series New Renewable and Storage Resources Summary Renew/storage Renew/Storage Renew/Storage2019-2024(MW) 202s-2027 (MWl 2019-2038 (MW) rWind n Solar a Solar+8at rWind r Solar r Solar+Bat rWind rSolar a SolartBat rWind+8at tBat iPumpSto rWind+EatrBat r PumpSto rWind+EatrBat rPumpSto r-rce f c,roce f "-35c" I c<scc f e+ce f P{5ce I caocr Nort::tco A\ o.roco $ o+orz:co \N p4ncP P.46J23CP e.ozce f crzcc f crzcc f arace f r-cce J r*." - e-::ce f e-s:cr f c-srce f 0 5,m0 10,0m 1t0m 0 5,m0 10,0m 1t0m 0 5,m0 10,0m ls,om Note: For wind or renewable resources paired rvith battery, tho capacity for the renewablc rcsource is shown in the graph. The battery capacity paired with thcsc rcsources is 25 percent ofthe renewablc .csource capacity. lncremental Demand-Side Management (DSM) Figure 8.18 summarizcs aggregated DSM selections by case. Selected volumes of DSM are relativcly stable among all CP-series cases. On average, Class 2 DSM capacity totals 826 MW through 2024, 1,259 MW through 2027, and 2,306 MW through 2038. On average, Class I DSM capacity totals 29 MW through 2024,45 MW through 2027, and 487 MW through 2038. 228 PAClr,rCoRP 20l9lR?CHAPTER 8 - M(n)LLTNG AND PoRTFoLro SEr.r.c'rroN RtisulTs N P^( [,rCoRP-20l9lRP CH,{p ftill 8 - MoDEl.rN(i ANt) PORTFot.to SLI-IC I loN R]:slI ts Figure 8.18 - CP-Series Incremental DSM Summary P-36CP P{5Cp p.t6cP P{ir23CP P17CP P-4aCP P-53CP p-36CP P{5CP P.l6CP P4{J23CP P47CP P.{acP P-53CP P-36CP P-{atcP P45CP P.16t23CP P{7CP P46CP P-53Cp DSM 2019-2024 (MW) r Class 2 . class l IIIIIII 0 1,m0 2,000 3,m0 1,m0 2,@0 DSM 2019-2027 (Mw) r Class 2 Class 1 0 1,m0 2,000 3,000 1,000 2,m0 DSM 2019-2038 (MW) r Class 2 Class 1 0 1,m0 2,m0 3,@0 Gas 2019-2038 (MW) I Peaker . CCCT Gas Conv 1,m0 2,000 New Natural Gas Resources f igurc 8.19 summarizes curnulative natural gas expansion resources for each CIP series portfolio. ln cases whcrc Naughton Unit 3 converts to natural gas, it is assumed to retire at thc end of2029, so it does not show up in the results through 2038. Each case includes 185 Mw ofnew peaking gas capacity in 2026. All CP-series cases exccpt case P-36C include 1,167 MW ol'new gas peaking gas capacity through the end of 2038. Case P-36CP, includes 210 MW of gas peaking oapacity over and abovc thc othcr CIP-scries cases, added in 2028. None ol'the cases include ncw gas CCCT capacity. Figure 8.19 - CP-Series New Natural Cas Resource Gas Gas 2019-2024 (MWl 2019-2027 (MW) r Peaker rCCCT GasConv. r Peaker rCCCT GasConv.IIIIIII 0 p-36Cp p.t6cp P4 73Cp p-4€cP p,53Cp IrIIIIr P 36CP P45CP P4 21CP P-48Cp P.53CP P.36CP p{5cp p.45CP P{ttJ23Cp PAtC9 P.a8Cp p-53Cp 0 Front Oflice Transactions Figurc 8.20 summarizes summer and u,inter FOTs for cach CP-series case. The summer and rvinter FOT limit assumcd tbr the 2019 IRP is 1,425 MW. Market rcliance is reduced in the 2025 to 2027 timefiame, coinciding with the addition of ncw transmission, new wind, and new solar+battery resources-on average, summer FOT purchases are 4[ I MW per year over this pcriod. Removing P-36CP (an outlier rvith nearly double thc FOTs ofother CP-serics cases) lrom the mix yields an avcrage of 344 MW per year. Longer-term, summer FOTs increase similarly among these cases, I o I 229 ['^crr,rCoRP f0l9lRP CHAPTLR 8 - MoDEt,tNG ANI) PORTITOLIo SH-ECTtoN RI-.sl it,ls on average ranging between I,31 0 MW and 1,334 MW each year f-rom 2028-2038. Winter FOTs remain well below the volumes included in each portlirlio to cover the summer peak pcriod. Figure 8.20 - CP-Series Front Office Transactions Summary Average Annual Average Annual Summer FOT Summer FOT 2019-2024 (Mw) 2025-2027 (MW) ,-aocc f c-:occ f o*.0 f "*." ! ,.rcc" f c.noco ! ,.orarco ! r*orc, f o.r.o f o-n.o ! "*." ! ,*c" ! c-sa." f ,-.r., ! Average Annual Summer FOT 2028-2038 (MW) P,36CP P{5CP P.a6CP P.|5n3CP P47CP r.4acP P.53CP o 5m 1,mo 1,500 Average Annual Winter FOT 201e-2024 (Mw) o*.0 ! P-36cP ".:c" ! p{scP ,*." ! p..6cP ,.rcrzrce ! P46n3cP ".r.r ! pltcp o*.0 ! P..acP o-tr." ! p,53cp 0 5m 1,000 1,500 Average Annual Winter FOT 202s-2027 (MW)I 0 5@ l,mo 1,500 Average Annual Winter FOT 2028-2038 (MW) r-:tc, ! c-nscc ! e<rcc I "nerzr" I ,ara, I ,*a, I o-trao I 0 5m 1,m0 1,500 0 5m 1.mo 1,500 0 5m 1,000 1,500 CO: Emissions Figure 8.21 reports cumulativc CO: emissions for each CP-serics portfolio. Total COu emissions is similar among these cases through 2027. Through 2038, totat CO: emissions range between 558 million tons (case P-46CP) and 577 million tons (case P-45CP). t30 lr\('I rCoRr, l0l9 IRP CIIAp'fl,R u - MODELING AND PoRTlot,to Sl].HCTtoN RLSLTLTS Figure 8.21 - CP-Series CO2 Emissions Summary Emissions 2019-2024 (Million Tons) Emissions 2019-2027 (Million Tons) Emissions 2019-2038 (Million Tons) IIIIIII p-l6cP P-a6CP P-46r1CP P.$C' P{5CP c{6)2rcP P-53CP o \B a& ",e $8 or& be o ^,8 18 ,,,8 s&,r& b8 \8 a8 De $e eB (oBo Figure 8.22 shows the annual emissions profile for each ofthe seven CP-series oases through the end of the planning period in 2038. F'igure 8.22 - Annul CO: Emissions among CP-Scries Cases 70\9 ?020 2021, 2022 2021 2024 +P-45CP +P.46CP 7075 Z026 2077 2028 2029 2030 2031 2032 2033 2034 2035 2016 2037 203E .+P 47CP -.--C-48CP +C 53CP -FP-35CP <bP-46i23CP CP-Series Cost and Risk Summary The Ibllowing tables and figures report the results of the CP-series cases for four pricc-policy scenarios. Each scenario assumes a low, medium or high gas price future, combined with eithcr a zero, medium or high CiO: price f'uture. ln addition to the seven CP-series cascs, results from the tive initial portfolios that were devcloped under varying naturul gas price and COz price assumptions are presented (cases P- [6 through P-20). CP-Series Medium Gas/Medium COz Scenario ln the medium gas/medium CO: price-policy scenario, Case P-45CP outperforms other cases on stochastic mean costs, risk-adjusted costs, and energy not served (ENS). While case P-45CP has higher cumulative CO: emissions, the case with the lowest cumulative emissions (case P-36CP) has a risk-adjustcd cost that is $235m higher than casc P-45CP. Further, as shown in the figure above, the annual emissions profile among the CP-series ofcascs is similar. None of the pricc- policy cases outperlbrm case P-45CP on cost metrics. 50 45 40 35 .30 e2s .E ro =rsl0 5 0 23t p-5lcp CIL\prER 8 Mot) -tNC AND P0RTFO|.to SF],ECIIoN RhsULTS 'I'able 8.4 - CP-Series Nledium Cas/Medium CO: Results Summa Table 8.5 - Price-Poli Cases, llledium Gas/Medium COz Results Summar ENS Avcraae Percent ol'l.odd CO2 E issn,ns I)YRR (sm) Ch8nge ($m1 (s,,1 Change from Cosr Ponfolio (Sm) ENS, 20t9- zo3a v" ch8nae ENS Portfolio Toul ( ()2 2019-10:18 ChdBc prscp I z.,.,,nr .lt.l0r $rl :18,.161 ,]0.0l 1n P+6CP I ,|s ,1 0.0l.io,o 557.8:.r : r.ll9 ll.l9l sl? 18 l 8.197 :.610 $ li6 (i 5t.t,il.l 0.0t1,,i 0.001% ,{:lt l.t.is5 slls 0.0n'ti i.l0.ll7 IiNS ^r..!rc Pcrc.nl ol t-oM ( o: Enrissions l,\]tR rS ') Chtnse Co3r Podolio(lm)PvRR tSmr Chdge (sm) ENS. :019, 2038 % t:Ns ToralCO2 Emissions, 2019-2018 t1.ll89 'r(l15,097 tlt,lit.l Ptt $1r rIr.000 la.:tr s 5 0 0009'.607.157 t80,017 l lJ.l8l $:el l l5-'100 0.057".,;,l8,l8l : tl8 ,ltr.l76 ti.60l 5506 l tt7. n0 tt0 .tt. ll 8 st.l:9 t6.t3i !t.lltll 180.0.r7 l z )l PACIFICORP 20I9IRP CP-Series Low Gas/No COz Scenario ln the low gas/zcro CO: scenario, Case P-45CP outperforms other cases on stochastic mean costs, risk-adjusted costs, and ENS. Whilc P-45CP has higher cumulative CO: emissions, the case with the lorvest cumulativc cmissions (case P-46J23CP) has a risk-adjusted cost that is $222m higher than casc P-45CP. l]urther, as shorvn in the figure above, the annual cmissions protile among the CP-series ofcases is similar. Cases P-16 and P-19, rvhich were developed without a CO: price assumption and with low gas price assumptions, rcspectively, are among the top-perlorming price- policy cascs *'hen analyzed in a low gas/zero CO: price-policy sccnario. I 21.t60 I 28,0t1 1.1.171 7 6 0.001o.i l :1..]03 sll]1.1_.178 55:.065 :J.l.l8 I l.l17 PJ6CP :1..1t1 7 sr3 I 5I .l l P^crr,rcl)rrP l0i9IRP CHAPTER 8 I,loDLt-t\G A\r) PoR II ot.to SELI:C lloN Rl:sl ]t. rs Table 8.6 - CP-Series, Low GaslZero COz Results Summa Table 8.7 - Price-Polic Cases, Low Cas/No COz Results Summa CP-Series High Gas/High COu Scenario In the high gas/high COz scenario, Case P-48CP outperfbrms other cases on stochastic mean costs and risk-adjusted costs. Case P-45CP ranks second in sbchastic mean and risk-adjusted cost and first in ENS. While P-45CP has higher cumulativc CO: emissions, the case $,ith the lowest cumulative emissions (casc P-36CP) has a risk-adjusted cost that is Sl55m higher than case P- 45CP. Further, as shown in the figure above, the annual emissions profile among the CP-series of cases is sirrilar. Cases P- I 8, P-20, and P- I 7, which werc developed using a social cost ol' carbon CO: pricc assumption, a high gas price assumption, and a high CO: price assumption, respectivcly, are among the top-perfbrming pricc-policy cases when analyzed in a high gas/high CO: price- policy scenario. Ri.l, \rlj \r.l UNS r.ruse Percenr ol'Load CO: L rissi(rr PVRR ( sml Change Cosl Ponfolio (sn) INS, 2019- 7O3t'/o or Change fmm ENS Podlolio l.r!l( ()l :1I9,:0I{ Chang. PVRR {Sn) Chrngc ftom Cosl Ponfolio ($m) t0 21.105 0_lIllri,0.000%2lt.a0ltD.09l : l.l.ll 5:l-661 :0.17:l I1.187 0.0l],h i(,7.t61 I l7.Ei,).l .l :1.105 tr:01 I 555,.11: | 6.018:0.18i 5 2l,Jt7 s::r:j 0.001% I){61:t( t':0.106 $lol $lll ll,3.l9 $:15 5 -lPtl( P t0.i:7 $t.r.l 0.0l]%Ir.88: :t.l9l $l.09li :.1,u6{)577..$t).18. l]5 I:NS ,\vsage Percenl ofLoad P!'RR ($m) Chdg. Cosr ($m; ENS, 2019- 2O3AY. Ch Se El.lS 'IbtalCO? 20t9-?0lE ChdBe PVRR ($m) ChoB. Cost (3m) :0,,r:7 67.1.1ll.lSO ,]$i3l +:0,I9.1 57.16 189.:6() lP.l0 .l0.Nt l : l.tli I s r,151 570,150 sl_i65 ,t ll.07l ! 1.6.r-l "l .l .1o5.998 .r7.tt.lI Lo l:i 5i.l60::..r56 -111 I I I I 'l'able 8.8 - CP-Series, Hi h Gas/Hi h CO: Results Summa Table 8.9 - Price-Polic Cases, Hi Gas/Hi h COz Results Summa As rvas discussed with stakeholders al the October 3-4,2019 public-input meeting, PacifiCorp applied social cost of carbon CO: prices to this price-policy scenario analysis such that the price for the sooial cost of carbon is reflected in market prices and dispatch costs. Consequently, it assumes that system operations (plant dispatch and market transactions) are not aligned with actual market forces (i.e., market transactions at the Mid-Columbia market do not reflect the social cost ofcarbon and PacifiCorp does not directly incur emissions costs at the price assumed fbr the social cost of carbon). Consequently, and unlike the othcr price-policy scenarios reviewed above, the modcl results for the social cost ol'carbon price-policy scenario represcnt cost drivers that are materially divergent from the cost drivers in the market. This creates challenges in understanding how to interpret the results from this price-policy scenario. INS Av.msc Perccnt ofload PVI'R ($'n)(sm) PVRR t$m) Chanse Cosr Podfolio ($m1 ENS. 20r9- 2038 o/t Chrnsc lNs 'lolal COI :0t9-:0i8 Chans. Plt( P 17.',l36 $r)lr.l]5 $0 0.011%t8.:I 221.;tr6 551 29. t lt't 2 0.010%5?t,61-t 2?.550 P.I7CP tq.t08 s7:0.011,.n l,.16l:lcP 17,8 t:Sr6 J 19.:15 si9 I 5.19.1i1 ? t7.nt.l $7E 5 :9.:17 sill 5 0.0lt9n 0.01.1%u lT.tilJt st15 19.:q0 0.0110..n$t55 0.00lqd l :7.88e s 161 0 0t]q;5 :56.:01 I l.loli .t ENS Ave6J.e Pereenl of L.ad COI Ilnissi{,ns PVRR ($n;PVRR (sm) ch6nc" Cost Ponfolio (Sm) ENS, 2019- 2038 % Lo8d Chmgp ENS 'lolalcoz l0l9-2038 Changc EnJssion ,r,rr, I s0 t9.187 0.1ll9,.n 1.618i(r 0.105.. t,l0 l18,197 | $6 rl 19.81:l l I.l1. t65 l t,ti _18,818 | St.071 l0,l ll $l. t:5 .t s t.4.le 10.701 ll.5l4 .l :598,587 5:_n(,1 1:.r ?o 65.1.96.i :ll.r li thcrr,rCoRP 2019 IRP CrrAp Ilrtt 8 l\4ot)t r rN(; AN1) PoR It.ot.to SItr.!,(' rroN Rr,sL r rs CP-Series Social Cost of Carbon Scenario In the social cost of carbon scenario, case P-46J23CP outperforms other cascs on stochastic mean cosls and risk-adjusted costs. While case P-45CP ranks sixth in thesc metrics and first in ENS, case P-46J23CP has a risk-adjusted PVRR cost that is Sl l8m higher cost than P-45CP when the medium gas/mcdium CO: price-policy assumptions is applied. The highest ranking ponfolio u,ith rcgard to cumulative CO: emissions is case P-36CP. Case P- 18, which was developed using a social cost ofcarbon CC): price assumption, is among the top-performing price-policy cases when analyzed in a social cost ofcarbon price-policy sccnario. Case P-18 has a risk-adjusted PVRR that is over S l.2b higher cost than casc P-45CP when medium gas/mcdium CO: price-policy assumptions are applied. 1 7 7 5 I Table 8. l0 - CP-Series Social Cost of Carbon Results Summa Table 8.1I - Price-Polic Clase Results Summa Based upon the rcsuhs summarized above, PacifiCorp identified case P-45CP as thc top- perfirrming case in the CP-series ofcascs. Relative cost dilTcrcnces between case P-45CP and thc cascs with the lowest cumulative CIO: emissions (cases P-36CP and P-46J23CP) do not support considcration ol'these trvo cases for potential selection as the preferred portfblio. Highcr FOT costs from market risk increased the PVRR by sirnilar amounts among the cases, 3820 million (3.6 percent), on average. Case P-45CP has a risk-adjusted PVRR that is $25m highcr than Casc P-47CP, which has the lorvest PVRR when higher FOT costs are applied. 235 tiNS r eracc l,.rccnt ol Lord COI Emisi{,ns ($m) ChdA. ($m)l{rnl PVRR(s-l Chansc ($m)Rulli l.Ns, 1019. 201t,r; ENS I oBl C()l :019,:0ttr Tons) P.16Jl1( l'$0 t8.19.1 $0 000396 .l .l I l.1tq l :r,4os I Jn :'iI 16.701 0.0 t :11,;.tl.1.-tt0 l' l l\( lr ,1 18.6{'tr:5.r .l l 5 5 18.68t $]17 0.(ll9b + 6.798 $:iJ ,:rl 1tt.07:l I I8.1 16 t8.10{ l:,t47 s-!79 38,rrl 0.0t0,r,t-l2.168 s.!1t .ll9.ltl t.l..It: tiNS veEAe Pucsr ofload P!'RR ($m) Change ($m) P}RR ($m) Change (Sm1 ENS, 2019- 2038n/o Ch8Jlee ENS lilal CO? l0t9-:018 Cha8c l,t\l7.0il 0.1 tl'ri l:t.oi)t)15.176 :,r8.li7 $ t. t97 l 0 05r%.1 2t,l7 $t.t19 0.057%166.t:0 .li.:l I l9,.tll $1.110Pt0-17.:t7 $l.l5l l ll7,ll2 6.l.l.l l $l.l:0 I 10.:l.l.l t t.:E.l 1 l ,l 19.71:54_.r]6 .ll.r-1i PACr[,rCoRP - 2019 IRP CHAPTER 8 - MoDELING AND PoR tr,ot.to SELEC noN Rtstil-t s Front Offi ce Transaction Portfolios Five ofthe CP-series cases (all but cases P-36CP and P-46.123CP) rvere further analyzcd fbr FOT risk. The [.OT studies are designed to quantily the impact and risk ofmarket reliance. As detailcd in Volume I, Chapter 7 (Modeling and Portfblio Evaluation Approach), these cases use an escalating scalar to clcvatc market prices during the peak months ofJuly, August and Deccmbcr ofevcry study year. This has the eflect of increasing costs for market purchascs or fbr acquisition ofthe altcmative resources required to avoid the high market prices. These results suggest that the risk ofhighcr FOT costs is not matcrially dill'erent between cases P- 45ClP and P-47CP and these results do not justily driving the selection of any over the other CP- series ofcases as benelicial to case P-45CP. l16.:55 I I 1 5 P^( ll,rCoRP 20l9lRP C Ap ltiR I MoDtil-tNC,\ND PoR lt.( )r.ro Sl't-[1]'toN RESI rl. ts Table 8.12 - FO'f Case Results Summarv Ca5e Slolh stic N{ean Risk diusled ENS Averagc Pcrccnt ofLo.d (lOl l.nris\i(,ns PVRR (sm) Change ftom Lo$est Cost Ponfolio ($m)Rank PVRR ($m.1 Change Iiom Cost Ponlolio (Sml Rink Avcragc ENS, 20t9- :018 0,r of Average Load Change fmm l.tNs Ponlblio Rank Tor.al CO2 Emissions, 20r9-2038 (Thousand Tons) Change liom Lowest llmiss rn Porrlbtio Rank l,+7( P :1.001 SO :5.20q | $0 0.010u.i lr.lx)lroo l 5l5.l]]7 ll.l l7 l P.l5( P t.l.ot.l sti st5 5.10.1ll t7.62i P.l8( P l.l.r)9E li97 15.l lt $l0l 0.012%I t.l tq P.+6( P $911 4 25,1l4 s r05 4 0.01i%0.001_0,1,522.5t0 o P5t( P 25, t8l I 525.161$ 173 0.0lr9n Table 8.13 - FOT Case S stem Cost Im act Summa t-t.16-l s t6i 2028-2029 Wyoming Wind Case As detailed in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach), PacifiCorp identified that 620 MW of Wyoming wind resources added to each portfblio in the 2028-2029 timelrame, which coincides with the trssumed rctirement of Dave Johnston, were being curtailed at rclatively significant levels through 2038, capacity lactors average 32 percent, down from the 43.6 percent assumed without curtailment. From 2029 through 2033 the level of curtailment is higher, with output falling below a 30 percent capacity factor. Upon observing this modclcd outcome, PacifiCorp produccd an nerv portlblio as a variant ofthe least cost CP series casc (P-45CP) that eliminatsd the 620 MW of incrcmental Wyoming rvind coming onlinc after the retirement ol'Davc Johnston.'fhis case is ref'erred to as P-45CNW. While the stochastic mean PVRR olP-45CNW is $ l5m higher than case P-45CP, as illustrated in Figure 8.23, PacifiCorp advanced Casc P-45CNW as the baseline fbr evaluating additional "No Neu, Natural Gas" and Energy Gatervay transmission cases on the basis that it is not rcasonable to include heavily curtailed wind resources in the leading case for the pref'erred ponfolio. Further, the shifts in system costs contributing to the $l5m increase in system PVRR are all beyond thc action plan windorv, which will allow PacifiCorp to continue to evaluate potential incremental wind additions in eastem Wyoming when Dave Johnston retires in future IRPs. 236 Sl()chrslic N4can Crsd PVR R (Snr) Change froln CP Portfolio ($m)R.rnl P.I7L'P l-t.0r)l sTll: P1511't-l.0t.l snl:.l P.18( P l-l.r)()N sx9l P.l6( P 11.099 $tio7 l.l.l6.l $8 t5 Table 8.l2 reports FOT casc evaluation results. Table 8.13 quantifies the increased system cost ol' cscalated FOT pricing compared to the system cost of each portfblio under the medium gas, medium CO: price-policy scenario. I 5 :r 5 5 0 00ic;2.tt5.l P53( P P^crnCoRP - 20l9lRP ('H,\ptt:R8 Mornir.rNC ANI) PoR r )t lo SI,LEC.I()N l{l'suL ts Figure E.23 - Wyoming Wind Alternative Portfolio and Cost Evaluation Dave Johnston New Wind Curtailment Difference in System Costs .9 ,f 0 (s) (10) (1s) (20) s400 .E s* =s0.^ (s2@) (s4@) r_rlrrrrll "d,t"dr&""drrdi"dPre"rdi"e""d"&' -PaR P45CP -DJ Wind (43.6%) Dlfference in New Resource Capacity rvarrrbl. rFi.d .M€det .Ir.nmkaon Net Difference in Total System Costs 2,0@ 1,0@ 0 {r@o) {2,q)O} slo r-lpirrIl ; 20 10 50 {Sro) r Gc . R.n.w.bl. tr !!orq. Dk cr Lod cdrd r €n.r3y Elll.ie.cy . t6@r FOI - Ner (B.neln )/( 6r - - - cumut.u € PvRntd) Customer Rate Pressure Figurc 8.24 shorvs the differencc in the cumulative PVRR, as an indicator ol'rate pressure ovcr time, betwcen among the CP-series ol cases discussed carlier relative to casc P-45CNW rvhen applying medium gas, medium CO: pricc-policy assumptions. Cases P-36CP, P-46CP, P- 46J23CP, and P-53CP consistcntly trend higher than oase P-45CNW. Through 2024, cascs P- 45CP, P-47CP, and P-48CP track rclatively close to casc P45-CNW. Afrer 2024, cases P-47CP and P-48CP trend higher then case P-45CNW, and then start to converge u,ith case P-45CNW over the longer-term. 237 P^( [rcoRP 2019 IRP CHAp tER 8 - MoDELIN(i AND PoRTroLto SF.t.t:( oN RtsLrLTs rc 8.24 - Chan in the Cumulative PVRR relative to P-45CNW Portlblio Development Conclusions Based on the findings ofthc initial portfirlios, C-series ofcases, CP-series ofcases, the FOT cases uscd to analyze markst-reliance risk, and the case that eliminates highly curtailed Wyoming wind in the 2028-2029 timeframe, PaciliCorp identified case P-45CNW as the top-performing case at the conclusion ofthe portfolio-dcvelopment process. As described below, case P-45CNW serves as the basis for additional analysis to inlirrm final selection of the preferred portlblio. "No New Natural Cas" Portfolios The "No New Natural Gas" cases, delined in Volume I, Chapter 7 (Modeling and Portlolio Evaluation Approach), provide two views of impacts stemming from an assumption that no new gas resources are acquired through the end ofthe study period. The first case, P-29 does not allow the model to select new natural gas resources (excluding the Naughton Unit 3 gas conversion). The second case, P-29PS is a variant of P-29 with the addition of a 400 MW pumped slorage projcct located in northeast Wyoming that is assumed to come onlinc in 2028 following retirement ofthe Dave Johnston plant. As seen in Figure 8.25, case P-29 accelerates renewablc resources liom 2036 to 2032 and adds incrcmental battery storagc resources beginning 2030 relative to case P-45CNW. Under P-29, system costs begin to decrease in 2027, horvever over the long term, incremcntal costs f<rr new battery storage resources and market purchases reverse the trend. $215 s250 s225 $200 $175 g $150 E $r25 E $loo,a s75 s50 $25 s0 ($2s) ($s0) 20t9 2020 2021 2022 2023 2024 2025 1026 2027 1028 2029 2010 2031 2012 20lt 2014 2035 2036 2037 203n +P36CP .+P45CP .+P46CP +P46J23CP +P47CP <-P48CP +P53C]P 238 Preferred Portfolio Selection PACrr,rCoRP - 2019 IRP CltAp rrR [i Mot)E]t-tNG ^ND PoR l iror.ro SFr ri(r roN Rr.strt.l s Figure 8.25 - P-29 No Gas Case Resource and Cost Compared to P-45CNW Difference in New Resource Capacity j 2.0m r.000 0 11,0m) t2,0m) l],000) --IIITII,TI 2019 2020 2021 2022 ZO21 7(}24 2025 2026 2027 2028 2029 t030 2031 2031 2033 203a 2035 2015 203' 2038 a6.i a R.ms.8. .Stdri. Or.(LedC.flrol . L..r8v tll,o..(V .5!meriol Difference in System costs s.1C0 c i2c,os =ro6 (32m1 rrrrrrrll islc( | 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2035 2037 203E .v.nable ariEd .vrl.t .Iraiihl$D. Net Difference in TotalSystem Costs 5!i- ; rsl oo: l52C0l 20t9 2020 2021 2022 202) 2024 2025 2025 2027 2028 2029 2030 2031 2012 2033 2034 20rs 2035 2017 2031t -r|etloen€t0/co.r --- cumutaivepvRntd) Figure 8.26 summarizes P-29PS portfblio and cost differenccs compared to P-45CNW, eliminating new gas and adding pumped storage (400 MW) and battery storage (227 MW) in 2028. By the end ofthe study period, casc P-29PS adds an additional 1,575 MW of battery storage. System costs increase beginning 2028 with incremcntal lixed cost lor the storage resources, and added market purchases costs increasingly contribute to the added system costs in thc 2036-2038 timeframe. Table 8.14 summarizes the results ofthc "No New Natural Gas" cases. Both ofthese cases rcsult in higher costs than case P-45CNW. Neither case justifies altering selection ol'Case P-45CNW as the top-perfbrming portfblio. 239 l'^0l,rCoRP - l0l9 IRP Figure 8.26 - P-29PS No Gas with Pumped Hydro Storage Compared to P-45CNW Difference in New Resource Capacity ;: 2,000 1,000 0 (1,000) (2,000) --r=II-===rlI 2019 2020 2021 2022 2021 7074 2025 2026 2027 2028 2029 2030 2031 .Gas .R€ndatlr .sro.aee Dnet Load Co^rol .End8Y€ll'oeicv 2012 2033 2014 2035 2036 2017 2018 Difference in System Costs s400 c 52oo .9 Eo (s2oo) (9400) --rIIIII-IIIII I Irl 2019 2020 2021 2022 2023 2024 2023 2026 2021 av.i.bl€ r fir€d . 2029 2030 2031 2032 2031 2034 2035 2035 2037 2038 Net Difference in Total System Costs 5100 so 5 (sloo) = rs2ml ; (5300) (s400) (ssm) 2019 2020 2021 2022 2021 2024 2025 2026 2027 2028 2029 2030 2031 2032 203t 2034 2039 2036 2037 203a -Net l8enefi0/con --- cumutarive pvRR{d ) Table 8.14 - No Gas Results Summa Energy Gateway Transmission Cases PacifiCorp rnodeled fbur Energy Catervay transmission cascs, expanding on scenarios defined in prcvious IRP cycles. 'l'he full build-out of all Energy Gateway segments was performed in two cases (P-23 and P-25) to assess thc potential value in tu,o dill'cre nt coal retirement sccnarios. All of these cases include thc endogenous selection ol'Gateway South in 2024 (as a proxy for year- end 2023). Full case definitions for the Energy Gatcway studies are providcd in Volume I, Chapter 7 (Modeling and Portfolio Evaluation Approach). Slochaslic Mean Risk i\diLLned ENS Averagc Pcrccnt ofload CO: F:missions Clrsc PVRR ($m1 Chaage fmm Lo\resl Cosl Ponlblio ($m)R.url PVRR ($m)Rallk Average ENS, 2019- 203Ao/o of Average Load 'l otal CO2 Emissions, 2019-2038 ( Thousand Ions) Change from Lowest Cosl PoIrfolio (sm) Change from t,owesl ENS Portfolio Rink ChanBe fmm Lowest Emission Portfolio Rank PJs(NW | 2.1.2i17 s0 2.r,176 I $0 0.008'7"0.002,t1,2 585.6.11 ll,ln5 P:9 l 2.l,s0l I sllT {).01r0,r;580.116 :l.t:0 P]9PS Sllrt)l.l.11116 I ${i0 i76,806 0 CllAl,tr,R 8 M(n)ril.lN(; ANI) Pott lt(n ro Sl,l.r,( l IoN RIrsul. ts I I -1 :1,3:8 $1:r 0.0069/o 2i.6t6 0.0170;l 1 210 PA( rFrCoRp 20l9lRP Cl{AprER8 \4oDLt-t\(i ANr) P( )R It,()t.to St,r-t,c I Io\ Rr,sr l rs Case P-22 includcs thc approximately 200 mile Bridgcr/Anticline{o-Populus Energy Gateway transmission segment (sub-segment D.3). The stochastic mean PVRR olcase P-45CNW is S396m lowcr cost than Case P-22, driven primarily by D.3 transmission project costs where thc net portfolio cost impacts are largely offsetting. Case P-45CNW sees highcr market, emissions and DSM costs, but reduccd capital and fixed operations and maintenance costs that are aligned with the increased proportion of gcncrating resources as opposed to storage resources. Figure 8.27 reports portfolio and cost differences compared lt) case P-45CNW. Figure 8.27 - P-22 (Segments D.3 and F) Compared to P-45CNW Difference in New Resource Capacity 2.000 1.000 !o {1.000) 12,000) 2019 2020 2021 ?p22 2023 7024 1025 2026 2071 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 a6.. aR.n.w$k astort. o[e(r Lod (ovol . Ei.rd Litu.fty . tmmr fol Difference in System Costs lI--rrr "--rFH--:F:==;i=:==H s40o E 9200.9 =s0d {92@) IJ4@i 2019 2020 2021 2022 242' 1424 2025 2426 202t 2028 2029 !010 20ll 2012 20lt 2034 2035 2016 2037 2018 Net Difference in Total System Costs 9r00 s0 lsro) ts200t t53oo) ts400t t5500t E 20ll 2034 2035 2036 2017 20182019 2020 2021 7072 1021 2024 2025 202b 2021 - et(8.nefitl/con 202E 2029 2030 2031 2012 --- Cumul.nvePVRRldl Relative to case P-36CNW, case P-23 includes the approximately 200 mile Bridger/Anticline-to- Populus transmission sub-segment (D.3), the approximately 500 mile Populus{o-Hemingu'ay transmission segment (E), and the approximately 290 milc Boardman-k)-Hemingway segmcnt (H). A variant ofstakeholder requested P-36CNW, P-23 leatures early retircmcnt ol-the entire Bridger plant in 2025, and also Naughton Units l-2 in 2025. As secn in Figure 8.28, the reduction olthcrmal resources due to highly accelerated retirements sauses P-23 to accelcratc significant thermal and rencwable additions into 2028. 241 P-22 [valuation P-23 Evaluation T I I,^( II,IC()RP 20I9IRP Cl rAp lltR 8 - MoDI].lNLi ANr) PoR I l.ol,to SILI]cIoN REsut. ts The stochastic mean PVRR of case P-45CNW is S977m lower cost than case P-23, driven primarily by transmission project costs where the net portfolio variable and fixed cost impacts are largely olfsctting. Figure 8.28 - P-23 (Additional segments D.3, E, F and H) Compared to P-45CNW Difference in Coal Resource Capacity Difference in New Resource Capacity llllrllrlluT',: 2,00o 1,000 o o,mo) (2,000) T Tllllillll' 2,000 1,000 o l1,o0o) (2,000) $400 {Sroo) {s600t (s1,10O) I Difference in Costs Among Coal Units with VaryinB Retirement 5torasE Drc.r tord Control . Energy tffo.^.y .5ummer FoI Difference in All Other System Costs _--_-rrrrllllilllltrrlrrrltllll-5400 9 (5ro0)'E ts.*t (s1,100) Net Difference in Total System Costs E isoo .lo.9 = llsmlE -' - 61,om) (s1,50O) --- 2019 2020 2021 2022 2073 2024 2025 7016 2027 2028 2029 20:t0 2031 2032 2033 2034 2035 2036 2037 2038 -Net (8€neno/con --- cumulatiE PvRRld, Clase P-25 includes the approximatcly 200 mile Bridger/Anticline-to-Populus transmission sub- segment (D.3), the approximately 500 mile Populus-to-Hemingrvay transmission segmcnt (E), and the approximatcly 290 mile Boardman-toEHemingway segment (H). Although the Energy Gateway additions match case P-23, P-25 is a variant of P-45CNW. I'he stochastic mean PVRR of casc P-45CNW is approximately $LOb lower cost than casc P-25, driven primarily by transmission project costs rvhere thc net portfolio variable and fixed cost impacts are largely oflsetting. 242 P-25 Evalr.rartion As seen in Figure 8.29, Gas capacity is acceleraled approximately 6 years (-500 MW) into 2030. Figure 8.29 - P-25 (Additional segments D.3, E, F and H) Compared to P-45CNW Difference in New Resource Capacity ----r 1,000 0 (1,000) (2,000) -...rlllllt-r 2019 2020 2021 2022 2023 2024 2025 2076 7021 2028 2029 2030 2031 2032 2033 2034 2035 2035 2037 2038 .Ga3 .Re@abl. rStor.*. Drc.l Load C@nd . En€Gy Effi.ien.v .Summ.rFOT 9m c S20o ,9 =loE4 (5200) (s4m) *rr -r-rrf-11 Difference in System Costs Net Difference in Total System Costs 2019 2020 2021 2021 2021 2024 ZO25 7026 2027 20Za 2029 2010 2031 2032 2033 2034 2035 2035 2037 2038 .V.i.ble afired r Ma*et rT.anrhietaon l)^( ll,r(]( )RP 2019 IRP Clt l, ,R 8 MoDILIN(; ANI) P( )R tfollo Stit.ticfloN RESt,l. ts 55oo .50,9 = rlsml E '(sr,ooo) (S1,soo) 2019 2020 2021 2022 2023 2074 7025 2026 2021 202E 2029 2030 2031 2032 2033 20t4 2035 2035 2037 2038 - iter (B.nefir)/cosr ___ cumuhrjve pvRR{d ) P-26 Evaluation Case P-26 includes the approximatcly 290 mile Boardman-to-Hemingway transmission segment (H). As seen in Figure 8.30 gas capacity is accelerated approximately 6 years (-500 MW) into 2030. '['ho stochastic mean PVRR of case P-45CNW is approximatcly S98m lower cost than case P-26. In 'Iable 8.15 case P-26 ranks second among gate\\,ay cases in 3 of4 categories, inctuding stochastic mean, risk-adjusted PVRR and low ENS. These rcsults are promising, and signal that with motivated project partners and potentially signilicant regional reliability benefits, updated modeling that can better capture the value of this project will ultimately support a business case to move forward with the project. Consequently, PaoifiCorp has included an action item in its 2019 IRP action plan to continue to evaluate and support the Boardman-to-Hemmingway project. 'l able 8. 1 5 reports a summary of the [--nergy (iatcrvay cases. t4.t P^('r rCoRP-20l9lRP CHAp't t R ti - MODLLINC AI,JD PoR I I,olto Slllc oN RF.sr r. rs Figure 8.30 - P-26 (Segments F and H) Compared to P-45CNW 0ifference in New Resource CapacitV 2,0m 1,000 !o tr.@0) 12,(x)0) rrrrrrIIII-- 20t9 2020 2021 2022 2023 ?024 202' 2026 2027 2028 2029 2010 20rr rG.! .f,enewibk .5rooi! creft -o- cor,ol . aneray Lfll.E.ry 2012 2033 2034 2015 2036 2037 2018 0ifference in System Costs c 3200 61S200)-1-Errrrrrfll is.100i 20t9 2020 2021 2022 2023 2024 2025 2A26 202t 2028 2029 2030 ?oit 20rZ Nn 2034 2035 2036 203' 2038 .v.@U. .Fired .v.rler .Ir-{E{r Net Difference in Total System Costs $100 $50 50 (ss0)E lsroo) {s150) 20)t 2Qf82019 2020 2021 2022 202' 2024 2075 2A26 202t 2028 2029 2030 2031 2032 2033 2034 2015 2036 -Neri&neli1)/Cort --- cumuralNePvRRld) Table 8. l5 - Catewa Case Results Summa While the results above did not compel PacifiCorp to alter its selection of case P-45CNW as the krp-performing portfolio, the company remains confident that additional Energy Gatervay scgments will provide incrcmcntal regional and customer bcnefits rvith an ongoing transition to the regional resource mix and as new markels devclop. EIiS Alc.aac Percenl ofl@d CO: Emissi06 PVRR (sm) Chmg€ Cosr (tn)RI PVRR t$m, Change Cor Ponfolio (Sm) ENS. l0t9- l0l8 % chaflge ENS 'lbtal cO2 :019-:038 Ch{Ec Emission !1,20,l0 0.00:ci .10,811 Pt6 t:r,t05 l:1..179 S I 0.1 0.0060/.i80.lt6 1_r.315 l ,]:.1-701 581.0:8stl6 l6.lt7 _'-r. t8.l s97i :i..r0l sl_016 i{.1.81I l, l-i l.l.ll9 1i..160 iE0.0t.r l5.tr).1 EEE EE 244 (latcwav Studies Conclusions $0 :l l I sL.Dtl s t.08.1 5 0 006% PA( rFrCoRP 20l9 lRP CrhprER 8- MoDELTNc ANr) PoR rror.ro SELECTToN RESULTS As discussed above, case P-26, rvhich includes the Boardman-to-Hemingrvay transmission line, shows signilicant potcntial fbr producing cuslomer benefits. This project has motivated partners and is cxpected to provide incremental bcnclits not captured in the current analysis that can be lurther explored in future IRPs and IRP Updates. Conscqucntly, PaciliCorp will remain an activc participate in the ongoing development ol'this project and has includcd an action item in its action plan to continue its partnership in this project. Some of the incremental bcnctits of Boardman-to- Hemmingway not captured in the analysis abovc include: Connecting geographical diversity to help balance the intermittency ofresources like wind and solar, to help meet clean-energy standards and bolsters resourcc adequacy. Decreasing market reliance by providing incremental infrastructure that can conncct additional resources to load. Improved reliability by increasing ability to share operating reservcs among utilities and providing additional source for energy to tlow. Help alleviate transmission congestion. lmproved access to participate in the Energy Imbalance Market and generate customer benefits. PacifiCorp has also includcd an action item kr continue permitting thc Energy Gateway transmission plan, as it is anticipated these additional segments u'ill also provide incremcntal valuc that can continue to be evaluated in future IRPs and IRP Updatcs. Final Preferred Portfolio Selection Case P-45CNW entered the final evaluations as the top candidate {br pref'erred portfolio, and for purposes ofthe 2019 IRP, the "No New Natural Gas" and Energy Gatcway cases did not change P-45CNW's top status. Consequently, PacitiCorp selected the resource portfblio tiom casc P- 45CNW as the 2019 IRP prefened portfolio. PacifiCorp's seleclion of the 2019 IRP pref'erred portfblio is supported by cornprehensive data analysis and an extensive stakeholder-input process. Figure 8.3 I shows that PaciliCorp's preferred portfblio continues to includc new renervables, facilitated by incrcmcntal transmission investments, demand-side management (DSM) resourccs, and fbr the first time, significant battery storage rcsourccs. By thc end of2023, the prclbrred portfolio includes nearly 3,000 MW olncw solar resources and more than 3,500 MW ofnew wind resources, inclusive ofresources that will comc online by the cnd of 2020 that were not in the 2017 It{P.r 't'he prefbrrcd portfblio also includes nearly 600 MW of battery storage capacily (all collocated i.r'ith new solar resources), and over 700 MW of incremental energy efficiency and new direct load control resources. Over the 2O-year planning horizon, the prefercd portfblio includes more than 4,600 MW ofnew wind resources, more than 6,300 MW of new solar resources, morc than 2,800 MW of battery storage (nearly 1,400 MW of which are stand-alone storage resources starting in 2028), and morc 245 The 2019 IRP Preferred Portfolio PA( ll r(1)RP - 20l9 lRP CHAp r ER 8 - M(n)H.rNC AND PoRTFOI.ro SEr.EC lroN Rl.sur. r's than 2,700 MW of incremental energy efiiciency and ncw direct load control resources.{ Whitc thc preferred po(folio includes new nalural gas peaking capacity beginning 2026, this thlls outside of the 2019 IRP action plan rvindow, which provides time for PacifiCorp to continue to evaluate rvhether non-emitting capacity resources can be used to supply the flexibility necessary to maintain long-term system rcliability. Figure 8.31 - 2019 IRI'Prefcrrcd Portl'olio (All Resources) I I .;.: - .-_..III NNNIII a Wind . cla5s 2 DsM I Ga5 CCCT I Wind+Bat , Onss L OSM . FOT t Sdnr+B.t a Battcry a Gn5 CorN. a 6a5 Penkcr I Rcrnovcd Copncity 246 To fhcilitatc the delivery of neu' renervable energy resourccs to PacifiCorp customers across thc West, the prefened portfirlio includes a 400-mile transmission line known as Gateway South, planned kr come online by thc cnd of2023, that will connect southeaslem Wyoming and northem Utah. Thc nerv transmission line is in addition to the 140-mile Gateway West transmission line in Wyoming currently under construction as part ofPacifiCorp's Energy Vision 2020 initiativc. The preferred portfolio firnhcr includes near-term transmission upgrades in Utah and Washington. Ongoing investment in transmission infiastructure in ldaho, Oregon, Utah, Washington, and Wyorning will facilitate continued and long-tcrm growth in new renewable resources. Tablc 8.16 summarizes the incrernental transmission projects included in the 2019 IRP preferred portfolio, and Tablc 8.17 summarizes the total amount of initial capital investment required to deliver incremental transmission and resource investments through the 2O-year planning period of the 20l9 tRP. N N I N L- .- I I i I N R N\\\\\ l P^clr rC()RP 20l9lRP C ltAl,I l,R tl Nl(n)r r.rN(; A\t) Pot{I I ol 1o Sr.1.r:( r roN Rr,s([.r s Table 8.16 - Transmission Pro ccts Included in the 2019 IRP Preferred Portfolio* *Note: TTC = total transl-er capability. Thc scope and cost of transmission upgrades are planning estimates. Actual scopc and coss u,ill vary depending upon the interconnccti()n queue, the transmission servicc qucue, the specific location olany givcn gcnerating resourcc and the type ofequipment proposcd lbr any given generating resource. Table 8.17 - Total lnitial Capital to Deliver Preferred Portfolio Transmission and Resource lnvestments S million New Solar Resources The 2019 IRP preferred portfolio includes more than 3,000 MW ofncw solar by the end of2023, u,hich accounts lor resources that will come onlinc by the end of2020 but not in the 2017 IRP, and morc than 6,300 MW of new solar by 2038 as shown in Figurc 8.32.i l0ll 69 MW Wind (2021) 231 Mw Sohr (202.1) \\ilhin Sourh.m l:l' Trarsmi\tion Area Enablcs 300 MW of inrcrconnection: UT Vallel l.l5-ll8 kV + I 18lV rcinforcement ($lim) Wilhin tlridtser WY Rcclaimed hnsmission upon reliremcnl olJinr BridJrcr I (X;(l):01.1 :i-54 N4W solar (202.1) t0:.+67.1 I\'1W Sol:rr (:01.1)Wilhin Nonhcrn tll' Transnrission Area [nirbles 600 MW of intcrconnection: Northem [J'l' 345 kV reinforccment ($30m) I I I North fnahlcs l-Cl0 MW ot inlcrconnection wilh 1.7(X) N'lW oI TTC: Eners\ ( iatc$a,t Soulh (S 1.75:m):01.1 1,920 MW Wind (:024) \! ithin Yiki'na !\i\-fransmission Arca Erlables 405 MW ofinterconnection: locll reinforcement ($3m)t0t.l 195 NI\\' Solnr (]0:.1) I0 NIW wind (l0l9l :02.1 359 MW Solar (20:4)wilhin Bridgcr wY'lransmission Area Reulaimed nansmission unon rctiremenl ol Jinr Bridse.2 (S0) (ioshen Il)lll Nofth F.nflblcs I,100 MW ol intcrconnection with tloll Mw ol I l( (S2i4n)2{)30 l,0,tll MW wind 120i0) 60 Vw Wind (2012) l0-10 500 MW Sokr (2030)Within Sourhcrn UT Tmnsmission Area I-nables 500 Mw ofi crconneclion: UT Valle\ local area reinfo(_cmenl (5206m) Wirhin Southcm ()R lransmission Arca lirrblcs.lTS Vw of [rtrrconncction: \'lcdlard xrcn S00 kV-llo kV rcinli)rccnrcnl ($l02lnll0l:l J75 VI Solar t]0ll ) SoLrlhcm OR Lnahlcs.l30 Mw of inrcrcoDn.ction with 450 MW ol l"l( : Yakima w/\ (o Bcnd OR 230 kV (:i,255nr)l0l6 .l lt) MW Solar (2016) No(hem U I:0:r 7 90c MW Sol.r (2017)Southem Lll Rcclaimed lr rsmission upon rctirement ot' Huntington l-2 ($01 Wirhin Willllmcxc Vallcl OR Transmi5sion Are,r Hnablts 615 MW of inler_onnection: Albdn) OR area reinforcement ($40m)7031 .1.13 Mw (;as (201?) lr)'l7 170 MW Gds {20.17)Within Southrv!'st wY Traosmission Area Enables 500 MW of inlcrconncction: separation ol' doublc circuit 230 kV lincs (539m) Withnr B.id8er \Iry Rc€laimcd hnsmission upon retirement of.lirn Drid,rcr 3-+ 1$0):0lll1 7(12 MW Solar (10i8) ldaho st5-l s l,659 $ l .912 S264 $2,s40 $2,804Oregon $ r ,004 s3,466 $4,470Utah Washington $ 136 $i l ,509 $ I ,644 Wyoming $76-s $s,3 76 $6,14 I s3 70 SO s370Clolorado '[otal $2,792 $ 14,550 s I 7,342 5 kl. 247 From To DescriotionYearResource(s) State Transmission Resources Total Figurc 8.32 - 2019 IRP Preferred Portfolio New Solar Capacity* 7,000 6,0m 5,000 4,000 :t,000 2,000 1,000 o I I I 202 llllllllllllll = ,: 3 E = .2s E ilillillllilll 10t9 20ro 20zt 7022 2023 2025 tO26 2071 2023 2029 2030 ?Ort 2or2 2031 2014 2035 2016 2ol7 2034 2019 tRP* 2077 tRP *Notc: 2019 IRP solar capacity shown in the figure includcs 559 MW of contracted new solar (all power-purchase agreements) that was not identified in the 2017 IRP. Thcsc rcsources rvill be onlinc by thc end o[2020 and are shown in thc lirst lirll year ofoperation (the year alicr year-online dates). Resourccs acquired through customer partncrships, uscd lor rene$able pontblio standard compliance, or for third-party sales of renewable attributcs arc included in the total capacity tigurcs quotcd. New Wind Resources As shown in Figure 8.33, PacifiCorp's 2019 IRP preferred portlblio includes more than 3,500 MW ol new wind generation by the cnd of 2023, which accounts for new resources that will come online by the end ol'2020 but not in the 2017 IRP, and more than 4,600 MW of new wind by 2038.6 Figure 8.33 - 2019 IRP Preferred Portfolio New Wind Capacity* 7,m0 6,m0 5,m0 4,000 3,000 2,000 1,000 0 rrl 2019 2020 2021 2022 2023 2024 2075 2026 2021 2028 2029 2030 2031 2032 2033 20,r 2039 2035 20:l' r 2019lRPr, 2017 tRP *Notc: 2019 IRP wind capacity shorvn in thc tigure includes 1.533 MW ol'contracted new wind (21 pcrccnt power- purchase agreements) that lvas either identified in the 2017 IRP and is under construction or that $as not identilied in thc 20I 7 IRP and is under contract. Thesc rcsources n ill come on-line by the cnd ol'2020. These resources arc shorvn in the flrst full year of opcration (the year atler year-end online dates). Resources acquircd through customer partncrships, used llor renervable ponfolio standard compliance. or for third-pany salcs of renewable attributcs arc included in the total capacity tigures quoted, New Storage Resources This is thc tirst PacifiCorp IRP that identifies new battery storage resources as part of its least- cost, least-risk portlirlio. As shown in F igure 8.34, PacifiCorp's 2019 IRP pref'erred portfolio includes nearly 600 MW ofbattery storage by the end of2023. All ofthe storage rcsources planned through this period are paired wilh new solar gcncration. The plan also adds ncarly 1,400 MW ol' stand-alone storage resources sta(ing in 2028. Pr\('ll,lCoRP 2019IRP CIIAPIIIIi 8 MoDF.I IN(;A\I) PoRI.I.oLI0 SI]I-I]CTtoN RI.st I.Is 248 PA( [rCoRP - 2019 IRP CI IApT[R [i - Mor)Er.1NC AND PoRTloLto Sl,t,t.:( TtoN RESt.rt-TS Figure 8.34 - 2019 IRP Prel'erred Portfolio New Storage Capacity r 2019 IRP 2017 IRP (None) Demand-Side Management PacifiCorp evaluates new DSM oppo(unities, which includes both energy efficiency and direct load control programs, as a resource that competes with traditional new generation and wholesale porver market purchases whcn dcveloping resource porttblios for the IRP. Conscquently, the load fbrecast used as an input to the IRP docs not reflect any incremental investment in new energy efticiency programs; rather, the load forccast is reduced by thc selected additions of energy efficiency resources in the [RP. Figure 8.35 shows that PacifiCorp's load fbrecast befbrc incremental energy efficiency savings has increased relative to projected loads used in the 2017 IRP and 2017 IRP Update. On average, tbrecasted system load is up 2.4 percent and forecasted coincident system peak is up 3.4 percent when compared to thc 2017 IRP Update. Ovcr the planning horizon, the avcrage annual growth rate, belbre accounting for inoremental energy ctticiency improvements, is 0.73 petcent for load and 0.64 percent for peak. Changes to PacifiCorp's load ftrrecast are driven by highcr projected demand from data centers driving up the commercial forecast and an increase the residential forecast. Figure 8.35 - [,oad Forecast Comparison between Recent IRPs (Before lncremental Encrgy Efliciency Savings) B s E ,,,,rlllllllll 2019 2020 2021 2022 2023 tO24 107\ Z026 lO)1 2028 2029 2010 2o3l 2032 2013 203! 2035 1035 2037 2013 ] 80,000 70.000 60.000 50.fi10 .10.000 10,000 10,000 t0.000 0 Forecasted Annunl Slstem Lof,d (Gwh) -:019 IRP . l0l7 IRP llldalc -+-:lrl7 IRP Iorecasled Annual System Coincident Peak ( \t !v) 14.000 11.000 t0,000 8.000 6.000 4-000 a l_000 - -2019lRI, a 20l?lRPLrld le ---.-:Dl7IRP DSM resources continue to play a key rolc in PacifiCorp's resourcc mix. The chart to the lcfi in Figure 8.36 compares total energy efficiency savings in the 2019 tRP pret-erred portfolio relative to the 2017 IRP preferued portfblio. In addition to continued investment in energy el)iciency programs, the prel'erred portfolio continues to shorv a role for incremental direct load control programs with total capacity reaching 249 1,000 2,500 2,000 1,500 1,000 500 0 ffi P^CIFICoRP 2019 IRP C' At,n R 8 Mor)l,t tNC A\t) PoR rFor.ro S -r:c oN R risl rr. rs 444 MW by the end of the planning period. The chart to the right in Figure 8.36 compares total incremcntal capacity ofdircct load control program capacity in the 20l9lRP pref'erred portfolio relative to the 201 7 IRP prcf-erred portfirlio and does not include capacity from existing programs. Figure 8.36-20l9lRP Preferrcd Portlblio Energy Efficiency (Class 2 DSM) and Direct Load Control Capacity (Class I DSM) Energy Efficiency (Class 2 DSIM) Direct Load Control{Class 1 DSM) = -E E.,,, rrrltil llllllll = .z! E 2,500 2,000 1,500 1,@0 500 0 2.5m 2,000 1,500 1,000 500 0 -.!alrrrt!I r 2019 tRP 2017 tRP r 2019 tRP 2017 tRP Wholesale Power Market Prices and Purchases Figure 8.37 shows that the 2019 IRP's base casc forecast for natural gas and power prices has increased lrom thosc in the 2017 IRP and 2017 IRP Update. These forecasts arc based on prices observed in the forward market and on projections liom third-party experts. The higher power prices observed in the 2019 [RP are primarily drivcn by the assumption ofa carbon pricc that is higher and starts earlier (2025) than whal rvas assumed in the 2017 IRP Update (2030).7 Moreover, the 2019 IRP assumed higher natural gas prices than either thc 2017 tRP or 2017 IRP Update as Henry Hub, in particular, is boosted by increasing LNG exports. While not shown in the figure below, the 2019 IRP also evaluated low and high price scenarios when evaluating the cost and risk o f di fl'ercnt resource porl[ol ios. Figure 8.37 - Comparison of Power Prices and Natural Gas Prices in Rccent lRPs Henry Hub Natural Gas Prices (Nom S/MMgtu)Average of MidC/Palo Verde Flat Power Prices (Nom S/MWh) s6 t5 54 ,3 s, + 2or9 rRP {s€p 2013) - -2OI7rRPUrd.r€(0€c20171 -2017rBPlod2016) i{i2orerRPls.p2013) - -2017tRPUpdar.(D.c2017) -z0rrtnP(od2ot5) Figure 8.38 shorvs an overall decline in reliance on x,holesale market firm purchases in the 2019 IRP preferred portfolio relative to the market purchases included in the 2017 IRP prcf'crred portfolio. [n partioular, reliance on market purchases during summer peak periods averages 366 MW per year ovcr the 2020-2027 limefiame down 60 percent from market purchases identified in the 2017 [RP preferred portfblio. This reduction in markct purchases coincidcs with the period 250 7 The 20 | 7 IRP did not assumc a curbon price but. instead. rcllcctcd implernentation ot the Clean Po!\'er Plan PA( rFrCoRP - 2019 IRP CHAp TF.R 8 - MoDELINC AND PoR trjot.to SELECTIo\ R[suLTS Figurc 8.38 - 2019 !RP Preferred Portlblio Front Office 'l'ransactions (FC)Ts) Summer FOT5 Wintcr FOTS t 2019 tRP 2017lRP Natural Gas Resources In the 20 l9 IRP prcf-crrcd portfblio, Naughton Unit 3 is converted to natural gas in 2020, providing a low-cost reliable resource for meeting load and reliability requiremcnts. New natural gas peaking resources appear in the preferred portlolio starting in 2026, which is outside the action-plan rvindow. This provides time fbr PacifiCorp to continuc to svaluate whether non-emitting capacity resources can bc uscd to supply the llexibility necessary to maintain system reliability long into the lirture. Figure 8.39 - 2019 IRP Preferred Portfolio Natural Gas Peaking and Combined Cycle Capacity* Natural Gas Peaking Capacity* Natural Gas CCCT Capacity ts ! E = s E mc 5m 0@ !m I I h,,,. .,lllllllllll : ts ,:g E 1,1, II RR 500 ,000 $0 0 3 s E ,000 500 ill0IIIIIIIIIIIIIII r 2019 tRP 2017 IRP r 2019 tRP 2017 tRP + Notc: 2019 IRP natural gas peaking capacity includes the conveniion ofNaughton Unit 3 to natural gas h2020 (241 MW). Coal Retirements Coal resources have been an important resource in PacifiCorp's resource portfblio. Changes in how PacifiCorp has been operating these assets (i.e., by lowering operating minimums) has allo*,ed the company to buy increasingly lorv-cost, zero-emissions renewable energy from market participants, w'hich is accessed by our expansive transmission grid. PacitiCorp's coal resources will continue to play a pivotal role in following fluctuations in renewable energy as thosc units approach retirement datcs. Driven in part by ongoing cost prcssures on existing coa[-fired facilities and dropping costs for new resource alternatives, of the 24 coal units currently serving PacitiCorp 251 over which there are resource adequacy concems in the region. Whilc market purchases increase beyond 2027, PacifiCorp is actively participating in regional elforts to develop day-ahead markets and a resource adequacy program that will help unlock regional diversity and facilitate market transactions ovcr the long lerrn. 2.000 r.500 lm0 500 - r.lll---.!rr!.- - r 2019 tRP 2017 tRP P^( rrrLloRf 20l9lRP customers, the prefened portfblio includes retirement of l6 ofthe units by 2030 and 20 ofthe units by the end ol'the planning period in 2038. As shorvn in Figure 8.40, coal unit retirements in thc 2019 IRP prct'crred portfolio will reducc coal-fueled generation capacity by over 1,000 MW by thc cnd of2023, nearly | ,500 MW by the end of2025, nearly 2,800 MW by 2030, and ncarly 4,500 MW by 2038. Coal unit retircments scheduled under the pref-erred portfolio include:o 2019 = Naughton Unit 3 (samc as 2017 tRP), converted to natural gas in 2020o 2020-2023 : Cholla Unit 4 (samc as 2017 IRP)o 2023 = Jim Bridger Unit I (instcad of2028 in the 2017 IRP). 2025 = Naughton Units l-2 (instead of2029 in the 2017 IRP)c 2025 : Craig Unit I (same as 201 7 tRP)o 2026: Craig Unit 2 (instead of2034 in the 20l7lRP)o 2027 : Dave Johnston Units l-4 (same as 20l7lRP)o 2027: Colstrip Units 3-4 (instead of2046 in the 2017 IRP). 2028: Jim Bridgcr Unit 2 (instead of2032 in the 2017 IRP). 2030: Hayden Units l-2 (same as 2017 IRP). 2036 = Huntington Units l-2 (same as 2017 IRP)o 2037 = Jim Bridger Units 3-4 (same as 20l7lRP) Figure 8.40 - 2019 IRP Prcferred Portlblio Coal Retircmcnts* ts .F ! E ,oo0 ,000 ,o@ - r, !,, il lllllllllll {s,0m)2019 2020 2021 1022 )O71 10)A 1AZ5 2A26 2A27 2023 2029 2030 2031 2032 tott 201.4 2035 7036 2037 20lS r 2019 tRP 2017 tRP * Note: Coal retircmenls are assumed to occur by the end ol- the year bel'ore the ycar shorvn in the graph. The graph shows the year in rvhich thc capacity will not be availablc fbr mccting summer peak load. All ligures represent PacifiCorp's owncrship share ol.jointly outcd facilitics. Carbon Dioxide Emissions 'l'he 2019 IRP pref'ened porttblio reflects PaciliCorp's on-going effofts to provide cost-effective clean-energy solutions fbr our customers and accordingly reflects a continued trajectory of' dcclining carbon dioxide (CO:) emissions. PacitiCory's emissions have been declining and continue to decline as a rcsult ofa number of factors, including PacifiCorp's panicipation in the Energy Imhalancc Market (L,lM), which reduccs customer costs and rnaximizcs use of clean cncrgy; PaciliCorp's on-going expansion of rencrvable resources and transmission; and Regional Haze compliance that capitalizes on 1)cxibility. Thc chart on the left in F'igure 8.41 compares projccted annual COz emissions between the 2019 IRP and 2017 tRP prel'erred portfblios. ln this graph, emissions arc not assigned to markct purchases or sales, and in 2025, annual CO: emissions are down sixteen percent relative to the 201 7 IRP prcl'crrcd portfolio. By 2030, average annual C0: emissions are down 34 percent relative 252 CltAp I l-.R ll - MoDtit-tNC ANt, PoR I t,ol.to SLLLC TTo\ RESUt. ts 0 P^cu,rCoRP 20l9lRP CIIAPI.I:R II _ MoDELING AND PORTIToI-I() SI.I I,(-TION RT]SIII-IS to the 2017 IRP preferred portfblio, and down 35 pcrcent in 2035. tly the cnd of the planning horizon, system CO: emissions are projected to fall from 43. I million tons in 2019 to 16.7 million tons in 2038-a 61.3 percent reduction. The chart ofthe right in Figure 8.41 includes historical data, assigns emissions at a rate of0.4708 tons/megawatt hours (MWh) to market purchases (with no credit to market sales), and extrapolates projections out through 2050. This graph demonstrates that relative to a 2005 baseline (a ubiquitous baseline year in the industry), system CO: emissions arc down 43 percent in 2025, 59 percent in 2030, 6l percent in 2035,74 percent in 2040, 85 percent in 2045, and 90 percent in 2050. Figure 8.41 - 2019 IRP Preferred Portfolio CO: Emissions and PacifiCorp CO: Emissions Trajectory* CO2 Emissions Pacificorp CO2 Emissions Trajectory 60 3r0 5ro 0 Ei: lllllllllruumrr, a:iEEEH*iEBEeEES€EnE r 2019 IRP 2017 IRP lllllfir llillilllnrn, I 0.8 06 o.4 4.2 0 oo ollllllrrr *Notc: PacifiCorp CO: Emissions Tra.jectory rellccts actual emissions through 2018 fiom owned fhcilities, specilicd sources and unspccitied sourccs. From 2019 through the end ol'thc tu,enty-year planning period in 2038, emissions rctlcct those from the 2019 IRP prelerred porttblio rvith market purchases assigncd thc Califomia Air Resources Board delault emission thctor (0.4708 rons/MWh) ernissions from salcs are not removed. Beyond 20311. cmissions reflect thc rolling averagc emissions ol'each resourcc fiom the 2019 IRP prel'encd porttblio through the lil'e ofthe rcsourcc. Figurc 8.42 shorvs PacifiCorp's renewable portlblio standard (RPS) compliance lorecast 1'or California, Orcgon, and Washington after accounting fbr new renewable resources in the prel'erred portlblio. While these resources are not included in the pref-errcd portlolio as cost-effective systcm resources and are not included to specifically meet RPS targets, they nonetheless contribute to meeting RPS targets in PaciliCorp's western states. Oregon RPS compliance is achieved through 2038 with the addition ofncw renewable resources and transmission in the 2019 IRP preferred portfolio. The Califomia RPS compliance position is also improved by the addition of nell'reneu'able resources and transmission in the 2019 IRP preferred portlblio but requires a small amount of unbundled renewable energy credit (REC) purohases undcr 150 thousand RECs per year to achieve compliance through Compliance Pcriod 4. Washington RPS compliance is achievcd with the benefit of repowcrcd rvind assets located in the west side, Marengo, Leaning Juniper and Coodnoc Hills, increased system renewable resources contributing to thc west side beginning 202 I 8, and unbundlcd REC purchases under 300 thousand 3 PacitiCorp wiJl proposc the Multi-State Protocol allocation methodology in a December 13,2019 Washington gsncral rate case (GRC) liling. The rnethodology would allocate a system generation sharc ofall non-emitting system resourccs k) Washington. Thc 2019 IRP Annual State RPS Compliance Forecast reflected in Iigurc t1.42 rcllccts PacifiCorp's proposal to be liled in thc ratc case starting in 2021. Upon approval, the effbctive date ofthe new allocation melhodology u,ould be January l, 2021. l)J Renewable Portfolio Standards l'ACr1,r( oRP-2019IRP CIIAl,r'|R 8 Mot)l:LINC A\t) PoRlljot.to Sl]t-lt(IoN I{tistrlts RECs per year through 2021 . Under current allocation mechanisms, Washington customers do not benctlt f'rom the new renervablc resources added to thc cast side ofPaciliCorp's system. While not shown in Figure 8.42, PacifiCorp meets the Utah 2025 state target to supply 20 percent ofadjusted retail sales rvith cligible renervable resources rvith existing ou,ned and contracted resources and nerv renewablc resources and transmission in the 2019 IRP prcferred portfolio. 254 PAor(l)RP l0l9IRP CHAP r LR 8 MoDht-tNG AND P(x r r or-ro Sfir.Fr( TroN Rr:slrr,TS Fi ure 8.42 - Annual State RPS Com liance Forecast 0 0 0 0 0 0 0 0 0 0 0 t- ;.1 60 55a50E r< e 40335 -E 30 YloL/ r( His) 1.600 1.400 I.200 I.000 800 600 400 200 0 5.000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 I.000 500 0 ,"rrs,t"s,tr6Pr$C"r{Frs,""$re""s,"rs".,s'r{i"dirs"r*tr*"rat.u*-Nutrbudled Sureodered rBtlodled Surrendered mUobrurdled Ba* Surreudqed IBmdled Ba* SrEenderedEYear-e[d Urbtudled Baok Balance rYear-eod Brmdled Banli Balalcer Shonfall +Requterert Oregon RPS00 00 00 00 00 00 00 00 00 00 00 00 0 0 \oFooo\ool c-l a.l a.l (aaaaaeal at a.l N aia.t c .to.tc al ala ola Oal a..1 O aoc.t a{ r- O(.l Oa.lO -Bundled StutendeledI Buldled Ba! i Srfienderedr Yea!-end BrI)dled Bar* Balaace -RequireDreDt IBurdled SurTelderdr Buldled BanI( St[re[deredrYear-end Budled Badi Balalce*Requiremeot O\O-..r!399!a.l a.l N c.l ^t -b ^1 ^$"rs, ^:\, ^r\, .rs,^s ^\ i! "ls, "r,\, "'s, Nutrburdled Su[eMeredE Unbrndled Baak Sru:reldered ElYear-etrd Utrbutrdled Badi BalancerShoifall hl& -g ^S ^\ ^"t ^1 ^U ^b ^ro A ^$ ^qns\ "rse lsv "\,sv 1sv "r$v "r\v .Vs, .rse lsv lsP Nutrbuodled Suretrdered 1sr- "ts, U buldled tsar* Sureldered EYear-eod LrDbrudled Baok Balauce - Shonfall 255 California RPS r r I al Washington RPS P^( rrrCoRP - 20l9 tRP Capacity and Energy Figure 8.43 displays how prel'erred portfolio resources meet PacitiCorp's capacity needs overtime. Through 2038, PacifiCorp mccts its capacity needs, including a l3 percent target planning reserve margin, through incremcntal acquisition of wind and solar resources, enabled by investment in transmission intiastructure, battery storage resources, ne\\,DSM, natural gas and r.r,holcsalc power markct purchases. I.'igure 8.,13 - Nleeting PacifiCorp's Capacity \eeds with Preferred Portlblio Resources t{.000 Obligitiotr + Reser|es " I 8.000 New Brttery Stor.ger' tl.m0 Nerr Witrd & Solsr lt,m0 lo,@o 9,000 q0(n 7,(m 6m 5,m Erktlng - LoDg Term Cortr.cls .rd PPA's 'lncludes ll'b Pla ftlg Reserves. S.les ardl\iou-Ow ed Reserves " lncludes Stand-alon€ Storageand the Stora8ecomponent of Renewables + Storage " * Ircludes lclrrsxellis. ard gas r€power. DSIVI ircludes both Class I a d 2 Figure 8.44 and F'igure 8.45 shor,', how PacifiCorp's system energy and nameplate capacity mix is projected to change over time. ln developing these figurcs, purchased power is reported in identifiable resource catcgories rvhere possible. Energy mix figures are based upon base price curve assumptions. Renewable capacity and generation reflect categorization by technology typc and not disposition ofrenewable energy attributes for regulatory compliance requiremcnts.e On an energy basis, coal generation drops below 40 percent by 2025, falls to 22 percent by 2030, and declines to Iess than 6 percent by the end of'the planning period. On a capacity basis, coal resourccs drop to 24 percent by 2025,lall to l3 pcrcent by 2030, and decline to 5 percent by the end ofthe 'qThe pro.lected PacitiCorp 2019 IRP preferred ponfolio "energy mix" is based on energy production and not resource capability, capacity or delivered energy. All or somc ofthe renewable energy attributes associated with wind, biomass, geothermal and qualifying hydro facilities in PacifiCorp's cnergy mix may be: (a) uscd in lllure years to comply with renewable portlolio standards or othcr rcgulatory requirements; (b) sold to third parties in the lirrm olrenervable energy credits or other cnvironmental commoditiesi or (c) excludcd l'rom energy purchascd. PacifiCorp's 2019 IRP prcl'cncd porttblio energy mix includes ou,ncd rcsources and purchascs t'rom third panies. - N.s Firn Md.t Purd.i6 Ncw B.!.ry Sror!!r. Exirtug - Lq l.rn Co,frlcr lId PPA'. -Ncw -DSM Ncw Wind & Sohr ..+-Oblhatioo + R6lrv.s . - Eristi!! - tty3iol As.t3 '!d DsM ... 256 CHAP I]]R II MoDIiLINC AND PoR I IOI,IO S[L[CI IoN RF.SI JI,Is m20 m2L 20u ar 201,1 20L< 2026 7027 20?a 2029 m.!0 lotl m32 20a! 20-!t 20t5 2036 2037 !038 New FirtD Mrrkel Purchrsc Gas Erirthg - Physicrl A$cts rtrd DSM *** P,\(rFrCoRr, 20l9lRP CHApttltt li Mor)rlr.rN(i ,^Nt) PoRTfol.t()Stil.ri( rluN RLsut.fs planning period. Reduced energy and capacity from coal is oflilet prirnarily by increased energy and capacity liom reneu'able resources, DSM resources, and to a smaller extent later in the plan, nerv natural gas resources. urc 8.44 - Pro ected Ene Mix with Preferred Portfolio Resources t,'re 8-45 - Pro ected C acity Mix with Preferred Portfolio Resources Detailed Preferred Portlblio Table 8.18 provides line-item detail of'PacifiCorp's 2019 IRP preferred portlblio shon'ing new resource capacity along with changes in cxisting resource capacity through the 20-year planning horizon. Tablc 8. l9 and Table 8.20 show line-item detail of Pacit'iCorp's peak load and resourcc capacity balancc lbr summcr, including preferred portfblio resources, over the 2O-year planning horizon. Table 8.21 and Table 8.22 shorv line-item detail of PaciliCorp's peak load and resource capacity balance lor winter, including prel'erred porttblio resources. over the twenty year planning horizon. t000" 904. EOoo 60!! t0.. 30". 20.o l0qo 09o 2020 202t 2022 2023 202.t 2025 2026 2027 2028 2029 20t0 20I 2012 20i3 2014 20ll 2036 2037 20J8 .col rO$ ! tt$ro.l.ctri tRcn.qrbL .t dD.rd R.rr6ol. I ld.rntpribl6 .E!ar, Ef6.ifty .lrinit[ hfrhlG r rdr off(. Ilror.(iirri 2020 202t 202! 2021 202{ 202' 2026 2027 202a 2029 2030 20lr 2012 203J !0r1 2015 :016 :017 2038 . c6l . c& . ttydEl(rt .RodbL . sror.r. .cl.< I lr6il - Itrkm$ibld .Ns-r.6tr Efrrial . r:irin, PBd!6 . rmr oflicc Tntr*tu'! 257 ,ti ,t0!i E tltl -fE- t:ca !h :tri l:r.t:16 -3F ll+c::!{ Ilt 7E' tm.. 90'o 8(Po 60'o 50.0 2(Fo lf. 6!a]t!?+aiT :2t6 : t!r tl% lort6 _ir lq- I co a..t tr 0i I€ €I F ! 4 = a- Q 1' il' 1:.::: _::::i ,1, i 'll' : I I rl 1t ll I 1t 1l I I I I I II I tll' I : tl I I I I I ,l l'l il I ; il i ! i :;: 1', i l tl :I I 'l': 1' l' ll ,.,l ,i .l ;: I I t' ']' IIl 1;l li fll El.d.t RdnEd Ehnr (lfrie 'l Ensacrions ibt Plm.dR.rdrud LlTotd L.arB Pliv.L (t:nedbn Frr.litd6 Ptnnin! R!r.d.s ( lY, [r.t Rd.Rt Fir Ollirrd@ a R6.rer iLlPdidd F^l n6.N lvtugltr I tl 115 I 17 ll5 'rir2J I llr t:1 ?JJJ ?: :3 lll7 7-550 8t! 7-5t t J6 ]5 !l L 7,7Jt I.l.l l l r.J: 6tl I lll Itl I tl6 l.{31 115 610ltl N7 q) 0 I87 I 8r0 718 ll5 l2l 6.n12 lm 155 l6: I 16n (!l)(51,(51) nn) (51) I,l ls8 '7528 t2t l',^('lr,rCoRr' 20l 9 lRl)CIIAP,IER tI MODELNG RLstjI,Is Table 8.19 - Preferred Portlblio Summer Capacity Load and Resource Balrncc (2020-21029) t0.1r l}i.r ltl.d.e *6at6 FDnl Ofe Im.crbns 1018 570 I 291 0 l]9 JJ6! 0 0 0 50t 1,441 3Jr0 2t1 I 285 D lll0) JJI.T 5t8 0 0 5lt J,7Jl :.oa I 2 ltl t:06 1.716 5lo 289 I 218 0 ]9I 3,tt2 lt5 0 0 t53 Jta ,!57t 3J29 ({5) 1.716 :98 I 0 I,tt9 ll0 0 0 0 288 ln6 :l0l I 218 l3) 120 J,I26 0 0 0 105 302 !621 1,597 3.753 1,1$ 5r0m Iy4 0 29t,N2 0 0 0 .l5lt 3.6i6 r5l ) :?3 I ,296 t.t07 0 0 0 0 22\ l.{97 I ltl lrlJ 3,695 0 0 0 5rJ trl9 3.113 w.!l Pl &d Rddr..! w.ii Tord Rdruc.r l,[trtrir! l{.rcn,e! {r ]!ir l.t1 3r85 117 !21 !Jt2tll) JJOI JJ5] lJ! r]l tJ2IJ:.r.]2 lJz{JJ2J JJ2I ,1ll lJ2 J.74.,ll!ll , tr:r JJ!I .tJr I 1l:.tl: n.rrOui*{ia + R...lB \'t 6t P6i.im *.rr R.rce Mrgitr 32 JJ57 JJ56 ll"b ll.t8l 1.107ll. t] 1_108 I t,102 1,321 I t.lol {lr l1.ll7 I l.l:8 I t,:19 t,llllt.tll I t,l@ l,lt7 I l:?0 t.t l3 lt,2li3 1,3t9 llr84(lr 11.105 l.Il 1l.l1x lt.t:o ,Ull 259 &r End.: R6dEs f'Dnt ofic. TBrssclions ,11 5 123 6rJ5 205 0 t6l I t,tt? TJlt 706 lt5 508 r88 170 :9 tJ5a 615 lt5 ,21 2t:l .t7t ?.1 l5.l l8? tJ57 7.C!7 118l) 3.E3E 7]5 5 555 123 0 6i:! 6,2{t 307 17 0 !88 t83 29tiJ9 11 I,l,l0 :1.3:18 74nt 5 3:3 0 5X 21 r82l9d 1,450 (:61) 3,838 117 lt5 501 113 0 847 aJl,t3 309 21 0 201 t3 r117 ll5 E5 121 887 5JIJ l(}) 8:il 5tl :8 0 ?14 :8 2Jl9 7$t2 2,9t1 t1lltl 0 8ll 5.lO 2t 92 149 2,4t6 3.2m(lI) 1.313 5 t:l {ll 5p9r I}n'akC.n.nlion I l77t I t77r ,r.l 6"151 |lannire lcscfrcs r :llr r 6J51 901 EBr Otai*.rio + t16.ffi fsrFdiria Far R6.N Nlrai. 7.652 8 1,120 1,19t (J3l) P^( rr rcor{l' l0l9lRP CHAPTIR 8 _ MODEI,IN(i RISTJLTS Table 8.20 - Prcl'erred Portfolio Summer Capacit-v Load and Resource Balance (2030-2038) 2031 l0.lJ 1037 \r'6r Ehd.l R6l.F6 tmtrr (]6.. T6rsacliom 'l4Br Ple.d R.rouree W6r ToEl &r@l@ P,iv{r. (in.aion W.rt.Uigrto Pl.nning R.rcd* (l3o/o) w.ttL6.Rt I:rl 1.t07 0 0 l7l t.37.! 1.265 570 143 I ?22 0 t,7E5 I,107 0 8 162 690 a:16, I t::t 0 2,0?t J.303 1,265 266 I z2\ rttl I,to 0 20r0 tjt l 1,738 l.:65 I zli 0 ts76 1.107 151 i6,12 :t- 0 l@ 2i22 l..tjl _t.ar: I I,r07 aa 0 5? 2559 1.107 l8 89 l.lcl 8 0 5?8 lp00 3Jt0 ill I 570 410 I 201 0 t,06, 1.265 259 I rr89 .ltJllJll tlI 423 3J5{ .lt1 l2l ,lll ,12.1 J.!10 lJ0.r .l,l3l $.itOtrie.do + R6.Nt \&rr lciti@ W.rInB(rwll$EiD tF. J689 t!J) ti71 22t Jn5r J.62t r.!l l-<98ttl,Jl1 I1.34' IJ]6 llJ50 1,354 10,0:8l.], rt) t3% _ltr l_:lt-l IIJJ] t0.0 l_11.t IrJt5 1t,1.16 10,0:t l.l1; I l-1116 lt.t37 L 1,3]t t1% lJ:8 tq@l.lll I t,l9l 260 Lr lttttta Rsrrc.r tontoli.e TE6sctbn! I I 2.019 l I Iti ll8 rlll :.r l I lEo I .t.i{5 tr l,(r10 lt5 5_532 (l I 971 6JJ2 0 I 7,715 681 6' 0 I 74t 0 0 61 I 919 84 0 I EutOlii*lrio. + R.rerur [!rPailion llnr R.leN tt rai. l-<35 1,611 :r 5.8E9 (18)(18)r:8r {18) 1r77r(l3l llr15) 5J96 '124 724 5,1r0rJ$ 5J0l aJr9 rll 1t2 7t.l r:r I 7J7S 7J7e ?Jlr 7.161 Piv{rc (id.drbn 5.6:19 Pbnni.B tuse^.s r l1'") sJsS 172 5rr20 ,3 724 6,t43 lJ32 sJ05 7t.) .l9l P^('lHCORP 2019 IRP C Apt'l-R ll MoI)ULING Rlistl.ls Tablc 8.21 - Prcferred Portfolio Winter Capacity Load and Resource Balancc (2020-2029) 1fi:O ![!t to!J ]ll]l !015 t0!6 w.rt Eltd.a n tdllg Fm 06.. Ttullcri)nt l.(lll) 670 672. I t42 0 ilql t57 3,!24 llt 0 0 0 0 tr5 a66t t)11 ,1t: ,r!, 6m 15t I 102 0 (lH, t53 .t,l6i ln 0 0 0 0 0 3,,t31 rJ53 lJ.l0 1O{l 2' I 9l 0 (l) t49Jr'l 1010 zx.t I EE I'16 rr59 lrt 0 o 0 323 t;E2 :1.529 3J'1, .lt5 1f,5 lJa2 t.7x 6tu 111 I 75 0 2926 1.7?8 l17 I 292O t,718 t:t3 I 12 2pr5 t.z3 I {5 2.t88 tol 6l 0 J,0!2 670 l17 I 0 2J99 219 0 0 0 0 6: tm .t8l Itr58 !16 I 2312 156 0 87 962 JJOJ ltl 0 0 0 .!r I JJIJ 1,499 3,),79 ,16 l0lwcr I lluxd RBE..! llerr Tot.l R.e@rc6 3,0J0 5l 0 (l t l,0I 0 0 0 0 0 0 ll6 1,03r 1,605 i:3r r:3r Wdt otalA.do Pbrnhs R.s.des {l:19/') lvBi R6.lE *'ar Odi*rL I f,a.ru w6tPdldo r,Vdl R.i.c \&4i! ll, JJf,I {.JJ lJ.rI .t3l (lr) l.l5 t13) r:t5 J.7a5 JJJt 3Jr7 r:".' ll,762 1.150q8ll Ll98 r 1,09! 8.7:5 tllJ I1.051 8,743 t.l@ t.l5l 1.153 'll 10.,I I 3.751 10,:55 8,611 LI.t5 &6t4 l.t,tt t.l.l7 9,836 t. t50 93ti$ 261 rrl lH.d.! RddmB !&nt O$r. 1'@saclions 0 0 0 I 1201 ql: 4"119 5'l l15 \16 0 0 ?!5 42]9 1t5 ll0 0 s.0r8 180 t3 0 ll rJo.r r.0t5 5 18,{ 0 5Ol5 0 t30 l0B :]l lJa9 Llrt ]J l lt 1..190 3.9fr ll5 ]JI 0 0 5rx5 180 t.t35 16 0ll] 0 10 lil93 5ltl 0 t80 !.141 ]6 lll I J98 1.099 ll5 0 8l tJ95 881 l.2t:l l8 0l9 2it6 881 t.ll9 38 ::8 0 190 7,156 55t0 0ll lJ,ta Pn$ar. c.n.6li.. 6,lll 6.t30 6217 ll:' 6.1:0 (18) ( 1?7) (18) ll77) (18) \111)(lli) 7ll 7ta 7li 735 118)l18) 5Jlt 6,0,t.1 238 5Jlr Phnning R.s.ner (lltr I3 12!120 tisr{) ig.li0n+Res.rreshrltsilior Ful Rr:.rr l&rsin 6,023 JOJ 6,0E1.llz 312 6,2tI 5t6 :l-qi, P^(,II ICoRP 20I9IRP Table 8.22 - Preferred Portlblio Winter Capacity Load and Resource Balance (2030-2038) !Il.: Wdl frnd.g REacl Fent Ofic TEB.cttun! w6r PL..{ R..ous w.rr Tor.l R.ror.6 Privli. C.n.atbn \ry.rt olliEnio Phrhs ReseNes (llp/d ll.rtnE.ru. rv6lo la.do +R-.8 $€t Pcitid W.tt X6.rE lr4ir l_r8 t$ Ill 2,.fi0 t5i 9.rl ]J5J 1.2J8 B5 I 0 ,188 23)5 :u 615 911 t:3 I )1 2,.t5J 10.1 0 5t 715 lo9E 355t l.!s8 I t9 !Jl7 0 5 120 7J5 t.05i l.:t8 I 2,13,1 _,16 (l l]5 1,08t t:58 159 I 0 105 2)at 157 0 5 715 I,tzf, t.25t I 25 0 l5E,J9t :n) l.r5 u.q)l l{2 3.8.ll (llt?) lsl ]t5 ll 0l, rJ2.r lc2 lr0 Iu 0 t7e) zn rr!,r 151 215 0 lt tJ06 JJ5O l,.tl I t_0,t t69 I 14 tJ35 t_816 0 ll9r J,7i0 .rJ{6 ,r.,5 J.r8r lJ55 ,lJd l.,9t rrlel a!8 !,toE 3J96 J'aJ8il,l) J,,l l5 't.t{ 3,71t ,tr 8,816 9.985 10.070 &E92 9 803 t.150 e.E:0 8,681 ,.t51 8.811 l.l7l 10,125 t.t85 lotS 262 CHAP I I.-R 8 - MoD[LINC REsI.II,1.S l P.^cr|rcoRP 201 I IRP (IHAPTFR 8 - MoDr-.r rN(;RFrsrrr rs In addition to the resource portfolios developed and studied as part ofthe portlblio-development process that supports selcction ol'the preferred portfblio, a number of'additional sensitivity cases were completed to better undcrstand horv 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 aftected by changes to uncertain planning assumptions and to address how altcrnative resources and planning paradigms affect syslem costs and risk. Tablc 8.23 lists additional sensitivity studies performed tbr the 2019 IRP. To isolate the impact of a given planning assumption, all sensitivity cases are compared to the prefered portfolio, case P- 45CNW. Tablc 8.23 - Sum of Additional Se Cases Low Load Growth Sensitivity (S-01) Table 8.24 shows the PVRR impacts of the S-01 sensitivity relative to P-45CNW. The reduced loads lower system costs significantly over thc 2o-year study pcriod. Figure 8.46 summarizes portfblio impacts. FOTs are reduced by an average of 275 MW from 2019 lo 2024, and by an averagc of' I 29 MW from 2025 to 2O?7 , followed thereaticr by an average ol 103 MW less per year. Over the f'ull portlblio, cumulative wind is higher by 162 MW, offset by a decrcase ol'346 MW ol' rvind rvith battery, solar with battery and standalone battcry. Renewable and storage resourccs are reduced by I 84 MW by the end of the study period, gas peakers are 221 MW less and DSM dccreascs by 25 I MW. Table 8.24 - Stochastic Mcan PVRR Benefit of S-01 vs. P-4SCNW 20.617 Lo"Bnse Bases-01 P-,15( NW lll 10 s-0:Iligh Load P-.15C\W tt.60l lligh lliNc :016 2t.614s 0l I in 20 t-oad Gro*1h P,.15CN W lin l0 Rirsu Ilirtc 1026 :l.75ti Ila\.Bas!t0:es-04 (icnemtion P-.{5CN W s,0i lligh Privarc Generation PJ5CNW 1t,371 llish llrlsc Uasc t0l0 I1.6q5 llrN.llrNe 1L\c U&rc B: \.l0llts-06 P-.15C\\\'1t.609 tlase lliNc R3sc Base Nonc :0i0s-07 No Crlslorner s-08 All ( ustomcr P-45CNW 2t.616 Aasc IIigh 10.10 $22,080 (s I .127)()1)O? 263 Pareol Case SO PVRR (sm)L0ad Prirrle c(): Polirr"F()Ts Customcr Preferencc Trryct Firlt Yerr ofNe$'Thermsl(lase D{:scripli|,n Additional Sensitivity Analysis Mcdium Gas - llledium COr ($ lllillion) s-01 (Benefit) / Cost Relrtive to P-45CNWP-45CNW P^crFrCoRP - 2019 IRP CIL\P]'ER 8 M(N)T-I-IN(; RLSULTS Figure 8.46 - lncrease/(Decrease) in N ameplate Capacity of S-01 Relative to Case P-45CNW 1500 1100 700 3m --N*,0*ssr-I..!!-r!--tffi lr---rrll D -900 -13m -17m ,droo"sl"Or*f ,o""dror6rdr$rdr&""d)"dP"dP"&""d"e""d"re- r Coal Removed r\ Sdar+Bat Class l DSM rWird a Batteryr Class 2 DSM r 5d8r r Punped Storage r FOT r Wind+Batt Gas High Load Growth Sensitivity (S-02) Table 8.25 shorvs thc PVRR impacts of the S-02 sensitivity relative to P-45CNW. Higher loads result in signilicantly increased rcsource requirements which translate into higher system costs, Figure 8.47 summarizes thc resource portlblio impacts. Annual FOTs increase by an average of 472 MW through 2024 and 556 MW liom 2025 to 2027, tbllo$,ed by 35 MW therealier. Renewablc and storage resources increase by 670 MW by the end of the study pcriod. An additional 953 MW ofnatural gas peaking capacity is shilled earlicr, split between 2028,2029 and 2033 instead o1370 MW ofgas pcaker and 505 MW olGas CCCT in 2037, for a net incrcase of 78 MW. DSM increases by 23 MW by the end of the study period. Table 8.25 - Stochastic Mean PVRR Benefit ost of S-02 vs. P-45CNW $23,207 s24,3.16 $ 1,1 39 264 = q, o- Ef(J Isi\ llledium Cas - l\Iedium COr ($ Million) P-,l5CNW s-02 (Benefit) / Cost Relative to P-45CNW P^cr[rCoRP - 20I9 IRP CI IAP] tiR 8 _ M(}I)I.I INC RESLJL,I.S Figure 8,47 - Increase/(Decrease) in Nameplate Capacity of S-02 Relative to Case P-45CNW 1500 1100 7m 3m - 100 -500 -900 -13m -17m rlrrr.rllll GT ,1f"+oref rd$"&Vp"dre*rdreo"c)ra}rserono"rd"o""d"ro" r Coa I Re nrove d $ Solar+Bat Class l DSM rWind+Bat r Gas r Wind r Battery r Class 2 DSM r Solar r Pumped Storage! FOT l-in-20 Load Growth Sensitivity (S-03) Table 8.26 shows the PVRR impacts of the S-03 scnsitivity relative to P-45CNW. This sensitivity assumes l -in-20 extreme rveather conditions during the summer (July) for each statc. System costs arc higher due to requirements to mcet additional peak load. Figure 8.48 summarizes resource portfolio impacts. Higher peak loads require morc annual FOTs, 158 MW greater on average from 2019-2024,220 MW morc 2025-2027 and 36 MW thereafier. Renewables and storage are dccreased by 304 MW, offset by an increase of'210 MW in gas peakers and a 62 MW incrcase in DSM by the end ofthe study period. Table 8.26 - Stochastic Mean PVRR Benefit Cost of S-03 vs. P-45CNW s23,207 $23,388 $l8l 265 = @.: rp =E =U Medium Gas - Medium COu ($ Million) P-45CNW s-03 (Benefit) / Cost Relativ€ to P-45CNW PA(.II ICoRP 20 I9 IRP CIIAPIIlR 8 [,10I)IiI-INC RI'SIILTS Figure 8.48 - I ncrease/(Decrease) in Nameplate Capacity of S-03 Relative to Case P-45CNW = OJ s =EfU 1500 1100 700 3m -100 -500 -900 -13m -17@ nnnl.-Nllll r---..NDI5IDrI* "S"&"rd)"dPrdF"rd}"dp""dr&t"d"&""dlrdlrdi"&""d"&""$"s.r Coal Removed N Solar+Bat Class l DSM r Wind I Batte ryr Class 2 DSM r Solar r Pumped Sttrage r FOT I Wird+Bat lG6 Low Private Generation Sensitivity (S-04) Table 8.27 shorvs the PVRR impacts of the S-04 sensitivity relative to P-45CNW. The lower private generation assumption result in higher net loads, increasing system oosts. Figure 8.49 summarizes portfolio impacts. Annual average FOTs increase by 6 MW from 2019-2024 and then 98 MW from 2025-2027, Ievcling out to I 7 MW higher on average thereafter. Renewables and storage decreasc by 305 MW over the long-term, along with I t4 MW less DSM, which are offset by an increase of443 MW in gas peakers. Table 8.27 - Stochastic Mean PVRR Benelit Cost of S-04 vs. P-45CNW $l:r,107 $2i,i08 $ l0l 266 Mcdium Gas - Medium COz ($ Million) P-45CNW s-0.t (Benelit) / Cost Rctative to P-45CNW P^( r,rCoRP - l0l9IRP C AF rr,R 8 - M(n)Lr.rN(i Rr.:sl Il 'l s Figure 8.49 - I ncrease/(Decrease) in Nameplate Capacity ofS-04 Relative to (lase P-45CNW = qJ -ga EfU TTNRRRRSRNNr--r'r 1500 1100 7@ 3m -100 -soo -900 -13@ -17m -r-III----rrrI ,n9r+a"sl.rePrcPro""rotrro"orsf ,**rotr.roora}ral"s+"e".rd"reord"rd r Coal Removed $5olar+Bat Class 1 DSM r Wind+Bat r Gas r Wind r Battery. Class 2 DSM r Solar a Pumped Storage r FOT High Private Generation Sensitivity (S-05) Table 8.28 shou,s the PVRR impacts of the S-05 scnsitivity relative to P-45CNW. The higher private generation assumptions dccrease net load, which in turn decreases system costs. Figurc 8.50 summarizes portfolio irnpacts, which are minor lor FOTs and natural gas over the long-term. There is 300 MW less renewable capacity and 92 MW less DSM. Table 8.28 - Stochastic Mean PVRR Bencfit ost of S-05 vs. P-45CNW s23,207 $22,970 ($238) 26'7 Nledium Gas - Medium CO: ($ l\{illion) s-05 (Benefit) / Cost Relative to P-45CNWP-,l5CNw P^( ll,rcor{r, 20lg IRP CHAPTTR 8 _ MODF]I,I};(; RIJSI]I, I S Figure 8.50 - Increase/(Decrease) in Nameplate Capacity of S-05 Relative to Casc P-45C){W 3 q) s =E =U 1500 1100 7W 300 -100 -500 -900 -13@ -17m .\tss .Cqr$ <qtg \ss. ,\r\\ lllll---rrr i "d"e"rd}"S"S"d.rdr*""d.u*-"da$aoadi.ud,,P"r..f trno"rd"o".rd.ue- NN***---ITI-NNN t Coal Removed N Sdar+Bat Class I DSM !WirdI Batteryr Class 2 DSM r Sdart Pumped StsaSer FOT I Wind+BattG6 Business Plan Sensitivity (5-06) Table 8.29 shorvs the PVRR impacts of the 5-06 sensitivity relative to P-45CNW. System costs increase by $72m whcn studied in SO and $831m when analyzed using PaR. This sensitivity complies rvith Utah requirements to perfbrm a business plan sensitivity consistent with the Public Scrvice Commission of Utah's order in [)ocket No. l5-035-04, summarized as fbllou,s: Over the first three years, resourccs align with those assumed in PacifiCorp's December 2018 Business Plan. Beyond the first thrce years ofthe study period, unit retirement assumptions are aligned with thc preferred portfolio. All other resources are optimized. Figure 8.5 I summarizes resource portlblio impacts, showing diltbrences associated with the prefbrred ponfolio's assumptions ofNaughton Unit 3's gas convcrsion and Cholla Unit 4's 2020 retirement. These are couplcd u,ith an average annual increase of 77 MW FOTs 2019-2024,207 MW higher avcragc annual FOTs 2025-2027 and then 5l MW less FOTs thereafter. There is a ditlbrence in the timing ofnew renewable resources and storagc, which net 23 MW higher through the longer term. DSM incrcascs by 57 MW. Tablc 8.29 - Stochastic l\lean PVRR Benelit ost of 5-06 vs. P-45CNW s23,207 $24,0i8 ssi r 268 N{edium Gas - Nledium CO: ($ N{illion) P-{5('NW s-06 (Benefit) / Cost Rclative to P-45CNW P^crr,lc( )RP 20l9lRP C APTLR ti - MoDEI-tNC RItsulls Figure 8.51 - I ncrease/(Decrease) in Nameplate Capacity of5-06 Relative to Case P-45CNW = qJ .=sf E = IIII****- .........cKKrGEHrlrrrrllrlN-----sN-r 1500 1100 700 300 -100 -500 -900 - 1300 -1700 "oP"&"rdl"S"S"o""d"ro""rd"o""d"e""dl"P"dre""dr*""d"e"r coalRemoved $ Solar+Bat Class l DSM r Wind r Battery r Class 2 DSM r Solar r Pumped Storage r FOT I Wind+Bat ! Gas No Customer Preference Sensitivity (S-07) Table 8.30 shows the PVRR impacts ol'the S-07 sensitivity relative to P-45CNW. The no customer preference sensitivity reflects no renewable resources specilically assigned to cuslomer preference, compared to basc renewable resource proxy options. Figure 8.52 summarizes portfolio impacts, which are zero for FOTs until 2024, when FOTs are 77 MW less, fbllorved by an annual FOT averagc decrease ol55 MW 2025-2027 and an average annual increase ol3 MW therealier. There is a 30 MW incrsase in renewable and storagc capacity and 32 MW more DSM. Gas peaking resources are postponed and nct to zero. Table 8.30 - Stochastic Mean PVRR Benefit ost of S-07 vs. P-4SCNW s23,207 $23,r26 ($81) 269 Medium CJas - Mcdium CO: ($ s-07 (Benelit) / Cost Relative to P-45CNWP.{5CN\Y I'AL rr,rctmP 2019 IRl,(.IIAP IIlR II _ ]\,loDI]I-IN( i I{IiSI JI 1S Figure 8.52 - Increase/(Decreasc) in Nameplate Capacity ofS-07 Relative to Case P-45CNW = o, o =Ef(J 1500 1100 7m 300 -100 -500 -900 -13m -17m N\\\N\\Nlri*iliiltI ...,.rs$ss$sGItrIIIa--*-*NNN ,drs,""6l"S"S"dl.rdr&""S4}""d"&",s"0"d"&""d"&""d"e'r Coal Rernoved $ Sdar+8at Class l DSM r wind r Batte ryr Class 2 DSM r Sdar a Pumped Storate r FOT r Wind+8atrG6 High Customer Preference Sensitivity (S-08) Table 8.3 I shorvs the PVRR impacts ol the S-08 sensitivity relative to P-45CNW. The high customer preference sensitivity reflects a rvider range ofrenewable rcsources assigned to customer preference, comparcd to base renewablc rcsource proxy options. Figure 8.53 summarizes portfolio impacts, \,!'hich are zero ftlr natural gas over the long term, delaying peakers. The annual averagc FOTs are zero until a 2024 decrease ol'20 MW tbllorved by 5l MW less on average 2025-2027, and l2 MW less on average thereaficr. Renewable resourccs and storage incrcase by 80 MW, slightly offset by a decrease ol62 MW DSM. Table 8.31 - PVRR elit ost of S-08 vs. P-45CNW s23,207 s2i.l86 ($22) 270 Medium Gas - i\Iedium COr ($ Miltion) P.45CNW s-08 (Benefit) / Cost Relative to P-45CNW P^crr,rC( )RP 20l9lRP CHAPr F.R 8 - MODEr.lN(i Rl.rsur.Ts Figure 8.53 - I ncrcase/(Decrease) in Nameplate Capacity ofS-08 Relativc to Case P-45C\W = (u.z (! a Ef(J 1500 1100 700 300 -100 -500 -900 -13m -17m "..i9r*o"uo}rdP.ud"d"f "ro""d"*."d"uono"uo,,I"rdry"uo+reordre""d.re" r Coal Remo\./ed c{ SolEr+8at Class 1 DSM rWind r Battery r Class 2 oSM r Solar r Pumped Storage r FOT I Wiod+Bat ! Gas 271 .... .\.* Nrs N\\ rN\ * N N.N * n* NR R cR R o*---IItrlr-:-nrrquI!!! P^( rF rCoR| 20l9lRP ( ti,^P lttll N1{)t)l.t t\(iRt'st I ts 272 P^( [ l('oRP - ]019 IRP Cl lAPl r,rt 9 A(roNPI-,,\N CunpreR9-AcrtoNPlaN CHlpren HrcHr,rcurs The 2019 Integratcd Resource Plan (tRP) action plan identilies steps that PacitiCorp will take over the next two-to-four years to deliver resources in the pref'erred portfolio. PacitiCorp's 2019 IRP action plan includes action items for existing resources, new resourccs, transmission, demand-side management (DSM) resourccs, short-term firm market purchascs (fiont ollice transactions or FOTs), and the purchase and sale of rcnewable energy credits (RECs). The 2019 IRP acquisition path analysis provides insight on how changes in thc planning environment might influence futurc resource procurement activitics. Key uncertainties addressed in thc acquisition path analysis include load, distributed gcneration, carbon dioxide (CO:) emission polices, Regional Haze outcomes, and availability ol'purchases fiom the market. PaciliCorp further discusses how it can mitigate procurement delay risk, summarizes planned procurement activities tied to the action plan, assesses trade-otli betu,een orvning or purchasing third-party power, discusses its hedging practiccs, and identifies the types of risks bome by customers and the types ofrisks bome by shareholders. PacifiCorp's 2019 IRP action plan identifies the steps the company will take over the ncxt two-to- lbur years to deliver its preferred portfolio, 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 stratcgies. Resources included in the 2019 IRP preferred portfblio help define the actions included in the action plan, fbcusing on the size, timing, type, and amount ol'resources needed to meet load obligations, and current and potential future state regulatory requiremcnts. The 2019 IRP action plan is based on thc latest and most accurate information available at the time portfblios are being dcvelopcd and analyzed on cost and risk mctrics. PacifiCorp rccognizes that the pref-erred portfolio, upon rvhich the action plan is based, is developed in an uncertain planning environment and lhat resource acquisition strategies nscd to be regularly cvaluated as planning assumptions change. Resource information used in the 20l9lRP, 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 firr resource procurement and not as a commitment. Resources cvaluated as part olprocurement initiatives may vary f'rom the proxy resources identified in the plan with respect to resource type, timing, size, cost and location. PacifiCorp recognizes the need to support and justifu resource acquisitions consistent with then- current laws, regulatory rules and commission orders. 273 Introduction C.IIAPTF]R g - AC IIoN PI ,\N In addition to presenting the 20l9lRP action plan, reporting on progress in delivering thc prior action plan, and presenting the 2019 IRP acquisition path analysis, Chaptcr 9 covers the following resource procurcment topics: o Procurement delays;. IRP action plan linkage to the business plan; I Resource procurement strategy;o Assessment ofowning assets vs. purchasing power; o Managing carbon risk tbr existing plants; o Purpose of hedging; and. Treatment ofcustomer and investor risks. ?.'7 4 P,\(IrCoRP-20l9lRP r-an =a9pdY ..1 =- =o- otr'o i;=r-!f9 oov .E oi ENC* cotr z*': (., c :': 0Jc>: 5Dc ()N o.trEi r)o! ,il tE Lt tr-cll .q d sl:2 d:l '; .i Et ,lv !l aElZlt -.JA 9_, oiJ -o c- - 2 =';4.*a\z -oa; a .!.c -r. = .r q!.o84i!E ! i ssEio=.rE.: G"1'.'=2Q64aZi L:F:E1t'z!.al '? u !=.4 F:.i:.- F =trp c.aP€ E= 5 =.'E!sEE3?b E;i iE 0 s EE = Z.--:c9=a,h--ax:eEf Eb6 .c ,=87=E=:Ei I6;ESi=:..i no = 2 c-tr !!: t,;--^cJdr=t--o! =tX?P;=strO hnd ^^ar.:trYa-c=c!= a a,, c -o cF O-=.-:E='=j=o!'t--o; F 9.E'; =; ; .; = = L.= i = >P u ?E; 2 L- ! I € a E EL(JE:!l'J^.---r;-. -- a 9:_.- - E d .r, 1)+ !:.{ oo'q E €-o - ?,- ? i4 E: 0,, 7 0r - a'.- a i. J.j t) r *P '. ()5E*rE3!gq.bE9-:=i-=.-=-l- "1 ,: EE E E TE T; UE.+j,:.3:i r.=,2 =; ;+ a.. tJ !, u = 6i7-_.= - . U q 3.1 _O O'..\JCLO'J=-ar!, .!.:-ciiEr=>t=n=itrgE€E;= =.,EFEligbl'lv q, :'E i ;i o-.: c- E -4l'E.=-e!"io7=27:tii'EYEz,==,i,'- i--t')Ptrodo:1= ". - .. - J a===-i:Orror- =-o.:Eo=a.l-ct,)a.l".^----J.=0.tEL=:'.!Q.rqN ,=-ora'=--at-<r. (g t; c a -a ) -a l- -l.-u-t;-.=v':v!?!.-.;.a- d;i -,- r,- ur (-_.irii.--F or otr 3o.! o;2 lU-'o ?'o.?'o .a :.a a.9 ; il : 6.E aWe'J_5--=!<.",E.) =E=*.s'jE?E7EEHssEiasasi $ = Q Ba- :1ll '- F ;1 'd E: bD S o -'J-.----r-c -i,'r3 gi!3 r.r- u€a.l =61 -rFOS bE 5 t-, !'I E tr:a r- ,'r o F c '-roi E ! r-, "=->5 .FZ: ILr J l,-bR:1 c I EvLe(!.l !lL! !+:-;8,U 5d:'E !.E .. 5 20 g" :) >'.5 q-r tr tr-= - 0r E., dE OaOolJ ?^= -o _ -! >, _!:Y- F X o> HL.=^Y.=-'= --c:Yq-.!.-.L^.= E E >.8 H.E o,'(g:i_o e -.E dPo. 21't.q>'''f o -6r - >,8 ? .n'=ELtra2Xi,aOJO.'9;LJtrLtr.{L=EoL o .'Fi fi 6 I c K U.t ZP I h n = 6 u'= a.) 'w dr ti - -O J^.r >_N O.y(ELryF.=iV.9-u - >\ i: c A) = :l€ u q.!E!.:6 :4'r-.J..r(.itr.=Y;'c-oco.= Y = i..r ..1 ..r L.= = 6l:.4.1 a'{ + a: = .d o iiOOO-- aC--;^i^A!li,e.E.Q;;;+E.Z2?.EEEXU9'; = c, a a .4) 'i-:e=;:;a = d cn >' >' >'a aaaa U o, a.l I a, F .= -., o-ox eaL_.o... u:l ;ri O- (J 'r,;oo'= 1) - 2:s .-:o'+ '- oo,nl! uo* a>+ -= -i9..a= yodo-o-q.r 9o .d ,lJ o > --c ,' -= 6 60>.6 c0 --o .=L! oJ-:1*Y c) zdI = -u L' €:E E'- r,! n -!l..==2 .O.= X ol) .,J! C ()-l o-, := L 'J!dr>. ^ -= - Y !i r-'= F<- O-d z Ez =i) IU A o U 0) g! tl I o\ e.l F a) cIl o o oo OJ o () (,) tr 0.) 'od al c.l iJ .q c) () 5_o id!:!o* ;'i o 9 -.i!--i-r., , -!r ts a_ 5A; H ',.r rr cJi(q 3S ,.Y ih = >,.'.r E '= =, e: 'j, hEa--hY5or bL tr ^" t".-jd^i EE Y rb-i E t7 't^: ., -v'w C ir !i'q e -E i- .9E ;;==;;: Er !;ur..: )'r I P ;h :.= : - I h X >- *: -.naE 5.= ol) _ o'E >, f" . i = .E E -;itfs-;= E6EEpf E-"-e aet5^=o=trE :.zillu E = ; a o Y.* L 2E H E F * E*:'itiy-iE 1:Z-!.994=, ;.:i:q o!.= L = 6 q e" tr ..r =tr E o S{ Fbr.REHE a-ag3 9p = I E I - b!.a s F :: ^ ^ = !;! 3 Y !.i Xtr u,Q-,[iliE!€eE:E€;i.=€3E.EsE llJ '= E a.r .{ .. e.1 .. - ..ri 1 r e.t ..i ..1 Ca .J i ..J.= :.1 +'o o c - c rlc.= g = a.l a.t aJ 6 r.J L r..t.E = E c..r c.r o.r q.r + u9 s =.do3CC/XO!=O5 a e a o o.: 3 X oc-E-9===-'ti'a!.ZAiE;.:;i]EE :t- 2'i o' u t' \ o.' ? ct E(; q;.c.c.E:E ii -E (JsEE;ersat;$ aaaaaa 6l = al z ut>'EC o=p.bo :oi =aX=(Dc- o- ='wIO1),c, (,= trd) o3 ;o- cF cl)n)(i rU !=bo E d)O'o r- 6r ylt ja);io^ uy '!- aro !tc!>rr.o +:L=.JE C;2 o- go a) Itr=FU-=U !U <- o,u- cOa\==- c .odr^:i Eaa!'i Y aJ dr:': X!e!:;- --r, =6'.= c- I +6 rla -EP.:E E1,) t- d crlE (. T ,C Y!JZJI- o. 5 -> (iJ "x arr + I ^o-cocP E€.96* >,o E,r?Ei3; o- e'=; E v.- E (J3E56:! u !(J =H E FgIar o, a i e t:.E ii'= o d -..,o,J !aCL.: -lj.1 ^ - -ca.rL:J(EI b Fo- tr LL >r(u (! ',E u=t-t 3s 6 ?s'>- 0iL z 3 2 .t)..r'=--=o--#lE€FE;* 8l o3"l cEE!l 7=aE,<iYl ! n^.:C c o--l EfxE3? "u I ry5;: ry-l = H=,Ec h9Eai!r i9lI H b-'o aeli e.e E 5.=ol o ce =.r;"El = 8:"4559l =E* > >-oal >r'a' .",r- EI i:IEEE{l c.gl 56qELl U a t; ;;.= Jqrl r.= ^. = = o LEl 5a <.''-' = g;ldRssEs =lUl . =Ea EOEc d;a 3 6! saf ..- - ,='= !Z d > oUliro6 ,(,E.Eiio U 0)r5 = =!u:'Eon-^ or'E I'u =.= . d)tr - tr =-o 9.=/_\d ! :'; (.) .- o- a,- a ae A?E's ; qdr = E* EH?5 a 'rl a'3 - Q 59(JEx :J.q=Et g=€8. .a a ua - ,v u^ Pl-ir-.I]-'(J - c'=!=aa -.r'- E,f,r ..l ,U = , .rjEXi,,*3ubcEa:=, t) - a ^,= A, i (.,-t =-):':-rE I d sEA . g ? 9 6ooEi'=o -4 ..1 ^=;ZEailtf - -.c = .. lJ !'o=-.:qE 6.;E EjEeEx* !E9ili:-J o $ - \ \J,)E36i:b ac o (u a a a.t \ot--a:l z zoF Io H s o ,') o- o (u , z ".1 (l) c-a-z o-z tr.! Io t- s c-d 5 c..) t c- e'! .= a/,-ooUQts eciroc:o,:: ;.95 a .:: (!.4EEtr!o a a 93i a'EdtE-:o 'E iE o h..j= ! +E-=6 = E h :i?r a =tsar-"-l*lL '! 9.8- = (! .) o d-, .: odr Y :"1 -.J:n = := E EF (i O = o-P c = a) (, '- a-= !ie + +1*39 3 i,q?.z'i 9.= - .qE -. (J ^" or :,! 5>.e=Eit c_ ,r= .a - >\..- o-I IJ- -.a, ) -= t\,i d, .9 vG "n-c,ePc, Fio,8.Fqe ! p E€ g i H, I '; A-c- ij =Y,!. E; E E E-?ilT teIEETE1 a.E=bh€9u q1: = = .i -+o .!x_EEoEC ^. 6 > > '!!3 !d .=;_trEd?a 1=3_.EZ,eeo- o- r-! !J u o '.-:';gF -€ -Et-m d) or .a:,.}= g-E HH €E€:i;! r- .-.; .- -?,- = vR=+RE=Eln::::s:E'r;i. -) 1-., -E -1 E /^v - \J lJ:: v d) - -) -= a\ ^ aaaaaa .? 'E 1.1c= > i: i: 4l-^ =2q.ij- eP - = ci f?.: .J1E.E+i. trU)trr..= 8 g 5i HE iC I ! >. -o E= I'= U E .=o(r!Lrl- E -qp; f I E c-c = lJ = o !>a50(-oe+> c - cJ o 'o --'i 7. 9 .2EiQXps ^ ! --ia r u =e;:.e8;,;=E:aay. lse2?. -vQaoPE>€9.9.85 - d <\) ^iaE9>,L- lJ \-/ En - 5rj .aE.c_ ?:-Y.!tr.r-?=t-q*.=.4 -;t P.E 5 -")e-q-9er = > ci= i - 4 5:'9 ?:< EEyi9!-ico-.E:S;Ec-{3 E ..t.= 1., XAEA,E.ES()-:-!/ -\c a\ \J .,\ - aaaa a t) Ut- I o.r oP',, =9'-oc E> d_i - ,r o_Atr _:' I) E.Yo E. -cc >, H.9 9.> -, u1 =- E or ts9ilur.= -! ! (.) ts'= J. E.: li co o) = tr.a >U o*t= a Y .! 'i >..6 g ! |Jl'i, .v, 4 tr9-c H :j = \a:=c'- v) aara.cq- = 0.)t?9.,,,.:!ioro d=43 .: -.{ a.r i-r,a.ta.t.1E^sh cB U !J \-/ .= aaaf oo vdJ -.coL.=c0 2 Ya =LY0) tr-. -t o>lq E vl _o ;$,= (daa 5 0., -a <r '=t)) -o> ?::y y o.. E-a{=-(JY= 6> : -'7),i E;l YEbh E,CD.E C)t>'a- =v'- -;6 E o-6-6 x -cJ6. gr6 .l -.= c0 o0i c,E tr t-- -2 d FL_V- =ri +li ov.a-Y 'r od<LE'Ep .Y2!-!'rco, I-^ tr-tr' > (!.= O=oc -Eo 6.6 oidr E - w (r3 (Lr !-=Lt.9E-2€ x!y.J:= u ,(, = =.o o - E tr?o.roanoojj aaa li I = t- Z F .!21trlqrl EI oJl cl€l .=l flolal EI o aot-at h -it L r,? -c.-, F .Ei.i 5 - tL tt'= t q!'€ iiui ? d ==-cl ! ,5 *!-qY 4 E F5=E A(i = a-9 ! Eor=_diHt)<r=!aJ-u^= I :,n2l^,2a.; .='l-:d,u olI o.r ^i: ": 9.! _a ==!bo-E ^ - - Ei.=*'Y I -.! 9:E_O r,,.o = y !: s !.t o_, +.= .J 2Pu?it>:!,E- E IPE;3 .b -Y ts ; : ,9^r s'-t_'-.-C=c/rI-j'3oL-Zic-'. g E z *. -ot 9o-s!.:a?6;0( I tr - r,A. o:€t.;5i-c x - -r- E.- tr 9!!9d;?EFEvotTs-oT_ir- a) A.c= u !:Y=E=ea"6ii-:qr.==a ,.aa,aq,/ur>a.E>EEUTZea.tu.Ztt!iEEQstCZQ=-.e 9 i = =oo - 7=72 o=cn-=;-a*,tr.o9;;Jlo-.--;i;=E33 * l >. rE :r 9! = r\ 9FE!d;ii,cE3!#H?=&' aaaaaa i-i -oE i1 z6: a.EO FI '=c'r5a u g; 8 -: v1 2 r) ^i - t. .7) (g - .r (/) -tr:i-0Jdl.i- e 9 xl /c-o7.1.. .-' u .: (F =- | a, Z-(!?E-,=(JU.-'r=,D-,U - 2- r)?!.:-v i3 r b3 3r=-E^' g -l!L> = +84,9,;..--(J(! ; ELId-2 - = a t.a- tr !.,trEE-55tl' - t) LL. --E ',; .= ,'. 5ad +g)E EE+;}'ZE?ur:,, cJ 5a --C .r- lP = t )= i €E:E b E: F3PU/=a.=iE?4)o, i' tr --- o.iH-,==CJ 1:9-JN:- ; , (.l!EEx3 ^ oZv !i E-.= E dr' aaa LC o OJ ! (D a.l € eCJo (-)|). c_ >1i !/ =- a u7,; -Etr = o Li.l =i:tr.:uF Eqii E>- (J.: iJ ,rii'!-,==E), &;a ab0 (g.- 7: (g .= E = L C!F O n- CE ;3E E c F.ai LP a.=7 12 x!E->.,^; a =,= u6>.' t ,=tt1 >X = crE! t \tt ! t) +a o)'-c = i: ! : trij: 65]) 25 :7ii 6.d,h55lr = i?; Ir- 6-'.4 q > v ';, c= ia=aai =-- an - Y IiEui- A'-iE6c7 ;X;-!. L- O0.= ,e '- Ou-4 "- 1..= -.'+.q-Yo-r-Oira 9.-oa=J.= o-= E g: -;5=,:.7-a;4a(,_ P-c.= ". 1)a.E a tr i'i )i Lr:c;iIitr.rioruc?or 'E-.-;:JtsE !, - J 'J.= cl \, aaaa bt = L c0 = =P_ a.l:-O:,ii5Irat !: o t ^:=oz,- r ao- o ! :-E = Q !!ai: r.0 -= - ZELA!- P a- ot C.t -- :E:iJOY - 5I) d E3sZ ,i -: .o ar- d* =! = .o'u l -!: it) 3 F€< o-, E ti .. ^'Ei.OE=,ia2- c;5&-Cu ,7, c ,, .J -* ^ =.6?, A )- ! vr !-- o .r ^^; [=>=-.--o -.=6: = cJ =! Y -, I J1 ''- JyEIE !r'i ch =.9(J C , .= i-L_v(J:rdLT.JJL:-dO- aaa o OJLc) Ll 5a 1lita-l?l^l-t <llt r-l?t 5l d.l-lel il 8l EI {l a oE .I) c Eo a Eo a) a o 0) .E UL! oo oE 1)N tr a U blL iil q) ;t 0-r tbd d o0 .tr1 >l 5dtr !.)4) E.: =t a -l,= a cd UtLl L'J .rr3QPo05.E o,ts9p(, .!: t> &3=>,, rl 'E o_ > s 3€ o- -c e!)-! uH r. a3y cZ=oo-.ucE 105 aca !.1 > .- 6 Ft4, >& YQ;a tr.2:- -; ---: ?€ ts = ath tr 6c5 (a ('"1 ^,64 ?LEidz boo-",? .- a= Be; L=U' '! 6a-d<d aa a (lla L 4) -iE:6 le AfrE y atu!, EEAJri (u= :3 c ir: a H.o9 ,: =Y-dOlJi:'zSi -E E:-'d .r F?-o- *. y - (! = - - .-- .J,..e=.J-a-;il-'!OOi 5E fi3: 5 3.E ?Z!..r 9: .E -: cEa u ! !-cau ) 9:l+ :!ES i6Zf53 * lx*Et aPE€t 3 .9'; ra;E EP396r.r ;cE'i- L d = or!tr oJ,- rir i o!C:SEi:EJ(tsat-1Je(s u z E0.- G o, €I >. ?,= i. 02 'ii-o-HE i:= i', o-.q o- Y - -ir-=FC&'r:v ar dI)'= r '- 2 I{ t'3,iq.= EES H€ ! u{:; c'; 'E 9P ?E F-! a .! : 0).! E=: aP 9 >r> L e Y sFo.a.{=tr="+Esjj:o-€:5.8-i I i P -, ! Aii;=az.\E dl 1l *-! U tr t: i'gE E g;-(r:L<i:dJ=i>E.=ri.ts a CJ I ,;a\lCcn o Oc.l at cd tr o .'.l .a a 50 0)bI, a,) .- 9! 1) oh c'o !I)d E.f -:-o 'l Q.J :2,lao.\ :9n >o) co =^ia=3>= lro ^l = o- ..aczz ".) rJ\ ci =: ,".':: a{ v t P: >-.= 'Po= 66='tioo a g a 3 1 9 z 3 E EI E; I - E Ea /, 9 o fa LU b! q) t, , (9 \o a (u q) bo qJ a q) i -? a o.c-cl: 50(,bgLa -9 }E :! 1,)io- E'^d9= .E iz o.d:a =E3xEou I5c ?-.a aP otr->.98 =E'i aiiP.>.E=5OF Y tr"'o. Z-Y c, A (E 'd .i ='E,) e>3p 9 a-l€-E.a.o- ,.Y. o '.tt! a ul't.9EI 9 P +atr'= = o =l d-= ''fll H3>)=iQ91.- n t) 'El eE€EI.? 8 P dE:-E;l o- (g o- EIkll o o) a-z3 i__ t- 3 U ?_=Z ;:=EE: !E=iga F,Eits= EI i Ef I;: E *ZAii; ; EE€! Ei3 EEE;!i iif:Et i?11: tiz iEiEcE giiii€, !E?EEE ;E E: a gx=a ;EF=F,"'E E t€;€: ;i Eiii:; i€i;: :i ?i;utt Eii. i;E;;Ec ;E=!sss E EE; =E ;E Es +=Eii F;;;?:E :'rEaZ ;ais f i;i;;f ;i;gs€EEEiEE - I _!.t I i= = =.E E ," =n 'ei E.-i9.=:.i a\s 6 +_! -= aa;g;il iiEsrt;; e fdliEf€ EiIBHAEE-g gEH'q* tE;= SEEi ESEE# ; E;E$EE$iR Fiee;iE:E t EaEEE:E=:EI:CaiEeE r Z:EtEf€IE E=-;p p='FE6 E *lflE; i] 1$Hi Egi! $EEE; ir tE!13 il ;ig! €Es3 e'Erf.5iE 6E"ar; ,1 EBEB , =tEl . =l c a] = a a t- I(-l (.) F o_o )lor ra) &.= EF,, -t)o-oa..t o,u > a.l 'o a9 '- (-),.e &ctr r-'i ; .l!28u{iF -it .-cth 9>;i ?E X E7) -: oo .- o=E a.r (!,= ^a d >i.c a2; > c= Or- h v a.t Y c,Fc U-Fsa= E!aF.9 5no:OcrU (J., E-o=t: 'o <- .9 9.5 tr c.E z Jo-z =U I &L!F I(, d a.t &d U Q a o cq I () ^r!-c, tr oo>,tr --'=a.i-';,3 E'i:-_e46v.i t>; n cEiizl EiY,=.Ei sEE'- ! Ub! E,3E - E- ; ? =. .' i- Ll-.- C).-'E aC a.4?1 E PE2Art7'=i 3.2=::i2.6,i' .itu- =;'=tiE P.q(-,f z=-r. \ 5 i,= > r o-adEi=9.0?E9 E=c-'r ,,.! 7Y'.== 3 :\ 4F C /..! c- - =,'.E =.E 5.=,_ 10 J : =.=or:9& o, io. f f .i-f E=i:-.J=, - ic-^ _;tr'i (J-.^ ii;-!:: a.,t E.=.rc'V5^cZj:!ec.';H-j = q-- L= 1,, - - ^^..) =:: !l -d: L/ o !: P- ::' r-- Y l,= tJ- .,'_:0., >'6 + -v L, .o !-t,E = ? /. E ?= i y,2'.E 7 .- ;"i =E o- rr =s o-. x oE# BE ii4i#-r IE !) d o i.oq- !,'; "E=agc a- u. > = ^ = LJ-E1:g !7,5e = 6 tr u )l -^r- =E d.!J !12 LZJq-==iyi! 9 .5c- e ;'=:-9= t h^z-:- >,o.i;a.dP*oo't H 8" EU.E^i ^i<>,.7<94-tttr-;; E:.: E-J.o2..,:iq6;,=t:-.q=--u2'5>.!c=9!r:, 1q*s s l:.E Er,..,i\i-th! u d !,/ _= 6;i;=Et-Y,atr Nr 2 =: tr: ! -a(.)*.=-.aJ=r- Q'- -;Eijv <E: i E\z>5.!; E.sHrE - E c B- X r-^p : o a nJ a#:EE: iE: :l;r.a i.E3; EcJr*"-.!Y(s-Yv.v=r.=-.^;L-gF<c-/.i-:id.; TR UE iE g:F 9.f c, td YEE:= 5a=:_ >_E c a.l srtr _ -_ ^ - ca J _ ., a.q* 3Xj!,E:o3F X- d : -E d * e 9 .. ioor--Hv:tslE =€^3n!-358>E-:-.=t!'-'QC=;:*+E -o c ur):47,XEr\<.rE-.r?*r e alfrEaz !12Xo-i\-cEXEa ^C-l!-.rE-=-FPve,rE=i:; E.= a.o^Ud, E:i.:'6 3 * #-d- r.='iE6itr!()ii^Zl= ptr.=.a ", :p : .d > =-; ra+iE ; 2 P ;:Ei:ass.q:' ry = E E 1";,;*EE;ii i,? ig,' 7;EiZ=.1i4Ev ,i-E I5.= >aa ETEiE=i EliliiE+Ea! it g;i.E=i=€5:=5;:E: n:q-Er e. i sR! E ER:::=!= =iEE*\iAiZiiziiE;EEgE iE E?5 E tfE EgE 5gE fg () ^ >,= EEL}E} : I ,o <t = d2= .jJ= o-tr Q .:: AU(..{ q) ...J8 O^Y tr ii -- (J C ::: >,,. a,\ :'o al z ..,1 z F(, 5. L'F0- :EO o- al ea.l /,c:l o c- a =o0dE/.ur-E c)-ol .999 =o)-F oo "..=> ='=q!gd -oE Ea. > l" 6l i2=.EOJi!-o - a aE =0J-< H-a o0q caadr OI) e(, (g!i:- 0r El O. (; .-l xio)--o .\F =i1!:a ! q., =!E E 5i E coE- q!l.c ^ 3 5c g:: odE)2.6€ o.rdl i= oJCO=;i:(id r,ti dr.nv A.! e i G.=> ,.! O'-.c I 9E.E'B=Por a+ ^+ iif:!i'rri.=!,9.-a4=7* i! - q = gr o (!i ,= :Y(J+ E tr cr: ,, = 5 €d3 !) 9;C.A -E'oo;H*:.cE50ib5I)(, d 6.=E Q.='-H 435? 3d.d.9.t =d,t .! .9 -! - .:e E3 = s .g 5E.E.;,8.ii "i= . E = :E :reZEEai*y 2y,3.E i ='; ==E:a>'i\= i€5"E p a E :EE.E;?i3-q O tr 1.8 I .E = .. - i'{ = +E: E ='E E:; f i E 3 183^aS 5,E ; ;iBtg;i i i ! Es=E\c\E ==EE;;EE a-i !*E€=$iieEs ?i aEii e r ?: g. i E EEE 3I = iEi 2 E Ei =E * : s'p 6 x2 Ea ; E i s ae e ;' r I rQ E 6 DY. = g3 bE!*a? EEE P*i 90=Fs* ". .= !'J'o!g + sObo:iig tis tr+:-o o. a==a E Y P.= B g !()..,;\-Y- i.! = .2: .=qE: -^-a=--- 'O = i=,', h i-3'= =4-E* E E r I ERE 3.E{ 9.E gR a I an (\l Z J z tri, o.! -a 3. E!J o-d, a.l :- \) =,J U) o 9 q.E _9 EC}5'G96a.= E QE9 >-=u7 aa-, !oo-(J i = .,4- P c, lX 9:E=xTta ^'.- ! <:20=. -itr o c<-ooir - >.'E !0 l)> =-o 50 a)s 0) 0) J U oo .r ooa- :t5.!.t, r_ oo9Ec)'= -\ '2? lJF t!acooE-=A = 4 AEt h E.9., x -. E >r E9. q' I ?44trEE#:gge; EqE ?'a I oo ?-F ;.= c*! F€od9 - Eo<> zariU..t : = : := ,e F a FleI .9F == 5.a _1) ,a t) .= o;6>,zaQZ oE UC o.Oov 6,Jc-a c. 1) r) .': .) . O- .:w '= .B ; (, -, d a.l ,= r-=.J-6lr ^ a.J C!r -Fl:.iil€9 6-y d o.ra<ai? - 9= o.: tt -! 'rt cO. oo .rl ar hLr--= -:C.a.a= '' - (.'.1 - tr U:.02 L .= N O-Y Y ot'E&i;$xE'EJ 5 E."3;eBE.=9 9# to." tr tr- oElE6.:oz d y FE,-'(rf.= iX: i:9 i - 7.!.-t t * E ! >EErg':fT :: :jP= c'r 1= =Fo-^o- a!; o-otr.3=aEE3 s= :ie -::'E F= -z 7 E co;=qt<ol)itr -.i 6-=,.42'Jdr Yrl 5=+eEd;5f -; 9EH EiEE?i i; i =,sS;EEHE ;! d:E.+i;i;: R=.88Ei E E:g q 3! E"!;2, -==s:= r'-==Q=::n!:;SI; :,E5;F€i g^ r.^.'r s>, Q=.r1 *v 6, I H i< e E hg 3o;*= i"= 3EE+Efi E E 6t o <!=oJ e.. F|_1 \J E :d; 9,?1t a, a. E 5I) (J.=93c h* oE o i€ -Ya.aa)&;* =B 3-:Etrr.gF- Yl-.O:_:-.:-tr=:+..1 E .: -': () ao -3 ^l,v G '-r-Etsqa?." E L: = -E =t<ZLc)c; i'lo.! H .;9tE5tl d8_5=>E U OJ I! a 6t @al z J z U I !.1F4 (, a\l cU U 0 a P $.sfi€- .'3 ; cO'=-.. = a =.=! > - d:: .)-, - c:'-l Fa -:i - i: ...r ,() cnr=.d cr =tr: q t; 6:-r ,9 ic: o.=or'a5E>,.4tEE E A= 5;C( yE or !-/ Q;o e ,"8 E UE ?-tttaa,6.- !.: d 6-.' q 0.1 tr-ci 3'e E*E I-9 h,g " 9P- o E I =:o.b EEvt 2a E;9 i< d =oit E I o F a.l q) q) q) &a.l Z J Z =\J i dt!F :E() ; ca't d,c,)tro (g :9'=? Eo90 i., o= .Y(EoY = l..r<;r a 6-: 3ZI-r!l!]= -=C>.tr =!?,)tr tlo=i)i:e F'eF 6.4 ;i or :-- =.! -- r- ! io€ =; a =c/: * : 'a d-d>-; ii: /l g = -.9.::.:6FEiE3 5 * is 5I E8<E.:5E ., :J o 2 c-: =! !ry,u H -.c ,^ =I E 5o 9.=:i:c '1,, d c - > -'-- -.- i .i,- 0-)E"i!p;.9ira9.:a6$ie '_q?NEO b EE ! F. s.r i 9.El!\.,/!c=rE E'= tE .r (!'='6 E E'o== Ed aYl .) 6 :'i = 0ra- =o- o- -Y bn o- o-L> tr t-l , '--,f a P.6 b E E -6E-.rdr^ !-iji>- 9r _ ,- o=trc, .- Ctl U o 6t) u_ =:o;,>C "e-s'o.^ bE E ='t a rriinat-vr)a' : c0- o i"i = 0J -:z'o i'" (, tq- Jan )^> v q.l =6-a^,t r gEi =:rt1 Y\J: L >'- L -= dr _a.a--E>,a!-* ! -'i: (, .J IZ - -.c r )l) '..6>>A\ E) a) a tr o E O .J 1J'ao\ - a.laazc3<)= 2(!9q => i.= c^o ^^o o .9 >r(a = a>.9 E o.r.EE : ==s d!Y E5-rr -= 9= - a..1 -FXdr.Y- = gE a E:R sp: i E-8 Rn.q= i PE: E di :,8 .! EiE;a? 6EE6E.JE e E,gg.= >. a .2 Ai':oEE =EEE r., € '=A'e,iir ;g;E Ers r:{E9i EE5-3 ?Es s.?!ii. .'i :: d!-J- .--3: EPa=Yi rj!E? =EE_ Eaq=r= {EEE E;':g EEE;.!: ;r!i ;5i =+iE'.=l ! - c= u a c - - E -' o o .,:l d= 'iq= ooq L'!6 ?9a'AE El g; .?s€EESiEEFc€Es da3 E5[E[ir=EEsEEs 9l "'4 r r r6l r.: -.OI .EEE dFE*arlvee trll o r-O O. CJ =ao)=at,JEq2o.vE 7.J o'Eoo9 >. .:. aE.= o ZFE'o ! , -.2 U ooHa A. l, -7 e *. =;c! dr.= i =@ Ez j ..r or.- d A=o,r -!-du.= -:>E] 5,s Qz-d, i.) .] F al z 2 e.l a.l a q) E 0) N N'J OJ _. c-,,Jp dJ ;-ir-a= = a.l uDo =! ^l!8.2.,p 2t.!? -B...>a=- ;fr=E-826E+i r E ; i3 iE i.-i=yz E E, Erilgi;F;:EFiEai: EE3T"*EiZf;EA;T+EiiiiVE;itiiE-iE ;tE;?E=ge:EiEEi .5EE;:=3ti.1.>i+EiE;FE*Ee3ii,sE-:Et.E i; * 6i! ;i+EEEzlat- = 1'= ! F= 3 =' i,=. -; co.E E -o:U.5 3 c FE = =+- E F3',J1.?6 \ a - 't c-. ') ! U o i = i' 6 6t! .J o a=ta--= = o- a\t /j_dE-c c- \o \O oo a- *' .. = rq::2 a-5o- ! ;FCvqr ^.: ,: v^)i 4y1<.c= En U, -= 1- (Jca F-a .9. l)-4 -- c =ra" )l) -L o.-Or , u:- o E 0., ^r G O- =.q 5^ =9-.cF- aEaNc!a j ur'5!= ro; ^ (, : -d: x aE 3-po lJ - -! o-P tr tr (J 3 o- (, a.l Y!= 'o - ;t aer ?i J-- ,, =a:f,?Ei Z'=e a! P E-I-J a= =.r !.-.= * Eo_ X " * 9*i;Ei :iF EEEIS i"; EEsEE=sIi +E5ii IEE!s:iEzlE E?,27; iEi.v7E,! ::E = ;- i n'ii,E=piz*aEEE ir E;-j3 til_E o=== L tr'= c !,= 2 -l:E t 9;. 5 EEZE:3i EE .s iii: FFiEv _:z Yt € F'oY (t , ';: aJ ^t c I ".= I I I,9 c-2 U "., 4 3:A=r-i,:!=ssj t-F h >,d 3 4- l'=6-Ya ! -='*2 z>, L : 5 =.E:n 1) *r )'*l:;EY6OlZ !()+--l, .^ L 1z..-3- tu d,J) d)> = t:! =*,4?2EZ., :o€ E ?!2q-Er*'2Ee 1 a.= a.\ '-t 2';. 12.=?r--=L'o'- Q .= '- 'E aj.t-,?E3t*.E =.--- - ,r' 4'rit.=t,-ts ; >'-o 9 -O ^.= () :.lo >r 'J N -'J'! a3.- -'d.= ,lr d :'.= Z--t)=-I. <{ a d 7 ul ,:,i - ,t\ al \, , | ,r,t6 | ..t zlto-l-lCI EI 1larlult4F <l "l d Oat 1 cU U !tcca{ -a ^, udi:!^EE A,"y -.'; E= rEa;=E 2fr.'tu6;'r= ^t,a('n-!r.=c!- - i =^ \) > ali"2d=-:il0., 16 ot!'! Eu.2.9=a-.4 H.=E:-))atjE;", .., -A A--^ ^. u&,rE.:;EIa:E;{EE E* E E l- X: c 3arqPic---=3i.-.22+.ii-s:e?::EI^ " o-a E h =u tE:;EE )ZY.=ae; 9. -a ?..c.! 4. ?s:".- .1)a!E>tr.a>,4y."E*-r95EEEEH =H -Y4 E- YF rn o- xrp_ = o=-_:- =- L d-:.-;-c- cr,e c'- c0.a a I.=''.r c E i o a^'== !! !l^ =EF5EREi=iR: ,^.=z -i'JE9 Ean-, =.- L -:: lyq: - (J I+ aTE;E 7€Ufr t.gU Pd2qz ) = u.= 'r o i - ;- - ? = L:'4 ^,d tr >-.= = .'r -|.=;a9o.-r iiEiS; 9p?.c -= 3.! i a:..4 Y E ; .J -d Ll :.1 ; =0)i 5 FF 6 a EEiI J L .-i E Et: 9e 3::.9cg=y =+f -) B'9 B= -E 3= 'j -= =i!; ;=?EE,:EaE E,g?f., E.? ii H r-7 e'I<E!b;?,i.Zz;!ieEtEwE"';9in=*.;r!lB al = EI at l) ^, A;E!^E5 p. ; ,'? F=,= u-.2E =ii;?,;=i.:{eE=a-=L1r.,? =->:,^YEU-c-==i E.tid-::tr q i E ".o=".(JeD_=aO(l H.:E:-r)tli=;:*€Ett3i353g =-r)2>r,i=C.^q!-E -:.i o--.!? 6:- or. P = c = Y (\ >r il tr oL-,58*;H€-3:sf .:=g'rz- i -E i ,..ta^ "o- -E=.=UtEq= g E'i.9 q= o.o:- L! C, ....- . t >''i ! = = -,-)zi2i>-)=..=a27'r Y G , ?.6 >.:jj 'r ; -aE I e; Y \ il l E s t ==. :,. < =E i i'C€=I::irEE=;.!e=Q-:rq_ =.J=*_b= E-a bE: e-=E*E;;.Ex3=;E=:8i,..^.-clr...---^---EEF5,iRi:FiR:= 5! ; :(, Eu != o- ya,-2 i;?'4i 2 >- 1) - != E,X -:= E!:E <:E \. 5 = 6; !9'r c i: : -r, a -u r'l r O I AE ?a* E.i-o ot- a^-ZE E E o 3 )G.Y 2 --:*;.o :=co*>,=2-:i:rY'.ql!o.= t. ,^ "' - ! = -c =='--=u'=!uJ-!A;;5: i 2='i7.e.; 1 U = J >\.; = . I .= -9=U\16-c=--" ,J\c1^-aapi=-a.c f :i.! E o-'= o-? = q E ,',n 6= r)2:C=*; ieEit:-=';"\- 'i-u': =4re, l) .93 ! E cit ld;E ;it :iER3I== E=V+:,::: i ?'2 t: >r- ? !i ri-L5XlJ _o=i^?Pj**4=..i e_i,=oEf E5Eeg !.=",*Z.5IrL - _d - . ! = > .-'-tJ: , A.! tr =:4 =-a'='- a.-cz- < 6= (g=}i (g'-'A E=.+Er;3;aE=e-c!:Uan;<<CE== a{ = a Z<l A- zc =!, o. -!: a F- ala'o .! o ! - ., .:-(]?P 4si f!AE,,.==A -.'-9F7><)I t-, c,rEa-e5:l= o -: et, L. o.';4^z6a!,t+ =.::..- L 4 :J \./ 'e+ \r - --. =E't4-.?'ii'ca= vr a - - a/^ 1la= aLEd'..=/.\.: a -E=sE3:ri1 = ^, c1 E.{ : E =aEP=P7bs, ,i E.: i 4 P, ad'J!!r=EiZ=P+dEo4=?-:c-a./.-:Y!:-E -\ o .t\ !\ -Y ,i, 6 :c4:iN2cz r /- |o^-| = ..{ c!- 1, X ..1 .=:ir:-!!=D= ^ q t ! lE< ::.: :;g5Er,+ -:.= E == ll: - -^ ii=-.i 4 1 ?. 9, c 4 -:.5 E E ! 3!; ETzE iEiBE-.EtsFe'.EFJa:Eg =E:oG"FE;C=5;*iEF *FliEE?E;&'=LQ;=o+;'s??.ts - o E =r: q f,;. r-={,o e;Efr i# 3 f Ei iile.: F:E; +; i.*.?io- E :; sE =E-Li? 5; S-iE E i #.=:=d,8 Si?.2 i 0 eez=.=a = c )o "eE=iltizE= fiEE9ER:EEE:i:*-.lli!=.= q:€;:3= Qcii,; ^'), ca r<.- c - = i - - ^.FHlf!'r!,g1'F;;E'J=rEci,=.,E>-_cc7= = =3 - a > C= O -.-, !-:foO a ! = >- (J >, -O >,L ...'r .d (sE3e'==;>al-9Eea lJ .a E -A'- oJ'D-> .!- ar ap'/ 4o, hl) a. d .=^/E a Y ...r -E -. 0J .a6.,u= l. ^ o) 5-- 9 (!O^/O- .J = .= i..., coe P 9l.=".=e = = 6Lv -:: .- 2 0- -s y =.P- a =l -.>YH:'3U)trdiD=^,a E_-.5 ii ^o- aJ a- -n iL '=d U! o yE eq=F o. P o+ 6(E:qE:i 2 c. >.4is=; o>l =-oe-,) . aa Cr'r!.i 5.=n-lFYthY-e:ad1a2?= =; rX.: !1 E!.-* - o;..i 0J:, F-o;i-o = .- -(r eN .i -i- - - :.1 . ^t-'+ I o < c- ^ a _ > -,9 = -^ u _._EAgbrUE;o6u=rEaEcf J C4 E: >. () .l ) ,-. -\J'=-= L)= a t!<t ts.. ai='! ar- -t e !-\ i,u A:::'a.2n-t?iFo ^-:L=E.!.:=-+ r! c .=.= P \J,= Y4=^'4E=Etsh Y - - -c E tr o tr ^,-.ER!3ts33= = -l a E a.r-O .i .Yi,cz.; '' ;:i'o<:iaJ*.= .= E ,.: Ei- '' i9,a - E E.!:i- ?!:rr == !v) L -t7 : *.E O,' ". ='- : F _:: E6 H i€iraE e r i5Et; q,iAEOd O $-=-'!oc- y ? E r.rq)-. =a --d Lr- Y -.9 = C ^,, r, Yr ^i = cl)-N =N'!^i a o d (,.= (R-->E,a.Z 6-.?',c=t='=>-,9=g:,-=)t =.4;iEE-3iI iY; Cl ?9 r- < iE.=.rC-d=d r-.1 = ET ! = 5J-^ '-c9.r o- .'G r, c:, OJ 7. .O OJP i,, -.C =-.c ts d -r. "3L PE - I ait) = v.= ?E!o O- ". lz o-od o-) cOd =D., ='thd.l= a..9E< iJl = cL '-6l E: Lr.j jj ol iJ c.!->l-t zlzl_lta. lzloFl ile.lurlFlo. si ,lo. I -tol rl olUI -l !lfl I E-,612 :u(6 3E H -.=,^.= 5{) -E r- 6t dtiorSo-E -Y .r' E?^ .= > O-a-Iri tr'(, os.dI-:tt e ; (-,, dJ:x "o- E aE!c-r =tr50 otEo_ dJ'"d c *- c-3,ta\^a- f >, f r- C3 d, d- 4 i=th,: ar 6,l*t (, .. -: E .;? dr "7 ;i . -E c- =: o- c.- --{ -- - 9r N132 q1 >Ca E '7EE&.E!L I- C* = :: d,;d n=y'E4=E J!Y./6=-V^ 6Z -:,- rc !j !s.- a-.7j.L--?!41-=-i)i'-"sEEEa^,L:>-=-a-q;i,i-.3]l,^E.ro=- l!-c..1 ;J C=.: a=d dJ E oL, Ei P ->'d;l=i.Z-!gP;1'-yzZ3a'Eu.?iE.z =:J;6i====J'trtr';=X.JEE.r3J-.EE88eE o -- (t -: :6.J af 2 -= 1) _E!:;T 5 H;'-.i -: i: .r: ,EF!93- zE';E_6. r 4 E 'c CE! o.'= *(* \J v q!? (s tr'o o (* C) 63lrrEiE :SE* i (J r* = .:_ _!l7=,:s..- )+ : $ u E E= 3.,3 E.?*?_,E;i;= 9$i ^,< Hq;, .= eT,Atv) _ . - 1) -.o-5;b.EEEEEi-. E E EiIE +5 rp Y .-:" (E ^ ! C)=:;-A&=i _"€ >= E EE-0, ivi q g[i 3o--^>iao.\a=>=).d-'_L-t/-,./L-;-c,!.i_:iyEE.l.4.tr.Yi:o>=tr3l)L-1 () 0lJ., c ! c)= +t,=>q:od=-oE j ) 9 cx ",, .1 il. y ; Le:v!-:-.r EEif9EE=if,; ! 3--uE?r, a-9 = o ; E >.: d E; 6 ; c=.= or.: 9J S. l, I EL 't E::'! !, .ii ztr6 i: u ii!-o -'=au-=.L=i;!t2=--.=_--'= !!:!.Jrr--=x:.1. =?-c =t=>., 1)i'"=.i€E;,H;(,.r!--E-at.n 0)-& c,,: c7]-: or = _ Y ._ O_._ ;.; .r .d ^. -u)r a t).-.aEil';.=cE6'=gQ.='c, aP 1) c) = 5I)E - - ri ,i r-^tLi;-,J-=-dE3& i eai =-et'o4'r Y;.=,7 ,i E zIEEYs *v?* auhA'-\-/-=- -1 !J o (-,d o dr= r8.tr].o.afil=.cE=EI LU r'. c\ a.1 \J =I1- o-- oEEotpo_u'edE U- ^:.=E -- dt ta\^; ,J .: or-u c ^)^ = 9E o,: l. ..tr ,u?9ii =: c.d z z. F '.,) o. d+ U P,\crIlC( )RP 20lg IRP CH,\p ,lt 9 A( lloN Pr.AN A\t) RLsol R( ll PRoct rtl.ti\.lti\ I Resource and Compliance Strategies PacifiCorp worked with stakeholders to definc portlolio cost and risk analysis in the 20l9lRP. This analysis rellests a combination of specific planning assumptions relatcd to coal unit relirements, potenlial Regional llaze compliance outcomes, Energy Gateway transmission investments, cttstomer-pref'erence renewable resources, largeted resource procuremcnt outcomes (i.e., no new natural gas), market-reliancc risk, market price assumptions, and COz price assumptions. PacifiCorp further analyzed sensitivity cases on planning assumptions related primarily to thc load lbrecasts and private generation penetration levels. The array of planning assumptions that define the studies used to dcvelop resource portfblios provides the lramework fbr a resource acquisition path analysis by evaluating horv resource selections are impacted by changes to planning assumptions. Given current load expectations, portfolio modeling perlbrmed for the 2019 IRP shows the resource acquisition path in the preferred portlblio is robust among a rvide range of policy and markct conditions, particularly in the near-tcrm, when cost-cll'ective renewable resources that qualify fbr lbderal income tax crcdits, FOTs, and cnergy efliciency resources arc consistently selected. With rcgard to reneu'able resource acquisition, the portfolio development modcling performed in the 2019 IRP shows that new renervable resource needs are driven primarily by esonomics and reliability. tseyond load, CO: policy also influenccs resource selections in the 2019 lRP. For these rcasons, the acquisition path analysis lbcuses on economic, load, reliability, and environmental policy triggcr e\ents that would require altcmative resourcc acquisition slratcgies. For each trigger event, PacifiCorp identifies the planning scenario assumption affbcting hoth shon- term (2019-2028) and long-term (2029-2038) resourcc strategies. Acquisition Path Decision Mechanism The Utah Commission requires that PaciliCorp provide "[a] plan ofdiflerent resource acquisition paths with a decision mcchanism to select among and modify as the future unlblds."r PacifiCorp's decision mechanism is centered on the IRP process and ongoing updates to the IRP modeling tools between IRP cycles. The same modcling tools used in the IRP are also used to evaluate and inform the procurement of resources. The tRP models are used on a macro-level to evaluate altemative portfolios and futures as part of'the IRP process, and then on a micro-levcl to evaluate the economics and system benefits of individual resources as part of the supply-side resource procurement and DSM target-setting/valuation processcs. PacifiCorp uscs the IRP and thc IRP modeling tools to serve as dccision support tools that can bc used to guide prudent resource acquisition paths that maintain system rcliability at a reasonable cost. Table 9.3 summarizes PacifiCorp's 2019 IRP acquisition path analysis, which provides insight on how changes in the planning environment rnight inf'luence future resource procurement activities. Cihanges in procurement activitics driven by changes in the planning cnvironment will ultimately be retlccted in futurc IRPs and resource procurement decisions. I Pubtic Sen ice Commission ol' Utah, In the Matter ol'Analysis o f an lnte grated Resourcc Plan lbr PacifiCorp, Report and Order, Docket No. 90-2035-0 l, JLrne I 992, p. 28, 289 Acqu isition Path Analysis l P^crFrcoRP-2019IRP CHAP'I.ER 9 _ ACTIoN PI-AN AND RESoUR(]I: PRoCUREMENI Table 9.3 - Near-term and Lon term Resource uisition Paths Higher sustained load growth . Within the action plan window, there would be no change to the resource procurement strategy lbcused on an all-source RFP and incremental transmission upgrades-o Increase acquisition of summer FOTs: on average, annual purchases are up 460 MW per year.o Increasc and accelerate solar+battery procurement: solar+banery capacity begins to rise as early as 2021-by 2028, solar+battery capacity is incrcased by 103 MW-. lncrease and accclcrate stand-alonc battery procurement: 165 MW of stand-alone battery capacity is accelerated into 2026.e Increase flexible capacity procurement: in 2028, new gas-pcaking capaciry increases by 370 MW.r Accelcrate Class I DSM procurement: in 2028, neq, direct-load control capacity increases by 149 MW. Accelerate t)cxible capacity procurement: nerv peaking gas capacity is accelerated- increased by 759 MW in 2029 and by 959 MW in 2033. By the end of 2038, gas capacity is similar to a base load tbrccast case. Deler procurcment of stand- alonc battery capacity: with an accclerated deployment of new gas capacity, stand-alone battery storage capacity is dorvn by 450 MW in 2029, dou'n by 255 MW by 2033. 290 Long T€rm Resourcc Acquisition Strategy (2029-2038)I'rigser Event Phnning Scen&rio(s) Near-Term Resourc€ Acquisition Slrategy (2020-2028) High economic drivcrs and high Utah and wyonring induslrial loads PACTFTC0RP-20l9IRP CHAP.Tt]R 9 A(,1I()N PLAN ANI) RF,SoTJRC}' PRoCI,,RIIMI1N.T Lolv economic drivers suppress load rcqLlircments with reduced dcmand liom Utah and Wyoming industriaI loads . Within thc acrion plan rvindow, there would be no change to the resource procurement strategy focused on an all-source Rl'P and incremental transmission upgrades.c Rcduce acquisition of summer FOTs: on average. annual purchases are dorvn 220 MW per year. o Reduce and defer solar+battery capacity procurcment: solar+battcry capacity begins to fall as early as 2021-by 2028, solar+battery capacity is reduced by 220 MW.r Reducc and defer stand- alone banery procurement: stand-alone banery storage capaciry declines beginning 2028 ( 180 MW).o Reduce flexible capacity procurement: 185 MW of ncw peaking gas capacity is defened liom 2026 to 2030.e Reduce energy efficiency procurement: through 2028, incremental energy clticiency procurcment is down bv 67 MW. Lowcr sustained load growth . Defer flexible capacity procur€ment: new peaking gas capacity remains relativeLy stable from 2030 through 2036-by 2038 neu' peaking gas capacity is down by 221 MW.. Adjust timing ofsolar+battery procurement: thc timing for solar+battery capacity shil1s- reduced by 720 MW by 2031, higher by 109 MW by 2035, and down by over 300 MW by 2038.r Increase stand-alone solar procur{}ment: stand-alone solar is higher through the last ten ycars ofthe planning period-by 2038 it's up by t62 MW.. Reduce stand-along bauery storage procurcmcnt: stand- alonc batlery storage capacity is dou,n through the last ten ycars ofthe planning period- by 2038 it is reduced by 420 MW. Higher sustained privatc generation penetration lcvcls Morc aggressive technology cost reductions, improved technology perlbrmance, and higher electricity retail rates . Within the action plan window, thcrc would be no change to the resource procurcment strategy t'ocused on an all-source RFP and incremental transmission upgrades.. Small changes to the portfolio would require minimal changes to the resource acquisition strategy.. Delay procurement of flexible resource capacity: a 185 MW gas peaking plant is deferred by one yeat fio,J:l 2026 to 202'7 . Small changes to the portfolio r,'ould require minimal changes to the resource acquisition strategy. Timing differences in stand- alone solar, stand-alone battery and solar+bahcry capacity would need to be assessed in procurement processes to achiovc the appropriate balance of encrgy and capacity. 291 Trisser Event Planning Scenario(s) Near-Tcrm Resource Acquisition Strategl (2020-2028) Long Term Resource Acquisition Strategy (2029-2038) P^c[.rCoRP ]0l9lRP CHAHTER 9 - AcrrcN PI.AN AND RrsouRCFt PRocUREMEN I Lower sustained private generation penetration levels Less aggressive technology cost reductions, reduced technology performance, and lower electricity retail mtes . Within the action plan rvindorv. there would be no change to the resource procurement strategy focused on an all-source RFP and incremental transmission upgradcs.. Delay procurement of flexiblc resource capaciry: a 185 MW gas peaking plant is defbrrcd by three years liom 2026 to 2029- Accelerate procurement of tlexible resource capacity: neu, gas peaking capacity increases by 370 MW in 2030. Timing differences in stand- alone solar, stand-alone battery and solar+battery capacity would need to be assessed in procurement proccsses to achieve thc appropriate balance of energy and capacity. tligh CO: prices with accclcrated coal retirements Fossil-fired generation is faced \r'ith a high COr price beginning in 2025 at 522.57lron and reaching $83.69/ton by 2038 that drives all coal to be retired by 2030 . Within thc action plan window. there would bc no change to the resource procurcment strategy fbcused on an all-source RFP and incremcntal transmission upgrades.. Accelerate procurcment of flexible resource capacity: nerv gas peaking capacity increases by 195 MW as early as 2023 and is 514 MW higher than thc base case by 2028.. Increase procurcment of market purchases: summer ljOTs increase rvith the potential tbr accelerated coal retirements.o lncrease procurement of cnergy efficiency: energy efficiency capacity is accelerated and increa-ses by 80 Mw by 2028.. Accclerate procurement ol. direct-load control resources: by 2028, direct- load control capacity is Lrp by 194 MW. . Accelerate and increase procuremcnt of flexible rcsource capacity: by 2029, neu. gas peaking capacity is l,l5l MW higher than in the base case and by 2038 it is 434 MW higher than the ba-se case.r Accelerate and increase procuremcnt of battery sbrage capacity: by 2038 battery storage capacity is incrcased by over 1,200 MW.. Accaleratc procurement of direclload control resources: by 2030, dircct-load control capacity is up by 68 MW and in the 203 l-2037 timeframe it is up by over 240 MW. 292 Trisser Eyent Plrnring Scenario(s) Near-Term Resource Acquisition Strategy (2020-2028\ Long Term Resource Acquisition Stratcgl/ (2029-2038) P^crr,rc( )RP 2019 IRP CHAPIIR 9 ACl IoN PI-AN ANI) RT]SoT]RCI: PR(X.URIiMI]NT Jim Bridger and Naughton Units retire by the end of 2025 Retircmcnts tbr Naughton Units l-2 and.lin Bridger Units 3-4 all occur by the end of2025. . Within the action plan rvindow, thcrc would be no change to the resource procurement strategy focused on an all-source RFP and incrcmcntal transmission upgrades.o lncrease procurement of market purchases: summer FOTs increa-se beginning 2026 and through 2028 by as much as 960 MW per year.. Accelerate procurement of flexiblc resource capacily: new gas peaking capacity is 210 MW higher in 2028.. Adjust timing and volumes fbr procuemcnt of battery storag€ capacity: battery storage capacity is down by about 100 MW in 2024, but increases by about by about 500 MW by 2026.. lncrca.lie procurement of energy efficicncy: energy efliciency capacity is acceleratcd and increases by over 40 MW by 2028.. Accelerate procurement ()l' direct-load control resources: by 2028, direct- load control capacity is up by 16l MW. . Accelerate procurement of tlexible resourcc capacity: new gas peaking capacity is between about 400 MW and 600 MW higher over the 2029 to 2034 timeframe, over {100 MW higher in the 2035-2036, and do\4,n by about 300 MW in 2037-2038.. Increase procurcment of battery storage capacity: battery storagc capacity is r,rp by over 100 MW liom 2030- 2036, and is up by about 700 MW by 203ti.. Accelerate procurcment of rencwable capacity: total renewable capacity is up by between 350 MW and over 1.200 MW fiom 2029-2037. On average, levelized gas and porver prices are down by approximately 25 perccnt relative to the base forecast . Within the action plan windou,, thcre *,ould be no change to the rcsource Procurament strategy fbcused on an all-source RFP and incremental transmission upgrades,. Thc near{erm RFP process would assess potcntial changes to the resource mix. based on market bids that maximize value t'or customels, with potential changes to wind, solar, battery storagc, and battery slorage collated with solar. e Accelcrate procurement of tlexible resourcc capacity: nerv gas peaking capacity increases by 342 MW in 2029 and by 1,518 MW in 203{,3.r Shifts in thc precise timing and need for rlind, solar, batlery sto.age, and battery storage collated \r,ith solar rr,ould need t() be evaluated through future competitivc solicitation processes.. Rcduce energy efficiency procurement: cnergy efliciency capacity is down by about 100 MW in this timefiame, ["ow markct priccs 293 Trisser Event Planning sccnari(l(s) Near-Term Resource Acquisition Strategy.' (2020-2028) [,ong'ferm Resource Acquisition Strategy (2029-2038) P^( n'rCoRP l0l9lRl,CHAp [ER 9 - AcrroN Pr.AN AND RESoUR(]r: PRoc(JREMEN'r' tligh market priccs On average, levelizcd gas prices arc up by about 25 pelcent and power prices by about l0 percent relative to the base fbrecast . Within thc action plan window, there would be no change to the resource procurement strategy lircused on an all-source RFP and incremcntal transmission upgrades.o Increase reneu,able procurement and battery storagc procurement in the 2023 timeframe: highcr prices increase rencwable capacity by about 260 Mw and battery storage capacity by ovor 400 MW.o Incrgasc procurement of energy efficiency: cnergy efficiency capacity is accelerated and increases by over 60 MW by 2028. r lncrease renewable procurement: higher prices incrcase renewable capacity by 720 MW in 2029 rising to over 1,200 MW by 2038.o Accelerate procurement of flexible resource capacity: new gas peaking capacity is higher by between 130 MW and 170 MW in rhe 2032- 2036 timeframe, but dou.n by over 500 MW in thc 2037- 2018 timeliame.. Battery storage capacity procurement would be adjusted in accordance with changes to gas capacity: battery storage capacity is down by about 300 MW in the 2032-2036 timeframe and up by 300-700 MW in the 2037- 2038 timeframe. . lncrease procurement ol direct-load control resources: dirqct-load control capacity is up by betwccn 40 MW and over 200 MW over the long term. No customcr- preference resource demand No resources ate added to meet customer- prcf-crence targets . Within the action plan rvindow. there would be no change t() the resource procurement strategy focused on an all-source RFP and incremental transmission upgrades.o Reduce procurement of customer-prel'crcnce rcnc\\'ables: total renewable capacity is down by nearly i00 MW through 2023, but up by l0 MW from 2024-202!t . Longer term, the total volume of reneu'ables is similar without customer preference resource demand.. Fuhrre RfP processes would evaluate timing adjustments fbr battery storage capacity and new gas peaking capacity; however, in aggregatc, these capacity rcsources are not matcrially ditTerent tiom the base case, 294 Trisser Event Planning Scenariu(s) Near-Term Resource Acquisition Stratcg] (2020-2028r Long Term Resource Acquisition Strstegy (2029-20381 Additional resources are added to meet higher customer- preference targets that exceed base case levels by over 3.5x in 2025 (5.7 CWh) rising to over 4.8x by 2038 (9.3 Cwh). . Within the action plan windorv, there rvould be no change to the resource procurement strategy focuscd on an alFsource RFP and incremental transmission upgrades.. Accelcrate procurement of renervablc resources: by the 2024-2025 timcframe. renetable capacity is up by about 100 MW and by 2028, it is up by over 550 MW. . Accelerate procurement of battery storage caPacity: by the 2024-2025 timeframe, baftEry storage capacity is up by about 50 MW and by 2028, it is up by over t30 MW_. Delay procurement of t)exible resource capacity: new ga.i peaking capacity is 185 MW lower fiom 2026-2029.. Reduce procurEment of market purchases: summer FOTs increase beginning 2026 and through 2028 by 20 to 160 Mw over the 2024-2028 timcfiame. . Accelerate procurement of rcnewable resources: in the 2029-2038 timeframe, renewable capacity is up by over 570 MW in 2029 and up by 100 MW by 2030.. Accelerate procwement of battery storage capacity: in 2029 battery storage capacity is up by over 550 MW and in the 2029-2038 timetiame, batlery slorage capacity is up by over 280 MW. High customcr- pret'erence resource demand P^cllrcoRP - 2019 IRP CttAprDR 9 - AcnoN PLAN ANr) RESoL;RCE PRoclrRF:MENT The main procurement risk is an inability to procure resources in the required timelrame to mect thr: least-cost, least-risk mix of resourccs identified in the preferred portfblio. There are various reasons why a particular proxy resource cannot be procured in the timeframe identified in the 2019 IRP. There may not be any cost-clf'ective opportunities availablc through an RFP, the successful RFP bidder may cxperience delays in permitting and/or dclhult on their obligations, or there might be a material and sudden change in the market fbr fuel and materials. Moreover, there is always thc risk of unforcseen environmental or other electric utility regulations that may influence the PacifiCorp's entire resource procurement strategy. Possible paths PacifiCorp could take in thc event of a procurement delay or sudden change in procurement need can include combinations ofthc Ibllorving: In circumstances where PacifiCorp is engaged in an active RFP where a specific bidder is unable to perform, altemative bids can be pursued. 295 Trisscr Event Planring Scenario(s) Near-Tcrm Resource Acquisition Stratesr (2020-2028) Long Term Resource Acquisition Strategy (2029-2038) Procurement P^cr,rCoRP ?0l9lRP CHAp I I-R 9 - AcIoN Pt-AN AND RtisouRCE PRoct;Rt-.MENT . Pacificorp can issue an emergency RFP for a specific resource and with specified availability.r PacifiCorp can seck to negotiatc an accelerated delivery date ofa potential resource with the supplier/dcveloper.o PacifiCorp can seek to procure near-term purchased power and transmission until a longer-term altemative is identified, acquired through customized market RFPs, exchange transactions, brokered transactions or bi-lateral, sole source procurcment.. Accelcrate acquisition timelines fbr direct load control programs. o Procurc and install temporary generators to address some or all ofthe capacity needs.. Temporarily drop below the targct l3 percent planning reservc margin.. Implement load control initiativcs, including calls lor load curtailment via existing load curtailment contracts. 'fhe 2019 IRP includes a scnsitivity (casc S-06) that complies \4,ith the Utah requirement to perfbrm a busincss plan sensitivity case consistent rvith the commission's order in Docket No. l5-035-04. This order sets fbrth the firllowing parameters for this sensitivity case: Over the first three years, resources align with those assumed in PacifiCorp's December 2018 Business Plan. Beyond the lirst tluee years of the study period, unit retirement assumptions are aligned rvith the pref'erred portfblio. All other resources are optimized. Differences between PacifiCorp's 2019 IRP prelerred ponfblio and case S-07 are driven by assumptions for Naughton Unit 3 and Cholla Unit 4. Case S-07 does not includc the Naughton Unit 3 gas conversion and assumes Cholla Unit 4 retires in early 2025 instead of2020. In thc near- tcrm, the prel'erred portfolio has lower summcr FOTs, slight changes in thc volumes and timing associated with DSM resources, and slight changes in customer-prelercnce renewable resources. Nonc of these difl'ercnces have any bearing on the 2019 IRP action plan, which calls for, among other things, issuance ofan all-source RFP and advancement of transmission investments that rvill enable adding new renewable resources to the system. Over the long term, the changc in resources fiom case 5-06 relative to the prefbrred portfirlio arc largely associated with timing; horvevcr, the overall long{erm portfolio resource mix is similar to the resources included in the pref'erred portf'olio and rvould not materially alter PacifiCorp's long-tcrm resource procurement plans. Table 9.4 compares the 20l9lRP prel'ened portfolio n'ith porttblio from sensitivity case 5-06. 296 a a IRP Action Plan Linkage to Business Planning I ffifffl t-- a.l I li i: !! iit;riii .l) .t) t- !r al L E U I1 z 2 4 J a- a az iz9 o = =5 c.e. (..) c- 1', .: I 11 I I I ll I td II ,-H II I I i tl . I tl itI l' |1 '|l E I E I E I E E llil ilil lffl lffll lil lfll ll llilt H EI llil illl II II II II flll fi tl ti I I '1 I I I I i . I I 1 l , I a I; I|', ll =lT 1# i i u 3 ! ! ! tri t+ I t] P^( ll,r( ( )Rr, 2(ll9IRP To acquire resources outlined in the 2019 IRP action plan, PacifiCorp intends to continue using competitive solicitation processes in accordance with applicable laws, rules, and/or guidelines in each ol' thc states in which PacitiCorp operates. PacifiCorp will also continue to pursue opportunistic acquisitions idcntified outside of a competitive procurement process that provide economic benefits to customers. Regardless ofthe method lbr acquiring resources, PacifiCorp will support its resourcc procuremenl 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 linancial analysis will account for any applicable long-term system benetlts with least-cost, lcast-risk planning principles in mind. Thc sections below profile the general procuremcnt approaches ftrr thc kcy resource categorics covered in thc 2019 IRP action plan. Renewable Resources, Storage Resources, and Dispatchable Resources PacifiCorp will usc a competitive RFPs to procure supply-side resources consistcnt applicable laws, rules, and/or guidelines in each of the states in which PacifiCorp operatcs. ln Oregon and Utah, thcse state requirements involve the oversight of an independent evaluator, which is also being considered in revised rules being developed in Washington. Thc all-source RFPs outline the types of resources being pursued, delines specific information required of potential bidders and details both price and non-price scoring metrics that will be uscd to evaluate proposals. Renewable Energy Credits PacifiCorp uses shelfRFPs as the primary mechanism under which REC RFPs and reversc REC RFPs will be issued to the market. The shelf RFPs are updated to dcfine the product dcfinition, timing, and volume and further providc schedule and other applicable criteria to bidders. Demand-side Management PacifiCorp offers a robust portfblio of Class I (demand response and direct-load control) and Class 2 (energy efficiency) DSM programs and initiativcs, most of which arc offered in multiplc states, depending on sizc of the opportunity and the need. Programs are reassessed on a regular bases. PacitiCorp provides Class 4 DSM offerings, and has continued wullsmart outreach and communications. Educating customers regarding cnergy efficiency and load managcment opportunities is an important component of PacifiCorp's long-term resource acquisition plan. PacifiCorp will evaluate how to best incorporate potential Class I DSM programs into the broader all-source R-FP process discussed above. As PacifiCorp acquires ne\.\, resources, it u,'ill need to dctcrmine whether it is better to orvn a resource or purchase powcr fiom another party. While the ultimate dccision will be madc at the time resources are acquired, and rvill primarily be based on cosl, therc are other considerations that may be relcvant. 298 C'IAprrR q A('r roN Pl AN AND ftlisolrR( ri PR(x r]r{lrN.tr,N I Resource Procurement Strategy Assessment of Owning Assets versus Purchasing Power PACrr,r( oRP - 20l9 IRP (lHApTriR 9 - Act Io\ Pr.AN i\NI) RLSoUR( lt IlRoctjRltMIiNT With owned resources, PaciliCorp is in a better position to control costs, makc lif'e extension improvenrents (as is being implemcnted rvith the wind repower project analyzed in the 201 7 IRP), use thc site firr additional resources in the I'uture, change Iueling strategies or sources (as is being implementcd fbr the Naughton Unit 3 gas conversion), efticicntly address plant modifications that may be required as a result ofchanges in environmental or other laws and regulations, and utilize the plant at embedded cost as long as it remains economic. tn addition, by owning a plant, PacifiC'orp can hedge itsell'against the unccrtainty of third-pany performance consistent rvith the tcrms and conditions outlincd in a porver purchasc agreement ovcr time. Altemately and depending on contractual 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 purchasc agreement relinquishes control of construction cost, schedule, ongoing costs and environmental and regulatory compliance. Purchase power agrecments can also protect and cap the buyer's exposure to events that may not cover actual seller financial impacts. However, credit rating agencies can 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 crcdit rating. CO: reduction regulations at the lcderal, regional, or state levels could prompt PacifiCorp to continue to look lbr measures to iower CO: emissions of fossil-lired power plants thror-rgh cost- efI'ective means. The cost, timing, and compliancc flexibility afforded by CO: reduction rules will impacl what types of measures might be cost-effcctive and practical fiom operational and regulatory perspeotives. As evident in thc 2019 IRP, known and prospectivc cnvironmental rcgulations can impact utilization ol'resources and inveshnent decisions. Compliance strategies will he aflected by ho$,and whether statcs orrhe federal govemment choose to implement greenhouse gas policies. State or fcderal fiameworks could impute a carbon tax or implement a cap-and-trade framervork. Under a cap-and-trade policy fiamervork, examples of lactors afl'ccting carbon compliance strategics include the allocation of emission allorvances, the cost ti['allowances in the market, and any flexible compliance mechanisms suoh as opportunities to use carbon ofl'sets, allorvance/otfict banking and borrorving, and sal'ety valvc mechanisms. Under a COr tax tiamework. the tax level and details around horv the tax might be asscssed rvould affcct compliance strategies. To lower the cmission lcvcls fbr existing fossil-lired power plants, options include changcs in plant dispatch, unit retirements, changing the fuel type, dcployment of plant ctliciency improvemcnt projects, and adoption of' new technologics such as CO: capture with sequestration, when commercially proven. As menlioned above. plant CO: emission risk may also be addresscd by acquiring offsets or other environmcntal attributes that could become available in the market under certain regulatory fiameworks. PacifiCorp's compliance strategics will evolve and continuc kr be reassessed in future IRP cycles as market forces and regulatory outcomes cvolve. 299 Managing Carbon Risk for Existing Plants PAC .ICoRP 20l9lRP CHAp IliR 9 - ACllo\ Pr.AN A\l) RltsoLrRCt: PR(xrIRtit\fl iN'l' While PacifiCorp fbcuses every day on minimizing net power costs for customers, the company also focuses evcry day on mitigating price risk to customers, which is done through hedging consistsnt with a robust risk management policy. For years PacifiCorp has ftrllowcd a consistent hedging program that Iimits risk to customers, has tracked risk metrics assiduously and has diligently documcnted hedging activities. PacifiCorp's risk managemcnt policy and hedging program exists to achieve the fbllowing goals: (l) ensure reliable sources ofelectric power are availablc to meet PacifiCorp's customers' nceds; (2) reduce volatility ol'net power costs lbr PacifiCorp's cuslomers. The purpose is solely to reduce customer exposure to net povv'er cost volatility and advcrse price movemcnt. PacifiCorp docs not engage in a material amount of proprietary trading activities. Hcdging is done solely for the purpose of limiting llnancial losses due to unt'avorable rvholesale market changcs. Hedging modilies the potential losscs and gains in net power costs associated with wholesale market price changes. The purposc ofhedging is not to reduce or minimize net power costs. PacifiCorp oannot predict the direction or sustainability of changes in forward prices. Thercfore, PaciliCorp hcdges, in the fbrward market, to rcduce the volatility of net porver 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 tbllow eleotric industry best practices and are periodically revie*,ed at least annually by the company's risk oversight committee. The risk oversight committee includes PacifiCorp representativcs from the front office, Ilnance, risk managemcnt, treasury, and legal department. The risk oversight committee makcs recommendalions to the presidenl of Pacific Power, who ultimately must approvc any change to the risk management policy. PacifiCorp's current policy is also consistent with the guidelincs that resulted liom collaborative hedging workshops with parties in Utah, Oregon, Idaho and Wyoming that took place in 20 I I and 2012. Since 2003, PacifiCorp's hedge program has employed a portfblio approach of dollar cost averaging to progressively reduce net porver cost risk exposure over a defined time horizon while adhering to bcst practice risk management govemance and guidelines. PacifiCorp's currcnt portfblio hedging approach is defined by increasing risk tolerancc levels represented by progressively increasing percentage of net power costs across the forw'ard hedging period. PacifiCorp incorporated a time to expiry value at risk (TEVaR) metric in May 2010. ln May 2012, as a result of multiple hedging collaboratives, the company reintroduoed natural gas percent hcdge 300 of I The main components of PacifiCorp's risk management policy and hedging program are natural gas percent hcdged volume limits, value-at-risk (VaR) limits and time to expiry VaR (TEVaR) limits. These limits lorce PacifiCorp to monitor the open positions it holds in porver and natural gas on behal{'ol'its customers on a daily basis and limit the size of these open positions by prescribed timc frames in order to reduce customer cxposure to price concentration and price volatility. The hedge program requires purchascs of natural gas at fixed prices in gradual stages in advance of rvhen it is rcquired to reduce thc size of this short position and associated customer risk. Likewisc, on the power side, PacifiCorp either purchases or sells powcr in gradual stagcs in advancc of anticipated open short or long positions to manage price volatility on behalf of customers. PACrr,rCoRP 2019 IRP CIIApll,R I Act IoN PLA\ ANI) RFSotrR('ti PRocURltvltNT volume limils ol'lorecasl requirements into its policy. l-here has been no conllict to-date bctween the new volumc limits and PacifiCorp's VaR and TEVaR limits, although the volume lirnits would supersede in such conflict, consistent rvith thc guidelines from thc hedgirrg collaboratives. Dollar cost avcraging is the term used to dcscrihe gradually hcdging over a pcriod oltime rather than all at once. This mcthod ol'hedging, u,hich is rvidely uscd by many utilities, captures time diversification and eliminates speculative bursts of market tirning activity. Its use means that at times PacitiCorp buys at relatively highcr prices and at othcr times relativcly lolver prices, esscntially capturing an array of prices at rnany levels. While doing so, PacifiCorp steadily and adaptivcly meets its hedge goals through the use of this technique rvhilc staying within VaR and TEVaR and natural gas percent hedge volume lirnits. The rcsult ofthese program changcs in combination u,ith changes in the market (such as rcduoed volatility to which PacifiCorp's program automatically responds), has been a signilicant decrease in PacifiCorp's longer-datcd hedge activity, 1.e., fbur years fonvard on a rolling basis. As a result of thc hedging collaboratives, PaciliCorp rnadc the lbllowing matcrial changes to its policy in May 2012: (l) a rcduction in the standard hedge horizon fiom 48 months to 36 months and (2) a percent hedged range guidcline lirr natural gas lbr each of thc three lonvard l2-month periods, which includes a minimum natural gas open position in each ofthe fbrward l2-month periods. The percent hcdgcd range guidelirre is greater for thc first rolling trvelve months and gradually smaller tbr the second and third rolling tu,elvc-month periods. PacifiCorp also agrccd to provide a ncrv conlidential semi-annual hedging repon. Cost Nlinimization While hedging doL-s not nrinimize net power costs, PacifiCorp takcs many actions to minimize net po$,er costs lor customers. F'irst, thc company is engagcd in integrated rcsource planning to plan resource acquisitions that are anticipated to provide the lowcst cost resources lo our customers in the long-run. PacifiCorp then issucs competitive requcsts lor proposals to assure that the rcsources we acquire are the lowest cost rcsources availablc on a risk-adjusted basis. In operations, Pacifi(orp optimizes its portfolio of resources on behalf of' customers by maintaining and opcrating a porlfolio of asscts that diversifles customer exposure to Iuel, porver markct and emissions risk and utilize an extensive transmission network that provides access to markets across thc westem United Statcs. lndependent of any natural gas and clcctric price hedging activity, to providc reliable supply and minimize net po\\'er costs lor customcrs, Pacili(.orp comtnits generation units daily, dispatches in real timc all economic gcncration resources and all must-take l0l The primary govcmance ol'PacifiCorp's hcdging activitics is docurnentcd in the company's Risk Management Policy. In May 201 0, Pacit'iCorp moved tiom hcdging targets based on volumc perccntages to largets bascd on thc "to expiry r'alue-at-risk" or TEVaR metric. Thc primary goal of this change was to increase the transparency of thc combined natural gas and porver cxposure by period. lt cnhanccs thc progressive approach to hedging that PacifiCorp has employed lor rnany years and provides the bcnetlt oia more sophisticated measure ofrisk that responds Io changes in the market and changes in open natural gas and porvcr positions. lmportantly, the'l'EVaR rnetrir: automatically reduces hedge requirements as commodity price volatility dccreases and incrcases hcdge requiremcnts as correlations among commodities divcrgc, all the whilc maintaining the samc customer risk exposure. P^( [,rCoRP 20l9lRP (' \t, ,R9 r\( lto\ [)t,\\.\NI)lltsot Ii( liPRo(l RI \{t:Nl contract resources, servcs retail load, and then sells any cxcess generation to generate wholesale rcvenue to reducc net power costs fbr customers. PacifiCorp also purchases porver when it is less expensive to purchase power than to generate powcr from our owned and contractcd resources. Hcdging cannot be used to minimizc nct power costs. lledging docs not produce a different expected outcomc than not hedging and therefore cannot be considcred a cost minimization tot)I. Iiedging is solely a tool to mitigate customer exposure to net power cost volatility and the risk ol adverse price movement. Horvever. PacifiCorp does minimize the cost ol'hedging by transacting in liquid markets and utilizing robust protections to mitigate the risk of counterparty dcfault. In addition, PacifiCorp reduces the amount of hedging required to achieve a given risk tolerancc through its portfolio hedgc management approach, rvhich takes into account otl-setting exposurcs when these comnrodities are correlated, as opposed to hedging commodity exposures kr natural gas and power in isolation rvithout rcgard for offsets. Po rtfo lio PacifiCorp has a short position in natural gas becausc of its ownership of gas-lired electric generation that rcquires it to purchase large quantities ofnatural gas to generate electricity to serve its customcrs. PacifiCorp may have short or long positions in porvcr depending on the shortlall or exocss of the company's total economic gcneration relativc to customer load requirements at a give n point in timc. PacitiCorp hedges its net cnergy (combincd natural gas and power) position on a portfolio basis to take full advantage ofany natural ofliets betrveen its long porver and shon natural gas positions. Analysis has shown that a "hcdge only power" or "hedge only natural gas" approach results in higher risk (1.e., a wider distribution ol'outcomes). There is a natural need lbr an electric company with natural gas tired electricity gcneration assets to have a hedge program that simultaneously manages natural gas and powcr open positiuns with appropriate coordinated metrics. PacifiCorp's risk management department incorporates daily updates of'fbnvard prices fbr natural gas, power, volatilities and correlations to establish daily changes in open positions and risk metrics rvhich inlirrm thc 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 inlo account its lull porttblio and utilizes continuously updated correlations of natural gas and pou'cr prices and thercby takes advantagc of olfsetting natural gas and po,,l'er positions in circumstances rvhen prices are comelated and a forecast long power position offsets a forecast short natural gas position. This has thc cffect of reducing the amount of natural gas hedging that PaciliCorp would otherpise pursue. lgnoring this correlation rvould instead result in the need ltrr more natural gas hedges to achieve the same lcvel ofcustomcr risk reduction. PacifiCorp's customers havc benetited lrom otIlctting porver and natural gas positions. Power and natural gas prices arc closely related bccause natural gas is ollen the fuel on the margin in cfilcient dispatch, as is practiced throughout the westem U.S. This means power sales tend to be more valuablc in periods u'hen natural gas is high cost, producing rev!-nues that are a crcdit or offiset to thc high cost fuel. II'spot natural gas priccs depart frorn prior foru,ard prices, porver prices will tend to do so in thc same direction, thcreby naturally hedging sorne ol-the unexpected cosl variance. 102 PA(rIrCoRP-20l9lRP CHAP II.]R 9 ACToN PI,^N AND RI]S(I;RCE PRoCURIMIiN I Effectiveness Measure The goal of'the hedging program is kr reduce volatility in PacifiCorp's net power costs primarily duc to changes in market prices. The goal is not to "bcat the market" and, theretbre, should nol be measured on the basis of whether it has made or lost money lor customers. 'fhis reduction in volatility is calculated and reported in the company's conlidential semi-annual hedging report which it bcgan producing as a result ol'the hedging collaborative. Instruments PaciliCorp's hedging program allorvs the use of several instruments including financial su,aps, Iixed pricc physical and options for these products. PacifiCorp chooses instruments that gencrally have greater liquidity and lower transaclion costs. The company also considcrs, with respect to options, the likelihood of disallowance ofthe option premium in its six jurisdictions. There is no functional difference belwcen financial swaps and fixed price physical transactions; hoth instrumcnts are equally effective in hedging the PacifiCorp's lixed price exposure. The IRP standards and guidelines in Utah require that PaciliCorp "idcntily rvhich risks u'ill be bome by ratepayers and which will be bomc by shareholders." This scction addresses this requirement. Thrcc types ol'risk are covered: stochastic risk, capital cost risk, and scenario risk. Stochastic Risk Assessment Several of the uncertain variables that pose cost risks to dif-fbrent IRP resource portfolios are quantified in the IRP production cost model using stochastic statistioal tools. The variables addressed with such tools include retail loads, natural gas prices, wholesale electricity prices, hydroelectric generation, and thcrmal unit availability. Changcs in these variables that occur over thc long-term are typically reflected in normalized revenue requirements and are lhus borne by customers. Unexpected variations in thesc elements arc normally not retlected in ratcs, and are therefore borne by investors unless specific regulatory mechanisms provide otheru ise. Consequently, ovcr time, these risks are shared between customers and investors. Between rate cases, inveslors bear these risks. Over a period of years, changes in prudently incurred costs will be reflectcd in rates and cuslomcrs will bear thc risk. Capital Cost Risks Thc actual cost ofa generating or transmission assct is expected to vary lrom the cost assumed in the lRP. State commissions may determine that a portion of the cost of an asset was imprudent and therefore should not be included in the determination ofrates. The risk ofsuch a determination is borne by investors. To the extent that capital cosls vary liom those assumed in this IRP lirr reasons that do not reflect imprudencc by PacifiCorp, the risks are bome by customers. Scenario Risk Assessment Scenario risk assessment pcrtains to abrupt or lundamcntal changes to variables that are appropriately handled by scenario analysis as opposed to representation by a statistical process or 303 Treatment of Customer and Investor Risks I',\crFr(loRP - l0l9 IRP CltAprER 9 Ac oN PLA\ ,\Nr) Rlrsot.:RCI-: PRocURti\lENT expected-valuc forecast. Thc single most important scenario risks of this typc facing PacifiCorp continucs to be govcmment actions related to cmissions and changes in load and transmission infrastructure. These scenario risks relate to the uncertainty in predicting the scope, timing, and cost impact ol'emission and policies and rcneu'able standard compliancc rules. 'l o address thcse risks, PaciliCorp evaluatcs resources in the IRP and fbr competitive procursmcnts using a range of CO: policy assumptions oonsistent with thc scenario analysis rnethodology adopted for PacifiCorp's 20 l9 IRP portl'olio development and evaluation process. Thc company's use of IRP scnsitivity analysis covering different resource policy and cost assumptions also addresses thc need firr consideration of scenario risks tbr long-tcrm resource planning. The cxtent to u'hich tuture regulatory policy shifts do not align lvith PacifiC'orp's rcsource invcstments determined to he prudcnt by state commissions is a risk bome by customcrs. 104