The URL can be used to link to this page

Home My WebLink About20180501PacifiCorp Updated 2017 IRP.pdfY ROCKY MOUNTAIN HP,}Y,E,^"N"-, May 1,2018 VA OWRNIGHT DELIWRY REC T IVEI) 2010 HfiY - l lH 9: 0? iUiiii* irUBLlC t.lT I l.lTl [$ r]OMM ISSION 1407 W. North Temple, Suite 330 Salt Lake City, Utah 84116 Diane Hanian Commission Secretary Idaho Public Utilities Commission 472W. Washington Boise, ID 83702 RE: Case No. PAC-E-17-03 IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR APPROVAL OF THE 2017 INTEGRATED RESOURCE PLAI\ Dear Ms. Hanian: Please find enclosed an original and seven (7) copies of PacifiCorp's 20lT lntegrated Resource Plan ("IRP") Update. A copy of the report is also available electronically on PacifiCorp's website, at www.pacificom.com. PacifiCorp is also providing data discs with this filing that support and provide additional details for analysis described in the document. Disc I is public, and Disc 2 contains confidential information. Confidential information in the 2017 IRP Update will be provided to parties who have signed a non-disclosure agreement in the referenced case. Rocky Mountain Power requests that interested parties contact the state manager listed below for a copy of the non-disclosure agreement that must be executed and submitted prior to obtaining a copy of the confi dential information. PacifiCorp's 2017 IRP Update summarizes updates since the 2017 IRP was filed. Highlights are as follows. l) An updated resource portfolio reflecting updates to load forecast, market prices and other model inputs; 2) The status of the 8Y2020 projects since IRP was filed; 3) A description of resource planning, procurement activities; and 4) A status update on action plan items from the 2017 IRP. AII formal correspondence and regarding this filing should be addressed to: Ted Weston Rocky Mountain Power 1407 W. North Temple, Suite 330 Salt Lake city, Utah 84116 Telephone : (801) 220-29 63 Fax (801) 220-4648 Email : ted.weston@fracifi corp.com Yvonne Hogle Rocky Mountain Power 1407 W. North Temple, Suite 320 salt Lake city, Utah 84116 Telephone: (801 ) 220-4050 Fax: (801) 220-4516 Email : yvonne.hogle@Facifi corp.com Idaho Public Utilities Commission May 1,2018 Page2 Communications regarding discovery matters, including data requests issued to Rocky Mountain Power, should be addressed to the following: By E-mail (preferred):datarequest@pacifi corp.com By regular mail:Data Request Response Center PacifiCorp 825 NE Multnomah St., Suite 2000 Portland, OR97232 Informal inquiries may be directed to Shay LaBray at (503) 813-6176 or Ted Weston at (801)220-2963. Very Truly Yours, "^..D Vice President, Regulation Enclosures cc Jim Yost, Idaho Governor's Office (without enclosures) Benjamin J. Otto, Idaho Conservation League (without enclosures) Mark Stokes, Idaho Power Company (without enclosures) Terrie Carlock, Idaho Public Utilities Commission (with enclosures) Matt Elam, Idaho Public Utilities Commission (with enclosures) Randall Budge, Racine, Olson, Nye, Budge & Bailey (without enclosures) Nancy Kelly, Western Resource Advocates (without enclosures) 7OI7 INTEGRATED RESOURCE PLAN UPDATE May 1,2018 7 I ffi - \ t n,t "l ..s. .' .Pt I J a a / I o ! - -l 1 __"1 I .lr z I /i: PacrnCoRP ,F This 2017 lntegroted Resource Plon Update is based upon the best available information ot the time of preparotion. The IRP action plan will be implemented as described herein, but is subject to change os new information becomes ovoiloble or as circumstonces change. lt is PocifiCorp's intention to revisit and refresh the IRP action plan no less frequently than onnuolly. Any refreshed IRP action plan will be submitted to the Stote Commissions for their informotion. For more information, contact: PacifiCorp IRP Resource Planning 825 N.E. Multnomah, Suite 600 Portland, Oregon 97232 (s03) 813-s24s irp@ pacificorp.com http ://www. pacificorp. com Cover Photos (Top to Bottom): Wind Turbine: Marengo Wind Project Solar: Pavant Solar Plant Transmission: Sigurd to Red Butte Transmission Line Demand-Side Management: Smart thermostat Pacific Power wattsmart Business Customer Meeting Thermol-Gas: Blundell-Geothermal Plont PecrrConp 2017 IRP Upna'rn TABLE oF CoNTENTS Tesrp oF CoNTENTS TABLE OF CONTENTS I INDEX OF TABLES tv INDEX OF FIGURES ....... vl CHAPTER 1 _ EXECUTIVE SUMMARY 201 7 IRP Upolrr HrcHlrcurs .. Loao-aNo-REsouncE BRlaNc E PREpERRSo PoRrrolro Upnars. CHAPTER 2 - INTRODUCTION CHAPTER 3 _ THE PLANNING ENVIRONMENT FpneRal Polrcy Upoare .. FoorntL Cuutrg Ca,qNco LTGISLATIzN .. Now Souncr Pznronu,.qI'{co Srtt'to.anos ron Ctnnottt Eutsstows - Cmty Am Acr $ I I I (e) C.tnsou Eutsstou Gutoottr,tts ron Extsrwc Souncts - Cmtn Am Acr $ I I I (o) CLe.tN An Acr Crurrru.t PoLturn'trs - N.trtot't,nL Auarcur Am QutLtrr ST,tNDARDS RrctoNtLHur Mo nc u av .tu o H,azt noo u s A m P o uurt t'trs Cotr Counusrtou RtstouALS........... lVtrrn Qu,aurr Sr.tNDARDS...... 2 0 I 5 Ttx Extet'toon Lsc t startoN................ 2017 Ttx RrronuAcr. Srarn Por-rcy Upoarp CtLnowu Orccow.... WtsruucroN.........,.. Ur,sH.......... GntrNaouss Gts Eutsstot t Poaronutttcr Srtuotnos ENpRcy Garpwev TRaNsurss roN PRocRarra PIaNN rNc . ENpncv INasar-aNcE MeRrEr CHAPTER 4 _ LOAD-AND-RESOURCE BALANCE UPDATE INrnooucuoN ............ Svsrsu CoNcroeNr Pear Loao Fonecasr. WrNo aNo SolaR. Qualrrvmc Facrlrrv RpsouRcs UpoarEs Upoateo Capacrrv Loao-aNp-RpsouRce Bar-aNce Loao+trr o- Rtsounc t B.aLdr't c o C o upor,tqnrs....................... Clptcrv Bat,qucr DrroaMINATtoN AND Rrsuns..... Eurncy BlLtNcr Resutrs............... 1 I 4 5 7 9 ,...9 ,.., 9 ,... 9 .... 9 .. t0 ,. 1t .. t3 .. t3 .. t3 ,. l4 . t5 ..16 .. t6 ,. l7 . t7 .. t8 .t8 .. l8 ,,22 23 LJ 23 24 27 27 3l 48 PacrrrCoRp -2011 tRP UPDATE,Tn BLIt or, CoNlr,lN'ts CHAPTER 5 _ MODELING AND ASSUMPTIONS UPDATE.... GENenal AssuvprroNS.............. INrttnou Rtres........ Dtscouyr FtcroR .......... PnooucrroN Ttx Cnrorrs (PTC9....... Fnowr Orrtco Tnqws.tcrtoNs (FOTs) Srocntsruc Ptntuqrsns................ Ftoxtsts RESERVE Sruoy NaruRar- Gas aNo Powsn MaRrer Pnrce UpoarEs ..... Ntruntt G.as lLqRKEr Pntcos Powzn Mtnxer P nrc85........... CaReoN Dtoxrpp Eurssror.r Polrcv Suppr-v-Sros RpsouRcES .............. INrna-HouR Drsparcs CRsorr INrna-HouR DrsparcH Cnrorr FuRrnpR ExplonarroN CHAPTER 6 _ PORTFOLIO DEVELOPMENT INrRooucrroN REcroNal HezE CasE DErrNrrroNS RrcroNer- Heze CasE ANelysrs AND Rrsulrs.... Dtvr JoaNsroN UNr 3 Jru Bruocnn Uurcs I & 2.......... Ntucurow Utwr 3 CaoLLd UNr 4 CHAPTER 7 _ ENERGY VISION 2O2O UPDATE INrnooucrroN ............ ENencv VrsroN 2020 PnorEcr Upoeres ................ MoooLtuc auo A ppnoac ru ]untvtny................. CovnroN AssuuprroN Upoares P ruco-pottcr 9ceu.tntos................ Fooentt T,ax Rtre .... Pnooucuow T,ax Cnrorc Mooeuuc. WrNIo RepowpRn tG ............... ErrtatNcr lupnorcuoNTs AND Exrot'toto Pnoncr Lut.. P no oucru or't Tax C nrotrs au o C usro ugn B u't g r trs .......... Upolroo D,qrl,4t'to ASSUMPTIINS RopoworuNc RtsuLrs..... Npw Wn{o auo TReNsMrssroN (CounmEo Pnorecrs)......... Wt u o P noL ecrs ............ 2017R RFP.......... TnaNsutsstor't Pnottcrs .. WvourNc CPCNs...... Pnooucrtoy T.au Crcorrs AND Cusrousn Bot'twrcs ...69 69 69 70 7l 73 75 78 5l 87 1l 87 87 88 89 90 9t 9t 92 93 98 98 98 99 t00 t00 PACII..ICoRP _ 2OI7 IRP UpOerE Taele or CoNrENrs Uponoo Dar, lt'to ASSUMPTIqNS....... Ntw Wtttro n'to Tnlt'tsutsstoN Rtsuns CoNcr-usroN................ t0l t02 105 CHAPTER 8 _ PORTFOLIO DEVELOPMENT 107 INrRooucrroN ............ 20 I 7 IRP Upoare PRpppnRro Ponrrolto... RrNpwasle PoRrrolro SraNoaRos (RPS) CaneoN DroxrpE Ev tsstoNs Pnomcrpo ENeRcv Mtx........... SENsrrrvrrv SruorEs Busrrur.ss P t,tt t Stt'tstrIVITy ......... F oors C aao x I Setrtstrtwrr....................... 107 107 l14 116 lt6 n7 117 lt9 CHAPTER 9 _ PORTFOLIO DEVELOPMENT t2t INrRooucrroN t2t t2t 123 t23 124 125 125 DsscRrprroN op TnaNSMISSIoN Sruptps..... TRaNsrrrssroN Ivpacr AsssssveNr - SceNnnto I TRRNsvrssroN Itrrpacr Asspssl,tpNr - SceNanto 2 TnaNsvrssrou IHapacr AssEssl,lENr - SceNnnlo 3 TnaNsvrssroN Iupecr AssEssvENr - SceNeRto 4 CoNclusroNS.............. CHAPTER 10 _ ACTION PLAN STATUS UPDATE 127 Rsr{pwes LE Rpsouncs AcrtoNs TRaNsrrarssroN AcrtoNS ................ Fnv Manrsr PuRcuasE AcrtoNs DsrrreNo SroE MaNaGEMENT (DSM) AcrtoNs Coal RssouRcE AcrtoNs ...........127 ...........130 ........... 13 l ...........133 ........... I 33 APPENDIX _ ADDITIONAL LOAD FORECAST DETAILS 137 Ixopx op TaBLES Tasr-B 1.1 - CovrpARrsoN op 2017 IRP UpoarE wrrH 2017 IRP PRspBRReo Ponrpor-ro (Mrcawarrs) ............. TaeI-p 3.1- ENEncy Gerpwav SecuENr IN-Senvrcp Darps Teer-p 4.1 -QualrFyrNc Facrr-rry Wn'{o PPAs......... Taslp 4.2 - QualrFyrNc Fecrlrry Solen PPAs Taslr 4.3 - SuuvER Ppar Capacrry CoNrRreurrou Var-ues poR WNo aNo So1aR........ Taels 4.4 - Suvruen PBar - Sysreu Capacrry Loao aNo REsouRcs BalaNCE wrrHour Reso uRc e A o o rrrous, 20 1 7 IRP Upoar n (20 I 8-2027 ) Tasr,B 4.5 - WrNreR Pear - Svsrpv Clpactrv Loao aNo ResouRcp BRIaNCE wrrHour RrsouRcr AoorrroNs,2017 IRP Upoare (201 8-2027) Taels 4.6 - SurraupR Prar - SysrEv Capacrry Loao aNo RrsouRcE BalaNCE wrrHour RrsouRcE AoorrroNs,20lT IRP (2018-2027\ ................38 Taele 4.7 WnrEn PEar - Sysrpu CapRcrry Loao aNo RrsouRce BaI-RNCE wrrHour RssouRcs AoorrroNs,20lT IRP (2018-2027) ................40 Tasr-B 4.8 - SuvrvrER PsRr- Svsrpu Cepacrry Loao aNo RpsouRcs BalaucE wrrHour Rnsouncs AoorrroNs,20lT IRP UpoarE LESS 2017IRP (2018-2027) . .............................42 TaeI-p 4.9 - WmrpR Pear - Svsrpur Cepacrry Loao aNo REsouRcs Bar-aNCE wrrHour RrsouRcE AporrroNs,20lT IRP UpoarE LESS 2017 IRP (2018-2027) .... ... ... ................44 Taslp 5.1 - Maxruuu Avarr-aeI-s FRoNr Orprce TRaNsacrroNS By MRRrcr Hus .......... ...... 52 TasLs 5.2 - Upoareo Cosr or Sor-aR ResouRcps (50 MWac SrNclE Axrs Tnacrmc) ........... 60 Taer-s 5.3 - Upoareo Cosr or Wnqo RrsouncEs ................. 6l Taelp 5.4 - Upoarso Cosr or ENsncy SronacE, 2017 DortARS........... ................62 Taet-p 5.5 - Upoareo Suppry-Srop RssouRce TRelE................ ............ 63 TaeLp 5.6 - Upoareo Suppry-Srop RpsouRcs Tae1E................ ............64 Taslp 6.1 -RecroNar- Hazp Casp AssuMprroNs ................. 70 Tler-r 6.2 -PVRR Cosr/(BrNenrr) on ruE Davs JonNsroN UNrr 3 INsralr- SCR EeurpMENr Casp RuanvE To tlg.p.2017 IRP Upoarp PRETERTo PoRrpolro ey PRrcp-Por-rcy ScpNanro ..................73 Tasre 6.3 - PVRR Cosr/(BeNrrrr) on rue Jrvr BRrocpR UNrrs I & 2 Iusrall SCR EeurpueNr aNo RprrnE 2037 Case Rrr-arrvp ro rHE 20l7IRP Upoarp PnepsRrup PoRrrolro av Pruce-Polrcy ScEuanro............... ................74 Taet-e 6.4 - PVRR Cosr/(BnNErrr) on rHE NaucsroN UNrr 3 Mexnruvr Ges CoNvpRSroN AND RprrRp 2029 Ctsp. Rslarrvp ro rHE 20l7IRP Upoarp PReppRRBo Ponrrolro ev PRrcE- Por-rcy ScpNaRro.. ......................76 TaeI-e 6.5 - PVRR Cosr/(Bnuerrr) or ruE NaucuroN UNrr 3 Lrvrrpo Gas CoNvpRSroN AND RprrRp 2029 Casp. Rrlarrvp ro rHE 20l7IRP Upoare PRppeRRro PoRrpolro av PRrcE- Por-rcv SceNaRro.. ...................... 78 Taer-E 6.6 - PVRR Cosr/(BnNurrr) on rue CHolle UNrr 4 Gas CoNvpRsroN AND RprrnE 2042 CesE RnlnrrvE To tup.2077IRP Upoare PnsrBRRBo PoRrrouo ey Pnrcp-Por-rcv ScENanro 80 TaeLp 7.1 - Pnolecr-sy-PRomcr SO Mooel eNo PeR PVRR(o) (BeNerrr)/Cosr oF RrpowpRrNc wrrH Merruu Narunal Gas aNo Mporuv CO2 PzucB Por.rcy Assuuprrolls ($ urr-r-roN) ................ 93 Teslp 7.2 - Pnolecr-sv-PRorncr SO Mooel auo PaR PVRR(n) (BeNnrrr)/Cosr oF WrNo RppoweRrNc wrrH Low Narunal Gas aNo No CO2 Pnrcs Por-rcy AssunaprroNs ....... .6 22 ,24 ,25 29 ,34 36 94 PacIplConp _ 20 I7 IRP UPDATE TABLE on CoNreNrs lv PACIFICORP _2017 IRP UpoarE TAtlt.lt ot,CoN't t,N Is Taer-E 7.3 - PnolECr-By-PRoJECT NoMrNal REvENuE REeUTREMENT PVRR(D) (BENEFTT)/Cosr op WrNo RspowERtNG............... ...................95 Taslp 7.4 - NorrarNRl LEvpr-rzeo NEr BpNpprr psn MWH op INcneH,lENral ENsRcv Ourpur AFTER Repow8RtNG............... .....96 Tasr-E 7.5 - SO Moosr- nNo PaR PVRR(o) (BeNenrr)/Cosr oF WrNo REpowenrNc................. 96 Taet-s 7.6 -NovrNal RsvBtrup ReeurneueNr PVRR(o) (BENenrr)/Cosr op WrNo REpoweRrNc Taet-s 7.7 -20L7RRFP FtNal SuoRrltsr Tler-e 7.8 - SO Moosl aNo PnR PVRR(o) (BeNenrr)/Cosr oF rHE ColasrNeo PRo:ecrs ..... Taer-B 7.9 - NourNal ReveNur RequrneveNr PVRR(o) (BeNenrr)/Cosr oF THE CoNasrNso Pno:Ecrs 103 Taele 8.1 - CourpARrsoN or 2017 IRP UpoarE wrrH 201 7 IRP PRppERREp PoRrpolro.......... 108 Taele 8.2 -2017 IRP UpoarE Survtrr,trR CRpncrry Loao aNo REsouRcE BRlaNcE ............... 109 Taelp 8.3 -2017IRP Upoerg WrNrrn Cnpncrrv Loao RNo REsouRce BalaNce ln Taer-E 8.4 - PacrrrCoRp's 2017 IRP UroATE, DErRreo PReppRRso PoRrpolro .................... I l3 Tasle 8.5 - PVRR Cosr/(Beuenrr) on rus BusrNrss PI-RN Rplerrve ro rHE 2017 tRP UpoRre PRsrpRRro PoRrrolro ............ I 19 Teslp 9.1 - Assuvrpo Coal-UNrr RETTREMENTS rN THE 2017 IRP PRepsRRso PoRrpolro ......122 Taet-e l0.l -2017IRP AcroN PI-aN Srarus UpoarE ........127 Taele A.l - Fonscasrso ANNual Loao GRowrH, 2018 runouaa2027, Rr GENeRarroN, PRE- DSM........... ................137 Taele A.2 - FoReclsrpo Amlual CoNcrosNr Pear Lono er GENEnerroN, pRE-Dsrra ..........138 Taer-E A.3 - Axm;al Loao GRowrH CHANGE, er GENEnarroN, PRS-DSM............................. 138 Taelp A.4 - Amrual CotNctoeNr Peer GRowru CsaNcE ar GENsRarroN, PRS-DSM.......... 139 Taele A.5 - Sysrev ANuual REran Sales FoRpcasr 2018 runoucu2027 , posr-DSM ......139 Taelp A.6 - Axuual Loao GRowrH CsaNcE: 2017 IRP FonEcasr lEss 2017 IRP UpoarE FoRscasr AT RETerL, Posr-DSM ...............140 Tler-p A.7 - Fonpcasrpo Rgterl Seles Gnowru m ORpcoN, posr-DSM .............141 Taele A.8 - FonEcasreo REran Sar-es GRowru rN WasurNcroN, posr-DSM ......................141 Taet-e A.9 - FonEcasrso REran SalEs GRowrH rN CalrpoRNre, posr-DSM............ .............142 Taele A.l0 - Fonscasrpo Rsran Salns GnowrH rN UrAH, posr-DSM ...............142 Teelp A.l I - Fonscasrgo RErarL Sar-ps GRowru rN IDAHo, posr-DSM .............. 143 Teele A.l2- Fonecasrgo RErRrr- Sar-ps GRowru rN WyourNc, posr-DSM..........................143 .97 101 102 Ixor,x op FtcuRES PecrprConr -2011 tRP UPDATE TABLE op CoNrsNls FrcuRE Ftcuns FrcunE I - Svsrpv CorNcroENr Prar Loao 2 - Powen aNo NaruRar- Gas PRrce Corr,tpaRrsoNs (NonarNar-) 3 - Capacrrv PosrrroN CovpaRrsoN ........... a..J ,.4 ..5 l9 .23 .24 aa.JJ .46 .47 FrcuRB 3.1 - ENency Garpway Map.......... FrcuRp 4.1 -FonEcASrED AuNual Loao (GWH) FtcuRe 4.2 - FonpcASrED AuNuar- CorNcrosNr PrRr Loao (MW) FrcuRB 4.3 - SurraurR Capacrry PosrrroN Covpazuson CHaRr..... FrcuRr 4.4 - SurrarraeR Sysrsur Clpacrry PosrrroN TRBNo Frcunp 4.5 - WrNrsn Svsrpv Capecrry PosruoN TneNo. FtcuRp 4.6 - Easr SuuupR PosrrroN TRpNo Frcuna 4.7 - WEsr Suulasn PosrrroN TnpNo FIcuRp 4.8 - Sysrev Avsnace MoNrHly ENpRcy Posrrrous FrcuRe 5. I - ScaraRS.............. FrcuRE 5.2 - HpNnv Hue NeruRal Gas PRrcps (Noumal) FrcuRE 5.3 -AvBnecr ANNual Flar Palo VpRop Er-EcrRrcrry PRrcps (Nounel) ...... FIcunE 5.4-Avenace Alwual Hpavv Loao Houn Par-o Venoe ElpcrRrcrry PRrces(Novrual) ................57 FrcuRp 5.5 -Avenace AxNual Flar Mro-CoLUMBTA Er-scrRrcrrv Pnrces (Noumal) .......... 58 FIcuRp 5.6 - Avpnacs AxNuar- Hgavv Lono Houn Mro-Coluvrsra Et-ecrRrcrrv PRrces(NourNar) ................58 Frcunr 5.7 - MEoruu COz PnrcE ....... 59 FrcuRr 5.8 - Norr4rNrar- YsaR-ev-Ypen EsceLarroN FoR DrrrERsNr RpsouRcE TypEs............ 60 FrcuRr 6.1 -FonwaRo PRrcp Cunvg AssuvprroNs ............. .................. 7l Frcunp 6.2-CvrnLATrvE INcruesE/(Drcnrese) rN PoRrnolro ResouRcES UNDER rus Davp JonNsroN UNrr 3 INsralr- SCR EeurpMENr (Pzuce-ScrNARro MM) ......... ......72 Frcunp 6.3 -CurauLATrvE INcruesa/(Drcnresr) rN PoRrroLro RpsouRcES UNDER rus Jru BRrocpn UNrrs I & 2 INsrar-l SCR EqunueNr aNo Rrrne2037 (Pnrce-SceNanro MM) .................74 Ftcunr 6.4 - CuvulArrvE INcnrase/(Decnease) w PoRrpolro ResouRcES UNDER THE NaucnroN UNrr 3 Maxrvuv Ges CoNveRSroN RNo RprrRe 2029 (Pwce-SceNenro MM) ....,.,,.....,...76 FrcuRp 6.5 - CuuuLATrvE Iucnnesr/(Dacnease) rN PoRrnolro ResouRcES UNDER THE NaucuroN UNrr 3 Lrurrro Ges CoNvpRSroN (Pnrce-SceNARro MM).............................. 78 FrcuRp 6.6 - CuruuLATrvE INcnrasr/(Decruasn) rN PoRrnoLro ResouRcES UNDER rne CHor-la Uurr 4 Ges CoNvaRSroN (Pruca-ScrNARro MM).......... ..................79 FtcuRp 6.7 - Davp JouxsroN UNrr 3 SCR Pnorpcr MnesroNs ScHsouLE .............................. 8l FrcuRs 6.8 -Jna Bnrocpn UNrrr I SCR Pnolscr MrlssroNg Scusou18.............. .....82 FrcuRp 6.9 -Jrru BRrocpR UNrr 2 SCR Pnorecr MresroNp ScsEou18.............. ..... 83 FtcuRp 6. l0 - NaUGHToN UNrrr 3 Maxruuu NaruRar- Gas CoNvERSToN PRorecr MnEsroueScHpour-e. .................84 FtcuRs 6.1 I - NaUGHToN Uurr 3 Lrurrso Narunal Gas CoNvpRSroN PRolecr MresroNE Scnpoulp. .................85 Ftcunr 6.12- Csolle Uutr 4 Narunal Gas CoNveRSroN PRorecr MresroNe Scupoulp .... 86 FrcuRe 7.1 - HsNny Hue NarunaL Gas Pnrce AssuuprroNs.............. .................... 89 FtcuRp 7.2-COz PRrcp AssuuprroNs.............. ..................... 90 VI ..47 ..48 ..49 .55 .56 .57 PACIFICoRP -2017 IRP Upo,,rre TABLE op CoNreNrs FrcuRe 8.1 -ArwuAL SrATE RPS Covpr-TANCE Fonscasr.115 FrcuRp 8.2 - CorrapARrsoN or COz EvrssroN FoRrcasrs BETWEEN rsa2017 IRP UpoarE PRpprRruo Ponrrorro AND THE 2017 IRP PRrpERneo PoRrror-ro FrcuRs 8.3 - PnolpcrEo ENsRcv Mtx wrru 2017 IRP Upoars PRerrRruo PoRrpolro ll6 RBsouRcps tt7 FrcuRs 8.4 - CuvulArrvE INcnease/(Decnrase) m 2017 BusrNnss Plau RNo 2017 IRP Upoerp PRrpBRRen PoRrpor-to .................. I 18 vl1 PncrFrConp -2017 IRP UPDA rE TABLE op CoNreNls [This page is intentionally left blank] vlll PACIFICoRP _2017 IRP Upoarg CuapreR I -Exscunvs Survrvanv CHaprER 1- Exscurrvp SUvTMARY PacifiCorp submitted its 2017 Integrated Resource Plan (lRP) to state regulatory commissions on April 4, 2017. That plan provides a framework for future actions that PacifiCorp will take to provide reliable and reasonably priced service for its customers through the least-cost, least-risk resource portfolio. The 2017 IRP Update reflects resource planning and procurement activities that have occurred since the 2017 IRP and presents an updated load-and-resource balance and an updated resource portfolio consistent with changes in the planning environment. The 2017 IRP Update also provides a status update forthe action plan filed with the 2017 IRP in Chapter 10. In presenting the updated load-and-resource balance and updated resource portfolio, PacifiCorp shows changes relative to the 2017 IRP which covers the 2017 to2036 planning horizon. In the 2017 IRP Update PacifiCorp also addresses recommendations and requirements identifiedby its state regulatory commissions during the 2017 IRP acknowledgement or acceptance process. 2017 IRP Update Highlights PacifiCorp's long-term planning process involves balanced consideration of cost, risk, uncertainty, supply reliability/delivery, and long-run public policy goals. The following summarizes the key highlights of PacifiCorp's2017 IRP Update: PacifiCorp's2017 IRP Update preferred portfolio includes updated cost-and-performance information for the Energy Vision 2020 projects, which include l,3l 1 MW of new wind, repowering just over 999 MW of existing wind capacity, and the new 140-mile, 500 kilovolt (kV) Aeolus-to-Bridger/Anticline transmission line in Wyoming. Collectively, these resources contribute to meeting the capacity need identified in PacifiCorp's updated load-and-resource balance and are on track to be in service by the end of2020. The Energy Vision 2020 projects continue to be a central feature of the 2017 IRP Update least-cost, least-risk preferred portfolio and will provide substantial benefits for customers. The 1,311 MW of new wind projects were identified through a robust competitive bidding process. Updated economic analysis of these new wind resources, enabled by the Aeolus-to-Bridger/Anticline transmission line, shows that they will provide substantial customer benefits. In addition to creating construction jobs and tax revenue in the state of Wyoming, the new wind projects will qualify for the full value of federal production tax credits (PTCs) and generate zero-fuel-cost energy. The new 500-kv, 140-mile Aeolus-to Bridger/Anticline transmission line, which is needed to strengthen the electric reliability of PacifiCorp's transmission system, will provide critical voltage support to the Wyoming transmission network, mitigate the impact of outages on the existing system, enhance the company's ability to comply with mandated reliability and perforrnance standards, and reduce line losses. The new transmission line will also relieve existing transmission constraints, increase transfer capability and enable interconnection of new capacity. The 999 MW of repowered wind facilities located in Oregon, Washington and Wyoming, will provide substantial customer benefits and optimize the existing wind fleet by using new technology that increases zero-fuel-cost energy production, reduces a I PACIFICoRP _2017 IRP UPDATE Cuep'tln 1 - ExECUTIVE SUMMARY a a a a a ongoing operating costs by avoiding capital expenditures related to component failures, renews the existing wind fleet with new turbines that extend the useful life of the wind facilities by up to 13 years, requalifies the wind facilities to receive the full value of PTCs for another l0 years, and improves delivery of wind energy into the transmission system through enhanced voltage support and power quality. With reduced loads and lower renewable resource costs, the updated preferred portfolio contains no new natural gas resources through the 20-year planning horizon. This is the first time an IRP has not included new fossil-fueled generation as a least-cost, least-risk resource for PacifiCorp. Through the end of 2036, the updated preferred portfolio includes over 2,700 MW of new wind resources, 1,860 MW of new solar resources, 1,877 MW of incremental energy efficiency resources, and approximately 268 MW of direct-load control resources. The 201 7 IRP Update preferred portfolio continues to assume existing owned coal capacity will be reduced by 3,650 MW through the end of 2036. In accordance with action items in the 2017 IRP action plan, PacifiCorp completed unit- specific coal studies in the 2017 IRP Update for Naughton Unit 3, Cholla Unit 4, Dave Johnston Unit 3, and Jim Bridger Units I and2. Consistent with the findings from these studies, the 2017 IRP Update continues to assume no incremental selective catalytic reduction (SCR) emission-reduction systems will be needed to satisfy regional haze compliance obligations. PacifiCorp continues to assume Cholla Unit 4 retires at the end of 2020, Dave Johnston Unit 3 retires at the end of 2027, and Jim Bridger Units I and 2 retire at the end of 2028 and2032, respectively. The 2017 IRP Update assumes Naughton Unit 3 retires end of January 2019, shifted one month from the 2017 IRP that assumed retirement at the end of2018. On March 28,2017, President Trump issued an Executive Order directing the U.S. Environmental Protection Agency (EPA) to review the Clean Power Plan (CPP) and, if appropriate, suspend, revise, or rescind the CPP, as well as related rules and agency actions. On October 10,2017, the EPA issued a proposal to repeal the CPP and the EPA will take comments on the proposed repeal until April 26,2018. In addition, the EPA published in the Federal Register an Advance Notice of Proposed Rulemaking December 28, 2017, seeking public input on, without committing to, a potential replacement rule. The public comment period for the Advance Notice of Proposed Rulemaking concluded February 26, 2018. PacifiCorp will continue to follow activities related to the CPP; however, the company has not included the CPP in its assumptions for the 2017 IRP Update. Rather, the 2017 IRP Update includes a medium COz price assumption starting in 2030 to reflect possible regulatory changes in the future. On December 22,2017, President Trump signed into law H.R. I (Tax Reform Act) which generally impacts PacifiCorp for tax years beginning in 2018 and going forward. The Tax Reform Act reduced the federal corporate income tax rate from a top rate of 35 percent to an across-the-board federal corporate income tax rate of 2l percent. The Tax Reform Act left intact the federal tax credit rules and phase-outs for wind and solar facilities as enacted in the 2015 tax extender legislation. Public utility property will no longer be eligible for 2 a PACIFICoRP - 2OI7 IRP Upoarg CuRpTp,n I - EXECUTIVE SUMMARY bonus depreciation for property placed in service after September 27,2017 , unless it was subject to a written binding contract on September 27 ,2017. PacifiCorp's 2017 IRP Update accounts for the Tax Reform Act, and updated economic analysis of Energy Vision 2020 projects are greater than originally estimated in the 2017 IRP despite the reduction in federal corporate income tax rate. a As shown in Figure 1.1 PacifiCorp's most recent coincident system peak load forecast, is down relative to the 2017 IRP. On average, across the first ten years of the planning period, the coincident system peak is down by roughly 424 MW relative to the 2017 IRP reflecting a less favorable outlook for the industrial segment and the adoption of more efficient appliances by residential customers. re 1.1 -Coincident Peak Load a Figure 1.2 shows that forecasted natural gas and energy prices have declined from those in the 2017 IRP through about the 2030-2031 time frame. Domestic gas price forecasts continue to be driven down by growth in unconventional shale-gas plays. This in turn (combined with lower forecasted regional loads) impacts forward market power prices. J ,.4. -- "$. .,p9 ,$,t "9 ,{P "p "$r ,of ,$,t ,$ I 1,000 10,500 9,500 +2017IRP +2017 IRP Update I1,500 B ro.oooF2 9,000 PACIt.ICoRP -20I] IRP UPDATE CHapren I - ExECUTIVE SUMMARY 1.2 - Power and Natural Gas Price C Figure 1.3 summarizes the 2017 IRP Update capacity load-and-resource balance, before acquiring new resources and making firm market purchases, alongside the load-and-resource balance from the 2017 IRP. The load-and-resource balance capacity need has decreased by an average of 408 MW, relative to the 20l7IRP, reflecting a lower load forecast and an increase in qualifying facility contracts. The capacity need in both the 2017 IRP and the 2017 IRP Update increases at the end of January 2019 due to the assumed early retirement of Naughton Unit 3 and at the end of 2020 due to the assumed early retirement of Cholla Unit 4. The 2017 IRP Update load-and-resource balance continues to show acapacity need throughout the planning period, but this need has been reduced relative to the 2017 IRP by 204 MW in 2018 rising to 539 MW by 2027. 8.00 7.00 6.00 5.00 4.00 3.00 2.00 1.00 0.00 6OO-NOVhQr@6O-Noth€f: : ! q! Al ! ! ! ! c!!1 ! a ! a! ! NNNdddNNddddddNdNddN -2017 IRP_Upd (Dec 2017) - -20l7lRP (Oct 2016) Henry Hub Natural Gas Prices z aa 70.00 Average Mid-C/Palo Verde Flat Electric Prices 60.00 @6O-No$69r€6O-Noih9ts--dNNNNdddNdoooooOOOOOOOOOOAAOao'-JJdNNNNNNNdNNddNNdNNNN -2017lRPUpd(Dec2017) o r20l7lRP(Oct2016) oz 50.00 40.00 30.00 20.00 10.00 0.00 4 Load-and-Resource Balance .2t)17 IRP 2017 IRp Lrpdate 2019 2r020 2{)212OIE 2027 (2oo) (.roo) { ( l.ooo) ( l,2oo) (l,.roo) 2{'25 2026 () () 7022 2023 ZO21 600 800 PecrprConp -2017 IRP Upn,,rrE Crrapren I -Execurrvs SuvnaeRv re 1.3 -Position Table I . I reports the 2017 IRP Update preferred portfolio and differences relative to the 2017 IRP preferred portfolio. The table shows the resource mix that achieves a l3-percent planning reserve margin in each reported year. As compared to the 2017 IRP preferred portfolio, changes in the resource mix reflect updates to Energy Vision 2020 new wind resources and a reduced load forecast that result in removal of the need for a new natural gas simple cycle combustion turbine (SCCT) and combined cycle combustion turbine (CCCT) and reduced reliance on higher risk market transactions throughout the 20-year planning horizon. As was the case in the 2017 IRP preferred portfolio, PacifiCorp continues to plan to meet its customers' needs largely through the acquisition of cost-effective Energy Vision 2020 resources, energy efficiency (Class 2 demand- side management (DSM)) resources, and front-office transactions (FOTs), over the next ten years. 5 t) Preferred Portfolio Update E E F _lt ;l 3t ilflil.l L .o r d o = r d E g ? ! ;l r d ra G e!u0c)Fa L o)frL.q) c) r- 6t Eq) qq r- 6t U) oU I q) 3 zzDca) rl.] F)Orl.]Xq I uF U F e f, Ed, c- c.l I oU tr U F Ell tl I +I Ii II !3 I ! tl tl tl tl 3 tl ll ll tl 33 t-t t-l l=l lzl t'l lt I F c e I.E> 6 E .9 o E Oo l I n 3 I c2 t R 3 J a 8 I a g 3 I $+ 3 -t sl lclIJl.=l l.!l a : o Ej o + ' ,E i \o tl Il lt tl I l I tl tl tl tl l .l PecrprConp - 2017 IRP Upoarp CH,qprgn 2 _ INTRODUCTION CHaprER 2 - IxrnoDUCTroN This 2017 IRP Update describes resource planning activities that occurred after the 2017 IRP was filed in April 2017, presents an updated load-and-resource balance, an updated resource portfolio consistent with changes in the planning environment, and provides a status update on the action plan filed with the 2017 IRP. In presenting the updated load and resource balance assessment and updated resource portfolio, PacifiCorp shows changes relative to the 2017 IRP and relative to its fall 201 7 l}-year business plan (Business Plan), which covers the 201 8 to 2027 planning horizon. In this update PacifiCorp also addresses recommendations and requirements identified by its state regulatory commissions during the 2017 IRP acknowledgement process, as applicable. PacifiCorp updated the 2017 IRP Update preferred portfolio reflect updates to forecasted loads, resources, market prices, and other model inputs. The 2017 IRP Update also includes the most recent analysis of Energy Vision 2020 projects, which includes new wind and transmission, plus wind repowering. Chapters I and2 of the 2017 IRP Update provide summary information. Chapter 3 describes the current planning environment, load updates, resource updates, state and federal policy updates, and Energy Gateway transmission planning and project completion forecast. Chapters 4 provides updated load-and-resource balance information. Chapter 5describes changes to key inputs and assumptions relative to those used for the 2017 IRP. Studies conducted in response tothe2017 IRP coal resource action plan items are discussed in Chapter 6. A summary of Energy Vision 2020 is presented in Chapter 7. Chapter 8 presents the updated resource portfolio. Chapter 9 presents transmission studies consistent with the 2017 IRP action plan. A status update on the 2017 IRP Action Plan is provided in Chapter 10. The Appendix provides additional load forecast details. 7 PrrcrprConp - 20 l7 IRP UpoerE CuaprEn 2 - TNTRODUCTION [This page is intentionally left blank] 8 Cneprpn 3 - TuE, PTaNxING ExvnoNMENT PRCIT.ICt;np 20 I7 IRP UPDAI.I,CHAPTER 3 -Tua PLANNTNG ENVIRONMENT Federal Policy Update Federal Climate Change Legislation To date, no federal legislative climate change proposal has been passed by the U.S. Congress. Federal climate change legislation is not anticipated in the near term, but remains possible in the mid- to long-term. New Source Performance Standards for Carbon Emissions - Clean Air Act $ 111(b) New Source Performance Standards (NSPS) are established under the Clean Air Act for certain industrial sources of emissions determined to endanger public health and welfare. On October 23, 2015, the U.S. Environmental Protection Agency (EPA) finalized a rule limiting carbon emissions from coal-fueled and natural-gas-fueled power plants. New natural-gas-fueled power plants can emit no more than 1,000 pounds of carbon dioxide (COz) per megawatt-hour (MWh). New coal- fueled power plants can emit no more than 1,400 pounds of COz/MWh. The final rule largely exempts simple cycle combustion turbines from meeting the standards. The NSPS was appealed to the U.S. Court of Appeals - D.C. Circuit and oral argument was scheduled for April 17 ,2017 . However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. Until such time as the EPA undertakes fuither action to reconsider the NSPS or the court takes action, any new fossil-fueled generating facilities constructed by relevant registrants will be required to meet the NSPS established in the EPA's October 23,2015 final rule. Carbon Emission Guidelines for Existing Sources - Clean Air Act $ 111(d) On August 3,2015, EPA issued a final rule, referred to as the Clean Power Plan (CPP), regulating carbon emissions from existing power plants. The CPP required states to develop standards of performance, which are the degree of emissions limitations achievable through the application of the best system of emission reduction (BSER). EPA's proposal calculated state-specific emission rate targets to be achieved based on the BSER. The final CPP established the BSER as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in service after 2012. The compliance period would have begun in2022, with three interim periods of compliance and with the final goal to be achieved by 2030. The CPP was expected to reduce COz emissions in the power sector to 32 percent below 2005 levels by 2030. On March 28,2017 , President Trump issued an Executive order directing EPA to review the CPP and, if appropriate, suspend, revise, or rescind the CPP, as well as related rules and agency actions. On October 10, 2017, EPA issued a proposal to repeal the CPP and the public comment period on EPA's proposal closed April26,2018. In addition, EPA published an Advance Notice of Proposed 9 PeclprConp -2011 IRP UpoarE CIIAP'II]R 3 TIIE PLANNTNG ENVIR0NMENT Rulemaking in the Federal Register December 28, 2017, seeking public input on, without committing to, a potential replacement rule. The public comment period for the Advance Notice of Proposed Rulemaking concluded February 26, 2018. Given the current status of the CPP, PacifiCorp does not assume applicability of any CPP emission limits in the 2017 IRP Update. Clean Air Act Criteria Pollutants - National Ambient Air Quality Standards The Clean Air Act requires EPA to set National Ambient Air Quality Standards (NAAQS) for six criteria pollutants that have the potential of harming human health or the environment. The NAAQS are rigorously vetted by the scientific community, industry, public interest groups, and the general public, and establish the maximum allowable concentration allowed for each "eriteria" pollutant in outdoor air. The six pollutants are carbon monoxide, lead, ground-level ozone, nitrogen dioxide (NOx), particulate matter (PM), and sulfur dioxide (SOz). The standards are set at a level that protects public health with an adequate margin of safety. If an area is determined to be out of compliance with an established NAAQS standard, the state is required to develop a state implementation plan (SIP) for that arca. And that plan must be approved by EPA. The plan is developed so that once implemented, the NAAQS for the particular pollutant of concem will be achieved. In October 2015, EPA issued a final rule modifying the standards for ground-level ozone from 75 parts per billion (ppb) to 70 ppb. Under the final rule, EPA is required to designate areas in the country as being in "attainment" or "nonattainment" of the revised standards by October 2017. State compliance dates will be set depending on the ozone level in the area. EPA is currently in the process of making attainment/nonattainment classifications. PacifiCorp facilities will only be affected to the extent they are located in an ozone nonattainment area. On January 9,2018, EPA published the results for the air quality designations for the 2010 SOz primary NAAQS-Round three in the Federal Register. The Utah county of Emery, where PacifiCorp's Hunter and Huntington Generation Stations are located, was classified as attainment/unclassifiable. The Wyoming counties of Campbell and Lincoln, where PacifiCorp's Wyodak and Naughton generation stations are located, were classified as attainment/unclassifiable. The eastern portion of Sweetwater County, where PacifiCorp's Jim Bridger generation station is located, was classified as attainment/unclassifiable. PacifiCorp's facility has conducted on-site ambient SO2 monitoring to demonstrate compliance and is currently working with the state and federal agencies to terminate the monitoring site. Converse County, where PacifiCorp's Dave Johnston generation station is located, will not be designated until December 31,2020- The classification of attainment/unclassifiable maintains the regulatory status quo for the affected facilities. PacifiCorp facilities located in areas classified as attainment/unclassifiable will be required to demonstrate ongoing compliance by performing modeling every three years using actual facility emission data. On January 23,2017, Gadsby and Lake Side were identified as major sources subject to Utah's serious nonattainment area SIP for PMz.s and PMz.s precursors. On April 28, 2017, PacifiCorp submitted a best-available control measure analysis for Gadsby and Lake Side to Utah Department of Air Quality for review. PacifiCorp proposed ammonia limits for the Gadsby and Lake Side facilities. Utah has until December 31, 2019 to demonstrate attainment through modeling or monitoring. If the state cannot demonstrate attainment through the measures proposed in the SIP, then the Lake Side and Gadsby facilities may be subject to more stringent environmental regulation. l0 PaCIpIConp _2017 IRP UPDATE CHAPTER 3 -THE PLANNTNG ENvTRoNnapNT Regional Haze EPA's regional haze rule, finalized rn1999, requires states to develop and implement plans to improve visibility in certain national park and wilderness areas. On June 15,2005, EPA issued final amendments to its regional haze rule. These amendments apply to the provisions of the regional haze rule that require emission controls known as the best available retrofit technology (BART) for industrial facilities meeting certain regulatory criteria with emissions that have the potential to affect visibility. These pollutants include fine PM, NOx, SOz, certain volatile organic compounds, and ammonia. The 2005 amendments included final guidelines, known as BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. States were given until December 2007 to develop their implementation plans, in which states were responsible for identifying the facilities that would have to reduce emissions under BART guidelines, as well as establishing BART emissions limits for those facilities. States are also required to periodically update or revise their implementation plans to reflect current visibility data and the effectiveness of the state's long-term strategy for achieving reasonable progress toward visibility goals. On December 14,2016, EPA issued a final rule setting forth revised and clarifying requirements for periodic updates in SIPs. States are currently required to submit the next periodic update by July 31,2021. EPA's final action on the regional haze rule amendments was published in the Federal Register on January 10, 2017, and has been appealed by several states and industry groups. On January 17,2018, EPA announced its decision to revisit certain aspects of the 2017 regional haze rule revisions. EPA intends to commence a notice-and-comment rulemaking process and expressed plans to finalize EPA guidance documents for regionalhaze SIP revisions due in202l. On January 30,2018, the U.S. Court of Appeals - D.C. Circuit issued an order holding the case in abeyance and directing EPA to submit a status report every 90 days, starting April 30,2018. The regional haze rule is intended to achieve natural visibility conditions by 2064 in specific national parks and wilderness areas, many of which are located in Utah and Wyoming where PacifiCorp operates generating units, as well as Arizona where PacifiCorp owns but does not operate a coal unit, and in Colorado and Montana where PacifiCorp has partial ownership in generating units operated by others, but are nonetheless subject to the regional haze rule. Utah Regional Haze In May 2011, the state of Utah issued a regional haze SIP requiring the installation of SO2, NO* andPMcontrolsonHunterUnitsland2andHuntingtonUnitsIand2.lnDecember2012,EPA approved the SOz portion of the Utah regionalhaze SIP and disapproved the NOx and PM portions. EPA's approval of the SOz SIP was appealed to federal circuit court. In addition, PacifiCorp and the state of Utah appealed EPA's disapproval of the NOx and PM SIP. PacifiCorp and the state's appeals were dismissed. In June 2015, the state of Utah submitted a revised SIP to EPA for review and approval with an updated BART analysis incorporating a requirement for PacifiCorp to retire Carbon Units I and 2, recognizing NOx controls previously installed on Hunter Unit 3, and concluding that no incremental controls (beyond those included in the May 201I SIP and already installed) were required at the Hunter and Huntington units. On June 1,2016, EPA issued a final rule to partially approve and partially disapprove Utah's regional haze SIP and propose a federal implementation plan (FIP). The FIP final rule requires the installation of selective catalytic reduction (SCR) controls at four of PacifiCorp's units in Utah by August 4,2027: Hunter Units I and 2, and Huntington Units 1 and 2. On September 2, 2016, PacifiCorp and other parties filed 1l PacrilCoRp -2017 IRP Upnarr Crrapren 3 - TrrE PLANNTNG ENvnoNur,Nr petitions for administrative and judicial review of EPA's final rule and requested a stay of the effective date of the final rule. Unless EPA's FIP is stayed or reversed, the controls are required to be installed by August 4, 2O2l . On September I l, 2Ol7 , the U.S. lOth Circuit Court of Appeals granted the petition for stay and the request for abatement. The compliance deadline of the FIP and the litigation will be stayed indefinitely pending EPA's reconsideration. On January 30,2074, EPA published its final action in Wyoming, published in the Federal Register, requiring installation of the following NOx and PM controls at PacifiCorp facilities: o Jim Bridger Unit 3 by December 3 l, 2015: SCR equipment. Jim Bridger Unit 4 by December 3 l, 2016: SCR equipmento Naughton Unit 3 by January 30,2019: SCR equipment and a baghouseo Jim Bridger Unit2 by December 31, 2021: SCR equipmento Jim Bridger Unit I by December 3 l, 2022: SCR equipmento Dave Johnston Unit 3: SCR within five years or a commitment to shut down in 2027o Wyodak: SCR equipment within five years Different aspects of EPA's final action were appealed by a number of entities. PacifiCorp appealed EPA's action requiring SCR at Wyodak and was granted a stay of the Wyodak SCR requirement pending resolution of the appeals. For Naughton Unit 3, EPA indicated support for the conversion of the unit to natural gas in its final action and stated that it would expedite consideration of the gas conversion once the state of Wyoming submitted the requisite SIP amendment. PacifiCorp obtained a construction permit and revised regional haze BART permit from the state of Wyoming to convert Naughton Unit 3 to natural gas in 2018. In late 2017 PacifiCorp submitted a petition to the state of Wyoming requesting that the requirement to convert Naughton 3 to natural gas be delayed one year which was approved by the state of Wyoming. The permit allows PacifiCorp to continue with coal-fueled operation through January 30,2019, with the option of gas conversion available thereafter. The Wyoming Department of Environmental Quality submitted a proposed revision to the Wyoming SIP, including a change to the Naughton Unit 3 compliance date, to the EPA for review and approval November 28,2017. Arizona Regional Haze EPA took final action approving the Arizona regional haze SIP revision and withdrawing the FIP for the Cholla power plant on March 16,2017 allowing Cholla Unit 4 to continue coal-fueled operations through April 30, 2025, with the option to convert to burn natural gas by July 31,2025. Colorado Regional Haze ln2016, the owners of Craig Unit 1, state and federal agencies, and parties to previous Colorado regional haze settlements reached an agreement to propose an alternate regional haze compliance plan for Craig Unit I that incorporated retirement of the unit by December 31,2025, with an option for conversion of the unit to natural gas by August 31,2023. The terms of this agreement were approved by the Colorado Air Quality Board on December 15, 2016. The Colorado Department of Public Health and Environment submitted the associated Colorado SIP amendment for EPA's t2 Wyoming Regional Haze Pe,crrrConp -2017 IRP Upoare CHAPTER 3 _ THa PLANNTNG ENVIRoNMENT review and approval on May 27,2017. EPA's review and approval process is expected to carry through 2018. Mercury and, Hazardous Air Pollutants The Mercury and Air Toxics Standards (MATS) became effective April I 6,2012. The MATS rule requires that new and existing coal-fueled facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16,2015. However, individual sources may have been granted up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or fortransmission system reliability reasons. In June 2015, the U.S. Supreme Court found that EPA did not properly consider costs in making its determination to regulate hazardous pollutants from power plants. In December 2015, the U.S. Court of Appeals - D.C. Circuit ruled that MATS may be enforced as EPA modifies the rule to comply with the Supreme Court decision. By April 2015, PacifiCorp had taken the required actions to comply with MATS across its generation facilities. Coal Combustion Residuals Coal Combustion Residuals (CCRs), including coal ash, are the byproducts from the combustion of coal in power plants. CCRs have historically been considered exempt wastes under an amendment to the Resource Conservation and Recovery Act (RCRA); however, EPA issued a final rule in December 2014 to regulate CCRs for the first time. Under the final rule, EPA will regulate CCRs as non-hazardous waste under Subtitle D of RCRA and establish minimum nationwide standards for the disposal of CCRs. The final rule was effective October 19,2015. Under the final rule, surface impoundments utilized for CCRs may need to close unless they can meet more stringent regulatory requirements. PacifiCorp operates seven impoundments and four landfills that are subject to the final rule. Three impoundments are currently being closed. The final CCR regulation was self-implementing; however, in December 2016 the Coal Combustion Residuals Regulatory Improvement Act was signed, which sets forth the process and standards for EPA approval (and withdrawal) of a state's permitting program for CCR units. A state may incorporate either the requirements of the EPA rule into its permit program or other state requirements that, based on site-specific conditions, are at least as protective as the EPA rule. On March 1,2018, EPA proposed to amend the April 2015 final CCR rule. EPA is proposing to allow states or EPA the ability to incorporate flexibilities into the coal ash permit programs of state, and EPA-issued permits. Comments on the rule amendment were due April 30, 2018, and EPA plans to hold a public hearing on the proposal. Water Quality Standards Cooling Water Intake Structures The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the U.S. through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling- water-intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. ln May 2014, EPA issued a final rule, effective October 2014, under $ 316(b) of the Clean Water Act to regulate cooling-water intakes at existing l3 PncrplConp _2017 IRP UPDATE CHAPTER 3 -Tug PLANNTNG ENVIRONMENT facilities. The final rule established requirements for electric-generating facilities that withdraw more than two million gallons per day, based on total design intake capacity, of water from waters of the U.S. and use at least 25 percent of the withdrawn water exclusively for cooling purposes. PacifiCorp's Dave Johnston generating facility withdraws more than two million gallons per day of water from waters of the U.S. for once-through cooling applications. Jim Bridger, Naughton, Gadsby, Hunter, and Huntington generating facilities currently use closed-cycle cooling towers but withdraw more than two million gallons of water per day. The rule includes impingement(i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) mortality standards and entrainment (i.e., when organisms are drawn into the facility) standards. The standards will be set on a case-by-case basis to be determined through site-specific studies and will be incorporated into each facility's applicable water permit (i.e., either NPDES permit or storm water permit). Effluent Limit Guidelines EPA first issued effluent guidelines for the Steam Electric Power Generating Point Source Category (i.e., the Steam Electric effluent guidelines) in 1974, with subsequent revisions in 1977 and 1982. On November 3, 2015, EPA finalized revised effluent-limit guidelines. The rule prohibits the discharge of bottom ash or fly ash transport water and directly impacts the Wyodak, Dave Johnston, and Naughton facilities. On September 18, 2017, EPA postponed certain compliance dates for the Steam Electric effluent guidelines. EPA intends to conduct a new rulemaking regarding the appropriate technology bases and associated limits for the best available economically achievable technology effluent limitations and pretreatment standards for existing sources requirements applicable to flue gas desulfurization (FGD) wastewater and bottom ash transport water discharged from steam electric power plants. The earliest compliance date for plants to meet the new FGD wastewater and bottom ash wastewater limitations is as soon as possible beginning November l, 2020. 2015 Tax Extender Legislation On December 18, 2015, President Obama signed tax extender legislation (H.R. 2029) that retroactively and prospectively extended certain expired and expiring federal income tax deductions and credits. Bonus Depreciation Bonus depreciation under the 2015 Tax Extender Legislation was superseded by the 2017 Tax Reform Act. Please refer to the bonus depreciation discussion under the 2017 Tax Reform Act section of this chapter. Production Tax Credit (Wind) The production tax credit (PTC), currently 2.4 cents per kilowatt-hour (inflation adjusted), has been extended and phased out for wind property for which construction begins before January l, 2020, as follows: o 2015 - 100% retroactiveo 2016 - 100% (construction begins before January 1,2017) t4 . 2017 -80% (construction begins before January 1,2018)o 2018 - 60% (construction begins before January 1,2019)o 2019 - 40% (construction begins before January 1,2020) Production Tax Credit (Geothermal and Hydro) The PTC for geothermal and hydro were granted a two-year extension as follows (no phase-out period was adopted): . 2015 - 100% retroactiveo 2016 - 100% (construction begins before January l, 2017) 307o Energy Investment Tax Credit (Wind) The investment tax credit (lTC) has been extended and phased out for wind property for which construction begins before January 1,2020, as follows: o 2015 - 30% retroactive t 2016-30% (construction begins before January 1,2017)o 2017 -24% (construction begins before January 1,2018)o 2018 - 18% (construction begins before January 1,2019) o 2019 - 12% (construction begins before January 1,2020) 307o Energy Investment Tax Credit (Solar) The ITC has been extended and steps down for solar property for which construction begins before January 1,2022, as follows: o 2015 - 30% retroactiveo 2016 -30% (construction begins before January 1,2017)o 2017 - 30% (construction begins before January l, 2018)o 2018 -30% (construction begins before January 1,2019) o 2019 -30% (construction begins before January 1,2020) o 2020 - 26% (construction begins befbre January 1,2021)o 2021-22% (construction begins before January 1,2022)o 2022 - l0% (construction begins on or after January 1,2022) 2017 Tax Reform Act On December22,2077, President Trump signed into law H.R. I (Tax Reform Act) which generally impacts PacifiCorp for tax years beginning in 2018 and going forward. Reduction in the Federal Corporate Income Tax Rate The Tax Reform Act reduced the federal corporate income tax rate from a top rate of 35 percent to an across-the-board federal corporate income tax rate of 2l percent. l5 PecrprConp -2017 IRP Upoerp Crmprsn 3 - THs PLANNTNG ENVTRoNMENT Bonus Depreciation 100 percent bonus depreciation was enacted for property placed in service after September 27 , 2017, with a phase-out beginning in2023. However, this new provision for bonus depreciation does not apply to public-utility property. Public-utility property is no longer eligible for bonus depreciation ifplaced in service after September 27,2017, unless it was subject to a written binding contract on September 27,2017 . For public-utility property subject to a written binding contract on September 27,2017, and placed in service during 2018,40 percent of the eligible cost of the property qualifies for bonus depreciation. For public-utility property subject to a written binding contract on Septemb er 27 , 2017 , and placed in service during 2019, 30 percent of the eligible cost of the property qualifies for bonus depreciation. For public-utility property placed in service after December 31,2019, there will be no bonus depreciation. Wind Investment and Production Tax Credits and Solar Investment Tax Credits The Tax Reform Act left intact the federal tax credit rules and phase outs for wind and solar facilities as enacted in the 2015 Tax extender Legislation. California Under the authority of the Global Warming Solutions Act, the Califomia Air Resources Board (CARB) adopted a greenhouse gas cap-and-trade program in October 2011, with an effective date of January 1,2012; compliance obligations were imposed on regulated entities beginning in 2013. The first auction of greenhouse gas allowances was held in California in November 2012, and the second auction in February 2013. PacifiCorp is required to sell, through the auction process, its directly allocated allowances and purchase the required amount of allowances necessary to meet its compliance obligations. In May 2014, CARB approved the first update to the Assembly Bill (AB) 32 Climate Change scoping plan, which defined California's climate change priorities for the next five years and set the groundwork for post-2020 climate goals. In April 2015, Governor Brown issued an executive order to establish a mid-term reduction target for California of 40 percent below 1990 levels by 2030. CARB has subsequently been directed to update the AB 32 scoping plan to reflect the new interim 2030 target and previously established 2050 target. In July 2017, California Governor Jerry Brown signed AB 398, extending the state's California Cap and Trade program from January l, 2021 through December 31, 2030. ln 2002, California established a renewable portfolio standard (RPS) requiring investor-owned utilities to increase procurement from eligible renewable energy resources. California's RPS requirements have been accelerated and expanded a number of times since its inception. Most recently, Governor Jerry Brown signed into law Senate Bill (SB) 350 in October 2015, which requires utilities to procure 50 percent of their electricity from renewables by 2030. SB 350 also requires California utilities to develop integrated resource plans that incorporate a greenhouse gas emission reduction planning component. The California Public Utilities Commission is currently developing rules to implement this new program. l6 PeCIpICoRp - 2017 IRP UPDATE CHAPTER 3 _TuT PLANNTNG ENVm.oNMENT PncrprConp -2017 IRP Upoa.t,CHAPTER 3 _ TUE PLANNTNG ENVIRONMENT Oregon Ln2007, the Oregon Legislature passed House Bill (HB) 3543 - Global Warming Actions, which establishes greenhouse gas reduction goals for the state that: (l) end the growth of Oregon greenhouse gas emissions by 2010; (2) reduce greenhouse gas levels to l0 percent below 1990 levels by2020; and (3) reduce greenhouse gas levels to at least 75 percent below 1990 levels by 2050. In 2009, the legislature passed SB 101, which requires the Public Utility Commission of Oregon (OPUC) to submit a report to the legislature before November I of each even-numbered year regarding the estimated rate impacts for Oregon's regulated electric and natural gas companies of meeting the greenhouse gas reduction goals of l0 percent below 1990 levels by 2020 and 15 percent below 2005 levels by 2020. The OPUC submitted its most recent report November 1,2016. ln 2007, Oregon enacted SB 838 establishing an RPS requirement in Oregon. Under SB 838, utilities are required to deliver 25 percent of their electricity from renewable resources by 2025. On March 8, 2016, Governor Kate Brown signed SB 1547-8, the Clean Electricity and Coal Transition Plan, into law. SB 1547-8 extends and expands the Oregon RPS requirement to 50 percent of electricity from renewable resources by 2040 and requires that coal-fueled resources are eliminated from Oregon's allocation of electricity by January 1,2030- The increase in the RPS requirements under SB 1547-8 is staged-27 percentby 2025,35 percent by 2030,45 percent by 2035, and 50 percent by 2040. The bill changes the renewable energy certificate (REC) life to five years, while allowing RECs generated from the effective date of the bill passage until the end of 2022 from new long-terrn renewable projects to have unlimited life. The bill also includes provisions to create a community-solar program in Oregon and encourage greater reliance on electricity for transportation. Washington In November 2006, Washington voters approved Initiative 937 (l-937), the Washington Energy Independence Act, which imposes targets for energy conservation and the use of eligible renewable resources on electric utilities. Under l-937, utilities must supply 15 percent of their energy from renewable resources by 2020. Utilities must also set and meet energy conversation targets starting in 2010. In 2008, the Washington Legislature approved the Climate Change Framework E2SHB 2815, which establishes the following state greenhouse gas emissions reduction limits: (l) reduce emissions to 1990 levels by 2020; (2) reduce emissions to 25 percent below 1990 levels by 2035; and (3) by 2050, reduce emissions to 50 percent below 1990 levels or 70 percent below Washington's forecasted emissions in 2050. In July 2015, Govemor Inslee released an executive order that directed the Washington Department of Ecology to develop new rules to reduce carbon emissions in the state. Ecology initiated the rulemaking process in September 2015 and finalized the Clean Air Rule on January 5, 2016. While the rules for the Clean Air Rule were being finalized by the Department of Ecology in September 2016, a lawsuit was filed by a coalition of employer groups challenging the Department of Ecology's authority to implement the rule. In December 2017, Washington's Superior Court concluded that the Department of Ecology did not have the authority to impose the t7 PACIFICORP - 2017 IRP UPDATE CIIap.I.IIn 3 _TIIn PLANNING ENVIRoNMEN.I Clean Air Rule without legislative approval. As a result, the Department of Ecology has suspended the rule's compliance requirements. Utah In March 2008, Utah enacted the Energy Resource and Carbon Emission Reduction Initiative, which includes provisions to require utilities to pursue renewable energy to the extent that it is cost effective. It sets out a goal for utilities to use eligible renewable resources to account for 20 percent of their 2025 adjusted retail electric sales. On March 10,2016, the Utah legislature passed SB ll5-The Sustainable Transportation and Energy Plan (STEP). The bill supports plans for electric vehicle infrastructure and clean coal research in Utah and authorizes the development of a renewable energy tariff for new Utah customer loads. The legislation establishes a five-year pilot program to provide mandated funding for electric vehicle infrastructure and clean coal research, and discretionary funding for solar development, utility-scale battery storage, and other innovative technology and air quality initiatives. The legislation also allows PacifiCorp to recover its variable power supply costs through an energy balancing account and establishes a regulatory accounting mechanism to manage risks and provide planning flexibility associated with environmental compliance or other economic impairments that may affect PacifiCorp's coal-fueled resources in the future. The deferrals of variable power supply costs went into effect in June 2016, and implementation and approval of the other programs was completed by January 1,2017. Greenhouse Gas Emission Performance Standards Califomia, Oregon and Washington have all adopted greenhouse gas emission performance standards applicable to all electricity generated in the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined cycle natural gas generation facility. The standards for Oregon and California are currently set at 1,100 lb COzlMWh, which is defined as a metric measure used to compare the emissions from various greenhouse gases based on their global warming potential. In March 2013, the Washington Department of Commerce issued a new rule, effective April 6, 2013, lowering the emissions performance standard to 970lb COzlMWh. Energy Gateway Transmission Program Planning As discussed in the 2017 IRP, the Energy Gateway transmission project continues to play an important role in PacifiCorp's commitment to provide safe, reliable, reasonably priced electricity to meet the needs of our customers. Energy Gateway's design and extensive footprint provides needed system reliability improvements and supports the development of a diverse range of cost- effective resources required for meeting customers' energy needs. The IRP has incorporated Energy Gateway as part of a solution for delivering the least cost resource portfolio for multiple IRP planning cycles. PacifiCorp continues to develop methods, in parallel with current industry best practices and regional transmission planning requirements, to better quantify all the benefits of transmission that are essential to serve customers. For example, Energy Gateway is designed to relieve operating limitations, increase capacity, and improve operations and reliability in the existing electric transmission grid. Figure 3.1 shows a high-level geography of the Energy Gateway transmission proj ect. l8 PecrrConr - 2017 IRP Upoars CuapTpn 3 -Tup, PLANNTNG ENVIRoNMENT Figure 3.1 - Energy Gateway Map I'VAgHliltrTOH Energy Gateway Wallulr HONTANA ?tWYOFIIHC coLotADo OEEG(}H IDAHO Crrtia lxhl CALI TORH IA Crdrr N EYA DT Sigirdl P{ur te f od Buua/ Af,IZONA HEW I.tEXtCO Energy Gateway Transmission Project Updates Wallula to McNary (Segment A) This project meets the requirements under PacifiCorp's Open Access Transmission Tariff to provide transmission service to a point-to-point transmission customer when the existing transmission system does not have the capacity to serve the need. In addition, this project is needed to improve reliability and support future resource growth. These requirements will continue to drive the project forward. The OPUC issued a Certificate of Public Convenience and Necessity (CPCN) in September 2011. Local, state and federal permitting is complete and the majority of private rights of way have been acquired. The next steps will be completion of all detailed design, issuing the construction contract and completing construction. The project is on-track to complete permitting efforts and construction for a 2018 in-service date. Pa.illcorp r€6ll rervlcs ar€e New tl?nsmlsrlon llner: - 500 kV mtnlmum volEge - :145 kv mhtrnum YolEga * 130 kV mtntmum yolEge a E(lrang rubdalon O NGrv rubcEtton l9 This map is for general reference only and reflects current plans. It may not reflect the final routes, construction sequence or exact line configuration. PectptConp -2017 IRP UpoerE CHAPTER 3 THa PLANNTNG ENvInONUeNT Gateway West (Segments D and E) Under the National Environmental Policy Act (NEPA), the U.S. Bureau of Land Management (BLM) has completed the environmental impact statement (EIS) for the Gateway West project. The BLM released its final EIS on April26,2013, followed by the record of decision (ROD) on November 14, 2013, providing a right-of-way grant for all of Segment D and part of Segment E as discussed below: Gateway West (Segment Dl): A single-circuit230 kV line that will run approximately 75 miles between the existing Windstar substation in eastem Wyoming and the planned Aeolus substation near Medicine Bow, Wyoming. Gateway West (Segment D2): A single-circuit 500 kV line running approximately 140 miles from the planned Aeolus substation to a new annex substation (Anticline) near the existing Bridger substation in western Wyoming; and a single-circuit 230 kV line running approximately 14 miles from the Shirley Basin substation near Medicine Bow to the planned Aeolus substation, also near Medicine Bow; and a single-circuit 345 kV line running approximately five miles from the planned Anticline substation near Point of Rocks, Wyoming, to the existing Jim Bridger substation. PacifiCorp received a conditional CPCN from the Wyoming Public Service Commission on April 12,2018. a Gateway West (Segment D3): A single-circuit 500 kV line running approximately 200 miles between the new annex substation (Anticline) and the Populus substation in southeast Idaho. Gateway West (Segment E) The BLM released its final EIS April 26, 2073, followed by the ROD November 14, 2013, providing a right-of-way grant for most of the project. The agency chose to defer its decision on the western-most portion of the project located in Idaho in order to perform additional review of the Morley Nelson Snake River Birds of Prey Conservation Area. In September 2014, the BLM announced their intent to conduct a supplemental EIS for the final two segments. A draft supplemental EIS was published in March 2016 and a frnal ROD was issued January 19,2017. On April 17, 2017 the Interior Board of Land Appeals remanded the January 2017 ROD back to BLM for reconsideration. In response to a request from Idaho Govemor Otter to the Secretary of the lnterior, the January 2017 ROD for the Gateway West project was officially rescinded and remanded back to the BLM Idaho State Office for further consideration. President Trump signed the Fiscal Year 2017 Consolidated Appropriations Act into law in May 2017, which included an agreement to route segments 8 and 9 of the Gateway West Transmission Line Project through the Morley Nelson Snake River Birds of Prey National Conservation Area (NCA). House Resolution 2 I 04 directs the Secretary of Interior to grant right of way for the route (Alternative I ) through the NCA. The BLM published the final environmental assessment for segments 8 and 9 on January 5, 2018. The ROD for segments 8 and 9 was approved on April 19,2018. a 20 PncrFrConp -2011 IRP UPDATE CIIAP'IIIR 3 TI III PI,ANNIN(i ENVIRoNMIjN I Gateway South (Segment F) The BLM published its Notice of Intent in the Federal Register in April 201l, followed by public scoping meetings throughout the project area. Comments on this project from agencies and other interested stakeholders were considered as the BLM developed the draft EIS, which was issued in February 2014. A ROD was issued by the BLM in January 2017 , and by the U.S. Forest Service in May 2017. PacifiCorp will continue to assess construction timing to best meet customer and system needs. PacifiCorp continues to work with the federal agencies on meeting notice-to- proceed requirements. Boardman to Hemingway (Segment H) Energy Gateway Segment H represents a significant improvement in the connection between PacifiCorp's east and west control areas and will help deliver more diverse resources to serve its customers in Oregon, Washington and Califomia. Idaho Power leads the permitting efforts on this project and PacifiCorp continues to support the permitting efforts under the conditions of the Boardman to Hemingway Transmission Project Joint Permit Funding Agreement. The Bureau of Land Management's Record of Decision was issued in November of 2017, this will be followed by the U.S. forest Service Record of Decision and the Oregon Energy Facilities Siting Council's final order on the Site Certificate. In-Service Dates Table 3.1 summarizes the in-service dates for segments of the Energy Gateway transmission project. 2t Segment & Name Description Approximate Mileage Status and Scheduled In Service (A) Wallula-McNary 230 kV, single circuit 30 mi . Status: local permitting completedr Scheduled in service: 20 I 8, sponsor driven (B) Populus-Terminal 345 kV. double circuit 135 mi o Placed in service: November 2010 (c) Mona-Oquirrh 500 kV single circuit 345 kV double circuit 100 mi o Placed in service: May 20 l3 Oquirrh-Terminal 345 kV double circuit l4 mi . Status: rights-of-way acquisition underway o Scheduled in-service: 2021 (D1) Windstar-Aeolus New 230 kV single circuit Re-built 230 kV single circuit 75 mi . Status: permitting continues o Scheduled in-service: 2019-2024 (D2) Aeolus- Bridger/Anticline 500 kV single circuit 140 mi . Status: permitting continues o Conditional CPCN received April 2018r Rights-of-way acquisition underwayr Scheduled in-service: 2020 (D3) Bridger/Anticline- Populus 500 kV single circuit 200 mi . Status: permitting continues o Scheduled in-service: 2020-2024 (E) Populus-Hemingway 500 kV single circuit 500 mi . Status: permitting continues o Scheduled in service:2020-2024 (F) Aeolus-Mona 500 kV single circuit 400 mi o Status: permitting contlnues. Scheduled in service:2020-2024 (G) Sigurd-Red Butte 345 kV single circuit 170 mi o Placed in service: May 2015 (H) Boardman- Hemingway 500 kV single circuit 500 mi . Status: pursuing joint-development and/or firm capacity opportunities with project sponsors o Scheduled in service: sponsor driven PactprConp 20 lT lRP UPDATE CHAPTER 3 -THE PLANNING ENVIRONMENT Table 3.1- E t In-Service Dates Energy Imbalance Market PacifiCorp and the California Independent System Operator (CAISO) launched the energy- imbalance market (EIM) November 1,2014. The EIM is a voluntary market and the first western energy market outside of California. The EIM provides for more efficient dispatch of participating resources in real-time through an automated system that dispatches generation across the EIM footprint, which cuffently includes PacifiCorp, NV Energy, Puget Sound Energy, Arizona Public Service, Portland General Electric, Idaho Power Company, Powerex, and the CAISO balancing authority areas (collectively, EIM Area). Entities scheduled to join the EIM include the Balancing Authority of Northem Califomia (April 2019), Seattle City Light (April 2020), Los Angeles Dept. of Water and Power (April 2020), and Salt River Project (April 2020). CENACE Baja California is investigating future entry into the market. PacifiCorp continues to work with the CAISO, existing and prospective EIM entities, and stakeholders to enhance market functionality and support market growth. 22 Cueprpn 4 - LoaD-AND-RpsouRCE Baraxcn, Upoarp This chapter presents an update to PacifiCorp's load-and-resource balance. Updates to PacifiCorp's long-term load forecasts (both energy and coincident peak load) for each state and the system as a whole are summarized in the Appendix. Updates to PacifiCorp's load forecast, resources, and capacity position are presented and summarized in this chapter. The2017 IRP Update relies on PacifiCorp's August20lT load forecast. Figure 4.1 compares PacifiCorp's most recent load forecast to the forecast used for the 2017 IRP. Figure 4.2 compares PacifiCorp's most recent coincident system peak load forecast to the forecast used for the 2017 IRP. Considering that PacifiCorp analyzes incremental energy efficiency and direct-load control programs as demand-side resource options in its IRP, both figures exclude incremental energy efficiency savings and direct-load control capacity included in the updated resource portfolio. The compounded average annual gowth rate (CAGR) for system load is 0.55 percent over the period 2018 through2027. The CAGR for system coincident peak is 0.54 percent over the period 2018 through 2027. 4.1- Forecasted Annual Load 68,000 66,000 64,000 62,000 60,000 56,000 54,000 52,000 50,000 ,.t. ff dP" ""Pt ,O ,S ,{F ,of ,"t ,$ -- .-rF2otT tRp +2017lRP Update PaCmICoRr _2017 IRP UPDATE CHAPTER 4 _ LOAD-AND-RESoURCE BALANCE UPDATE 23 Introduction System Coincident Peak Load Forecast PACIFICoRP - 20 I7 IRP UPDATE CHarrsn 4 - Loao-eNn-RESoURCE BeLeNcs UPDATE 4.2 - Forecasted Annual Coincident Peak Load Table 4.1 and Table 4.2 summarize the capacity from wind and solar power-purchase agreements (PPAs) with qualifying facilities (QFs) that have or are expected to come online over the 2017 - 2021time frame assumed in the 2017 IRP Update compared to the 2017 IRP. Table 4.1 - Qualifying Facility Wind PPAs ,-^ -- ".t. ,.,r}t "{,," "{| "NP ,sP "s} ,of "s,t ,$ I 1,s00 I1,000 10,500 10,000 9,000 -(F20l7lRP +-2017lRP Update 9,500 WY t7 J t7 JCasper Wind (Chevron) IChopinWAl01l0 239 38Everpower(r)WY Foote Creek II WY 2 0 2 0 4Foote Creek III WY 25 4 25 9 60 9Latigo Wind UT 60 Mariah Wind OR l0 I 10 I 40 6Meadow Creek Project - Five Pine ID 40 6 24 Wind and Solar Qualifying Facility Resource Updates 2017IRP Preferred Portfolio 2017IRP Update Qualifying Facilities State Capacity (M\Y) L&R Balance Capacity at System Peak (M!v) Capacity (Mw) L&R Balance Capacity at System Peak (Mrv) PaCIpICOnp _2017 IRP UPDATE Cna.prEn 4 - Loao-aNo-RESoURCE BALANCE UpDATT (1) New since the 2017 IRP Table 4.2 - Qualifying Facility Solar PPAs 2017 IRP Preferred Portfolio 20l7IRP Update Qualifying Facilities Meadow Creek Project - North Point State ID Capacity (Mw) 80 L&R Balance Capacity at System Peak (Mw) l3 Capacity (Mw) 80 L&R Balance Capacity at System Peak (Mw) 13 Monticello Wind (')UT 79 13 Mountain Wind Power I WY 61 l0 6l 10 Mountain Wind Power II WY 80 l3 80 l3 Orchard Wind WA 40 5 40 5 Oregon Wind Farms I & II OR 65 8 65 8 Orem Family Wind OR l0 I l0 I Pioneer Wind Park I WY 80 13 80 13 Power County Wind Park North ID Z)4 23 4 Power County Wind Park South ID ./.)4 23 4 Spanish Fork Wind Park2 UT 19 -J t9 J Three Mile Canyon WA l0 I l0 I Tooele Army Depot t't UT J 0 Small Wind WY 0.2 0 0.2 0 TOTAL - Purchased Wind 6s4 97 975 148 2017 IRP Preferred Portfolio 2017IRP Update Qualifying Facilities State Capacity (Mw) L&R Balance Capacity at System Peak (MW) Capacity (Mw) L&R Balance Capacity at System Peak (Mw) Adams Solar Center OR l0 6 l0 6 Bear Creek Solar Center OR 10 6 l0 6 BeattY Solar(3)OR 5 3 Beryl Solar UT J I J I Black Cap Solar II OR 8 5 8 5 Bly Solar Center OR 9 6 9 6 Buckhorn Solar UT J I J I Cedar Valley Solar UT 3 I 3 I Chiloquin Solar OR l0 5 10 5 Collier Solar OR l0 6 l0 6 25 PACIFICoRP _2017 IRP UPDATE CHApIE,R 4 - Lono-a,No-REsouncp, Be,leNce Uppern Elbe Solar Center OR l0 6 l0 6 Enterprise Solar UT 80 47 80 47 Escalante Solar I UT 80 47 80 47 Escalante Solar II UT 80 47 80 47 Escalante Solar Ill UT 80 47 80 47 Ewauna Solar OR I I I I Ewauna Solar 2 OR 3 2 J 2 SunE Solar XVII Proiect 1 - 3 (2)UT 9 5 9 5 Granite Mountain - East UT 80 47 80 47 Granite Mountain - West UT 50 30 50 30 Granite Peak Solar UT J 1 )1 2 I 2 IGreenville Solar UT Iron Springs UT 80 47 80 47 Ivory Pine Solar OR 10 6 l0 6 Laho Solar UT J I 3 I Merrill Solar OR l0 l0 6 Milford Flat Solar UT J 2 J 2 IMilford Solar 2 UT J I J Norwest Energy 2 (Neff)OR l0 6 l0 6 Norwest Energy 4 (Bonanza)OR 6 4 6 4 6Norwest Energy 7 (Eagle Point)OR 10 6 l0 Norwest Energy 9 Pendleton OR 6 3 6 J OR Solar 2, LLC (Agate Bay)OR 10 6 l0 6 OR Solar 3, LLC (Turkey Hill)OR 10 6 10 6 8 5OR Solar 5, LLC (Merrill)OR 8 5 OR Solar 6, LLC (Lakeview)OR 10 6 l0 6 OR Solar 7, LLC (Jacksonville)OR r0 6 l0 6 OR Solar 8, LLC (Dairy)OR l0 6 l0 6 Pavant Solar UT 50 29 50 29 Pavant Solar II LLC UT 50 30 50 30 Pavant Solar III LLC UT 20 12 20 12 5Quichapa Solar l- 3 UT 9 5 9 Sage I Solar (r)WY 20 8 Sage II Solar tr)WY 20 8 Sage III Solar trr WY 18 7 3 2South Milford Solar UT J 2 26 2017 IRP Preferred Portfolio 2017IRP Update Qualifying Facilities State Capacity (M!Y) L&R Balance Capacity at System Peak (MW) Capacity (Mw) L&R Balance Capacity at System Peak (Mw) 6 PaCIpIConp - 2017 IRP UPDATE CTTapTe,R 4 _ LoAD-AND-RESoURCE BALANCE UPDATE 2017 IRP Preferred Portfolio 2017lRP Update Qualifying Facilities State Capacity (Mw) L&R Balance Capacity at System Peak (MW) Capacity (Mw) L&R Balance Capacity at System Peak (Mw) Sprague River Solar OR 1 5 7 5 Sweetwater Solar WY 80 48 80 48 Three Peaks Solar UT 80 41 80 47 Tumbleweed Solar OR l0 5 10 5 Utah Red Hills Renewable Park UT 80 41 80 47 Woodline Solar OR 8 5 8 Small Solar UT I 0 I 0 TOTAL - Purchased Solar 1,145 679 1,197 699 ( I ) New since the 20 I 7 IRP (2) Formerly Fiddler's Canyon Solar l-3 (3) Contract terminated Updated Capacity Load-and-Resource Balance Load-and-Resource Balance Components Capacity and energy balances make use of the same load-and-resource components in their calculations. The main component categories consist of the following: resources, obligation, reseryes, system position, new Energy Vision 2020 wind, and available front-office transactions (FOTs). The resource categories include resources by type-thermal, hydroelectric, renewable, QFs, purchases, existing Class I demand-side management (DSM), sales, and non-owned reserves. Categories in the obligation section include load, private generation, intemrptible contracts, existing Class 2 DSM, and new Class 2 DSM from the updated resource portfolio. Both resources and obligations can be represented as either a positive or negative value, which is consistent with how these elements are represented in portfolio modeling. A description of each of the resource categories, including a description of variances from the summer load-and-resource balance in the 2017 IRP, is provided below. Existing Resources Thermal This category includes all thermal plants that are wholly owned or partially owned by PacifiCorp. The capacity balance counts thermal plants at maximum dependable capability at time of system summer or winter peak, as applicable. The energy balance also counts them at maximum dependable capability, but de-rates them for forced outages and maintenance. This includes the existing fleet of coal-fueled units, and six natural-gas-fueled plants. These thermal resources account for roughly two-thirds of the firm capacity available in the PacifiCorp system. lnthe2017 27 5 PacrprConp -2017 tRP UPDATE Cuaprsn 4 - Lono-aNn-RESoURCE BALANCE Upoarp, IRP Update, certain coal plants had small increases in the assumed capacity when compared to the 2017 IRP. These changes reflect a reduced level of parasitic load associated with installation of selective catalytic reduction systems, which results in a 16 MW increase in summer capacity relative to the 2017 IRP. Hydroelectric This category includes all hydroelectric generation resources in PacifiCorp's system, as well as a number of contracts providing capacity and energy from various counterparties. The capacity balance counts these resources by the maximum capability that is sustainable for one hour at the time of system summer peak, an approach consistent with current Western Electric Coordinating Council (WECC) capacity-reporting practices. The energy associated with stream flow is estimated and shaped by the hydroelectric dispatch from the Vista Decision Support System model. Also accounted for are energy impacts of hydro relicensing requirements, such as higher bypass flows that reduce generation. Over 90 percent of the hydroelectric capacity is on the west side of the PacifiCorp system. An updated hydro generation forecast reflects changes to the Umpqua River hydro facilities peak capacity projections with varying impacts in specific years throughout the planning period. Renewable This category includes geothermal and variable (wind and solar) renewable resource capacity. The capacity balance counts geothermal capacity at the maximum dependable capability while the energy balance counts the maximum dependable capability after forced outages. The capacity contribution of wind and solar resources, represented as a percentage of resource capacity, is a measure of the ability for these resources to reliably meet demand. PacifiCorp defines the peak capacity contribution of wind and solar resources as the availability among hours with the highest loss-of-load probability. PacifiCorp updated its capacity contribution values for solar and wind resources, differentiated byresource type and balancing authority area in the 20l7IRP and uses these same capacity-contributionvalues, as shown in Table 4.3 below, in the 2017IRP Update. PacifiCorp's wind repowering project results in a net two MW increase in peak capacity by 2021. 28 PactprConp -2017 IRP UPDATE CHaprpn 4 - LoAD-AND-REsounce BALANCE Upon'rs East Balancing Authority Area West Balancing Authority Area Wind Fixed Tilt Solar PV Single Axis Tracking Solar PV Wind Fixed Tilt Solar PV Single Axis Tracking Solar PV Capacity Contribution Percentage 15.8%37.gyo 59.7%ll.8Yo s3.9%64.8% Table 4.3 - Summer Peak C Contribution Values for Wind and Solar Purchases This includes all major purchase contracts for firm capacity and energy in the PacifiCorp system.l The capacity balance counts these by the maximum contract availability at the time of system summer peak. The energy balance counts contracts at optimal economic model dispatch. Purchases are considered firm and thus planning reserves are not held for them. There were no changes in purchases from what was assumed in the 2017 IRP. Oualifyine Facilities All QFs that provide capacity and energy are included in this category. Like other purchases, the capacity balance counts non-wind and non-solar QFs at maximum system summer peak availability. The capacity balance counts wind and solar QFs using the assumed capacity- contribution values summarized in Table 4.3 above. The energy balance counts QFs at expected generation levels. By 2022, the addition of incremental wind and solar QF contracts increases system capacity at the time of peak load by 7l MW. Other QF contracts increase the capacity at the time of peak load by an additional six MW. Disoatchable Load (Class I DSM) Existing dispatchable load control program capacity is categorized as an increase to resource capacity. This is in line with the treatment of DSM capacity in the latest version of the System Optimizer model that PacifiCorp uses to select resources. There were no changes in Class I DSM from what was assumed in the 2017 lRP. Sales This includes all contracts for the sale of firm capacity and energy. The capacity balance counts these contracts by the maximum obligation at time of system summer peak and the energy balance counts them by expected model dispatch. All sales contracts are firm and thus planning reserves are held for them when accounting for these contracts in the capacity balance. There were no changes in sales from what was assumed in the 2017 IRP. Non-owned Reserves Non-owned reserve capacity is categorized as a decrease to resource capacity to represent the capacity required to provide reserves as a balancing authority for load and generation that are in PacifiCorp's balancing authority area (BAA) but not owned by PacifiCorp. There are a number of counterparties that operate in PacifiCorp control areas that purchase operating reserves. The annual reserve obligation is about 3 MW and 38 MW on the west and east BAAs, respectively. The non- owned reserves do not contribute to the energy obligation because this requirement is for capacity only. The non-owned reserves were updated in the 2017 IRP Update resulting in a small, three- MW decrease relative to the 2017 IRP. ' PacifiCorp has curtailment contracts for approximately 172 MW on peak capacity that are treated as firm purchases. PacifiCorp has the right to curtail a customer's load as needed for economic purposes. The customer in tum may or may not pay market-based rates for energy used during a curtailment period. 29 Obligation The obligation is the total electricity demand that PacifiCorp must serve, consisting of forecasted retail load less private generation, existing Class 2 DSM, new Class 2 DSM from the preferred portfolio, and intemrptible contracts. A description of each of these obligation categories, including a description of variances from the summer load-and-resource balance in the 2017 IRP, is provided below. Load and Private Generation The largest component of the obligation is retail load. In the 2017 IRP, the hourly retail load at a location is first reduced by hourly private generation at the same location. The system coincident peak is determined by summing the net loads for all locations (topology bubbles with loads) and then finding the highest hourly system load by year. Loads reported by east and west BAAs reflect loads at the time of PacifiCorp's coincident system summer peak. The energy balance counts the load on a monthly basis by on-peak and off-peak hours. Summer peak loads net of private generation are lower in the 2017 IRP Update than in the 2017 IRP. PacifiCorp's2017 IRP Update load forecast was finalized in August 2017. Relative to the load forecast prepared for the 2017 IRP, PacifiCorp system sales decrease over the planning period. While economic conditions continue to improve following the most recent recession, a less favorable outlook for select industrial customers results in lower sales projections relative to the 2017 IRP. Further, the2017 IRP Update forecast projects that residential customers are likely to use more efficient appliances, which results in a lower residential forecast relative to the 2017 IRP load forecast. Furthermore, the 2017 IRP Update incorporates a methodological update for the treatment of private generation and how it affects the coincident peak. In previous IRPs, the load forecast summed the hourly output for seven different private-generation sources to produce the hourly private-generation shape within each state. For the 2017 IRP Update, since a high percentage of forecasted private generation is solar (>90yo), a more appropriate methodology was adopted to weight the seven individual private-generation sources by annual capacity. This improvement to the methodology results in better alignment of solar occurring at the time of coincident peak than was identified when using the prior, unweighted approach. Class 2 DSM An adjustment is made to load to remove the projected embedded Class 2 DSM as a reduction to load. Due to timing issues with the vintage of the load forecast, there was a level of 2016 Class 2 DSM that was not incorporated in the forecast for the 2017 IRP. The 2016 Class 2 DSM forecast of 100 MW was accounted for by adding an existing Class 2 DSM resource in the load-and- resource balance; this adjustment was not required for the 2017 IRP Update because the 2016 projected embedded Class 2 DSM is included in the load forecast. The DSM line also includes the selected Class 2 DSM from the 2017 IRP Update resource portfolio, which, consistent with a reduction in overall load, results in a decrease in incremental Class 2 DSM totaling 77 MW by 2027 when compared to the 2017 IRP. 30 PacIrICOnp - 20I7 IRP UPDATE CHAPTER 4 - LOAD-AND-RESOUNCE BALANCE UPNRTP PeCIpICoRT - 20I 7 IRP UPDATE CHapren 4 - Loap-nNo-R-esouRcs BeleucE Upoa.rs Intemrptible Contracts PacifiCorp has intemrptible contracts for approximately 195 MW of load intemrption capability. These contracts allow the use of 195 MW of capacity for meeting reserve requirements. Both the capacity balance and energy balance count these resources at the level of full load intemrption available. Intemrptible resources directly curtail load and thus full planning reserves are not held for the load that may be curtailed. As with Class I DSM, this resource is categorized as a decrease to the peak load. There were no changes in intemrptible contracts from what was assumed in the 20l7IRP. Planning Reserves Planning reserves represent an incremental planning requirement, applied as an increase to the obligation to ensure that there will be sufficient capacity available on the system to manage uncertain events (i.e., weather, outages, variable resources) and known requirements (i.e., operating reserves). System Position The system position is the resource surplus or deficit after subtracting obligation plus required reserves from total resources. While similar, the system position calculation is slightly different for capacity and energy. Thus, the position calculation for each of these balances are presented in their respective sections later in this chapter. Energy Vision 2020 Wind For the 2017 IRP Update, PacifiCorp has incorporated capacity from the new Energy Vision 2020 wind projects as a separate line item starting in 2021. While these projects are undergoing a regulatory review and approval processes, the capacity contribution associated with these wind resources, and their associated impact on the system position, is provided for informational purposes. Available FOTs As is the case with Energy Vision 2020 wind resources, PacifiCorp also shows available capacity from uncommitted FOT resources. These resources are shown as the amount of uncommitted FOTs that could be used to satisfy any remaining short system capacity position (after accounting for the capacity contribution from Energy Vision 2020 wind resources) up to the maximum level of FOT procurement assumed available for planning purposes. As is the case with Energy Vision 2020 wind resources, these data are shown for informational purposes. Any resource that is lower cost and lower risk can displace FOTs when selecting resources in the preferred portfolio. Capacity Balance Determination and Results Methodology The system position, which represents the projected capacity need, nets existing resources against the projected obligation while accounting for planning reserves. The basic formulae used to establish the system position are summarized below. 3l PACIF.IC0RP - 20 I 7 IRP UPDATE CsaprEn 4 - LoAD-AND-RrsouRcp BALANCE UpDATE Existing Resources: Thermal + Hydro * Renewable + Firm Purchases + Qualifying Facilities + Existing Class I DSM - Firm Sales - Non-owned Reserves The peak load, intemrptible contracts, existing Class 2 DSM, and new Class 2 DSM from the preferred portfolio are netted together for each of the annual system summer and winter peaks, as applicable, to compute the annual peak obligation: Obligation: Load - Intemrptible Contracts - New and Existing Class 2 DSM The amount of reserves to be added to the obligation is then calculated. This is accomplished by the net system obligation calculated above multiplied by the l3 percent target planning reserve margin (PRM) adopted for the 2017 IRP. The formula for this calculation is: Planning Reserves: Obligation x PRM The annual system capacity position is derived by adding the computed reserves to the obligation, and then subtracting this amount from existing resources as shown in the following formula: System Capacity Position: (Existing Resources) - (Obligation * Reserves) Informational Calculations As discussed above, for informational purposes, PacifiCorp has also shown how the system capacity position is affected by Energy Vision 2020 wind resources: System Position with New Energlt Vision 2020 ltind: (System Capacity Position) + (New EV 2020 Wind) Similarly, and also for informational purposes, PacifiCorp also shows how the potential acquisition of uncommitted FOTs could be used, if lower cost and lower risk than other resource alternatives, to meet any remaining system capacity shortfall: Net Surplus (Deficit) : (System Position with New Energy Vision 2020 Wind) + (Uncommitted FOT's to meet remaining Need) "Uncommitted FOT's to meet remaining Need" refers to that portion of available FOT's that could be used to meet any remaining capacity deficit calculated in the "System Position wAllew EV 2020 Wind" calculation without exceeding the maximum level of FOT procurement assumed available for planning purposes. Figure 4.3 summarizes the 2017 IRP Update capacity load-and-resource balance, prior to acquiring any new resources and making firm market purchases, alongside the load-and-resource balance from the 2017 IRP. Before accounting for Energy Vision 2020 wind resources and uncommitted FOTs, PacifiCorp shows a capacity deficit beginning 2018. This deficit is lower, on average, than in the 2017 IRP by approximately 408 MW over the 2018-2027 time frame due in large part to the decreased load forecast net ofprivate generation. 32 PeCmrConp - 20 I 7 IRP UPDATE CHAPTER 4 - LOAD-AND-RESoURCE BALANCE UpoeTT, r:OlTlRP , 201 7 tRP Update 20 llt 20le l(r20 l0tl 202(;2\)27 o (2o0) (4OO) ( r,0oo) ( l,20o) ( r,4oo) 2023 20:.1 2025 (600) ( 80o) 201 I 4.3 - Summer Position Co Chart Table 4.4 through Table 4.7 present the capacity load-and-resource balance details from the 2017 IRP Update and the 2017 IRP for the summer and winter peak. The load-and-resource balance tables show the system position before Energy Vision 2020 wind resources and uncommitted FOTs. Line-item differences between the 2017 IRP and2017 IRP Update are shown in Table 4.8 and Table 4.9. JJ Pe.Cm,rCOnp - 20 I 7 IRP UPDATE Cuaprsn 4 - LoAD-AND-RESoURCE BALANCE UpDATE Table 4.4 - Summer Peak - System Capacity Load and Resource Balance without Resource Additions, 20 I 7 I RP Update (2018-2027) (Megawatts)2 ClalendarYear 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 First Theml Hydroelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-Omed Reserues Fas t Fxis ti ng Resources tlad Private Ceneration lntemptible DSM East oHigation Planning Resenes (13%) East OHigation + Reserres East Position AwilaHe Front Oflice Transactions 6,403 t07 t96 249 @8 323 (65s) (15) 7236 6,t23 l14 t94 249 691 323 (65s) (35) 7,004 6,91 I ( 166) ( le5) (l7r) 6378 855 6,t23 rt4 199 249 743 323 (655) (35) 7,061 5,736 l14 197 221 735 (175) (3s) 7,117 5,736 l4 190 221 738 323 (t75) (15 ) 7,112 7,n5 (220) ( le5) (l le) 6382 855 5,736 ll4 190 22t 734 323 (t75) (15 ) 7,1 08 5,736 93 190 221 679 323 ( 148) (3s) 7,061 5,736 93 lm t2t 674 323 (t48) (15) 6,955 5,654 93 180 t2l 670 323 (66) (35) 6,941 5,654 93 180 t2l 666 323 (66) (15) 6,937 7,365 (169) ( 195) (5s5) 6,346 6,853 ( 108) ( 195) ( ll8) 6,432 862 6,972 ( 20:) ( 195) €16) 6)49 851 7,200 ( l -19) 318 7,041 (213) (le5) 1273\ 6360 852 7,254 (l{6) 318 7 ?{q (214) (r95) (1 l0) 6,421 7,281 (220) 318 7,321 (?42) (195) (460) 6424 7,322 (252\ ( res) (50e) 636s 857 860 860 853 850 7,294 (sn) 318 7,233 (22e) 318 7,212 (es) 318 7284 (32e) 318 7,218 (277) 318 7,196 (260) 318 7236 (12{) 318 West Thennal Hydroelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-Onned Reserues West kisting Resources had Private Crnemtion Intemptible DSM West oUigation Planning Reserues ( I 3olo) West OHigation + Reserws West Position AuilaHe Front Office Transactions 2,254 861 m l8 235 J ( l6s) (3) 3294 3,238 ( t3) 0 (G) 3,161 2,254 747 88 I 220 3 1165) (l) 3,146 3,279 ( l9) 0 ( 9-1) 3,166 ') )\l 7q) 95 I 227 J ( l6s) (3) 3,203 2,254 &3 95 I 203 0 (r6l ) (3) 3,034 3,312 (31 ) 0 (1.14) 3,137 3,545 (51l) I,352 2,254 587 65 I 194 0 (lr0) (l) 2,988 2,254 624 65 I 187 0 (l r0) (l) 3,018 3,351 (42) 0 (l8l) 3,129 407 2,254 655 60 I 185 0 (80) (l) 3,072 3,366 (48) 0 ( le8) 3,120 406 3,526 ({s3) t,352 2,254 655 60 I 184 0 (80) (3) 3,072 ) )\4 645 59 I 182 0 ( 80) (j) 3,058 ) )\t 658 58 I 150 0 (80) (3) 3,039 3,572 (21e1 13s2 3,578 ({-12 ) r,352 3,293 (2s ) 0 (lll) 3,t46 3,554 (3sl) l3s2 3,331 (37) 0 ( l6l) 3,132 3,539 (ssr) r 3s2 3,535 (sl8) l Js2 3,395 (55) 0 (2 r4) 3,126 406 3,533 (.16 r ) 1352 3,4t5 (63) 0 (228) 3,124 3,s30 (1721 1352 3,436 (71) 0 (lll) 3,123 3,529 ({e0) l3s2 4ll 412 4W 408 407 406 406 System Total Resources OHigation Reserws OHigation + ReserEs System P6ition New Dr'2020 Wind System Pcition w/ NewWind AmilaUe Front OII!ce Transactions Uncommited FOT's to meet remaining Need Net Surflus (Deficit) 10,530 9.594 1,273 10,867 (137) 0 (337) I,670 337 0 10,150 9,544 t,266 10,81 I (661 ) 0 (66r ) 1,670 661 0 10,264 9,495 t.260 10,755 (.190) 0 (.190) t,670 490 0 10,15 I 9,497 1,260 10,757 (606) 207 (399) 1,670 399 0 l0,l0l 9,5 t3 1,262 10,775 (675) 207 (,168) 1,670 468 0 10,126 9,526 1,2@ 10,790 (6il) 207 (.157) 1,670 457 0 10,t33 9,541 1,26 r0,807 (674) 207 (467) 1,670 467 0 t0,u7 9,550 1,267 10,8 l7 (7e0) 207 (583) 1,670 583 0 9,999 9,490 t,259 10,749 (7.1e) 1,670 542 0 9,976 9,469 t,256 t0,725 (750) 1,670 543 0 207 (512) 207 (s-li) 2 The DSM line includes selected Class 2 DSM from the 2017 IRP Update resource portfolio. 34 7,183 12261 ( le5) ( 365) 63e7 PACIFICoRP - 20 17 IRP UPDATE CHApTER 4 - Lono-aNo-RESoURCE BRleNcs Upoere Table 4.4 (cont.) - Summer Peak - System Capacity Load and Resource Balance without Resource Additions, 201 7 IRP Update (2028-2036) (Megawatts)3 C-alendarYear 2028 2029 2030 2031 2032 2033 2034 2035 2036 Fast Theml Hydroelectric Renewab le Purchases Quali$ing Facilities Class I DSM Sales Non0wned Reserues li'lst Fxisting Resources toad Private Genemtion Interruptible DSM Fast oHigation Planning Resewes (13%) Fist Obligation + Reserws Fast Position AlailaUe Front OfIice Trans actions 4,892 93 180 121 662 323 (66) (35) 6,171 7,445 (288) ( le5) (602) 6"360 4,892 93 180 t2l 655 323 (66) (35) 6,t64 4,459 93 t26 t2t &8 323 0 (15) 5,736 4,459 93 126 t2l 637 323 0 (35) 5,725 7,ffi (261) (res) (771\ 6,413 4,102 93 t26 t2l s89 323 0 (35) s32O 7,789 (308) (l9s) ( rJ35) 6Asr 4,021 93 126 121 584 323 0 (35) s234 7,872 (333) (le5) (863) 6,481 868 4,Ul 93 126 t2l 532 323 0 (-15) 5,182 7,953 (354) (tes) (8e2) 6,512 872 7 384 (2,20f) 318 4,102 93 126 t2l 60s )25 0 (3s ) s337 4,53s 93 158 t2t 652 323 (66) (35) 5,782 852 855 7,521 (l0l ) (195) (645) 6378 7,601 (324) ( r95) (690) 6J93 7,249 (t,467) 3r8 7,543 (236) (re5) (734) 6J78 7 232 (r,4e6) 318 7.716 (284) (re5) (tt05) 6432 856 854 8s9 862 8@ 7 213 (l,042) 318 7,233 (r,068) 3r8 7,294 ( 1,957 ) 318 7 349 (2,1 l 6) 318 7,272 ( r ,s47) 318 73rs ( l,99s) 318 West Thernnl Hydroelectric Renewable Purchases Quali&ing Facilities Class I DSM Sales Non-Owned Reserues West Eristing Resources Load Private Generation lntemrptible DSM West oHigation Planning Reserues (l3o%) West Obligation + Reser\,€s West Position ArrailaHe Front Office Transactions 1,541 653 53 I 96 0 (78) (3) 2264 2,2s4 l,9m 1,900 653 653 6s3 55 54 54 lll t49 138 133 000 (80) (78) (78) (3) (3) (3) 3,030 2,666 2,660 1,900 653 53 I t32 0 (7li ) (3) 2,659 1,900 6s3 53 I 99 0 (7n) (3) 2,626 3,532 (80) 0 rlOlr 3,149 449 3,559 (e33) t3s2 1,541 6s3 53 I 97 0 (78) (3) 226s 1,541 6s3 53 I 97 0 (78) (3) 2264 3,575 ( r00) 0 (322) 3,1s2 3,s62 (r,2e8) t3s2 1,541 653 53 I 94 0 (24) (3) 2316 3,4s7 (78) 0 (2ss) 3,124 q6 3,530 (s00) t)52 3,s03 (86) 0 (268) 3,150 410 3,560 (894) t3s2 3,495 (e3) 0 (280) 3,122 3,528 (867) r,352 3,5 l3 (72) 0 (2er) 3,150 3,559 (e00) t3s2 3,554 (8e) 0 (3 r3) 3,152 3,s62 (1,297) 3,620 (lll) 0 (332\ 3,176 3,589 (t J2s) t3s2 3,6t2 (t221 0 (342) 3,149 409 3,558 (1,2.r2) 1352 406 409 410 4to 413 tem Total Resources OHigation Reserrts Ouigation + Reserws System Pmition Newf,V2020 Wind System Position il NewWind ArailaHe Front OIIIce Trans actions Uncommited FOT's to meet remining Need Net Surflus (Deficit) 9,201 9,4U 1,258 10,743 (r,s42\ 2U ( 1,335) 1,670 1,335 0 8,830 9,s28 t,2g 1o,792 ( I,962) 207 ( l,7ss) 1,670 t,670 (ri6) 8,442 9,514 t,262 to,777 (2.334) 207 (2.127\ t,670 1,670 (.ls8) 8,395 9,527 1,2& lo,79l (2,396) 207 (2, l 8e) 1,670 |,670 (sle) 8,35 I 9,5O r,268 10,83 l (2,480) 207 12.273\ 1,670 t,670 (601) 7,602 q 5R5 1,27t 10,856 (3,254) 207 (3,M7) 1,670 1,670 ( I.378) 7,585 9,603 t,274 10,877 (3,293) 207 (3,0rJs) 7,497 9,658 1,281 10,938 (3,441) 207 (3,234) 1,670 1.670 ( r.564) 7,497 9,661 1,281 10.943 (3,lu5) 207 (3,23n) r,670 1,670 ( l..ll6) 1,670 t,670 ( 1.s69) 3 The DSM line includes selected Class 2 DSM from the 2017 IRP Update resource portfolio. 35 PACIFICORP _2017 IRP UPDATE CHeprsn 4 - Loeo-eNn-Rrsouncs BALANCE UpDATE Table 4.5 - Winter Peak - System Capacity Load and Resource Balance without Resource Additions,2017 IRP Update (2018-2027) (Megawatts) a CalendarYear 2018 2019 2020 2O2l 2022 2023 2021 2025 2026 2027 ['qs f Thernal Hydroelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-Owned Reserves Fqqt Bdsting Resources toad Private Cenemtion Intemptible DSM East oHigation Planning Reserues (13%) East OHigation + Reserws East Pmition AuilaHe Front Ollice Transactions 6513 72 t% 734 691 0 (173) (3s) 7,998 6,233 72 t99 734 742 0 (173) (35) 7,772 5 5qO (0) (le5) (84) sSrr 6,233 72 197 734 740 0 (173) r l5r 7,768 5,U6 72 190 235 745 0 (173) (35 ) 6,879 5,U6 72 190 235 736 0 (l7j) (ls) 6,870 5,846 72 lm 23s 682 0 (r7l) (3s) 6,816 5,846 72 lm l2l 6'78 0 ( r.l8) 1.r5) 6,723 5,846 72 lm t21 673 0 ( l;18) (35) 6,714 5,763 72 180 t2t @ 0 (66) (35) 6,700 5,763 72 180 tzt 658 0 (66) (35) 6,703 5,560 (0) (les) (56) s3r0 6,025 1,973 318 5,629 (0) (tes) (il r) s323 6,04t 1,727 318 5,69 (0) (re5) ( r.+7) 5328 6,045 8-1.1 3l ti 5,730 (0) (le5) (lni) 5J52 5,785 (0) ( r95) (2ltt) 5372 724 6,096 720 318 5,823 (0) (re5) (253) 5375 6,099 625 318 5,804 (0) (le5) (328) s,280 5,992 7tt 318 5,825 (0) (les) (363) s267 5,977 723 318 5,877 (0) ( re5) (2er) 5392 716 716 7t7 718 721 724 726 712 7tO 6,026 1,716 3r8 6,073 797 3l8 6,1 l8 600 318 West Therrnal Hydroelectric Renewable Purchases QualiSing Facilities Class I DSM Sales Non-Omed Reserues West kisting Resources Inad Private C-€neration Intenuptible DSM West obligation Planning Reserves (13%) West Obligation + Reseres West Position AuilaHe Front OIIice Transactions 2,316 917 90 I 224 0 (162) (3) 3r83 2,316 943 95 I 211 0 ( 162) (3) 3,402 2,316 940 95 I n0 0 (ls4) (3) 3,415 785 95 I 195 0 (ls4) (3) 3,235 3,408 (0) 0 (ll0) 3,278 2,316 784 65 I 183 0 (r li) (3) 3,233 2,316 786 65 I t77 0 (l l3) (3) 3228 783 60 I t76 0 (81) (l) 325r 2,316 747 59 I 175 0 (81) (3) 3,253 3,498 (0) 0 (2r r) 3,247 427 3,714 (-16 l ) rJs2 2,3t62,316 2,3t6 2,316 784 794 58 56 l1 t7t 144 00 (81) (81) (3) (3) 3246 3227 3,342 0 0 l 55) 3,246 427 3,713 (3-10) 1,352 3,723 (321 ) t3s2 3,384 (0) 0 (l0s) 3,274 3,705 (2e0) t3s2 3,704 (468) rJs2 3,431 (0) 0 (ts2) 3,279 3,705 (.r7.1) t3s2 3,455 (0) 0 (17.i) 3,242 3,709 ({8l ) lJ52 3,473 (0) 0 ( le3) 3,280 426 3,707 ({s6 ) lJs2 3,521 (0) 0 (228) 3,293 428 3,721 ("17s) r3s2 3,547 (0) 0 (241) 3303 429 3,732 (s06) t3s2 3,376 (0) 0 (t3o) 3,295 428 426 426 126 427 System Total Resources OHigation Reserws OHigation + Reseres System Position New EV2020 Wind System Pmition il NewWind Awilable Front OlIice Transactions nmited FOT'S to meet remaining Need Net Surpus @eficit) 207 446 1 The DSM line includes selected Class 2 DSM from the 2011 IRP Update resource portfblio. I 1,381 8,596 1,143 9,739 t,@3 0 |,643 1,67O 0 1,643 tt,t74 8,606 1,144 9,750 1,425 0 1,425 1,670 0 1,425 I 1,183 8,@2 I,144 9,745 1,438 144 1,582 I,670 0 1,582 l0,t l4 8,605 t,t44 9,749 365 10,103 8,631 t,147 9,778 324 207 531 1,670 0 531 10,044 8,655 I,1 50 9,805 239 I,670 0 446 s q75 8,6ss I,l5l 9,805 t69 207 376 1,67O 0 376 9,971 8,678 l,l 54 9,832 139 9,949 8,573 l,l.l0 9,713 237 9,926 8,570 1,139 9,709 2t7 207 424 1,670 0 424 207 572 ?o7 144 0 444 207 346 1,670 0 572 1,670 1,670 0 346 36 PncIrIConp _2017 IRP UPDATE Cuaprgn 4 - LoAD-AND-RssouRcp BALANCE UpDATE Table 4.5 (cont.) - Winter Peak - System Capacity Load and Resource Balance without Resou rce Additions, 20 I 7 IRP Update (2025-2036) (Megaw atts)s CalendarYear 2028 2029 2030 203t 2032 2033 2034 2035 203 6 Fias t Thernul Hydroelectric Renewable Purchases Qualifoing Facilities Class I DSM Sales Non-Owned Reserues toad East &isting Resources 5,001 72 180 t2t 657 0 (66) (35) s,930 6,00s (7s) 318 5,001 72 tu t2t 653 0 (66) (-ls) 5,911 4,94 72 126 t2t 650 0 (66) r 15r 5,5r2 4,568 7Z 126 t2t u6 0 0 (35 ) 5,498 6,041 (0) (le5) (497\ s349 4,568 72 126 t2l 635 0 0 (35) 5,488 4,212 72 126 t2l 590 0 0 (r5) 5,086 4,130 72 126 tzt 570 0 0 f15) 4,985 4,130 72 t26 121 t75 0 0 rlSr 4,589 6,31 I (0) (l9s) (615) 5,500 6,240 (l,6sr ) 318 4,212 72 126 t2l 587 0 0 (3s) 5,083 Private Crneration Intemptible DSM Planning Resewes (l3o%) East Ouigation + Reserres East Position ArailaHe Front OIIice Transactions 5,884 (0) (les) (3e7) tr'qst 6Higsti6n 5,292 713 717 718 721 5 q41 (0) ( les) (429) sJr9 6,036 (l 2s) 3r8 5,984 (0) ( r9s) (461) s326 6,043 (5-l I ) 318 6,091 (0) (re5) i S)5r s37l 6,094 (607) 318 6,150 (0) (le5) (s5l) 5,404 6,209 (0) (tes) l 57lt 5,440 6,173 ( l ,090) 3r8 6,269 (0) (les) (594) 5,480 6,217 (1,233) 3r8 724 728 738 740 6,069 (s7l) 318 6,132 ( I,045) 318 West Thennal Hydroelectric Renewable Purchases Quali&ing Facilities Class I DSM Sales Non-Owned Reserves West E\isting Resources Ioad Private Ceneration Intemlptible DSM West oHigation Planning Reserues (13%) West OHigation + Reser\,€s West Position ArailaHe Front Oflice Trmsactions 2,316 788 55 I 143 0 (8r) (3) 3,219 1,962 788 54 I 133 0 (78) (3) 2,856 t,962 788 53 I 102 0 (78) (3) 2,826 t,962 788 53 I 98 0 (7ll) (3) 2,82r 3,657 (0) 0 (ll6) 3341 434 1,fi2 788 53 I 97 0 (78) (3) 2,461 3,684 (0) 0 (32e) 3,355 436 1,fi2 788 53 I 96 0 (78) (3) 2,461 3,708 (0) 0 (341) 3367 438 1,602 788 53 I 95 0 (78) (3) 2,460 3,731 (0) 0 (3s3) 3377 3,817 (1,357) 1352 1,ffiz 788 53 I ll 0 (78) (3) 237s 3,746 (0) 0 (365) 3J80 t,962 788 54 I 134 0 (78) (l) 2,858 \ \1) (0) 0 (260) 3312 431 3,743 (s24) 1352 3,599 (0) 0 (274) 3)2s 132 3,757 (899) 1352 3,615 (0) 0 (288) 3327 3,759 (90-r ) r352 3,636 (0) 0 (302) 3J33 3,766 (e.10) t352 3,77 5 (es{) l3s2 3,791 (r,330) 13s2 3,805 ( l ,3.1,1) t332 3,820 (r,,144) 432 433 439 439 System Total Resources Obligation Reserws Obligation + Reser\€s System Position New EV2020 Wind System Position W NewWind Auilable Front OfIice Trans actions Uncommited FOT's to meet remaining Need Net SurPus (Deficit) 9,149 8,6(X 1,144 9,748 (599) 207 (392) 8,769 8,&3 1,t49 9,792 ( 1.024) 207 (8r7) 1,670 817 0 8,369 8,652 1,150 9,802 ( 1..134) 207 (1.227\ 1,670 1,227 0 8,324 8,682 I, t54 9,836 ( 1.5 r2) 207 ( 1.30.r) 1,670 1,304 0 8,309 8,7t2 r,158 9,870 ( 1.561 ) 207 ( l.-154) 1,670 1,354 0 7,548 8,759 t,t& 9,923 (2.375) 207 (2. I 68) r,670 t,670 (4ee) 7,543 8,807 1,170 9,978 (2..11.r) 207 (2.2?7\ 1,67O 1,670 (558) 7,444 8,8s7 1,177 10,034 (2.590) 207 (2,382) 6,965 8,880 1,180 10,060 (3.09s) 207 (2,888) t,670 1,670 ( r,219) 1,670 392 0 1,67O 1,670 (7r 3) s The DSM line includes selected Class 2 DSM from the2017 tRP Update resource portfolio. )t PaCIr.ICOnp - 20 I7 IRP UPDATE CHepTpn 4 - Loao-aNo-RESoURCE BALANCE UPDATE Table 4.6 - Summer Peak - System Capacity Load and Resource Balance without Resource Additions, 201 7 IRP (2015-2027) (Megawatts)6 CalendarYear 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Thernnl Hydroelectric Renewable Purchases Quali!ing Facilities Class I DSM Sales Non-Orxned Reserues East kisting Resources tnad 6,406 106 201 249 646 323 (652) (37) 7 241 6,126 l13 201 249 689 t/l (65t) r 17r 7,012 6,126 It3 201 249 681 )/) (652) (37) 7,004 7,250 ( loo) ( le5) (2e8) 6,657 5,739 ll3 l99 221 672 323 (t721 (37) 7,058 5,739 lt3 l9l 221 6t 323 (172\ (37) 7,038 5,739 ll3 l9l 22t 657 323 (t72t (37) 7,034 7,509 (lr8) ( les) (468) 6,728 900 5,739 92 l9l 22t 603 323 ( l,16) (37) 6,987 7,589 (r23) ( re5) (.527) 6,744 x2 5,735 92 l9l lzt 598 323 ( 146) (37) 6,878 7,688 (r3l) ( re5) (s84) 6,779 907 5,&5 92 l8l tzl 594 323 (63) (37) 6,856 5,45 92 l8l l2t 590 323 (63) (37) 6,853 Private Ceneration Intemptible I)SM Planning Reserves ( l3%) East OHigation + Reserres fast Pmition AuilaHe Front OIfice Transactions 7,t02 (61) ilq5r ( 190) E st oHigation 6,657 891 887 7,\52 (83) (t9s) 12461 6,629 7,516 (50{ ) 318 7,353 (108) ( les) (35s) 6,695 896 7591 (s33) 318 7,443 (l14) ( 195) (,1r0) 6,725 900 7,692 ( r,1l ) (le5) (641) 6,714 898 1,612 (7s6) 318 7,774 (r53) ( 195) (6971 6,729 900 7,629 (77 6\ 318 891 7,548 (s{{ ) 318 7,547 (306 ) 3r8 7,624 (sn6) 318 7,628 (se{) 318 7,646 (6se ) 318 7,685 (807 ) 3r8 West Theml Hydroelectric Renewable Purchases Qualirying Facilities Class I DSM Sales Non-Owned Reserves West kisting Resources Ioad Private Genemtion Intemrptible DSM West obligation Planning Reserues (13%) West OHigation + Reseres West Pmition ArailaHe Front OIIice Transactions 2,247 859 93 l8 200 3 ( 165) (2) 32s3 2,247 717 93 I 2A J (165) (2) 3,097 2,247 806 93 I 207 3 ( l6s) (2) 3,191 3,268 (ts) 0 (r52) 3,101 2,247 635 93 I 198 0 (l6l) (2) 3,01I 3,291 ( l7) 0 (r75) 3O98 403 3501 (48e) rJs2 2,247 549 62 I 195 0 (il0) (2) 2942 3,315 (20) 0 ( 196) 3,099 403 3,502 (s60) t3s2 2,247 u4 62 I 186 0 (il0) (l) 3028 2,247 u4 55 I 150 0 (80) (2) 3,0r 6 3,437 (37) 0 (278) 3,r22 406 2,247 2,247 2247 648 634 651 57 57 56 lll 185 184 182 000 (80) (80) (80) (2) (2) (2) 3,056 3,042 3,056 3,192 (e) 0 (e7) 3,086 401 3,487 (2-1s ) lJs2 ? )s, (12) 0 (126) 3,1 l5 3,519 ({23 ) 13s2 3,338 (23) 0 (214') 3,101 403 3,505 (171\ 1352 3,364 (26) 0 (212) 3,106 404 3,391 (2e) 0 (248) 3,1l4 405 3,4t4 (33) 0 (263) 3,117 405 3,523 (167\ l3s2 405 403 3,504 (313 ) l3s2 3,510 ({s.r ) lJs2 3,518 ({76 ) r3s2 3528 (s l -1) 1352 Total Resources OHigation Reserws OHigation + Reserres System Pmition NewWind System Pmition uy' NewWind AmilaHe Front OIfice Transactions Uncommited FOT's to meet remaining Need Net Surflus @elicit) t0,494 9,743 l,)O) I 1,035 (s4r) 0 (s4l ) t,670 54t 0 10,109 9,743 1,292 I 1,035 (9)7\ 0 (927\ 1,670 921 0 10,194 9,758 1,294 I 1,052 (8s8) 0 (858) 1,670 8s8 0 10,069 9,793 1,298 I 1,092 ( r,023) 174 (849) t57O 849 0 9,980 9,824 r,302 n,t26 (1.r16) t74 t972\ 1,670 972 0 10,062 9,829 1,303 I 1,132 ( r.070) t74 (8e7) I,670 897 0 10,043 q850 1,306 I 1,t56 (l.l ll) 174 (940) 1,670 940 0 1,670 t,l l0 0 9,912 9,831 1,303 l 1,135 ( l.ll-.r ) 1,670 1,049 0 9,869 9,851 1,306 n,t57 ( 1.288) 174 ( t.l l5) 1,670 l,l l5 0 9,920 9,892 l,3ll n,203 ( r.28,r) 174 ( l.r r0) 174 ( r,049) 6 The Load and Private Generation lines include an offsetting adjustment (average of 43 MW) from the 2017 IRP that nets to zero. The DSM line includes selected Class 2 DSM from the 2017 IRP Pref'erred Portfolio. 38 [ast PACIFICORP - 2OI7 IRP UPDATE Cuaprr,n 4 - Loa.o-euo-RESoURCE BALANCE Upoerp Table 4.6 (cont.) - Summer Peak - System Capacity Load and Resource Balance without Resource Additions, 201 7 IRP (2028-2036) (Megawatts)7 C'rlendar Ycar 2028 2029 2030 2031 2032 2033 2034 2035 2036 F'ast Thernral Hydroelectric Renewable Purchases Qualifuing Facilities Class I DSM Sales Non-Oumed Reserves Eas t Eris ting Resources had Private C-€neration lnterruptible DSM East oHigation Planning Res erues ( l37o) Fqst OUigation + Reserles East Position AmilaHe Front OIIice Transactions 4,883 92 l8l t2t 586 323 (61) (17) 6,087 4,883 92 181 t2t s80 323 (61) (37\ 6,081 7,951 (182) ( r95) (799\ 6,775 906 7,681 (l,600) 318 4,526 92 159 tzt 576 323 (63) (,17) 5,698 4,449 92 t27 t2t 562 323 0 (37) 5,637 8,299 (2s0) (les) (940) 6,914 4,092 92 t27 t2l 530 323 0 (37) 5,249 8,393 (27s) (les) (977) 6,946 4,092 92 127 t2l 5t4 323 0 (37) 5,232 8,460 (300) (le5) ( 1.008) 6,957 4,010 92 127 t2l 506 323 0 (17) 5,143 8,584 (r23) ( res) ( r,037) 7,029 4,010 92 t27 t2t 454 323 0 (-r7) 5,091 8,72t (-143) (res) ( r.067) 7,1 l5 4,449 92 127 t2l 573 323 0 131 ) 5,648 7,U2 (1fl) (te5) (749) 6,733 901 8,U4 (205) ( 195) (rJ48) 6,796 909 7,70s (2,007 ) 318 8,152 (226\ ( les) (898) 6,832 7,746 (2,097) 318 9t4 924 928 930 939 950 7,634 (1.s47) 3r8 7,838 (2,201) 318 7,887 (2.6s4) 318 8,065 (2,97 4\ 318 7,968 (2,ri2s ) 318 7,875 (2,626) 318 West Theml Hydroelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-Owned Reserues \ves t Existing Resources tlad Private CEnemtion Intemptible DSM West oHigation Planning Reserues ( I 3oZ) West OHigation + Reser\cs West Position AvailaHe Front OIIice Trmsactions 2,247 a4 52 I 149 0 (80) (2) 3,0r2 3A6t (42) 0 (2el) 3,128 q7 1,893 g4 5l I 138 0 ( 7r]) (2) 2,648 3,487 (4ti) 0 (104) 3,135 408 1,893 il4 5l I t33 0 (78) (2) 2,643 3,512 (s6) 0 (3 l6) 3,140 t,893 g4 5l I 132 0 (78) (2) 2$42 3,536 (s) 0 (328) 3,144 N 1,893 644 5l I 99 0 ( 7tl) (2) 2,608 3,559 (73) 0 (3.10) 3,147 1,534 644 5l I 97 0 (78) (2) 2,247 3,585 (82) 0 (3s0) 3,r54 1,534 &4 5l I 97 0 (78) (2\ 2,247 3,608 (e2) 0 (360) 3,157 t,534 u4 5l I 96 0 (7tt) (2) 2246 3,634 ( 102) 0 (370) 3,162 t,534 &4 5l I 94 0 (21) (2) 2298 3,ffi (ilr) 0 (179) 3,168 409 4t0 410 .1il 3,534 (s22) r352 3,543 (89{ ) t3s2 408 3,548 (e0s ) t3s2 3,553 (9u ) r)52 3,556 (e,ltt) t3s2 3,564 (1,3r6) t352 3,567 ( r.-120) l J52 3,574 (r..r27) r352 412 3,580 ( r .21r2 ) r352 System Total Resources OHigation Reserws OHigation + Reserws System Position NewWind System Position w/ NewWind AuilaHe Front Office Transactions Uncommited FOT'S to meet remaining Need Net Surflus (DeIicit) 9,89 9,86r 1,307 I 1,168 (2.068) 174 ( I,n95) 1,670 1,670 (2?s\ 8,729 9,910 t,314 n,223 (2.49s\ 174 (2,32t\ 1,670 t,670 (6sl) 8,341 9,936 |,3t7 1t,253 (2.912) 174 (2,718) I,670 t,670 ( I .06()) 8,290 9,976 t,322 I 1,298 (-3.008) t74 (2,834) 1,670 1,670 (r.l6s) 7,389 l0,l9l I,350 I 1,541 ("1.152) 174 (3,978) 7,389 10,283 t,362 n,&5 (4,2s6) 174 (.1.0It2) 1,670 1,670 ( 1..1 r -.] ) 1,670 1,670 ( 1.309) 7 The Load and Private Generation lines include an offsetting adjustment (average of 43 MW) from the 2017 IRP that nets to zero. The DSM line includes selected Class 2 DSM from the 2017 IRP Preferred Porttblio. 39 8,246 10,061 1,333 I 1,395 (1. l-19) t74 (2.e75) 1,670 I,670 ( l.-106) 7,496 10,100 1,338 I1,438 (3,s421 174 (3.76rJ) 1,670 1,670 (2.099) 7,479 10, I 14 1,340 n,454 (3.97s) t74 (-r,801) r,670 t,670 (2.131) PeCmICOnp - 20 1 7 IRP UPDATE CHnprEn 4 - Loeo-eNo-RESoURCE, BaleNce UpDAlE Table 4.7 Winter Peak - System Capacity Load and Resource Balance without Resource Additions, 201 7 IRP (2018-2027) (Megawatts)8 ClalendarYear 2018 2019 2020 21121 2022 2023 2021 2025 2026 2027 trast Theml Hydroelectric Renewable Purchases Qualifing Facilities Class I DSM Sales Non-Owned Reseryes Load Fast Bisting Resources 6,514 72 201 688 2l ( 170) (17) 8,023 6,234 72 201 734 680 2l (170) (371 7,73s 6,234 72 t99 734 676 2l (170) (17) 7,729 5,847 72 l9t 235 668 2l ( l70) (,]7) 6,826 5,777 (.i tt ) I 195) s288 5,U7 72 l9l 235 658 2t ( 170) (37) 6,8r6 5,856 (40) ( 195) (297). 5J23 5,847 72 l9l 235 604 2l ( 170) ( 37) 6,762 5,847 72 191 t2l 600 2t ( 116) (-.i7) 6,670 5,843 72 l9t t2l 595 2t (t46) (37) 6,661 5,753 72 l8l t2t 591 2l (6.1) (37) 6,640 5,753 72 l8l t2t 588 2l (6.1) (.17) 6,636 Private Generation Intemptible DSM 5,620 (20) ( 195) ( 132) BastoHigation 5274 5,691 (19) ( 195) (l7i) s294 6,007 t,728 318 5,604 (15 ) ( 195) (llj) 5,161 5,857 1,872 3r8 5 q1) (.+l) ( res) (i40) sJss 5,965 (44) ( r95) (381 ) s343 6,063 607 318 5 q?o (46) ( le5) (42s) s262 s,934 ( 50) (te5) (.169) 5,220 6,W2 (54) ( le5) (5lr) sr32 Planning Reserues (13%) Fast OHigation + Reserws East Pmition ArailaHe Front Oflice Transactions 7| 7t4 696 713 7t7 721 720 709 7M 718 5,985 2,039 3r8 600l 826 318 6,076 686 318 5g7l 689 318 5,924 716 318 6,050 586 318 6,040 776 318 West Theml Hydroelectric Renewab [e Purchases Qualifying Facilities Class I DSM Sales Non-Owned Reserves West Existing Resources Inad hivate Crnemtion Intemptible DSM West oHigation Planning Reserues (13%) West OHigation + Reserws West Position AnilaHe Front Oftce Transactions 2,308 915 93 I 192 0 (t62) (2) 334s 3,29t (2) 0 (109) 3,180 413 2,308 943 93 I 195 0 ( 162) (2) 3)77 3,306 IJ' 0 ( 143) 3,160 4ll 2,308 937 93 I 197 0 ( 154) (2) 3381 3,417 (3) 0 (t74) 3239 42t 2,308 7U 93 I 190 0 ( ls4) (2) 32,21 3,360 (4) 0 (201) 3,155 410 2,308 782 62 I 183 0 (lll) (2) 3221 3,379 (5) 0 (22s) 3,t49 409 2,308 783 62 I t77 0 (lB) (2) 32ls 3,400 (5) 0 (246) 3,149 409 2,308 779 57 I t76 0 (81) 3238 2,308 786 56 I 175 0 (81 ) (2) 3244 3,542 (7) 0 (286) 3249 422 3,671 ({2ri ) r3s2 2,308 784 53 I t44 0 (81) (2) 3207 2,308 7t36 55 I t7t 0 (81) (2) 3r38 35e3 (2{8) 1352 3,571 (r 9{) l3s2 3,661 (2n0) 1352 3,565 (.1.1{) 1352 35s9 (338) 1352 3,558 (-1{-1) t3s2 3,4t7 (6) 0 (267) 3,144 409 3,553 (-1l s) l3s2 1 SSO (7) 0 (304) 3247 422 3,49 (8) 0 (321 ) 3,169 412 3581 (.17{) t)s2 3,670 ({-i l ) t)s2 System Total Resources OHigation Reserws OHigation + Reserws System Poeition l 1,369 8,453 1,124 9,578 |,791 I I,l t2 8,453 t,124 9,578 1,534 I I,l l0 8,400 t,\7 9,5 l8 t,592 t,670 0 t,592 I,670 0 655 r0,037 8,472 1,t27 9,599 438 9,978 8,503 I,l3l 9,634 344 1,670 0 517 9,908 8,487 1,129 9,616 ?92 t,670 9,905 8,51 I 1,t32 9,93 262 1,670 0 436 9,878 8,467 1,t26 9,593 285 t74 459 1,670 0 459 9,843 8,501 I,130 9,632 2t2 174 386 t,670 0 386 NewWind 0 System Pmition w/ NewWind 1,791 AlailaHe Front OIfice Transactions Uncommited FOT'S to meet remaining Need Net Surflus (Delicit) I,670 0 1,79t 0 1,592 174 655 t74 6t2 t74 517 t74 436 0 1,534 t74 466 t,670 0 1,534 1,670 0 6t2 0 466 8 The Load and Private Generation lines include an offsetting adjustment (average of 15 MW) from the 2017 IRP that nets to zero. The DSM line includes selected Class 2 DSM from lhe 2017 IRP Prefened Portfolio. 40 t0,M7 8,,143 1,123 9,566 48r Fast Theml Hydroelectric Renewable Purchases Qualifiing Facilities Class I DSM Sales Non-Owned Reserves Eas t Exis ting Resources Inad Private Generation Intemptible DSM East oHigation Planning Reserves ( I 3%) East Obligation + Reserr,ts East Position Awilable Front OIIice Trans actions 4,991 72 165 l2l 577 2l (61) (.37) 5,848 4,991 72 t8t lzl 580 2l (63) (37) s,867 4,634 72 t27 t2l 573 2t (63) (-37) 5,449 6,332 (73) (195) (624) 5,440 4,557 72 t27 tzt 570 2l 0 (37) 5,431 4,557 72 127 tzt 559 2t 0 (37) 5,420 6,4& (89) (te5) (6e2) 5,488 4,2W 72 127 t2t 5t4 2t 0 (17) 5,018 6,545 (e8) (le5) (719) 5,532 4,200 72 127 t2t 5ll 2t 0 (17) 5,0r5 6,630 (r07) (le5) (741) 5,586 4,1 l8 72 t27 l2l 493 zl 0 ( 37) 4,915 6,722 ( ll5) (te5) (7$\ 5,648 4,1 l8 72 t27 tzt 109 2t 0 ( 37) 4,532 6,750 (r23) (re5) (786) 5,646 6,180 (s8) ( l9s) (5s0) s376 6,1 00 (23{ ) 318 6,2ffi (65) (le5) (587) sAtg 6,149 (-r0l ) 318 6,2& (8r) (195) (661 ) s327 724 730 733 718 739 715 75t 760 759 6,172 (723) 318 6,04s (6 l.l) 318 6,226 (806 ) 318 6,277 (1,2s8) 318 6337 ( I ,-i22) 318 6,408 ( r ,.1e2 ) 318 6,406 ( r ,{t7{) 318 PnclpIConp _2017 IRP UPDATE Cueprr,n 4 _ Loeo-euo-RESoURCE BALANCE UpoeTE Table 4.7 (cont.) - Winter Peak - System Capacity Load and Resource Balance without Resource Additions, 201 7 IRP (2028-2036) (Megawatts)e Calendar Year 202a 2029 2030 2031 2032 2033 2034 2035 2036 Therrol Hydrcelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-Owned Resewes West Existing Resources toad Private Generation Interruptible DSM West oHigation Planning Reserues ( I 3oZ) West OHigation 4 Reseres West Position Avrilable Front OIIice Transactions 4t2 413 412 427 2,308 1,9s4 1,9s4 7U 784 7U 52 5l 5l ll1 143 134 133 000 (81 ) (78) (78) (2) (2) (2) 3105 2,444 2843 1,954 784 5l I tw 0 (78) (2) 2,812 1,954 784 5l I 98 0 (78) (l) 2,807 1,595 784 5l I 97 0 (78) (2) 2,448 3,628 ( l8) 0 (.108) 3,202 3,618 ( r,r 70) t3s2 1,595 784 5l I 97 0 (78) (2) 2,447 1,595 7U 5l I 96 0 (78) (l) 2,446 3,668 (23) 0 (.1-13) 3212 3,630 ( 1,r 8{) r352 1,595 7U 5l I lt 0 (78) (2) 2362 3,515 (10) 0 ( i-17) 3,168 3,580 (-17s) lJs2 3,538 (ll) 0 (351 ) 3,r 75 3,588 (7{{ ) lJs2 3,546 (ll) 0 ( i67) 3,167 3,578 (736) rJs2 3,680 ( l4) 0 (381 ) 338s 3,7t2 (8ee) 1352 3,ffi7 ( l6) 0 (3e5) 3,195 415 3,611 (80.1) r3s2 3,&8 (21) 0 (.+10) 3,208 3,625 (r,r 78) l3s2 3,654 (25) 0 (44s) 3,tE4 3,598 (r.2-16) t3s2 .+16 417 4ltt 114 System Total Resources Obligation Reseres Obligation + Reserws System Position NewWind System Position w/ NewWind Arailable Front Ollice Trans actions Uncommited FOT's to meet remaining Need Net Surplus @eficit) 9,O72 8,545 1,t36 9,681 (60e) t74 (435) t,670 435 0 8,691 8,594 I,143 9,737 ( r,0.1s) t74 (87r) 1,670 871 0 8,292 8,607 1,144 9,751 ( r.,+59) 174 ( r,28s) 1,670 1,285 0 8,243 8,612 1,145 9,757 (1,514) 174 ( l,r40) 1,670 1,340 0 8,228 8,683 1,154 9,837 ( 1,609) 174 ( 1,436) 1,670 t,436 0 7,46 8,734 l,l6l 9,895 (2,129', t74 (2,2ss) r,670 1,670 (586) 7,462 8,793 I,168 9,962 r ) i{)Or 174 (2,326)- t,670 1,670 (6s71 7,361 8,860 I,t77 10,037 12,6761 174 (2,s02) 1,670 1,670 (833) 6,893 8,830 1,t73 10,003 (i.r r0) 174 (2,e36) 1,670 I,670 (1,267\ e The Load and Private Generation lines include an offsetting adjustment (average of l5 MW) fiom the 20 l7 IRP that nets to zero. The DSM line includes selected Class 2 DSM from the 2017 IRP Preferred Portfolio. 4t West East Theml Hydmelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-OMed Reseryes Fas t Eris ting Resources toad Private Ccneration Intemptible DSM East oHigation Planning Resewes ( I 3olo) FiNt OHigation + Reserws F4s t Pcilion Awilade Front OfIice Transactions (l) I (6) 0 2 0 (l) 3 (s) (1.+9) (.17) 0 72 (22{) (le) (2s3 ) 244 0 (2) I (8) 0 I o (l) 3 (8) ( 2.11 ) (8.3) 0 73 (2sl) (31) (2) I (l) 0 0 (3) J 74 (2) I (l) 0 77 0 (3) 3 2 I (l) 0 77 0 (3) 3 7E 9 I (l) 0 76 0 (3) 3 t5 (370) (ll0) 0 t32 (3,te) (4s) (3e4) 479 0 9 I (l) 0 76 0 (-.i) E4 (2) I (3) (l)(2) I (l) 0 0 (3) 3 74 (l) 0 62 0 (3) 3 60 o 62 0 (ll J 57 (283 ) 276 0 (3.1E) 405 0 (37e) 438 0 (36s) 439 0 (.r0 l ) 474 0 (.1-12 ) 516 0 (278) ( r02) 0 72 (30E) (40) (3 r2) (10s) 0 82 (33s) (44) (328) (106) 0 90 (343) (,ls) (388) 462 0 (326) ( 108) 0 1M (330) (43) (373) 447 0 r ltgt (lll) 0 tt7 (323) (42) (368) (lll) n 124 (3ss) (46) (,108) (lr6) 0 142 (3E3) (s0) PeCIpICOnp - 2017 IRP UPDATE CHAPTER 4 - LOAD-AND-RESOURCE BALANCE UPDATE Table 4.8 - Summer Peak - System Capacity Load and Resource Balance without Resource Additions,20l7 IRP Update less 2017IRP (2018-2027) (Megawatts)r0 Calendar Year 2018 2019 2020 2021 2022 2023 2021 2025 2026 2027 West Therul Hydrcelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-Ouned Reseryes West histing Resources bad Private Canemtion Intemptible DSM West oHigation Planning Reserues ( I 3oZ) West OHigation + Reseres \vest PGition ABilaHe Front OIIice Transactions 44 (22) 0 l5 I 0 7 2 (2) 0 35 0 0 (l) 4t 46 (3) 0 32 75 l0 E5 (,14) 0 7 30 (s) 0 l8 0 0 (l) 49 27 (8) 0 32 52 7 59 (10) 0 7 37 3 0 (0) 0 0 (l) 46 l6 (17) 0 JJ 33 4 37 9 0 7 (20) 0 I o 0 (l) ( l0) l3 ( ls) 0 34 27 4 3l (41) o 7 7 3 0 (0) 0 0 (l) t6 7 2l J 0 0 0 0 (l) 30 4 (26) 0 35 l3 2 l5 l5 0 7 (16) J 0 20 0 0 (l) l3 26 (tl) 0 30 44 t4 3 0 0 0 0 (l 23 (6) 3 0 0 0 0 (l) 3 2 (30) 0 35 7 '7 8 3 0 5 0 0 I 22 ?t ( l-1) 0 3l 39 I ( 22) 0 34 t4 2 (l) (34) 0 35 I 065 8 (s) 0 50 (-Il) o I 22 0 System Total Resources Odigation Reserws OHigation + ReserEs System Pcition New EV2020 Wind System PGition w/ NewWind AwilaHe Flont Omce Transactions Uncommitted F'llT's to meet remaining Need Net Surdus (Delicit) 36 ( l,l9) ( l9) ( 168) 2M 4l ( 199) (26) (225) 26 70 (263) (34) (2e7) 367 a (303) (19) (312.)w 90 (309) ('10) (3s0) 440 108 (3,r2) (141 (386) 494 87 (341) (44) (386) 473 107 (382) (50) (432) 539 82 (2e6) (38) (33s) 417 120 (3 r0) (40) (3sr) 471 504450 0 367 0 26 0 (266) 0 0 204 572507473 33 440 527 0 (204) 0 0 (367) 0 0 0 (4s0) (s04) (440) (4'73) 0 0 0 0 0 0 0 (s27) 0 0 (s07) 0 0 (572\ 0 r0 The DSM line reflects differences in Class 2 DSM resources between the 2011 IRP Update resource portfolio and the2017 IRP Preferred Portfolio, which includes a level of 2016 Class 2 DSM (100 MW) that was not incorporated in the load forecast for the 2017 IRP. The 2016 Class 2 DSM forecast of 100 MW was accounted for by adding an existing Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP Update because the 2016 projected embedded Class 2 DSM is included in the load forecast. 42 PacrprConp 2017 IRP UPDATE CsaprER 4 - Loeo-aNo-Rssounce BALANCE UpoerE Table 4.8 (cont.) - Summer Peak - System Capacity Load and Resource Balance without Resource Additions,2017 IRP Update less 2017IRP (2028-2036) (Megawatts)rr Calendar Year 2024 2029 2030 203t 2032 2033 2034 2035 2036 East Theml Hydrcelectric Renewable Purchases Quatifying Facilities Class I DSM Sales Non-Owned Reserues Fas t Exis ting Res ources had Private CEnemtion Intemptible DSM East oUigation Planning Reserues (137o) Fast Obligation + Reserws East Position AwilaHe Front OIIice Transactions il I (l) 0 78 0 0 3 9l l1 I (l) 0 78 0 0 3 9l ll t (l) 0 75 0 0 3 88 ll I (l) 0 75 0 0 E8 t0 I (l) 0 75 0 0 3 EE l0 I (l) 0 75 0 0 3 88 9 I (l) 0 76 0 (-l) 3 84 9 I (l) 0 76 0 (.\ ) J 84 (-rle) (llt) 0 t54 (.r e7 ) (51) ({{8) 532 0 9 I (t) 0 76 0 (3) 3 84 (397) (124) 0 148 (373) (48) (42r) 505 0 (442) (l19) 0 158 (40.r) (s2) (4s6) 540 0 (60e) ( l0) o ta (4s4) (se) (sr4) 601 0 (659) (ll) 0 169 (s0l) (6s) (s66) 654 0 (677',| (e) 0 t72 (s r4) (snl) 669 0 (671'l (tt) o t73 (s06) (57 2l 659 0 (7 12) ( l0) 0 174 (s47) (618) 709 0 ( 761t) (ll) 0 176 (603) (67). ((fi) (71) (7r{) (68r) 772 0 Theml Hydroelectric Renewable Purchases Quali$ing Facilities Class I DSM Sales Non-Owned Reseryes West kisting Resources Ioad Private Genemtion Intemptible DSM \vest oHigation Planning Resewes (13%o) West OHigation + ReserEs West Pmition AEilaUe Front Oflice Transactions (3) (36) o 36 (3 1) (8) o 37 (r) 7 9 3 0 0 0 0 (l) 18 7 9 3 0 o 0 0 (l) 18 7 9 3 0 0 0 o (t) 18 (23) (8) 0 6 7 9 3 0 0 o 0 (l) r8 7 9 3 0 0 0 o (l) 18 7 9 3 0 o 0 0 (l) t8 l6 (37) 0 36 t5 2 7 9 J o 0 0 0 (t) 18 (27t (8) o 2 (-r3) (e) 0 37 (s) (4ll) (lt ) 0 (le) (t7) \37 t o 36 ( l8) (2) (20) 38 0 7 9 3 0 0 0 0 (l) l8 7 9 0 o o 0 (l) 18 (ls) (e) o 37 t4 2 (4) (0)o (o)(2) (4) 22 0 (l) (s) 23 0 l6 ) 0 2 l5 0 t7 I o 6 ll 0 (l ) l9 0 (22) 39 0 OHigation Reserres Obligation + Reserws System Position NewEV2020 Wind System Position il NewWind AEilaHe Front OIIice Transactions Uncomitted FOT'S to meet remining Need Net Surflus (DeIicit) lol (376) (4e) (42s', 527 r0l (382) (s0) (431 ) 533 l0l (422) /55\ (476) 574 33 6ll 105 (449\ (58) (5o7) 6t2 l05 (.19e) (65) (scl) 669 l06 (sls) (67) (s82) 688 t06 (5 lo) (66) (s771 682 108 (s34) (6e) (603) 711 108 (622) (13l) (703) 8ll JJ u4 0 0 u4 33 744 o o 744 33 7o2 0 0 702 JJ 46 0 0 616 o 33 56 0 0 s66 33 560 22s 0 0 6ll 33 721 JJ 715 0 0 721 0 o 7t5 (33s) rrThe DSM line reflects differences in Class 2 DSM resources between the2017 IRP Update resource portfolio and the2017 IRP Preferred Portfolio, which includes a level of 2016 Class 2 DSM (100 MW) that was not incorporated in the load forecast for the 2017 IRP. The 2016 Class 2 DSM forecast of 100 MW was accounted for by adding an existing Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP Update because the 2016 projected embedded Class 2 DSM is included in the load forecast. 43 West PacIpIConp - 2OI7 IRP UPDATE CHapren 4 _ Loeo-eND-RESoURCE BeLaNce UPDATE Table 4.9 - Winter Peak - System Capacity Load and Resource Balance without Resource Additions,20l7 IRP Update less 2017IRP (2018-2027) (Megawatts)r2 Calendar Year 20lE 2019 2020 2021 2022 2023 2024 2025 2026 2027 Theml Hydrcelectric Renewab le Purchases Qua[rying Facilities Class I DSM Sales Non-Owned Reseryes bad Private C€neration Intemptible DSM East oHigation Planning Reseryes ( l3%) East Otligation + Reserws F2s t Position AEilaUe Front OlIice Transactions (l) (l) (l) 0 77 (ll) (.1) 3 53 (108) 38 0 t09 39 25 35 0 102 162 2l (60) 20 0 76 36 5 4t (66) 0 Fast kisting Resources ( t) (l) (6) 0 3 (21) (r) (2s) (l) (l) (2) 0 62 (21) (3) 3 37 0 63 (ll) (l) 3 39 (l) (l) (l) 0 78 (21 ) (3) J 54 (147) 42 0 t22 t7 (l) (l) (l) 0 78 (21 ) (3) 3 54 4 3 (l) (l) 0 77 (ll) (-l ) 3 57 l0 (t) (r) 0 77 (21) (3) J 64 l0 (l) (l) 0 77 (21) (3) 64 il) (l) (l) 0 78 i2l ) (]) 3 54 (s 1) 46 0 135 130 l.l-l ) 43 0 131 3t 102) 29 0 89 t7 (l16) 40 0 l t5 29 (131) 50 0 141 6t (267') 54 0 148 (6s) (8) (73) 137 0 1 l9 l8 0 5 4 1 t7 (8e) I lE3 (l{{) 0 45 E 0 33 2t 0 r46 0 20 34 0 35 l8 0 Theml Hydroelectric Renewable Purchases Quali$ing Facilities Class I DSM Sales Non-Owned Reserues West Bisting Resources trad Private Crneration Intemptible DSM West otligation Planning Reserues ( l3olo) West OUigation + Reserws West Position AEilaHe Front OIIice Transactions 139 (r 2{) 0 43 5l (33) (43) 00 7 2 3 0 23 0 0 (1) 34 (33) t 0 69 39 7 (0) 3 0 l6 0 0 (t) 25 70 J 0 63 135 l8 7 z (2) 0 32 0 0 (l) 38 5l 2 0 54 to7 t4 7 I 3 0 4 0 0 (l) l5 7 2 3 0 I 0 0 (l) t2 52 5 0 73 130 1'.7 7 0 0 (0) 0 0 (l) 9 7 (2) 3 0 (0) 0 0 (l) 7 ({,1) 7 0 75 38 ,18 4 0 7t t23 l6 7 4 0 (0) 0 0 (l) l3 56 6 0 137 l8 7 J 3 0 I 0 0 (t) t3 55 5 0 74 134 t7 (38) 7 0 76 45 7 l0 0 (0) 0 0 (l) l9 49 8 0 77 34 t76 t20 (82) 0 153 11 (127) (r0) 0 0 147 (l3s) 0 l5t ! 5,1 ( 139) (r,r l ) o 0 l5l (l 32) 0 System Total Resources OHigation Reseres OHigation + Reseres System Position NewEV2020 Wind System Pmition uy' NewWind AmilaHe Front OIIice Transactions Uncommited FOTS to meet remaining Need Net Surdus (Delicit) 63 152 20 172 (l l0) 0 (ll0) 0 0 (n0) 67 168 22 190 ( 123) 33 (8e) 0 0 (8e) 13 143 l9 l6l ( l,l8) 0 ( 148) 0 0 (148) 73 201 26 227 ( l s.1) 144 ( l0) 0 0 ( l0) 67 r62 2t r83 (ll6) 5J (83) 0 0 (83) 6 159 2t 180 (l14) 55 (81) 0 0 (81) 6 t5t 20 l7t ( 105) 33 (72) 0 0 (72\ 6 167 22 189 (l2l) 33 (8e) 0 0 (8e) 7t 106 t4 ll9 (,18) 33 ( r5) 0 0 ( l5) 83 69 9 78 5 33 38 0 0 38 r2 The DSM line reflects dift'erences in Class 2 DSM resources between the 2011 IRP Update resource portfolio and the2017 IRP Pref-erred Portfolio, which includes a level of 2016 Class 2 DSM (81 MW) that was not incorporated in the load forecast for the 2017 IRP. The 2016 Class 2 DSM forecast of 8l MW was accounted for by adding an existing Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP Update because the 2016 projected embedded Class 2 DSM is included in the load fbrecast. 44 69 (s) o Eas t West 55 PACIFICORP _ 20 I7 IRP UPDATE Cuepren 4 - LoRo-eNo-Rssouncp BALANCE Upoare Table 4.9 (cont.) - Winter Peak - System Capacity Load and Resource Balance without Resource Additions,20lT IRP Update less 2017 IRP (2028-2036) (Megawatts)r3 CalcndarYear 202ra 2029 2030 2031 2032 2033 2031 2035 2036 Erst Thetml Hydroelectric Renewable Purchases Qualifting Facilities Class I DSM Sales Non-Ouned Reseryes East Bisting Resources trad PriYate C€nemtion Intemptibte DSM Eflst ouigation Planning Reserues ( I 37o) East Ouigation + ReserEs Fast Position AwilaHe Front OIIice Transactions (l lt) 177 0 (l -r2) r99 0 l0 (l) (l) 0 77 (21 ) (l) 3 64 (296') 58 0 153 (84) (l l) (es) 159 0 l0 (t) (l) 0 77 (2r) (3) 3 63 ( l3) 10 ( r) (l) 0 (21) (3) 63 t2 (l) (l) 0 76 t2 (l) (l) 0 78 t2 (l) (l) 0 66 ll (l) (l) 0 76 (2tt 0 3 67 ll (l) (l) 0 76 (21 ) 0 3 67 (2t) 0 3 (21 ) 0 3 (2r) 0 3 t2 (l) (l) 0 76 (21\ 0 3 68 (323) 65 0 t59 (100) (348) 73 0 161 (r l.l) ( 1s) (129) 192 0 (223) 80 0 t@ 2t (.17.r ) 89 0 167 (l l7) (3e5) 98 0 169 (r 2e) (t7) (r4s) zt3 0 (122) 107 0 170 (l 4s) (le) (l 64) 232 0 (4s4) l15 0 170 (r 68) (22) (r 90) 259 0 58 (43e) 122 0 t7l (r 46) ( l9) (l 6s) 223 0 6968 3 24 43 0 ( ls) lilest Theml Hydrcelectric Renewable Purchases Qualifying Facilities Class I DSM Sales Non-Owned Reserues \Mest Eristing Resources Load Private Generation Intemptible DSM West ouigation Planning Reseryes ( I 39lo) \ilest Ouigation + ReserEs West Position ABilaUe ftont OIIice Transactions 7 5 3 0 (0) 0 0 (l) t4 7 5 3 0 (0) 0 0 (l) t4 7 5 3 0 (0) 0 0 (t) t4 69 12 0 78 160 2t 181 (l 67) 0 7 5 J 0 (0) o o (l) t4 (4s) t4 0 79 49 6 55 (4r) o 7 5 3 0 (o) 0 0 (l) t4 5l l6 0 79 146 t9 165 (lsl ) 0 7 5 I 0 (0) 0 0 (l) t4 56 l8 0 79 153 20 173 (l se) 0 7 5 3 0 (0) 0 0 (l) t4 60 20 0 80 159 2l 1E0 (r 66) 0 7 5 3 0 (0) 0 o (l) l4 7 5 3 o o 0 o (l) t4 92 25 0 79 196 26 222 (208) 0 57 9 0 77 144 l9 6t ll 0 78 t50 l9 63 23 0 80 165 21 163 (r4e) 0 169 (156) 0 lE7 (17-r) 0 System Total Resources OHigation Reserws OHigation + Reserws System Position New EV2020 Wind System Pmition w/ NewWind ABilaUe Front Oflice Transactions Uncomited FOT'S to meet remining Need Net Surdus (Deficit) 0 (43) 0 0 (5e) 0 0 ( -16) 0 0 0 48 0 o 99 8l 25 3 2A 53 33 a7 0 0 a7 8l 29 4 33 48 33 a2 0 (82) 0 8t '70 9 79 2 33 36 77 46 6 52 26 33 59 0 (5s) 0 77 60 8 67 l0 33 43 77 50 6 56 2t JJ 55 8l t4 2 l6 6 33 99 83 (3) (0) (4) 87 JJ t20 7t 50 7 57 t5 J5 48 o 0 t20 13 The DSM line reflects differences in Class 2 DSM resources between the 2017 IRP Update resource portfblio and the 2017 IRP Preferred Portfolio, which includes a level of 20 l6 Class 2 DSM (8 I MW) that was not incorporated in the load forecast forthe 2017 IRP. The 2016 Class 2 DSM forecast of 81 MW was accounted forby adding an existing Class 2 DSM resource in the load-and-resource balance; this adjustment was not required for the 2017 IRP Update because the 2016 projected embedded Class 2 DSM is included in the load forecast. 45 PACIFICORP -2017 IRP UPDATE CTupTeR 4 - Loeo-eNo-RESoURCE BALANCE UPDATE Figure 4.4 through Figure 4.7 are graphic representations of the above tables for the 2017 IRP Update annual capacity position for the summer system, winter system, east balancing area, and west balancing area, respectively. Also shown in the system capacity position graphs are the capacity contribution from Energy Vision 2020 wind resources and uncommitted FOTs, which as discussed above, are provided for informational purposes. Figure 4.4 - Summer System Capacity Position Trend l2,ooo 10,000 8,O00 6,000 4,OOO 2,OOO o 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 []lll West trxisting Resources I East Existing Resources r New EV2O20 Wind Uncommitted FOT's to meet remaining Need +Obligation + 139/0 Planning Reseryes +Obligation East Existing Resources West Existing Resources 46 PACIFICoRP _201] IRP UPDATE Cueprgn 4 - LOAD-AND.RESOURCE BeIeNcg UPDATE Etgqe i rz.ooo I O.(X)O 8,O00 6,O00 {.ooo 2,000 I 2.OO0 10,000 8,000 6,OOO 4.000 2,OOO 4.5 - Winter System Capacity Position Trend U o 2018 2019 2020 2021 2022 2023 2024 2025 tr- West Existing Resources rNew EV2O20 Wind *Obligation + 139lo Planning Reserues 2026 2027 202a 2029 2030 2031 2032 2033 2031 2035 2036 - East Existing Resources Uncommitted FO'f's to meet remaininq Need +Obligation Figure 4.6 - East Summer Position Trend 20ta 2019 2020 2021 2022 2023 2024 2025 2026 2027 202a 2029 2030 2031 2032 2033 2034 2035 2036 IEast Existing Resources r New EV202O Wind East - Uncommitted FOT'S to meet remaining Need -GObligation + l3yo Planning Resenes +East obligation o 13oZ Reserues East Existing Resources West Existing Resources East Existing Resources 47 I 37o Reserves PacIpICOnr _ 2OI7 IRP UPDATE CHeprsR 4 - Loeo-aNo-RESoURCE Bal-aNcr UPDATE 4.7 - West Summer Position Trend t2,ooo I O,00() West Existing Resources 8,OOO I E o.ooo l-rl=l 4,OOO 2,000 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 202a 2029 2030 2031 2032 2033 2031 2035 2036 r \[est f,xisting Resources West - Uncommitted Fot's to meet remaining need +Obligation + 137" Planning Reseroes -swest obligetion Energy Balance Results The capacity position shows how existing resources and loads, accounting for coal unit retirements and incremental energy efficiency savings from the 2017 IRP Update resource portfolio, balance during the coincident summer and winter peak. Outside of these peak periods, PacifiCorp economically dispatches its resources to meet changing load conditions taking into consideration prevailing market conditions. In those periods when variable costs of system resources are less than the prevailing market price for power, PacifiCorp can dispatch resources that in aggregate exceed then-current load obligations facilitating off system sales that reduce customer costs. Conversely, at times when system resource costs fall below prevailing market prices, system balancing market purchases can be used to meet then-current system load obligations to reduce customer costs. The economic dispatch of system resources is critical to how PacifiCorp manages net power costs. Figure 4.8 provides a snapshot of how existing system resources could be used to meet forecasted load across on-peak and off-peak periods given the assumptions about resource availability and wholesale power and natural gas prices. This snapshot does not reflect energy from Energy Vision 2020 wind resources. At times, resources are economically dispatched above load levels facilitating net system balancing sales. At other times, economic conditions result in net system balancing purchases, which occur more often during on-peak periods. Figure 4.8 also shows how much energy is available from existing resources at any given point in time. Those periods where all available resource energy falls below forecasted loads are highlighted in red, and indicate short energy positions without the addition of incremental resources to the portfolio. During on-peak periods and during off-peak periods, there are no energy shortfalls through the 2027 time frame, however, the forecast shows on-going net balancing purchases in all years beginning 2018. l) 48 5,000 4,000 3,000 2,000 1,000 0 nr$,""" r"J J o;^ -"*' op J C ."a' oP .J C ."$ "P J Ct 'J "/,J On-Peak Energy Balance rEnergy at or Below Load - Energy Shortfall rNet Balancing Sale Energy Available - Net Balancing Purchase -Load 5,000 4,000 3,000 2,000 1,000 0 of oi* ore ,J o$ o$ oP ."$ oP Jo/ o$ o/ ,"$ "t' J C' .,.*'.,u, .,J Off-Peak Energy Balance r Pnsrgy at or Below Load r Energy Shortfall -Net Balancing Sale Energy Available - Net Balancing Purchase -Load Pe,crr,rConp 2017 IRP UPDATE CuaprEn 4 LoAD-AND-RtSOUnCn Brrt.nNCE UpDA tE re 4.8 -Positions 49 PncIpIConp 20IT IRP UPDATE CHaprEn 4 LoAD-AND-RESoURCE BalRNcs Upoarn, [This page is intentionally left blank] 50 PaCrpIConp 20I7 IRP UPDATE Cue.pTgn 5 _ MODELTNG AND ASSUMPTIoNS UPDATE CueprER 5 - MooELING AND Assul,rprroNs Upoerp Consistent with the 2017 IRP, the study period for the 201 7 IRP Update is 201 7 -2036, with a focus on the 2018-2027 planning horizon. Updated resource portfolios were developed assuming a l3 percent planning reserve margin consistent with the stochastic loss-of-load-probability study included in the 2017 IRP. PacifiCorp has updated certain general assumptions in the 2017 IRP Update from the 201 7 IRP as discussed below. Inflation Rates The20lT IRP Update model simulations and cost data reflect PacifiCorp's corporate inflation rate schedule unless otherwise noted. A single annual escalation rate value of 2.27 percent is assumed whereas 2.22 percent was assumed in the 2017 IRP. The annual escalation rate reflects the average of annual inflation rate projections for the period 2017 through2036, using PacifiCorp's December 2017 inflation curve. PacifiCorp's inflation curve is a straight average of forecasts for gross domestic product and consumer price index. Discount Factor The discount rate used in present-value calculations is based on PacifiCorp's after-tax weighted average cost of capital (WACC). The value used for the 2017 IRP Update is 6.91 percent, updated for the 2017 Tax Reform Act that reduced the federal income tax rate, up from 6.57 percent in the 2017 IRP. The use of the after-tax WACC complies with the Public Utility Commission of Oregon's IRP guideline 1a, which requires that the after-tax WACC be used to discount all future resource costs.lPresent-value revenue requirement values reported in the 2017 IRP Update are reported in January 1,2017 dollars. Production Tax Credits (PTCs) The 2017 IRP Update model applies PTC benefits for eligible resources on a nominal basis rather than on a levelized basis. This approach better reflects how the federal PTC benefits for these projects will flow through to customers, conforms the treatment of PTC benefits with other costs and benefits that are not actually spread over the life of an asset, and appropriately weights the contribution of PTC benefits in present-value calculations. t Public Utility Commission of Oregon, Order No. 07-002, Docket No. UM 1056, January 8,2001 51 General l PACIFICORP - 20 I7 IRP UPDATE CuepTER 5 - MooaLNC AND ASSUMPTIONS UPDATE Front Office Transactions (FOTs) FOT modeling assumptions have not changed from the 2017 IRP to the 2017 IRP Update. Three types of FOTs are modeled: an annual flat product, a heavy-load hour (HLH) July summer product, and a HLH December winter product. An annual flat product reflects energy provided to PacifiCorp at a constant delivery rate over all the hours of a year. The HLH transactions represent purchases received 16-hours per day, six-days per week for July and December. Table 5.1 reports the FOT resources included in the 2017 tRP and 2017 IRP Update modeling assumptions, identifying the market hub, product type, annual capacity limit, and availability associated with the product. PacifiCorp develops its FOT limits based upon its active participation in wholesale power markets, its view of physical delivery constraints, market liquidity and market depth, and with consideration of regional resource supply. Prices for FOT purchases are associated with specific market hubs and are set to the relevant forward market prices, time period, and location, plus appropriate wheeling charges, as applicable. Table 5.1 - Maximum Available Front Office Transaction Quantity by Market Hub Stochastic Parameters PacifiCorp has not modified its stochastic parameters from the 2017 IRP in its 2017 IRP Update modeling assumptions. PacifiCorp provided a detailed description of its stochastic parameters and their development in Volume II, Appendix H of the 2017 IRP. While PacifiCorp discussed its short-term correlation estimation process and calculation in Appendix H of the 2017 IRP, the discussion did not include descriptions of the reason for the (sometimes) low correlations subsequently requested by the Public Utility Commission of Oregon.2 2 See discussion and requirement to explain the reasons for the (sometimes) low correlations in the short-term forecast pursuant to the Public Utility Commission of Oregon's 2017 IRP acknowledgement order issued April27, 2018, Docket LC 67. Micl-Columbia (Mid-C) Flat Annual ("7x24") or Heavy Load Hour ("6X16") Heavy Load Hour ("6X16")375 400 375 400 400 400 Caldornia Oregon Border (COB) Flat Annual ("7x24") or Heavy Load Hour ("6X16") 100 100Nevudu Oregon Border (NOB) Heavy Load Hour ("6X16") 300 300Mona Heavy Load Hour ("6X16") 52 Market Hub/Proxy FOT Product Type Available over Study Period Megawatt Limit and Availabitity (Mw) Summer (July) Winter (December) PeCIpIConp - 2017 IRP UPDATE CHApTER 5 - Moosr,rNc ANo AssuuprroNs UpDATE The drivers for deviations can be different for different stochastic variables. One event can impact a different combination of stochastic variables than another event. For example, load deviations are usually due to weather/temperature deviations; generation deviations can also be driven by weather deviations, renewable resource forecast deviations, and unplanned generator unit outages. Power market prices can be affected by drivers that affect either load or generation, as well as the unit commitment stack and the current marginal resource. For all of these categories, deviation events which impact one part of PacifiCorp's system do not necessarily affect other parts of the system, due to its geographic diversity and transmission constraints. An example of low correlations from the 2017 IRP stochastic parameters is the correlation between Kern-Opal natural gas price deviations, which can be caused by weather deviations in PacifiCorp's east balancing area, and hydro, which is primarily driven by weather deviations in PacifiCorp's west balancing area. Another example from the same table is the correlation between Mid-C power market price deviations, which can be caused by drivers such as northwest weather deviations or resource mix, and Wyoming load deviations, which can be driven by planned or unplanned changes in industrial customer usage. Other examples include low correlations between different load areas, which have deviations driven by local weather deviations and customer types, and low correlations between west power markets (COB and Mid-C) and east power markets (PV and 4C), which have deviations driven by regional factors, such as weather deviations, resource stacks, and planned and unplanned outages. Flexible Reserve Study Appendix A of the Public Utility Commission of Oregon's 2017 IRP acknowledgement order issued April27,2018 in Docket LC-67, states that "[n the IRP Update, PacifiCorp will model natural gas and storage for meeting flexible reserve study needs." Due to the timing of the issuance of the order following completion of analysis supporting the 2017 IRP Update, PacifiCorp was not able to conduct an updated flexible reserve study to fully incorporate this requirement but plans to update its flexible reserve study in the 2019 tRP. PacifiCorp's supply-side tables, Table 5.5 and Table 5.6 included in later discussion in this chapter, includes a variety of natural gas and storage resources, which can help meet the flexible reserve obligations associated with the company's portfolio. PacifiCorp recognizes, however, that while the IRP models include flexible reserve obligations, they may not capture all of the value associated with flexible resources such as natural gas and energy storage resources, particularly intra-hour. For instance, flexible resources can provide additional net benefits when dispatched in the energy imbalance market or when they defer transmission and distribution system upgrades. PacifiCorp plans to further explore where possible, the additional benefits and resource potential for various flexible resource applications, including natural gas and storage, in the 2019 IRP. Natural Gas and Power Market Price Updates Portfolio modeling for the 2017 IRP Update was prepared using PacifiCorp's December 29,2017 official forward price curve (OFPC). OFPCs are produced for both natural gas and power prices by point of delivery. For both natural gas and power, PacifiCorp's OFPCs are developed using forward market prices in tandem with a fundamentals-based price forecast. The first72 months of the OFPC, beginning with the prompt month, represent broker quotes or settled forward prices per the end-of-quarter quote date, followed by l2 months of blended prices that transition to a market fundamentals-based forecast, starting in month 85. 53 l PacIpIConp _201] IRP UPDATE CHAP.I I,R 5 _ MODEI-tNG AND ASSiJMPTIONS UPDA.III For the natural gas OFPC, the fundamentals-based component is developed using expert third- party forecasting services with consideration given to underlying supply/demand assumptions, forecast documentation, peer-to-peer forecast price comparisons, date of issuance, location granularity, and forecast horizon. For power, the fundamentals-based component is produced using AuroraXmpn (Aurora), a production cost simulation model. PacifiCorp's fundamentals-based natural gas price forecast is a key driver the electricity price forecast produced using Aurora. For wholesale power prices, PacifiCorp uses hourly price scalars, which are applied to monthly on-peak and off-peak prices in the forward price curve, to derive hourly market price profiles that vary by month and day type (i.e., weekdays, Saturdays, and Sundays/trolidays). The shape of the hourly price curves or scalars were updated to reflect one year of day-ahead hourly market price data available from the California Independent System Operator (CAISO). Prior to implementing this update, PacifiCorp used five years of hourly Powerdex price data to develop its hourly price scalars. The company's review of the Powerdex data shows that the five-year price history is not supported by a significant volume of reported transactions and that the resulting hourly price shapes do not align with hourly prices observed in operations that are being increasingly influenced by growth in solar resources across the region. The updated hourly price scalars are supported by a large volume of market transactions and produce hourly price profiles that are more aligned with operational experience. Figure 5.1 shows average hourly price profiles as derived from historical Powerdex alongside hourly price profiles derived from historical CAISO data, which is used in the 2017 IRP Update. In both figures, the hourly price profile is based on the average hourly prices from representative months (January, April, July, and October). 54 PaCIpICORp - 2OI7 IRP UPDATE CuaprER 5 - MODELTNG AND ASSUMPTToNS Upoe.rE re 5.1 - Scalars Natural Gas Market Prices PacifiCorp's December 2017 natural gas OFPC reflects a fundamentals-based forecast, issued November 2017, heavily influenced by a cost-effective domestic supply expansion largely due to growth in the Marcellus, Utica, and Permian plays. The October 2016 natural gas OFPC, which was used in the 2017 IRP, was based on an expert third-party long-term natural gas price forecast issued August 2016. A significant price driver, since August 2016, has been the "rediscovery" of the Permian basin. The Permian basin, located in west Texas and southeast New Mexico, is becoming as well known for gas as it is for oil. It has been in production since 1920 but horizontal drilling and fracking have liberated oil volumes, consisting of 20 percent - 50 percent natural gas, previously untouched. Moreover the Permian contains six to eight geological formations, stacked on top of each other, with each layer being its own reservoir. Thus, producers can access multiple reservoirs from the same acreage. This stratification coupled with the potential for triple cash-flow streams (from crude, natural gas, and natural gas liquids) yields low break-even prices with the associated gas being ultra-low cost.3 It is produced solely as a by-product to oil drilling and its production is indifferent to the price of natural gas. Thus, associated gas volumes may continue to enter the market even when it is seemingly uneconomic to develop other natural gas resources. Figure 5.2 compares the nominal annual Henry Hub natural gas prices from the October 2016 (2017 IRP), and December 2017 (2017 IRP Update) OFPCs. 140 r30 1203 rroI roo de0380 870 r99o)u ?oo E30 20 10 0 I 2 3 4 5 6 7 8 9 10111213141516t7t819202t222324 +2021Price Profile **-2036 Price Prohle Former Method (Powerdex)Current Method (CAISO Day Ahead) 140 130 120 3 ll0 ? roo Sqofro870€60isoo40 il0 20 l0 0 | 2 3 4 5 6 7 8 9 1011121314151617t8t9202t222324 .+.2021 Price Profile e2036 Price Profile 3 Land Rush in Permian Basin, Were Oil Is Stacked Like a Layer Cake, January 11 ,2011 , New York Times. 55 /* \ PacmlConp - 20 I 7 IRP UPDATE CHAPTER 5 _ MoogljNc AND ASSUMPTIONS UPDATE (r-Hub Natural Gas Prices ominal Power Market Prices The natural gas fundamentals forecast described above is a key input to the Aurora model, and consequently, the gas curve shape is reflected in wholesale electricity prices. Figure 5.3 and Figure 5.4 compare the average annual flat and heavy-load-hour electricity prices for the Palo Verde market hub from the October 2016 and December 2017 OFPCs; Figure 5.5 and Figure 5.6 show the comparison for the Mid-Columbia market hub. 8.00 7.00 6.00 s.00 4.00 3.00 2.00 1.00 0.00 oo or\ O c.l co $ tr) \O f- oO O\ O * N ca $ r \O# C.l N N C..l a.l N c] N c'..1 c{ ca cA .O .o ca ca cA 999V9VVV99VVVVVVVVc.l c\ a.l cn (\ c.i a.! c.l c\ ci c.l N c\ a.l c-.1 N c'.1 c.l c.l ozz 6 z -2017 IRP_Upd (Dec 2017)- -2017IRP (Oct 2016) -- -a - a)-.)- 56 PACIFICORP _ 2OI7 IRP UPDATE CHepren 5 - Moopr-Nc AND AssuMpnoNs UpDATE OO O\ O N cO S'.a) \O t-- OO O\ O r (..l cA $ 1r) \Or c.l c.l N c\ N c..l N c\ o..l c\ co ca .o ao e.l ca covvvvvvvvvvv99v9999u(-{ c.l an (.{ N c.l N c.l a.l a.l C.l N (-.l c.l c\ N c.l N N 70.00 60.00 50.00 40.00 30.00 20.00 10.00 az @ E Z -2017 IRP_Upd (Dec 2017)- -2017IRP (Oct 2016) a) -a- 0.00 5.3 -Annual Flat Palo Verde 5.4-A Annual Load Hour Palo Verde Prices omrn Prices O - N cO $ tr) \O I-- OO O\ O * an ci * (r) \ON C.l N N C.l C.l N N a'l N cA cO cO ca ca .a cOvvvvvvvv9v9vv9999o.l c\ N c.l N N a.l N ..t (-..l c.l N N c.l N (..l c.l @ oz 10.00 @ c.I -2017 IRP_Upd (Dec 2017)- -2017IRP (Oct 2016) O- 0 00 70.00 60.00 50.00 40.00 30.00 20.00 N 57 - Pa.crprConp -2017 tRP UPDATE CHAP.IER 5 _ MooeI-nc AND ASSUMPUONS UpoarE -- aa sca --a)a-- @o\ - -2017IRP (Oct 2016) -2017 tRP_Upd (Dec 2017) 70.00 60.00 E s0.00 ca E +o.ooz ? :o.oo z 20.00 10.00 0.00 N Oc.l .a$n\Ot--ooo\N c.l c.l c.l N N c.l N c'.1 N9999999999N c.l c.l c.l c'.1 N c..l N c.l c..l lr)\oaa ca NN O+a.lcoca ao ao co9999N a.l c.l ..1C\N re 5.5 -Annual Flat Mid-Columbia Prices omrn 5.6 -Annual Load Hour Mid-Columbia Prices On March 28,2017, President Trump issued an Executive order directing the U.S. Environmental Protection Agency (EPA) to review the Clean Power Plan (CPP) and, if appropriate, suspend, revise, or rescind the CPP, as well as related rules and agency actions. On October 10, 2017, EPA issued a proposal to repeal the CPP and the public comment period on EPA's proposal closed April 26,2018. In addition, EPA published an Advance Notice of Proposed Rulemaking in the Federal OO O\ O c.i ca S tr) \O f- oo O\ O N .a $ tr) \O - 6l N N N 6l c.l c.l c.l N cn ca ca ca .a co cO cA999999999U9999999V9c.l an a{ N N 6l a.l C.l C.l c.l N a..l (...l c..l c.l c.l C.l N N - -2017 IRP (Oct 2016) a) -a O .r- - -2017 IRP_Upd (Dec 2017) 70.00 60.00 E 50.00 ca E +o.ooz !:ooooz 20.00 10.00 0.00 -a- 58 a Carbon Dioxide Emission Policy PACIFICoRP - 20I7 IRP UPDATE CHApTER 5 - Mooer-rNc AND AssuMprroNs UpDATE Register December 28, 2017, seeking public input on, without committing to, a potential replacement rule. The public comment period for the Advance Notice of Proposed Rulemaking concluded February 26, 2018. Given the current status of the CPP, PacifiCorp does not assume applicability of any CPP emission limits in the 2017 IRP Update however, in the 201 7 IRP Update, PacifiCorp does assume a medium COz price as shown in Figure 5.7 below. re 5.7 - Medium COz Price The cost for supply-side 50 MWac solar photovoltaic (PV) projects are updated to reflect lower market costs for PV modules and mounting structures as well as the 30 percent tariff on imported modules. Engineering and owner costs are decreased slightly to reflect increasing levels of certainty for large commercial PV projects. The levelized cost of energy calculated from these updated cost assumptions are more reasonably aligned with power-purchase agreement bids that submitted into the recent 20175 Request for Proposals. Projected costs, in real terms, during the 2O-year study period continue to reflect a downward trend as in the 2017 IRP. Figure 5.8 shows the nominal year-by-year escalation percentages for wind, solar and other resources. Wind and solar escalate below other resource options due to declining cost curves for these resources. $14 $12 sl0 $8 $6 s4 $2 $0 ,$r$.Crs,"T"d'rSr{FrSr$,tr$rs,""P"pt"f, ,{i"ofrs-r$.us' -Mediurn 59 Resources 25% 2.0% 1.5% t.0% 0.5% 0.0% -0.5% -1.0% -15% -2.0% -2.5% -3.0% no$ro.ororors)rof;of,of,of,olt o4rol*rof"us,ors)rs?"pf,eorof,ort o4rs.rd+N -Wind -Solar -Other Resources PRcIpIC<IRp -20I] IRP UPDATE CHAPTER 5 - MoDELTNG AND ASSUMPTIONS UPDATE 5.8 - Nominal Y ear Escalation for Different Resource Table 5.2 reports the updated cost assumptions for new single-axis tracking solar resources. Table 5.2 - Updated Cost of Solar Resources - (50 MWec Single Axis Tracking) Utah/Single Axis Tracking s 1.392 $ 19.690 $ 1.800 s 19.410 Oregon/Single Axis Tracking $1.421 st9.720 $1.114 s 19.440 60 Location/Technology 2017 IRP Update 2OIT IRP Total (with Owner's Costs) $/Wac Fixed O&M $/kW-year Total (with Owner's Costs) $nilAC Fixed O&M $/kW-year 2017$2016$ PAcIpIConp _2017 IRP UPDATE CHeprER 5 _ MODELTNG AND ASSUMPUoNS Upoarg The resource capital costs for wind resources have been updated to more closely align with market data for wind turbine and construction costs, as informed by bids submitted into the recent 2017R Request for Proposals. Market conditions, more precise construction bids, and technology changes led to cost reductions on a $/kW basis. As was the case in the 2017 IRP, PacifiCorp continues to assume that that new projects will be built on leased land, and consequently, PacifiCorp has not updated its fixed operations and maintenance (O&M) cost assumptions since the 2017 IRP. Table 5.3 summarizes the updated cost assumptions for new wind resources. Table 5.3 - U Cost of Wind Resources The 2017 IRP Update provides updated capital cost information for battery energy storage as summarized in Table 5.4 below to reflect an update to capital costs, provided by DNV GL, based on installations and contracts that have been executed for the installation of energy storage systems in 2016 and 2017. DNV GL's "Cost Update to Battery Energy Storage Study" is included as Volume II, Appendix P to the 2017 IRP. The average one-MW battery costs are estimates of the total installation costs to PacifiCorp in2017 dollars. A change was made to the way lithium-ion battery costs were calculated. The original20lT IRP costs for lithium-ion batteries were averaged costs for NCM, LiFePO4, and LTO batteries. For the 2017 Update, it was determined that the company is unlikely to procure LTO batteries, so updated lithium-ion battery costs are based on average costs for NCM and LiFePO4battery systems. Note that the costs represented in this update are averages based on the following assumptions: Using a standardized 2O-year life required different operating profiles for the three battery types listed. Both lithium-ion and sodium-sulfur batteries had similar profiles with 365 cycles per year: about halfofthe days at an 80 percent depth ofdischarge (DoD), and about half of the days at a 20 percent DoD. This is a very simplified way of representing actual complex usage profiles which may vary greatly depending upon use cases. Flow batteries are assumed to be capable of operating at 500 cycles per year at 100 percent DoD. Costs were developed using a proxy site, and an average additional owners cost of 2l percent. Depending on the location, owner's costs may vary from less than l0 percent to greater than 40 percent. $ 1.465 $36.455 s r.800 $36.4s5Washington st.444 s36.455 $1.114 $36.455Oregon s 1.47s s36.455 $ l.8l 1 s36.4s5ldaho $1.4r3 s36.4ss $ 1.73s $36.455Utah $ 1.415 s36.455 $ l .737 s36.4ssWyoming 6l 2017IRP Update 2OTT IRP Capital Cost $/kw Fixed O&M $/kW-year Capital Cost $/kw Fixed O&M $/kW-year 2017$2016$ Location PaclrIConp - 20 I7 IRP UPDATE CuapTen 5 _ MODELING AND ASSUMPTIONS UPDATE Costs were validated against actual U.S. projects listed in the U.S. Department of Energy's Global Energy Storage Database. For sodium-sulfur batteries, only projects with NGK batteries in the six to eight MW range were listed. Therefore, sodium-sulfur batteries in the one, two and four hour options are considered to unavailable (N/A). Table 5.4 - U Cost of 2017 Dollars Due to extension in federal production tax credits (PTCs) and investment tax credits (ITCs), the levelized cost of renewable resources are lower, not only due to updated capital costs and O&M costs, but also due to the nominal treatment of tax credits to more closely align with how these credits would get passed through to customers. Table 5.5 shows updated costs of the renewable resources with and without applicable tax credits, considering timing of construction and in-service dates. First year real levelized costs for wind and solar resources are presente d for 2017 , assuming a 2018 wind project meets IRS guidance demonstrating the project began construction by January 1,2017, and for the last year in which PTCs (wind) and ITCs (solar) are phased down. Wind and solar resources with online dates between 2019 and 202312024, the tax credit period, were considered in the company's analysis. Solar lTCs are now treated as an upfront benefit rather than being amortized over the life of the asset. This approach is more consistent with how independent power producers can price ITC benefits into PPA prices. Levelized costs for Pacific Northwest wind projects are shown at 38 percent, reflecting the upper range of performance anticipated from wind facilities in the region. For modeling purposes, a commercial operation date of January I is assumed, which is a proxy for December 3l of the prior year. The cost for Energy Vision 2020 new wind resources are also shown in the Table 5.5 and Table 5.6, which reflect the aggregate cost of winning company-owned bids from the 2017R Request for Proposals, but presented in 201 7 dollars. 62 Average I MW Battery Costs Standardized ata20 year life.2hours | 4hor., Duration I hour 8 hours 8MW 4 hours 1,319 1,014 862 786 831Installed Cost, $/kWh energy storage Installed Cost, $/kW 1,319 2,029 3,449 6,289 3,324 N/A N/A N/A 1,036 N/AInstalled Cost, $/kWh energy storage Installed Cost, $/kW N/A N/A N/A 8,286 N/A 1,936 1,365 1,080 937 1,049Installed Cost, $/kWh energy storage Installed Cost, $/kW 1,936 2,731 4,320 7,499 4,195 Lithium Ion Sodium Sulfur Flow aa ccicc 6dddt-Et>d--caz.-a,e 3 > dd66dEt-Eii d6-Ett>ooL^ .E ccxi=oa=z B6= >dd66d>>>>E >>>i>>E>>ddd6 666dil-E> ri N-?^z=7i. = ddd66 .E>>>-E r ?,> -d;4 l, :, .E ddddd ddncd.E>>>>d666tltt dddd qo oQooo oo cov\ t d6ddd>>>>>>i-Et>dd6d>i.--E o t! U{ t !;i>._ or= 9!^\ * - u SE*=EiJara* .E $9+$$sjqiUee nlnn.to@a9a66606 6rr++*++*i6*jo r++rr+d6odoi ro 6r"=*^.!dy !.EO- Eeeqq aooo6 oooo EEEE codo,>, U> oo U 2v-?i ev o+h66@$r--+++t+ 6+hr,hO+r--+++<<,i -i -i.j j 388533i+.or..1 dl a. 1. 660ro hhh6.l al at al 6nal at al al.s& a 6(to6m cal al at at al alar at at ct al al at al al al s$$$tal at al at at al al al al al at ol al al ot at al ol *tidat al al alcQooal ot al al oo ? t o5-c-aoccc h6hh hh66z'= >z 2.>U 3gE=g 88'2'2 ? 4{,8 I 88888h66hh.j-i++.d 88888 -:--i++a 8888h6€€++{-f 8888r) ul *. €.tnss fEPEq:LLAS o-\-\q6388ts; Fi i.I rr 3o .r ai ! .r') aax,3zxt-B rrrr(JOOOO-.." ." -" -" F; 60m6souoou 6n353EzEEP>>>>=zZZAZ oi ci ci oi ri !9!rYL:Liio^{a-e-oXY SEXXF.r o 5 Y_ "t rt ., )Szx-) rrreUUUUU.. 6€@--6660+ouooo 9D9bD2'E=E ocoo6oi ci oi ci ri OQUL) oFi(iioi6(i6 U CI: qr (J 9.l 60 tf<H;X<Flf;i Srj orSz oe6\Ci6ACA\d1!:+Y=Y.ro9o.ro9o'E d f cE d f c =2928292e> 9i 9> 9>i>2>=>=>q>q>q>q>_4.6 _h6 ->- h-O d O .r Q 6 o .r OUUU .Iu{ {sX O--o-U-.o-eXaXeIqI<i=Fi<nn-S - ui S y uoi6-qio^E^H-.t;i;t; ! 6 U d- 6 U d r292r292o > d: u: d -\ =>2>=>2>?>?2?:?>36464\^Z't^O 6 O .r C 6 O .r 2222 :> r b EAto J alrt ar ? > zooal a ccccc ddddoaQoaaaa _(-E-(-E aaa0 a! oc aa'r t- q)(.) ,r)0) 0) aI a =I m ra 0) F i- o)az tr )(A v1 Z Z,-]rl]oo I &t!F EU aF f, & F- a't c, I =., $\o U I! /44 Fv o1o a-€@Nrd60---.io6i rdi+*+oo4@4@@ O-A€Nrd-o---.io.irod+++o-6A@4@ -€NrO-AA$r66!!sNaq@@ -&NrO-@@+r€oiNNNNG446 ne a3 J a 2{ o rr F 6ct<iN Oc rr O o\ di v] d rrrrr6h6r6rjNrrr----o oooo- NNNdd rididididi r^6ra6htt$t$a(ja<r€----- rrrrr6h660rrrrr -6--O o-ooc:::AA NdNNd €€€aaooooodi di -i di ci n6666$$$t$----- N6$Nrarrod6od6 OOOO r€r€NddN h-rS$+t+d6d6 N6+dr€rrod6da aaaa OOOO r€r@NdNN aa99tt$t n-r+t+(+ododoi ro or O-A C oo88 ro$o6r OO cci ts 3 2'=a:, s U P (.) 2€ U U -=L! i)- E F'*d> al-I o\ al 6t€-6-6r+6+6i +ddooooo 444G@ 9€AA€ rrrrr 6*6669$r--+++++--: --: --t --: --i@4@O4 -$€-6-Gr+6+.i+cidocooo o@4@@ €64@@ rrrrr h+h6ha$r--*++++--i --t -i --: --.:404@4 NdNNrrrrrrrr +dor600N66++--.t -i -t -:4GAq o6@-$orirod 4e@ c NNNNrrrrrrrr +NOroooN66++-.t -.t --a --:aGe@ o6€-sorirdi @64 roridNO 66 6O c.i -i L b - F >E CC a 6h6hh hnhhn --t$9 hh66+s+*h6@@*+*+ I ln 9r :d oE llL,,= +.s 2 .E Z al N 9;:-^i,FiY9=o. o-\^\q'@ =558?90 S Is I HNOd= - N N '' >Scaxr) ?9-)Lr!r!EEOOOOO.o \o\o\o\o; 6€@--6m60* ooooo.E .E .E .E .E333!!hhh!h +=:==22222OOOOO.i 6i oi 6i di a\):--t,l--!r9-G =x"sa=-v$J$EXxxRNOo:i. n n .. )-3*,;s7 -9-rLrrrr(JOOOO.o \o \o \o \o ;n-€€--oo66+ooooo.S .E .E .E .E!!3!!3aa1a <=<=<zzzzzOOOO-.i .i .i 6i di UU!,9 -v-^v^N c., X I <..., IoH{HuIi(E oF=EUFSF<X;X<xKxSioiSczocz€i.E-6-.9^ N o ? oN o ? os 6:6s c f, Gi->L>i->L> E2.!22E2.!22o .\ d .\ o > d -\ =>2>=>2>q>2>q>q> -Z, n -E, n -l, n -E, nO-OdO6ON a??- UUQQ -v_^v^s r -< x., x1v=^vAel(Yqr(r "+S+"wNwuqJ-q!(rt!-tlliai:1K1a: L dL o\ d ild@- tr-64 C^s;::x:E:E 6 i 6E 6 i d:->L>:->L> r2-.928232o > {> o > d: =>2>=>2>q>q>q>q>-L,n -l,o -l,o.ts oO6 Od Oo od aaaa E >azaoir>>z6n 1a. Eco llL q) GF 0)I ar)o)il, q) OI a q) I\o ra() F t!F o f,az E aa oz lJ Z --.1 Ir..io I !t- () tr.lF o f, t-- c\ I (-) E U o. v^) d ! o: oo0 o o o3i q) F q) C' U)q) c) aI a D I () \o V; OJ c!F ?zPEt.?l t € N -60r6€6QQOrrd6$atatal6d o$o66Rq9\\ 660t6 ogQr90ctIrdi .1 6 -o$.a NO-ol-€*ioidir$+n$ QT6di c ci datolatdn1n.1 n6hn6h €@o6@99999 v+oat€6h+60r6 ato6€rh€Ori+ri$xl-2cr tr e.?rF!J -\a n 9) - z i) F ?e € o n-hO- -r6jjri ci ri -: oi9t+h6 n-nC*.\.11.I-.1 -*O$it66 t-r-d;rd.ihsn6 +ooo*-N'-ri rca-ih$nh 9Nodi -al o 6hh66 oococ n66h6ooooQ atddat499@ atal0tN9A€A 2=driA'= Q qc ocaaaoococ aaoaoooooQ ooooOQQO OO ii I o\oqo 9\o\o\o\o oooooAAAAA ^s^s^<^<s55544 oooooooooooci 8888dodo o\ o\oo od Q z "A oooon ocado oooooaoaao aooooooQ oooooooo oo IT \ J Utr a_- 2 J u I Q >= &EQrr c - c.d s6 ooooo ralA-@n-r€-oioioio<ii+t66 AAA-a66-61 coooQ ral 6-O cicioioxi+++n6 @€€--666o$ ddd6 .l€$@6O+$oi6dijh$6h r+6Odod.t c c c o dddd N€+-€9-$ciodi.i6$6h ri66.loald c c .tO oi ri 9€oo €Nr:r cC @ 66n66 --$$9 h6666--$+9 -.]aIr E] oooc h6€-+++3 oooo s$s$ oooc 2n or?- =da= .,r9 L.:-Eaz +.,! 'r- = o ') .9 azacl al o 9--,,5;.YPFA 5-<s"SB33eE; 3Fr:iii3 sa');9?9;)QrqlrrOOOOO." €€€FF6-6-l .E .S .E .E .E!!!!E33=aa oooo6oi oi oi ci ri 9.^-r,FF99-d 6SStY O d;r q'al.r o d :- cr cr .. ).S.axr)?a)JrrrrruOUOO-" €&€--6-66$ .s .E .E .E .S!!!!!1)a1a 22222oooo6ci oi oi ci ri --9Uuu ro9o.o9.o5Ut '.OAra<Xqii(iiu3+IuI$i<.rj=<X@XSl o-Ss uo1€JEi6^trAd ^rZ - + - rZ -"l 99;de9a E€-.922't2-92D U d: U > d>la-!t9c9414>r>@>q>?>?>q>t4 Bn i's l.nd-d.dd 2222o&&L UUUU v-9-NoN Xu{ '+s*+"sSvuc-r-.-!uq]@il<X=X<nnx S i oil S ai moi6icidAc :).4)jv.rvXaEA.',a!a = F-i: !3E S-:: $-!' !r!' a!2-EZt2-929 > 10> g > 10>r>@>r>@>q>q>?>?> -h---.^h^-4.- ...1r -c -J E olrt i o! :L)- o f, tnzIF Daa z o Z-jh..l z I EIF f(, r!F IJ D t-- N I 9 =U o- PncrprConp - 2017 IRP UPDATE CHAPTER 5 - MoopIruc AND ASSUMPTIONS UPDATE Intra-Hour Dispatch Credit The energy-imbalance market (EIM) provides economically optimized dispatch instructions to participating units of PacifiCorp's fleet of diverse resources every five minutes. Prior to the ElM, PacifiCorp would resolve load-resource imbalances within the hour through manual dispatches of generation within its balancing authority area (BAA). With the introduction of the EIM, whose footprint spans multiple BAAs, the aforementioned imbalances are resolved with least-cost generation sourced from across the EIM footprint, on a five-minute basis. This sub-hourly dispatch process increases efficiency and lowers cost. In addition, the EIM provides PacifiCorp with a way to value the changes in generation within the hour through locational-marginal pricing at five and fi fteen-minute intervals. In contrast to actual operations, PacifiCorp's production cost models used to estimate the economic value(s) of a resource plan over the long term are hourly dispatch models, which cannot capture the sub-hourly benefits/requirements of generation flexibility, or the EIM benefits related to intra- hour economic opportunities. For example, an hourly production cost model can replace a megawatt-hour (MWh) from a generation resource with a market purchase of energy with no recognition of the fact that electricity requirements do not stay constant across the hour. In this scenario, value is lost at the sub-hourly level given that market purchases are fixed products that have no intra-hour flexibility. These discrepancies between modeling and operations created a need to develop an intra-hour dispatch credit in order to capture value realized from sub-hourly dispatches to meet PacifiCorp's load-and-resource changes, as well as transfers across the EIM footprint. The methodology for calculating the intra-hour dispatch credit for units participating in EIM is discussed further below. PacifiCorp's participation in the EIM includes PacifiCorp's submission of a balanced load- resource hourly base schedule. Within the hour, the EIM provides PacifiCorp with fifteen-minute advisory schedules and five-minute dispatch schedules. The determination of sub-hourly benefits incorporates the difference among these three schedules, moving from the hourly schedule to the fifteen-minute schedule and then to the five-minute schedule. By taking into account the cost of generation, a margin is calculated and attributed to a specific unit in a specific interval. This margin represents the intra-hour value reahzed through moving that unit in the EIM. EIM dispatches can be in response to changes in PacifiCorp's load, changes in variable resources or changes in transfers into or out of the BAA. Determination of Intra-Hour Dispatch Credit: Base = Pacif iCorp's Hourly Base Schedule Dts = EIM's Fif teen Mtnute Aduisory Schedule Ds = EIM's Ftue Mtnute Dispatch Schedule Prs = EIM's Ftf teen Mtnute Market Price Ps = EIM's Ftve Mtnute Market Prtce Btd = Paci.f iCorp's Cost of Generati.on Intra - Hour Dispatch Credit = (Drs - Base) x Prs * (Ds - Dr.s) * Ps - (Ds - Base) x Btd 66 PeCIr.IConp 20I7 IRP UPDATE CHepTgR 5 - MoDELING AND ASSUMPTIoNS UPDATE In the 2017 IRP Update, PacifiCorp incorporated unit specific intra-hour dispatch credits as part of its 2017 IRP prefened portfolio and coal studies discussed in Chapter 6. The average intra-hour dispatch credit value is $6.47 kwlyr based on the following units: Dave Johnston Units 3-4, Hunter Unit 3, Huntington Units l-2, Jim Bridger Units 1-2, andNaughton Units l-3. In addition to coal resources providing flexibility to the market, PacifiCorp is also exploring how energy storage resources, such as batteries, have the potential to provide ElM-dispatch benefits due to their ability to respond rapidly with no start-up costs, minimum load costs and an ability to move both up and down across a varying capacity sizes. Some of the items that PacifiCorp is reviewing for potential benefits of energy storage resources are storage capacity, charge and discharge rates, efficiency, and degradation rates. PacifiCorp does not yet have any direct experience with energy storage resources participating in EIM, and market structures for energy storage resources continue to evolve, but as the market continues towards additional renewable generation, incentives will continue to be explored towards resources with low cost minimum operating levels while still supporting integration needs. PacifiCorp anticipates further exploration and discussion of such credits with robust stakeholder engagement as part of its 2019 IRP public input process. 67 Intra-Hour Dispatch Credit Further PacIuConp - 20 I 7 IRP UPDATE CuapTT,n 5 _ MooELTNIc AND ASSUMPTIONS UPDA.TE [This page is intentionally left blank] 68 PecrprConp - 2017 IRP Upoars CuaprER 6 - Rgcroue,t- HazE CnsEs CueprER 6 - RpcroNAL Htzr, Casps Introduction IRP modeling is used to assess the comparative cost, risk, and reliability attributes of different resource portfolios, each meeting a target planning reserve margin. These portfolio attributes form the basis of an overall quantitative portfolio-performance evaluation. This chapter discusses regional haze case definitions and presents study results developed in accordance with action items 5c,5d,5e, and 59 of the 20l7lRP action plan. PacifiCorp used its resource expansion plan model, the System Optimizer (SO) model, and its stochastic risk model, the Planning and Risk model (PaR) to perform these studies under three price-policy scenarios. Regional Haze Case Definitions The four coal resource action items in the 2017 IRP action plan were studied relative to the 2017 IRP Update resource portfolio. [n addition to analyzing known and prospective regional haze compliance requirements, these studies incorporate compliance cost assumptions related to the Mercury and Air Toxics Standard (MATS), coal combustion residuals (CCR), effluent limit guidelines (ELG), and cooling water intake structures as may be required under the Clean Water Act (CWA). Each compliance case drives the timing and magnitude of run-rate capital and operations and maintenance costs for each individual coal unit in PacifiCorp's fleet. For instance, if a specific regional haze compliance case assumes an early retirement for a given coal unit as part of a compliance plan, the run-rate operating costs for that unit are customized to reflect the assumed early closure date. This can include changes to the timing of planned maintenance throughout the twenty year planning horizon and avoidance of future costs related to known or assumed MATS, CCR, ELG or CWA compliance requirements, as applicable. Compliance alternatives for coal units in any given compliance case can include, continued operations through the end of a unit's assumed depreciable life, early retirement, conversion to gas-plant operations, or installation of a selective catalytic reduction (SCR) system to continue operations with reduced emissions. Individual unit outcomes under any regionalhaze compliance case will ultimately be determined by ongoing rulemaking, results of litigation, and future negotiations with state and federal agencies, partner plant owners, and other vested stakeholders. While the regionalhaze compliance cases represent a range of strategic paths to be evaluated, no individual unit commitments are being made at this time. Table 6.1 summarizes key assumptions forregionalhaze compliance cases that address the four coal resource action items studied in the 2017 IRP Update. The 201 7 IRP Update resource portfolio assumptions are also included for reference. 69 PecrprConp 2017 tRP Upoare CHAPTER 6 - REGIONAL HAZE CASES Table 6.1 -al Haze Case NoSCRNOX+2021 NoSC&NOX+2022 NoSCR:NOX+2022 NoSCRNOX+2022 NoSCR;NOX+2022 NoSCRNOX+2022 NoSCR;NOX+2022 Ret.2042 Ret.2042 Ret.20.12 Ret.20,l2 Ret.2042 Ret.20.l2 Ret.2042 NoSCRNOX+2021 NoSCRNOX+2023 NoSCR;NOX+2023 NoSCR;NOX+2023 NoSCRNOX+2023 NoSCRNOX+2023 NoSCRNOX+2023 Re1.2042 Ret.2042 Ret.2042 Ret.2042 Ret.2042 Ret.2M2 Ret.2042 No SCR; Ret.2036 No SCRI Ret. 2036 No G&s Conv. Ret. 201 tl NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022 NoSCR;NOX+2022 Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036 NoSCR;NOX+2023 NoSCR;NOX+2023 NoSCR;NOX+2023 NoSCR|NOX+2023 NoSCR;NOX+2023 NoSCR;NOX+2023 Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036 Ret.2036 No SCR Ret. 2028 No SCR Ret. 2028 No SCR Ret.2028 scP.t2/3tDo22 Ret 2037 No SCR Ret. 2028 No SCR Ret. 2028 No SCR Ret.2028 No SCR Ret. 2032 No SCR Ret. 2032 No SCR Ret. 2032 scR lz3l202l Ret 2037 No SCR Ret.2032 No G6 Conv. Rer. l/30/2019 No SCR Ret.2025 No G6 Conv. Ret.1/30/2019 No SCR Ret.2025 No Gu Conv. Ret. l/302019 No SCR NO SCRRet.2032 Ret.2032 GaConv.l/312019 GsConv.42MW b 6lln0l9 ll3l2019 to 5D0Dol9Ret.2029 Ret.2029 No Go Conv. No G6 Conv. Ret.2020 Ret.2020 No G6 Conv. Ret.1/30/2019 No Go Conv. Ret.2020 No Gs Conv. Rei. 2020 No G6 Conv. Ret. 2020 No G6 Conv. Ret.2020 No SCR Ret.2025 No SCR Ret.2025 No SCR Ret.2025 No SCR Ret. 2025 No SCR Ret. 2025 No SCR Ret.2027 No SCR Ret.2027 scR + 2019 Ret.2027 No SCR Ret.2027 No SCR Ret.2027 No SCR Ret. 2027 No SCR Ret.2027 The following sections describe PacifiCorp's analysis consistent with 2017 IRP action plan items 5c, 5d, 5e, and 59. All studies incorporate updates to forecasted loads, resources, market prices, and other modeling inputs and are compared to the 2017 IRP Update preferred portfolio that includes the assumed retirement dates from the 2017 IRP preferred portfolio in order to assess the present-value revenue-requirement differential (PVRR(d)) for the studied action. PacifiCorp's SO model was used to develop resource portfolios under three price-policy scenarios for a benchmark case (i.e., the 2017 IRP Update preferred portfolio and the alternative compliance scenario. PVRR(d) analyses are used to quantify the benefit or cost of the regional haze environmental compliance alternatives relative to the benchmark for each of the three price-policy scenarios. The PVRR(d) for a given environmental compliance alternative is calculated as the difference in system costs between the two PaR simulations-the benchmark simulation and the alternative compliance scenario. Each of the studies, which are described in more detail in the following sections of this chapter, were perforrned using medium, high and low price-curve scenarios. The medium price scenario is based on PacifiCorp's December 2017 official forward price curve (OFPC), consistent with medium price assumptions used to develop the portfolio for the 2017 IRP Update. Gt Cow.l2Rl/2024 b 6AnO25 R.et.2M2 70 Hunter I Hlnter 2 lluntington I Huntington 2 Jim BriQer I Cholla { Craig I Daw Johnston 3 2017 IRP U@te @ref. Port) 2017 tRP U@te DJ] SCR 2017 IRP U@te 2017lRP Update .tBt &.IR2 SCR NALBtr 2017 IRP Update 20l7IRP UFbte NA[B 42 fr{w (f CHOI,{ GC .lim BriQer 2 Naughton 3 Haze Case Analysis and Results PacrprConp -2017 IRP UPDATE Cuaprsn 6 - RrcrouAl HAZE CASES Figure 6.1 summarizes heavy-load hour (HLH) and light-load hour (LLH) wholesale power prices, natural gas prices, and COz prices assumed for this analysis.l The low price-policy scenario assumes there are no COz prices throughout the planning horizon. Figure 6.1 - Forward Price Curve Assumptions2 Dave Johnston Unit 3 Consistent with action item 5c inthe 2017 IRP action plan, PacifiCorp has updated its analysis of regional haze compliance alternatives and its analysis of the retirement of Dave Johnston Unit 3 by the end of 2027 as reflected in the 2017 IRP preferred portfolio. Dave Johnston Unit 3 is one of four units located at the Dave Johnston plant in Glenrock, Wyoming. The EPA's final regional haze federal implementation plan (FIP) requires the installation of SCR equipment at Dave Johnston Unit 3 in 2019 or a commitment to retire Dave Johnston Unit 3 by the end of 2027 . The major project schedule for Dave Johnston Unit 3 SCR is reported in Figure 6.7 at the end of this chapter. PacifiCorp's updated analysis compares installing SCR equipment by March 2019 with a case that does not install SCR equipment but nonetheless retires Dave Johnston 3 in 2027. This analysis shows that retirement at the end of 2027 without installing SCR equipment is lower cost than installing SCR equipment. t HLH prices cover hours ending seven through 22PPT, Monday through Saturday, excluding holidays. LLH prices cover all other hours. 2 For presentation purposes, power prices reflect the average of Mid-Columbia and Palo Verde prices. Opal is the natural gas market hub most applicable to natural gas conversion alternatives studied in the Naughton Unit 3 analysis. $100 $80 i60 $40 $20 lo € o7. 66 O i r.t6 ? 5 I F- 6 O o' r.l h t r^ €H - at al tt tl tl al el al a{ al 6 aa 6 6 m 6 6ooooooooooooooooooort at at rt rt al rt at tt -t al -t tr at at ^t tl -l rt*NIed *e* High *-Lorv LLE Pow'er Prices 66 O - rl 6 { r^ € l- 6 6 O - rt 6 ? h I - - al Fl.l al rt ^l -l Fl -l Fl 6 6 6 m 6 m 6ooooooooooooooooooott at at al at tl rt 6t Ft at Ft at el at rt rt 6t .t rt*$r&*HEh sl00 $80 $60 $40 $20 $0 oz .a-],Ied qdFl-Low Natural Gas Prices 6 O Q i.t 6 ! 6 I r_- € o\ o r -l 6' n I - H tI tt al Fl tl al a,l tl al al m m m 6 6 6 6oooooooooooooooooooat el Fi F.I at at Ft tt al al al tl tl -! 6l al tt tt tt-+-Ivted +HEh -FLoIl. $10 E,' E$6 E$4-!g E$l $0 CO2 Prices 6 6 O - tl 6 ? r^ E l_- 6 6 O H et 6 ? 6 Ii i.{.1 -l Fl -t tl Fl Fl.l aloooooooaooaooooooooal a.l rl rl r! rl rl rt -t at il et al et et at Ft ct al $35 $30 $25 $20 $lJ $10 $5 $0 Eo a .Ecoz *Nfed Heh 71 PaclprConp - 2017 IRP UpoRtE CHAPTER 6 - RECIONAI HAZE CASES In the case SCR equipment is installed and Dave Johnston retires at the end of 2027, portfolio changes are de minimis when compared to the preferred portfolio. This is expected because Dave Johnston Unit 3 retains the same essential operating costs and characteristics with or without the installation of SCR equipment. The most significant of these shifts in the resource portfolio (changes in portfolio resources are less than 12 MW in all years of the study) is a decrease in renewables additions in 2035. The sole driver for these small portfolio shifts is a slight (two MW) reduction in Dave Johnston Unit 3 capacity associated with the SCR equipment. Figure 6.2 summarizes the cumulative change in resource portfolio nameplate capacity when SCR equipment is installed in 2019 and Dave Johnston Unit 3 is retired at the end of 2027 as compared to not installing SCR equipment and retiring at the end of 2027 wder the medium gas, medium COz (MM) price-policy scenario. Positive values show cumulative resource portfolio additions and negative values show the cumulative capacity of resources that are removed from the portfolio when Dave Johnston Unit 3 is assumed to install SCR equipment and then retire at end of 2027 . There are no notable portfolio changes resulting from installing SCR equipment in 2019 relative to not installing SCR equipment. Figure 6.2 - Cumulative Increase/(Decrease) in Portfolio Resources under the Dave Johnston Unit 3 Install SCR Table 6.2 reports the PVRR(d) impacts of installing SCR equipment in 2019 and retiring Dave Johnston Unit 3 the end of 2027 relative to the 2017 IRP Update preferred portfolio that does not install SCR equipment and includes retirement at the end of 2027 for each of the three price-policy scenarios. =a q) U q) 6l (J n$r$.Croorslnd}rof ,s}rof ,obroilro*rof ,onors)rslrof ,oorof ,orb I DSM r FOTs r Gas a Renewable I Gas Conversion r Early Retirement lRetirement 6 4 2 (8) (10) (12) ) ) ) Q (4 (6 72 PACIFICoRP - 20I 7 IRP UPDATE Cuapren 6 - Rcc;roNnr- HAZE CASES Table 6.2 - PVRR Cost/(Benefit) of the Dave Johnston Unit 3 Install SCR Equipment Case Relative to the 2017 IRP U Preferred Portfolio Price-Scenario The PVRR(d) results are attributed almost entirely to the cost of the SCR equipment, and the slight changes among price-policy scenarios are associated with the impact on system costs associated with slight change in capacity of Dave Johnston Unit 3. The net cost increase in each price-policy scenario does not support installing SCR equipment on Dave Johnston Unit 3. Consequently, PacifiCorp continues to assume retirement of Dave Johnston Unit 3 at the end of 2027 in the 2017 IRP Update. Jim Bridger Units I & 2 Consistent with action item 5d in the 2017 IRP action plan, PacifiCorp has updated its analysis of regional haze compliance alternatives relative to the Jim Bridger Units I and2 in the 2017 IRP Update preferred portfolio. The 2017 IRP preferred portfolio assumed an early retirement date of 2028 for Jim Bridger Unit I and an early retirement date of 2032 for Jim Bridger Unit 2. The Jim Bridger plant consists of four units and is located just outside of Rock Springs, Wyoming. The Wyoming regional haze state implementation plan (SIP) and EPA's final regionalhaze FIP for Wyoming require the installation of SCR on Jim Bridger Units I and 2 by the end of 2022 and 2021 respectively. The major project schedule for Jim Bridger Unit I SCR, and tJnit2 SCR is reported in Figure 6.8 and Figure 6.9 at the end of the chapter. PacifiCorp's updated analysis compares installing SCR equipment on Jim Bridger Units I and2 in 2022 and 2021 respectively with retirement in 2037 versus the 2017 IRP Update preferred portfolio assumption, where Jim Bridger Unit I is assumed to retire in 2028 followed by Jim Bridger Unit 2 in 2032 with no SCR installations. This analysis shows that the early retirement scenario without the installation of SCR equipment is lower cost. In the case where it is assumed that SCR equipment is installed and the Jim Bridger units retire at the end of 2037, the continued operation of the Jim Bridger Units I and2 fills incremental net- capacity needs beginning 2029, driving a lower need for incremental renewables, demand-side management (DSM) and front-office transaction (FOT) resources over the 2029 to 2036 time frame. Figure 6.3 summarizes the cumulative change in resource portfolio nameplate capacity when SCR equipment is installed at Jim Bridger Unit I in 2022 and Jim Bridger Unit 2 in 2021 under the medium gas, medium COz price-policy scenario. Positive values show cumulative resource portfolio additions and negative values show the cumulative capacity of resources that are removed from the portfolio when SCR equipment is installed at Jim Bridger Unit 1 in 2022 and Jim Bridger Unit 2 in 2021. In the medium natural gas, medium COz price-policy scenario, notable resource portfolio changes resulting from installing SCR equipment and retiring Jim System Optimizer PaR Stochastic MeanPVRR(d) Costi(Benefit) ($ million)Low Gas, Zero COz Med Gas, Med COz High Gas, High COz Low Gas, Zero COz Med Gas, Med COz High Gas, High COz Change from 17 IRP Update Pref-Port $e4 $e7 $ 106 s 100 $l0r $ 105 t5 - =a (.)cl clI q) L) ,$r**r*ero"r,ors)rsProf ,$of ,obroilro$ror)r* r DSM r FOTs r Gas a Renewable I Gas Conversion r Early Retirement iRetirement 1 ,000 500 (s00) (1,000) ( 1,500) (2,000) PACIFICORP _ 20 I7 IRP UPDATE CHAPTER 6 - REGIoNAL Heze CesTs Bridger units in 2037 relative to not installing SCR equipment and retiring Jim Bridger Units I and2 early include: The installation of SCR in 2021 and 2022 results in minimal shifts in DSM and FOTs in the years leading up to the retirement dates assumed in the preferred portfolio. Starting in2029, the continued operation of Jim Bridger Unit I with SCR displaces FOTs and DSM. Starting in 2030, the continued operation of Jim Bridger Unit 1 with SCR and the continued operation of Jim Bridger Unit2 with SCR in 2033 displaces renewable resource additions (both wind and solar). Figure 6.3 - Cumulative Increase/(Decrease) in Portfolio Resources under the Jim Bridger Units I & 2Install SCR E and Retire 2037 arro Table 6.3 shows the PVRR(d) impacts of installing SCR equipment at Jim Bridger Unit 1 in2022 and Jim Bridger Unit 2 in 2021 and retiring at the end of 2037 relative to the 2017 IRP Update preferred portfolio that does not install SCR equipment and includes early retirement at the end of 2028 for Jim Bridger Unit I and 2032 for Jim Bridger Unit 2 for each of the three price-policy scenarios. Table 6.3 - PVRR Cost/(Benefit) of the Jim Bridger Units | & 2Install SCR Equipment and Retire 2037 Case Relative to the 2017 IRP Update Preferred Portfolio by Price-Policy Scenario a a a Change from l7 IRP Update Pref-Port $ 157 $179 $ 193 $89 $83 $rs0 74 IIr- PVRR(d) Cost(Benefit) ($ million) System Optimizer PaR Stochastic Mean Low Gas, Zero COz Med Gas, Med COz High Gas, High COz Low Gas, Zero COz Med Gas, Med COz High Gas, Hieh COr PACIFICORP 20 I7 IRP UPOETE CuapTgR 6 REcIoNaI- HAZE CASES The following summarizes observations and results for installing SCR equipment at Jim Bridger Unit I in 2022 and Jim Bridger Unit 2 rn 2021 and retiring at the end of 2037 relative to the 2017 IRP Update preferred portfolio that does not install SCR equipment and includes early retirement at the end of 2028 for Jim Bridger Unit I and 2032 for Jim Bridger Unit 2 under medium natural gas price, medium COz price-policy scenario: o Fuel costs increase due to the extended years of Jim Bridger Units I and 2 operation beginning in2029 and the displacement of renewable resources and FOTs which do not carry a fuel expense.o Extended operations of Jim Bridger Units I and 2 reduces system balancing purchases, offsetting fuel cost increases. . SCR installation in202l and2022 increases capital costs.o Extended operations of Jim Bridger Units I and 2 increases emissions costs relative to the preferred portfolio. o Offsetting costs and benefits result in a net $83 million cost (PaR stochastic mean), as the value of extended generation does not fully offset the cost of SCR installation. o PaR, which has additional granularity and more refined unit commitment and dispatch logic relative to the SO model, reports a PVRR(d) that shows installation of SCR is lower cost when compared to the SO model results. PaR is able to mitigate costs with increased spot market net sales. However, PaR results still show that installation of SCRs is higher cost. Naughton Unit 3 Consistent with action item 5e inthe2017 IRP action plan, PacifiCorp has updated its analysis of regional haze compliance altematives for Naughton Unit 3. The 2017 IRP preferred portfolio assumed an early retirement date of 2018 for Naughton Unit 3. The Naughton plant consists of three units for a combined generating capability of 637 MW and is located near Kemmerer, Wyoming. PacifiCorp's updated analysis includes two gas conversion cases for Naughton Unit 3. The first case analyzes the full gas conversion of Naughton Unit 3 in June 2019 with retirement in2029, increasing its capacity slightly from 280 MW to 285 MW. The second case analyzes a limited gas conversion of Naughton Unit 3 that would enable the plant to run on gas at a lower generating capacity of 42 MW, without the capital investment of a full gas conversion, and also with retirement in 2029. These cases are compared to the 2017 IRP Update preferred portfolio assumption where Naughton Unit 3 is assumed to retire at the end of January 2019. This analysis shows that the early retirement scenario without the gas conversion is lower cost whereas a limited gas conversion of Naughton Unit 3 and retirement in 2029 shows benefit in two of the three price- policy scenarios. Each case is discussed in more detail below. Naughton Unit 3 - Maximum Generating Capacity Gas Conversion This case studies conversion of Naughton Unit 3 to natural gas with the capital investment necessary to enable it to operate up to 285 MW generating capacity in June 2019 with retirement in 2029. The case creates a lower incremental capacity need beginning in the summer of 2019, which drives the need for lower replacement resources over the 2019 to 2029 time frame. The 75 PecrprConp -2017 IRP UPDATE CHlprEn 6 RrcroNnr- Hnze Cases major project schedule for Naughton Unit 3 maximum gas conversion is reported in Figure 6.10 at the end ofthis chapter. Figure 6.4 - Cumulative Increase/(Decrease) in Portfolio Resources under the Naughton Unit 3 Maximum Gas Conversion and Retire 2029 Price-Scenario MM Table 6.4 shows the PVRR(d) impact of converting Naughton Unit 3 to natural gas with maximum generating capacity and retiring at the end of 2029 relative to the 2017 IRP Update preferred ponfolio that includes early retirement at the end of January 2019 for Naughton Unit 3 for each of the three price-policy scenarios. Table 6.4 - PVRR Cost/(Benefit) of the Naughton Unit 3 Maximum Gas Conversion and Retire 2029 Case Relative to the 2017 IRP Update Preferred Portfolio by Price-Policy Scenario PVRR(d) Cost/(Benefit) ($ million) System Optimizer PaR Stochastic Mean Low Gas, Zero COz Med Gas, Med COz High Gas, High COz Low Gas, Zero COz Med Gas, Med COz High Gas, High COz Change from l7 IRP Update Pref-Port s58 $63 $11 $64 $71 =a q) ctU() G U "$r*"Cr*ors|r0.r$rSn$robr$ne$rdno+n$n$no+n{,*no+.r!rbr DSM r FOTs I Gas a Renewable r Gas Conversion r Early Retirement Retirement 400 300 200 100 (100) (200) (300) (400) (500) (600) 76 Figure 6.4 summarizes the cumulative change in resource portfolio capacity when Naughton Unit 3 is assumed to convert to gas and retire in 2029 relative to the 20 1 7 IRP Update preferred portfolio that includes early retirement of Naughton Unit 3 at the end of January 2019 under the medium gas, medium COz price-policy scenario. Positive values show cumulative resource portfolio additions and negative values show the cumulative capacity of resources that are removed from the portfblio when Naughton Unit 3 is assumed to convert to gas in June 2019 and retire in 2029. The conversion of Naughton Unit 3 to full capacity natural gas operation from 2019 through2029 reduces the capacity need for west side summer FOTs during this period with the exception of 2021 and 2022. Dut',ng this two-year window, the system's ability to transfer capacity from the Naughton Unit 3 location (in the Utah North topology bubble) to the west becomes constrained and no offsetting displacement of capacity resources is available. $61 PACIF.ICORP - 20 I7 IRP Upna.rE Cueprp,R 6 - RecroNal Haze Casgs The PVRR(d) results indicate that the fixed costs of converting and operating Naughton Unit 3 as a natural gas fueled facility with maximum generating capability are not covered by the operational benefits accounting for reduced FOT and DSM. The PVRR(d) ranges from 561 million to $71 million higher costs for Naughton Unit 3 when assumed to operate at maximum generating capacity under this gas conversion scenario relative to the 2017 IRP Update preferred portfolio that assumes Naughton Unit 3 retires at the end of January 2019. The cost increase in each price-policy scenario does not support converting Naughton Unit 3 to gas with maximum generating capacity in June 2019 with an assumed retirement in 2029 relative to early retirement in January 2019 as is assumed in the 2017 IRP Update preferred portfolio. Naughton Unit 3 - Limited Gas Conversion This case studies a limited gas conversion of Naughton Unit 3, allowing continued operation through 2029, but reducing unit capacity from its current level of 280 MW to 42 MW . This limited conversion option takes advantage of existing natural gas-fueling arrangements, eliminating the capital investment that would be required to operate the unit up to its maximum generating capability. Similar to the case that assumes maximum gas-conversion capacity, the limited gas conversion is assumed to occur in June 2019 with retirement of the unit in 2029, which creates a lower incremental capacity need beginning in the summer of 2079 and a lower need for replacement resources over the 2019 to 2029 time frame. The major project schedule for Naughton Unit 3 minimum gas conversion is reported in Figure 6.11 at the end of the chapter. Figure 6.5 summarizes the cumulative change in resource portfolio nameplate capacity when Naughton Unit 3 is assumed to convert to gas on a limited basis and retire in 2029 relative to the 2017 IRP Update preferred portfolio that includes early retirement of Naughton Unit 3 at the end of January 2019 under the medium gas, medium COz price-policy scenario. Positive values show cumulative resource portfolio additions and negative values show the cumulative capacity of resources that are removed from the portfolio when Naughton Unit 3 is assumed to convert to gas on a limited basis in June 2019 and retire in2029. The portfolio changes are similar to those from the Naughton Unit 3 maximum gas conversion case and mainly include the reduction of FOT and a reduction of DSM in2029. 71 PecmIConp _ 20 I7 IRP UPDATE Cueprpn 6 - REGTONAL Hezp Ceses Figure 6.5 - Cumulative Increase/(Decrease) in Portfolio Resources under the Naughton Unit 3 Limited Gas Conversion and Retire 2029 Table 6.5 shows the PVRR(d) impact of converting Naughton Unit 3 to natural gas with limited generating capacity and retiring at the end of 2029 relative to the 2017 IRP Update preferred portfolio that includes early retirement at the end of January 2019 for Naughton Unit 3 for each of the three price-policy scenarios. Table 6.5 - PVRR Cost/(Benefit) of the Naughton Unit 3 Limited Gas Conversion and Retire 2029 Case Relative to the 2017IRP Update Preferred Portfolio by Price-Policy Scenario With limited fixed costs, this case shows there is potential for benefits of operating the unit at a limited capacity, accounting for reduced FOT and DSM. This is evidenced by the slight benefits coming out of the SO model for the low gas, zero COz and medium gas, medium COz price-policy scenarios. The SO model benefits shown for these price-policy scenarios warrant further analysis of the Naughton Unit 3 plant in the2019IRP. PacifiCorp will continue to assume early retirement of Naughton Unit 3 in January 2019 in this 2017 IRP Update while continuing to evaluate the economics of gas conversion options in the 2019 IRP. Cholla Unit 4 Consistent with action item 59 in the 2017 IRP action plan, PacifiCorp has updated its analysis of regional haze compliance alternatives for Cholla Unit 4. With consideration of environmental compliance and unit economics, the 2017 IRP preferred portfolio assumed Cholla Unit 4 retires in 2020. The Cholla plant consists of four units for a combined generating capability of 995 megawatts. PacifiCorp owns 37 percent of the plant's common facilities and all of Unit 4 which ,o$ro*r$roons|rsPror)rof ,of ,obroilro*rof ,eorc|rclrof nororof ,pnbr DSM r FOTs r Gas ;e Renewable r Gas Conversion I Early Retirement I Retirement =2 60 40 20 (20) (40) (60) (80) (100) Change from l7 tRP Update Pref-Port ($4)($0.4)$13 $0.s $3 $11 78 PVRR(d) Cost/(Benefit) ($ million) System Optimizer PaR Stochastic Mean Low Gas, Zero COz Med Gas, Med COz High Gas, High COz Low Gas, Zero COz Med Gas, Med COz High Gas, Hieh COz PacrprConp - 2017 IRP Upoarp Cuaprnn 6 - REGToNAL Hezs Casps was commissioned in 1981 with a generating capability of 395 MW. Arizona Public Service Company owns Units 1,2 and 3 and operates the entire facility. EPA has approved the Arizona SIP incorporating an alternative regional haze compliance approach that avoids installation of SCR equipment with a commitment to cease operating Cholla Unit 4 as a coal-fueled resource by the end of April2025, with the option of natural gas conversion thereafter. The major project schedule for Cholla Unit 4 gas conversion is reported in Figure 6.12 at the end of the chapter. PacifiCorp's updated analysis compares a scenario where it is assumed Cholla Unit 4 continues to operate as a gas-fueled facility by the end of April2025 and assuming retirement in 2042 to the 2017 IRP Update preferred portfolio, which assumes Cholla Unit 4 retires at the end of 2020. This analysis shows that the early retirement scenario without the gas conversion is lower cost. In the case that assumes conversion of Cholla Unit 4 and retirement in 2042, extended operation of the resource fills a projected capacity need beginning 2021, driving a lower need for incremental renewable resources, DSM and FOT resources over the 2021 to 2036 time frame. Figure 6.6 summarizes the cumulative change in resource portfolio nameplate capacity under the medium natural gas, medium COz price-policy scenario when Cholla Unit 4 is assumed to convert to gas and retire in 2042 relative to the 2017 IRP Update preferred portfolio that includes early retirement of Cholla Unit 4 at the end of 2020. Positive values show cumulative resource portfolio additions and negative values show the cumulative capacity of resources that are removed from the portfolio when Cholla Unit 4 continues to operate and is assumed to convert to gas at the end of April 2025 retire in 2042.In the medium natural gas, medium COz price-policy scenario, continued operation of Cholla Unit 4 after 2020 followed by conversion to natural gas in 2025 reduces FOT and DSM resources. Beginning 2030, wind and solar resource additions are also reduced. Figure 6.6 - Cumulative Increase/(Decrease) in Portfolio Resources under the Cholla Unit 4 Gas Conversion and Retire 2042 Medium Natural Gas Table 6.6 shows the PVRR(d) impact of assuming Cholla Unit 4 converts to natural gas in 2025 and retires at the end of 2042 relative to the 2017 IRP Update preferred portfolio that includes early retirement at the end of 2020 for each price-policy scenario. 79 .r$r**r*er&ors)r0rSr{$ro6r$ro*rdr* r DSM r FOTs r Gas I Renewable r Gas Conversion I Early Retirement , Retirement 600 400 200 z (200) (400) (600) (800) ( 1,000) Change from 17 IRP Update Pref-Port $r29 $128 $ 168 $l l4 $6e $ 104 PecrprConp - 201 7 IRP UpDRTp Cuaprpn 6 - RncroNnl HAZE CASES Table 6.6 - PVRR Cost/(Benefit) of the Cholla Unit 4 Gas Conversion and Retire 2042 Case Relative to the 2017 IRP U Preferred Portfolio Price-Scenario The following summarizes observations and results from this study under the medium natural gas price, medium COz price-policy scenario: Fuel and variable operation and maintenance costs increase when Cholla Unit 4 continues generating and then converts to natural-gas-fueled operations in2025. These costs are offset by reduced costs from new DSM and FOT. Increased thermal generation when Cholla Unit 4 continues to operate until2042 as a natural-gas-fueled resource enables more spot market sales and reduces spot market purchases. These benefits are offset by increased COz emission costs starting in 2030. Fixed costs related to Cholla Unit 4 are incurred after 2020 for operations and gas conversion in2025. This is offset by lower fixed costs for renewables. The PVRR(d) reported out of the SO model is nearly the same the medium natural gas, medium COz and low natural gas, zero COz price-policy scenarios. PaR, which has additional granularity and more refined unit commitment and dispatch logic relative to the SO model, reports a lower net cost in the medium natural gas, medium COz price-policy scenario. However, these results still show that it is lower cost to retire Cholla Unit 4 in 2020. Overall, the increase in present-value system costs in each price-policy scenario does not support converting Cholla Unit 4 to natural gas at the end of April2025. Subject to further evaluation PacifiCorp will continue to assume early retirement of Cholla Unit 4 at the end of 2020 in the 2017 IRP Update while continuing to evaluate the economics of early retirement and gas conversion options in the 2019 IRP. a a a 80 System Optimizer PaR Stochastic MeanPVRR(d) Cost/(Benefit) ($ million)Low Gas, Zero COz Med Gas, Med COz High Gas, Hieh COz Low Gas, Zero COz Med Gas, Med COz High Gas, Hieh COz PACIF-ICoRP 20 I7 IRP UPOATE Cnnpren 6 - RecroNel Haze CesEs Figure 6.7 through Figure 6.12 show illustrative timelines for each regional haze study 6.7 - Dave Johnston Unit 3 SCR Milestone Schedule Pmject DeveloPment Receive Owner's Engineer developnrcnt work propGal Devebpment phase Appropriatbn Request approved Ffue gas baseline fbw and perfomnce test progmm compbte Des@ basis studies complete NFPA 85 Code complhnce review and fumace draft study Conlrm interconnection requLements Begin wDEQ AQD construction pemit applbatbn Complete EPC contract technical specilEation Comphte phnt stakeholder review ofdraft A version ofProject Execution Phn Finalire tumkey template EPC contract and exhibits Complete EPC cont.act RFP rehted p.@urement approvab Request for EPC contract propcab rcleased ftr bil EPC cotract proposab due Begin reguht6y filing applications Prepare wyming Certilpate of Public Covenience and Necessity Oder Appliation Prepare Utah Code Section 5,t I 7-402 preapproBl applicatim Prepore Oregon IRP acknowbdgercnt filing (2015 IRP) Complete memorandm to "short-lbt" EPC contractoE and begin negotiatbns Shoft-list EPC Contract presenhtions and complete regotiatbns Submil and receive WDEQ AQD coNtructlr pemit Project Executbn Phn baselire Version 0 approved Submit and receive Wyoming Cenilrcate ofPublic Convenbnce and Necessity Order Submit and receive Utah Code Sectbn 5,1-17-402 preapproval Submit and receive Oregon IRP acknowhdgement Prcj€ct lmplementation Impbmentatbn Appropriation Request approved EPC Contract Effective Date (May 31,2016) Cmplete boib. and air Eeheater structumlreinforcement detailed engireering Boibr and ai preheater reinforcerent mat€rials onsih Begin scope devebpment economizer modfratbns Complete ecmmizer modifrcations dehiled engineering Econmizer modilpation mabrhb msite EPC c@tract pre{uhgc work cmpbte (September 2018) EPC cotract rechanbal compbtion (November 2018) EPC coract subshnthl compbtion (Janury 2019) EPC cotract fmal compbtix (July 2019) 81 Actil ity Descriptiotr -==={ ",' ",, .,, o?oa OCOa ?aao -=:= OOOC a:: ii6cCd Compliance PacrprConp - 2017 IRP Upoere Cuep'Ien 6 RgcIoNaI HAZE CASES 6.8 - Jim Unit I SCR ect Milestone Schedule Prcjeci Development Receive Owne/s Engineer developrnent wffk propGal Develop(reil phase Apprcpriation Req@st aprf,oved FIue gas boselhe fk)w and perfomrce test program compbrc Design basb studbs complete NFPA 85 Code compliance review ard fumce &aft study Confm inErconnection rcquiremenb Begin WDEQ AQD construction pemit application Complere EPC conkact lechnhal specilEarion Complete plant stakeholder rcview ofdraft A venion ofProject Execution Plan Finalire tmkey temphte EPC contract and exhibits Complete EPC conract RFP rebted prourement apprcvals Reqrest for EPC contmct proposals released for bid EPC contract proposab due Begin regulatory filing applications Pr€p6rc Wyoming Ceflifrcare of Public Convenience and Necessity order Application Preparc Ubh Code Seclbn 5,1 I 7-402 preapproval applhatbn Preparc Orcgff IRP acknowledgemnt filing (2015 IRP) Complete memmndum to "shon-lbt" EPC conractm and begin negotiatbffi Shon-lbt EPC ContEcl presenhlbm and cmplete negotiatbm Submi andreceive WDEQ AQD co$wcrion pemit Prcject Executbn Phn boseline Vereih 0 approved Submit and receive Wyoming CenilEate of Public Convenbrce and Necessity Order Submh and receive Ubh Cod€ Sectbn 5+17-.102 prca@mval Submit and receive Oregon IRP acknowledgement PDject ImpleDctrbtiotr Implemenbtion Apprcprirtion Reqwst aproved EPC Contract Effective Date (December 31.2019) Cmpbte boiler and air preheater strrctural reinforcement deEiled engineering Boibr and air preheater reinforcement mteriab onsite Begin scope development eco@mizer modifpatioN Complete economizr nrcdilEarioN d€uiled engineering Ecmomizer modifEation maErials oNite EPC cmract prc-o&ge work compleb (Jme 2022) EPC contract mchanhal compbtion (Augut 2022) EPC cmtract subEtantbl completion (Ocbber 2022) EPC coract f@l completion (Ap. 2022) 82 Actiyit-v D€scription =5=5????Cto?o occc o?oc :;in. CCCO x.'.'F' atJ)C Complirnce PRcm'rCoRp - 2017 IRP Upoeru Csapren 6 - R-acroNnl HAZE CASES 6.9 - Jim Unit 2 SCR ect Milestone Schedule PDject DeveloPmeot Receive Owre/s Engimer devebpinent wck propGal Devebprreil ptEe Apprcpriatbn ReqEst appmved FhE gs baselift fbw and perfomnce tesl progmm comphte Design basis studbs cmplele NFPA 85 Code compliance review and flmce dmft study Confm ifr ercmrection requiremefr s Begin WDEQ AQD costretion pemit application Complete EPC contract Echnical specifration Complere phd shkeholder rcview of draft A ve6im of Prcject Execulion PIan Fimlize turnkey remphb EPC contmct and exhibits Compbrc EPC cffict RFP rchted pr@rcmenl appmvah ReqEst ftr EPC cmmct propGab rebased for bil gPC contract prcpGab d@ Begin rcgulatory filing applbatbN Prepare Wyoming CedfEate of Public Convenicnce ard Necessiry Order Applicalion Prepare Uah Code Sectix 54-17-402 prcapproval application Prepare Oregon IRP acknowledBement filing Compbte memoBndm to "shd-list" EPC conEacto6 and begin regotiatbN Shon-list EPC Cotuact prcsenhtioff and cmplete regdiatim Submit and receive WDEQ AQD coBmtbn pemit Prcject Execuim Phn baselire Ve6ih 0 approved Submit ard receive wyming CerlilEate of Public Convenierce and Necessity Order Submit and receive Ubh Code Sectim 54- 17-402 preapprcBl Submit and receive Oregon IRP acknowledgemeft Pmject Implementetion Implemenhtion Appropriatim ReqEst approved EPC Conhct Effective Date (December 3l,20lE) Complete boiler and air preheater strotml rcinforcerent dehiled engireering Boiler and air preheater reinforcemen! mteriab mite Begin scope dewbprnent ecomizer rrcdifrcatkxB Complele ecmmiEr modifEaliN de6iled engireering Ecmmizer modifuation materials oNite EPC cmmc! pre-oMge wdk conplete (Jue 2021) EPC conmct reclEnical compbtion (Aug6t 2021) EPC conmct subsBntial completion (October 2021) EPC cmract fMl compbtim (Apr 2021) 83 Activity Description OCOO =55-OOOO innn atCOO OOOC OCOO Compli.uc. PacmrConp - 20 17 IRP UpoRre CHAPTER 6 - REGIONAL Heze CnSES Figure 6.10 - Naughton Unit 3 Maximum Natural Gas Conversion Project Milestone Schedule PmFcl DevelopmeDt Technbal Studies Develop EPC cotract technaal specilpatbn and RFP package Obtain WDEQ pemit (corected) P002ll l0 date (March 17, 2017) Obhin WDEQ BART permit MD-604242 date (March 7,2012) Obtain WDEQ BART pernit (modifEatbn) MD-15946 date (Jure 20, 2014) Intercomection prcess foa removal from system EPC contract lechnbal specifuatin and RFP dGmeft EPC contract RFP EPC conftact propGal eva[atbn Iilercomectih preess for new gereratbn Regubtory and ecorcmic rcview NEPA ES compliarce review EPC Conhact regdhtions; confom d@ments for contract Devebp prcject executbn phn Prepare and approve imphmentatir APR Impbmenhtin APR approval date (December 5, 2017) NaMlgas suppty cmtract RFP Natml gas suppy cont.act negotbB Prcject IEpleEeution DiscontinE c@l-flreling date (Janury ]0, 2019) EPC c@tract executim date (December 8,2017) EPC conhct execution perbd to Mechanical Completion (> 10 months) Natural gas supply contract execution (December 3, 2017) Gas supply contract constrctbn perild Natuml gas supply tb-in Tie-in outage EPC c@tBct rcchanialcmpbtbn date (Jue 30,2019) EPC c@mct sub6hnital cmpbtion date(September 2q 2019) EPC c@mct lmalcmpbtlh date (Jan@ry 30, 2020) 84 Acaivity Description Proiect Period {2018 2ul9 2020 o o o ,/ Ntual gs convasion PACIFICORP -2017 IRP UPOATP CHAPTER 6 - R-E,CIONAI- HAZE CESPS 6.11 - Nr Unit 3 Limited Natural Gas Conversion Milestone Schedule - II - II / a l Prcject Development Technical Studbs Obtain WDEQ pemit (conected) P0021 I l0 date (March lZ 201 7) Ohain WDEQ BART pemit MD-6042A2 dah (March 7,2012) Ohain WDEQ BART permit (modiflcation) MD-I5946 date (Jm 20,2014) Ohain WDEQ Tith V pemit modilEation Reguhtory and economic review PmFct Implementation Dbcontinue c@l-fuelhg date (Janury 23, 2019) Removal ofc@l puherizers frm seilice complete date (Janury 10, 2019) Saft natual gas opemtbn date (Janmry 21, 2019) 85 701 5201{ = !o 6 Activity Description PACIFICoRP _2017 IRP UPDATE CHAPTER 6 - REGIoNAL Heze Casps 6.12 - Cholla Unit 4 Natural Gas Conversion ect Milestone Schedule Pm.iect Development Technical studies Develop EPC contract technical speciflcation and RFP package Obtain ADEQ comtruction pemit Obtain ADEQ BART pemit Contract preparatioro: EPC and NFPA 85 compliance scopes ofwork EPC contract RFP EPC contract negotiatims; confoming dcments for contract NFPA 85 compliance review, scope development and tramient analysis Develop prcject execution plan Prepare and approve implementation APR Implementation APR approval date (Janwry 1,2024\ Natual gas supply conkact R-FP Natual gas supply contract negoliatiom Pmhct Implementation Discontinue cml-fueling date (December 31, 2024) EPC conkact execution date (Janury l, 2024) EPC confact executim period to Mechanical Completion (18 months) Natwal gas supply contract execution date (Janury 1, 2024) Natual gas supply contract consluction period Natual gas supply tie-in Tie-in outage EPC contract MechanicalCompletion (May 2025) EPC contract Substantial Completion (AugNt 2025) EPC contract Final Completion (December 2025) 86 ,fi'r 1 'r at) ))n7 1 ',.l', t )o)\ Activity Description NaN N da a o dN Ndad N NNa NdaN o aN o a N a NoN Na N N q o N olq o NO Assumed @tuEl 8as coNeEio op€iating date PACIFICORP - 2017 IRP Uponrc CHAPTER 7 - ENERGY VISIoN 2O2O UPDATE CuaprER 7 - ExsRGy Vrsrox 2020 UppATE, Introduction PacifiCorp's 2017 Integrated Resource Plan (IRP) presented its preferred portfolio, identifying least-cost, least-risk resources providing near-term and long-term benefits to customers. The 2017 IRP preferred portfolio included 1,100 MW of new Wyoming wind resources, enabled by the proposed Aeolus-to-Bridger/Anticline transmission line, and maximizing customer benefits through wind production tax credits (PTCs). In addition, the preferred portfolio reflected repowering 905 MW of existing wind resources by the end of 2020, re-qualifying these zero- emission resources to receive the full value of PTCs for an additional ten years. These three major components of the preferred portfolio (new wind and transmission, plus repowering) are collectively described as the Energy Vision 2020 projects, providing significant net benefits to customers over the 2}-year planning horizon. This chapter summarizes updated analysis of Energy Vision 2020 resources. The 201 7 IRP Update preferred portfolio includes 1,311 MW of new Wyoming wind, the Aeolus-to-Bridger/Anticline transmission line, and just over 999 MW of repowered wind. By displacing higher cost uncommitted market purchases and other resources, the 2017 IRP Update preferred portfolio continues to provide the least-cost, least-risk means of meeting system needs identified in Chapter4. This chapter also describes analysis conducted since filing the 2017 IRP, outlines regulatory milestones and concludes with considerations for the 2019 lRP. The 2017 IRP lays out PacifiCorp's long-term plan to deliver reliable electricity supply at a reasonable cost. The 2017 IRP identified the best mix of resources to serve customers overthe short- and long-term, based on an analysis of the costs and risks associated with various resource portfolios. The2017 IRP identified the preferred portfolio as the least-cost, least-risk portfolio that could be delivered through specific action items to deliver resources at a reasonable cost and with manageable risks, while ensuring compliance with state and federal regulatory obligations. PacifiCorp's 2017 IRP identified wind repowering as a least-cost, least-risk resource- The 2017 IRP also identified significant new wind (Wind Projects) and transmission resources (Transmission Projects) as a component ofthe least-cost, least-risk resource portfolio (collectively, the Combined Projects). After filing the 2017 [RP, PacifiCorp conducted a comprehensive updated economic analysis in support of its application for approval of the Energy Vision 2020 projects in Idaho, Utah, and Wyoming. Consistent with analysis in the 2017 IRP, this analysis demonstrated that wind repowering and the Combined Projects will provide substantial customer benefits. Additional filings, incorporating updated data and assumptions to reflect results of the 2017R Request for Proposals (RFP), changes in the federal income tax rate for corporations, an updated load forecast, and updated market price and COz price assumptions. Energy Vision 2020 project risks have been materially reduced since the 2017 IRP. When the company made its initial filings, it was uncertain whether federal tax-reform legislation would be 87 PACIFICoRP - 20 I7 IRP Upoare CHApTER 7 - ENERGy VrsroN 2020 Uponra introduced and how that legislation might impact PTC benefits, which are critical to the economic benefits of the Energy Vision 2020 projects. Similarly, atthat time, the company had not yet issued the 2017R RFP and had not received firm pricing for wind resource bids solicited through a competitive bidding process. At this time, these uncertainties have been eliminated and replaced with known tax law changes and competitive pricing for repowering and the Combined Projects. Also since filing the 2017 IRP, PacifiCorp received conditional certificates of public convenience and necessity (CPCNs) for the Aeolus-to-Bridger/Anticline transmission line, the TB Flats I & II wind project, the Cedar Springs wind project, the Ekola Flats wind project, and associated network upgrades from the Wyoming Public Service Commission. These CPCNs are required to secure the necessary rights-of-ways, which has been initiated, before construction begins. In the latest analysis that serves as the basis for the 2017 IRP Update, the company analyzed nine different scenarios, each with varying natural gas and carbon dioxide (COz) price assumptions (price-policy scenarios).r Both repowering and the Combined Projects continue to show significant customer benefits which are quantified and described later in this chapter. Modeling and Approach Summary PacifiCorp uses two models to optimize and evaluate the least-cost, least-risk portfolio for meeting customer needs and minimizing system costs. For this update, and consistent with the 2017 [RP, these models were used to evaluate dozens of economic scenarios and sensitivities to inform an updated preferred portfolio, demonstrating continuing customer benefits as a result of the Energy Vision 2020 projects. The System Optimizer (SO) model operates by minimizing operating costs for existing and prospective new resources, subject to system load balance, reliability and other constraints.2 Over the 2O-year planning horizon, it optimizes resource additions subject to resource costs and capacity constraints (summer peak loads, winter peak loads, plus a target planning reserve margin for each load area represented in the model). In the event that an early retirement of an existing generating resource is assumed for a given planning scenario, the SO model will select additional resources as required to meet summer and winter peak loads inclusive of the target planning reserve margin. The Planning and Risk model (PaR) uses the same common input assumptions described fbr the SO model with additional data provided by the SO model results (i.e., the selected resource portfolio).3 While the SO model solves to ensure there is sufficient capacity for each case, PaR considers stochastic-driven risk metrics to the evaluation of the studies. While PaR cost-risk metrics are ultimately used when selecting a preferred portfolio in the IRP, SO model results remain valuable and informative. ' The COu price assumptions used in the Energy Vision 2020 results analysis in this chapter were inadvertently modeled in2012 real dollars instead of nominal dollars. Consequently, the PVRR(d) net benefits in the six price- policy scenarios that use medium and high COz price assumptions are conseryative. 2 For a detailed description of System Optimizer's role in IRP analysis, please refer to the PacifiCorp 2017 IRP, Chapter 6 Modeling and Portfolio Evaluation Approach, pages 145- 156, which is publicly available at the following website link: http://www.pacif-rcorp.com/es/irp.html.I For a detailed description of the Planning and Risk model's role in IRP analysis, please refer to the PacifiCorp 2017 IRP, Chapter 6 - Modeling and Portfolio Evaluation Approach, pages 156-169, which is publicly available at the following website link: http://www.pacifi corp.com/es/irp.html. 88 PACIFICoRP _ 2OI7 IRP UPDATE CgepTEn 7 - ENERGY VISION 2O2O UPDATE During the period between the April 4,2017 filing of the 20l7lRP and the preparation of this 2017 IRP Update, PacifiCorp has continued to refine its economic analysis supporting the Energy Vision 2020 projects. The analysis represented here incorporates the most current modeled assumptions, reflecting: (l) updated cost-and-performance assumptions for the wind repowering project and the Combined Projects; (2) current price-policy scenario assumptions, including more current natural gas and COz prices; (3) recent changes in the federal tax rate for corporations, and (4) nominal modeling of production tax credits. This most recent analysis also incorporates the updates and refinements made in the second half of 2017, which included updates to PacifiCorp's load forecast. This section summarizes updates to price-policy scenario assumptions, federal tax assumptions, and PTC modeling assumption that are applicable to the updated analysis of the wind repowering project and the Combined Projects. Price-policy Scenarios The repowering project economic analysis uses nine price-policy scenarios, developed by pairing three natural-gas price forecasts (low, medium, and high) with three COz price forecasts (zero, medium, and high). The medium natural-gas price assumptions were derived from PacifiCorp's December 2017 offrcial forward price curve (OFPC). The low and high natural gas price assumptions and the medium and high COz price assumptions are based on assumptions adopted by third-party experts. Figure 7.1 shows natural gas price assumptions and Figure 7.2 shows the COz price assumptions used in the updated analysis. 7.1-Hub Natural Gas Price $10 $e $8 $z Etu Ess Eto $3 $2 $l $0 oO O\ O N .O $ tr) \O (-- oO O\ O N .a $ tr) \Oc.l c..l N c\l c.l (\ c.l N c\ c.l .a .o .n .o .o ca ca 99999VVV99999999U99C\ C\ N N N a.l c.l c.i c.l ..1 c.l N o.l a.l o..l c.l .-l c.] a.l -I-Low MedGas(Dec20l7OFPC) -e-High J aa'ra- .f.lfJ .J.J *+ n-e .l- r1l -e .rO{> 12J -J-D-D-* t't'{'{ a-I-I-lao* 89 Common Assumption Updates PncrrrConp 20 l7 IRP UponrE CIIAP,IER 7 ENERGY VISION 2O2O UpoaTE 7.2 - COz Price Federal Tax Rate PacifiCorp's updated analysis assumes a 2l percent federal income tax rate as provided in H.R. l, which was passed by Congress on December 20, 2017, and became law on December 22, 2017 . Based on an assumed net state income tax rate of 4.54 percent, the effective combined federal and state income tax rate used in the updated analysis is24-587 percent. The effective combined federal and state income tax rate affects PacifiCorp's post-tax weighted average cost of capital, which is used as the discount rate in the SO model and PaR. With the changes in tax law, PacifiCorp's discount rate was updated from 6.57 percent, as was assumed in the 2017 IRP, to 6.91 percent. The modified income tax rate also affects the capital revenue requirement for all new resource options available for selection in the SO model. Finally, the updated income tax rate affects the tax gross-up of all PTC-eligible resources. As noted above, the current value of federal PTCs is $24lMWh, which equates to a $3 1.82lMWh reduction in revenue requirement assuming an effective combined federal and state income tax rate of 24.587 $0 I.{-I'-I-|-}{-|-E{-}.{-I-}{-I-I-{-I ,P'-'-O-{l 'P' oF G $s I$5 tat ,tI0$t /,a ao N N $aa s2s $20 @O\O* - C.l C-l 9999a.l N N c..l c.l .oStr)\Oft@O\O*a.l a.l a.l o.l (ti c..l o.l a.l co coOOOOOOOOOON c.l c'l c.l N c-l c.l c.l (t.l c\ Medium -C-High -l-Zero a.)ca c.l \oC.Oc.t a.laa N 90 Capital revenue requirement is levelized in the SO and PaR models to avoid potential distortions in the economic analysis of capital-intensive assets that have different lives and in-service dates. This is achieved through annual capital recovery factors, which are expressed as a percentage of the initial capital investment for any given resource alternative in any given year. Capital recovery factors, which are based on the revenue requirement for specific types of assets, are differentiated by each asset's assumed life, book-depreciation rates, and tax-depreciation rates. Because capital revenue requirement accounts for the impact of income taxes on rate-based assets, the capital recovery factors applied to new resource costs in the SO model were updated for each of Pacifi Corp's system simulations. PACIFICORP 20 I7 IRP UPOATE Csap'mn 7 - ENERGy VrsroN 2020 UponlE In recent analysis including this 2017 IRP Update, the Company applied PTC benefits on a nominal basis rather than on a levelized basis. This approach better reflects how the federal PTC benefits for the repowered assets and Wind Projects will flow through to customers, conforms the treatment of PTC benefits with other costs and benefits that are not actually spread over the life of an asset, and appropriately weights the contribution of PTC benefits in present-value calculations. Wind Repowering Recent advancements in wind generation technology, including innovations in wind turbine design and control systems, allow modern wind turbines to generate greater energy from available wind resources. To take advantage of these recent technologies, PacifiCorp intends to repower most of its Wyoming wind fleet (Glenrock I, Glenrock III, Rolling Hills, Seven Mile Hill I, Seven Mile Hill II, High Plains, McFadden Ridge, and Dunlap);the Marengo [, Marengo II and Goodnoe Hills facilities in Washington; and the Leaning Juniper facility in Oregon. The combined current capacity of these facilities is just over 999 MW, with 594 MW in Wyoming, 304.6 MW in Washington, and 100.5 MW in Oregon. Efficiency Improvements and Extended Project Life Wind repowering involves the installation of new rotors with longer blades and new nacelles with higher-capacity generators. Longer blades increase the wind-swept area of the wind turbine and allow it to produce more energy at lower wind speeds. The nacelle is the housing that sits atop the tower and contains the gear box, low- and high-speed shafts, generator, controller, and brake. The new nacelles will include sophisticated control systems and more robust mechanical and generator components necessary to handle the greater loads that come with longer blades. Together, the new rotors and nacelles are estimated to increase wind project generation by approximately 26 percent. In addition, the innovative technologies provide for greater control of power quality and voltage, allowing PacifiCorp to more easily integrate the energy from the wind facilities into the transmission system and support the reliability of the grid. The new equipment also reduces future operating costs and extends the useful life of each wind plant by at least l0 years. PacifiCorp intends to file new depreciation rates in 2019. At that time, PacifiCorp will reset the 30-year depreciable life of the repowered wind facilities, effectively extending the depreciable life of the facilities by l0 to l3 years. Over the current life of the repowered facilities, incremental annual energy production is approximately 738 GWh. Over the extended life, the incremental annual energy production is approximately 3,500 GWh. Importantly, because the wind repowering project involves efficiency improvements to existing facilities, these benefits can be achieved without the costs and complexity of permitting and constructing wholly new facilities. 9l percent, adjusted for inflation over time. The impact of the updated income tax rate assumptions were applied to all PTC-eligible resource alternatives available in the SO model. Production Tax Credit Modeling PacIplConp -2017 IRP UPDATE Cueprsn 7 - ENs,ncv VrsroN 2020 Upoarp Production Tax Credits and Customer Benefits The cost-effectiveness of the wind repowering project is driven in part by the fact that repowering requalifies PacifiCorp's existing wind facilities for PTCs, which are set to expire l0 years from their original commercial operation date (expiration dates range from 2016 through 2020). Currently, wind facilities qualifying for the PTC receive 2.4 cents per kilowatt-hour-or $24lMwh-a value that is adjusted annually based upon an inflation index. To requalify for PTCs, the repowered wind facility must meet the Internal Revenue Service's 80120 test-meaning that the fair market value of the retained property (i.e., the tower and foundation) is no more than20 percent of the facility's total value after installation of the new property (i.e., nacelle and rotor). PacifiCorp has designed its wind repowering project to satisfy this test to ensure that the repowered wind facilities are PTC eligible. Further, to ensure the repowered facilities are eligible for 100 percent of available PTC benefits, in December 2016, PacifiCorp contracted with global wind industry leaders General Electric, Inc., and Vestas-American Wind Technology, Inc., to purchase new wind-turbine generator equipment. These "safe-harbor equipment" purchases allow the repowered wind facilities to qualify for 100 percent of the value of PTCs, assuming commercial operation by the end of 2020. PacifiCorp's construction schedule will maximize the value of the existing PTCs by minimizing the period between the expiration of the original PTCs and the eligibility for the new PTCs. The original PTCs expire l0 years after each plant became commercially operational. Thus, the PTCs for most of the facilities will expire in 2018 and 2019. Achieving commercial operation in2019 for most of the facilities will minimize the time during which any wind facilities are ineligible for PTCs. Updated Data and Assumptions During the period between the April 4,2017 filing of the 2017 IRP and the preparation of this 2017 IRP Update, PacifiCorp has continued to refine its economic analysis supporting the wind repowering project. In addition to the assumption updates summarized earlier in this chapter, the updated analysis of the wind repowering project incorporates the most current cost-and- performance assumptions for the wind repowering project. Cost estimates for the wind repowering project have been updated consistent with findings from technical review studies. These technical review studies have led to a change in turbine specifications at the Leaning Juniper facility to ensure turbine loading remains within allowable limits. Project costs have been updated to account for the need to strengthen foundations at the Leaning Juniper and Goodnoe Hills facilities. Updated cost assumptions also reflect information received through a competitive bidding process for installation, foundation retrofits, as applicable, and other construction services needed to complete the wind repowering project. Performance estimates for the wind repowering project have been updated to reflect: a) updated turbine specifications for nearly all facilities, including larger rotor diameters and higher capacity generators for the Wyoming wind facilities; b) a change in turbine specifications at the Leaning Juniper and Goodnoe Hills facilities; c) the incorporation of four years of historical production data and increased wake losses into the estimates of increased energy production for the repowered 92 PACIFICoRP 2O I7 IRP UPONTE CHAPTER 7 - ENERGY VISIoN 2O2O UPDATE facilities; and d) increased incremental energy production at the Marengo I and II facilities to reflect a modified interconnection agreement that will allow the facilities to operate at their full repowered capacity. Repowering Results The SO model and PaR were used to calculate the present-value revenue requirement differential ("PVRR(d)") between a simulation with and without the wind repowering project after applying the modeling updates summarized above. These simulations continue to cover a forecast horizon out through 2036. PacifiCorp also updated its calculation of the PVRR(d) from the change in nominal revenue requirement due to the wind repowering project through 2050. Proj ect-by-Proj ect Results Table 7.1 summarizes the PVRR(d) results for each wind facility within the scope of the wind repowering project under the medium natural gas price, medium COz price-policy scenario. The PVRR(d) between cases with and without wind repowering are shown for each wind facility based on system modeling results from the SO model and for PaR, before accounting for the substantial increase in incremental energy beyond the 2036 time frame. When applying medium natural gas, medium COz price-policy assumptions, benefits from repowering the Leaning Juniper wind facility are equal to costs. All other wind facilities are projected to deliver net benefits. Table 7.1 - Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Repowering with Medium Natural Gas and Medium CO2 Price million Table 7.2 summarizes the PVRR(d) results for each wind facility within the scope of the wind repowering project under the low natural gas price, zero COz price-policy scenario. The PVRR(d) between cases with and without wind repowering are shown for each wind facility based on system modeling results from the SO model and for PaR, before accounting for the substantial increase in incremental energy beyond the 2036 time frame. When applying low natural gas and zerc COz price-policy assumptions, costs from repowering the Leaning Juniper wind facility are slightly higher than the benefits. All other wind facilities are projected to deliver net benefits. Glenrock I ($2s;($2 t;($2:1 Glenrock 3 ($s;($z;(sz; Seven Mile Hill I ($::;($24;($2e) ($z;($z)($z; (s l7)(s l3)($ l3)High Plains McFadden Ridee ($s;(S+1 ($+1 ($30)($26)($27\Dunlap Ranch Rolline Hills (st2)(se)($ l0) Leaning Juniper s0 $0 $0 (s35)($33)($34)Marengo I Marengo 2 ($ls;($ t+1 ($ls1 Goodnoe Hills (s l8)($ l8)($lq) Total (s20s)($ l 80)(s l 89) 93 Wind Facility SO Model PVRR(d) PaR Stochastic- Mean PVRR(d) PaR Risk-Adjusted PVRR(d) Seven Mile Hill2 ($22)Glenrock I ($z t;($z t; Glenrock 3 ($7)($6)(s6) Seven Mile Hill I ($241 ($28)($20; ($6)Seven Mile Hill 2 ($o;($o; Hieh Plains ($ 12)($e)($ l0) McFadden Ridee ($+)($:)($3) Dunlap Ranch ($2s1 ($zz1 ($2+; Rolline Hills ($e)($7)(s7) Leaning Juniper $6 $3 s4 (s26)Marengo I (5221 ($2s; Marengo 2 ($l t)($ l0)(sl l) Goodnoe Hills ($ t:;($ls)(sl s) Total (s1s7)($ 1 49)($ I s6) PRcrprConp -2011 IRP UPDATE CHnprsn 7 - ENERGy VrsroN 2020 Upoarp Table 7.2 - Project-by-Project SO Model and PaR PVRR(d) (Benefit)/Cost of Wind with Low Natural Gas and No CO2 Price Assu million Table 7.3 summarizes the PVRR(d) results for each wind facility calculated off of the change in annual nominal revenue requirement through 2050 for both price-policy scenarios. Unlike the results summarized in Table 7 .l and Table 7 .2, these results account for the substantial increase in incremental energy beyond the 2036 time frame. Each of the wind facilities within the scope of the proposed repowering project show net benefits with repowering under the medium natural gas and medium COz price-policy scenario and all facilities show net benefits under the low natural gas and zero CO2 price-policy scenario, except for the Leaning Juniper wind facility, where the benefits are equal to the costs. However, these results are conservative, as the assumed benefits do not account for the capacity value of the repowered wind facilities in the period when they would have otherwise hit the end of their depreciable lives (i.e., beyond 2036). 94 Wind Facility SO Model PVRR(d) PaR Stochastic- Mean PVRR(d) PaR Risk-Adjusted PVRR(d) PACIFICoRP -2017 IRP UPDATE Crr.,rpT[n 7 ENrnc;y VrsroN 2020 UpDAlr, Table 7.3 - Project-by-Project Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of Wind million A fuither assessment of the magnitude of the PVRR(d) results must be considered in relation to the specific attributes of the repowered wind facility, including the size of the facility, the expected cost to repower the facility, and the level of annual energy output expected after the new equipment is installed. For example, the PVRR(d) for McFadden Ridge shows a $7 million benefit when repowered (using medium natural gas and medium COz price-policy assumptions)-the lowest PVRR(d) among all of the project-by-project results. The PVRR(d) benefit for McFadden Ridge is approximately 74 percent of the $50 million benefit for Marengo I, which yields the highest PVRR(d) among all of the project-by-project results. However, the current capacity of McFadden Ridge (28.5 MW) is approximately 20 percent of the current capacity of Marengo I (140.4 MW). Similarly, the expected energy output after repowering McFadden Ridge (approximately I l7 GWh per year) is approximately 24 percent of the expected energy output after repowering Marengo I (approximately 488 GWh per year). A reasonable metric to evaluate the relative benefits among the wind facilities that captures the specific attributes of each facility is the nominal levelized net benefit per incremental MWh expected after the facility is repowered. This metric captures the specific repowering cost for each facility net of the specific benefits of each facility per incremental MWh of energy expected after the facility is repowered. Table 7.4 shows the nominal levelized net benefit of repowering per MWh of expected incremental energy output after repowering for each wind facility. When using medium natural gas, medium COz price-policy assumptions, the table shows the Seven Mile Hill II facility produces the largest net benefit per incremental MWh ($37lMWh), and Leaning Juniper produces the smallest net benefit per incremental MWh ($7/MWh). Wind Facility Medium Natural Gas and Medium COz Low Natural Gas and Zero COz Glenrock I ($::1 ($::1 Glenrock 3 (s1l)($o; Seven Mile Hill 1 ($4t1 ($40) Seven Mile Hill2 (sto;($o) High Plains ($221 ($6) McFadden Ridee ($7)($z; Dunlap Ranch ($:e1 ($23) Rolline Hills ($ts;($s; Leaning Juniper ($8)s0 Marengo 1 ($so1 ($zz1 Marengo 2 ($20)($21 Goodnoe Hills ($26)($ll; Total ($2az;($ t zo) 95 Medium Natural Gas and Medium COz Low Natural Gas and Zero COzWind Facility Glenrock I $29lMWh $29lMWh s l6lMWhGlenrock 3 $28lMWh $30/MWh $29lMWhSeven Mile Hill I Seven Mile Hill2 $36lMWh $23lMWh s5/MWhHigh Plains S I7lMWh s l7lMwh s5/MWhMcFadden Ridge Dunlap Ranch $28lMWh sl7/Mwh Rolline Hills s1g/MWh $7/MWh $7/MWh $0/MWhLeaning Juniper Marengo I $25lMWh sr l/Mwh Marengo 2 $21lMWh $8/MWh s26lMWh $ l8/MWhGoodnoe Hills Weiehted Average s23lMWh s l4lMWh PACIFICoRP _2017 IRP UPDATE ClrAprER 7 - ENERGy VrsroN 2020 UpDAlr, Table 7.4 - Nominal Levelized Net Benefit per MWh of Incremental Energy Output after All Repower Project Results Table 7.5 reports that in this latest analysis over a Z}-year period, repowering reduces customer costs in all nine price-policy scenarios. The outcome is consistent in both the SO model and PaR results. Under the central price-policy scenario, assuming medium natural-gas, medium COz price- policy assumptions, the PVRR(d) net benefits range between $180 million, when derived from PaR stochastic-mean results, and $204 million, when derived from SO model results. PaR risk- adjusted results range from $146 million when assessed with low natural gas, medium COz price- policy assumptions to 5260 million when assessed with high natural gas, medium COz price-policy assumptions. In the expected medium natural gas, medium COz price-policy scenario, wind repowering results in PaR risk-adjusted customer benefits of $ 189 million. Table 7.5 - SO Model and PaR d of Wind owerl million Projected system net benefits increase with higher natural-gas price assumptions, and similarly, generally increase with higher COz price assumptions. Conversely, system net benefits generally decline when low natural-gas prices and low COz prices are assumed. This trend holds true when looking at the results from the two simulations used to calculate the PVRR(d) for all nine of the PaR Risk- Adiusted PVRR(d)Price-Policy Scenario SO Model PVRR(d) PaR Stochastic Mean PVRR(d) (s I se)($ l4 l)(s148)Low Gas, Zero COz Low Gas, Medium COz ($ I 58)($ I 3e)($ t +o; ($ 1 73)Low Gas, High CO:($ I s:;($ I os; Medium Gas, Zero COz ($20 1 )($l7l)($ 1 80) Medium Gas, Medium COz ($204)($ I 80)(s 1 8e) (s I e3)($203)Medium Gas, High COz ($2 I s) Hieh Gas, Zero COz ($2s7)($234)($z+o; High Gas, Medium COz ($zoo;(s248)($260) Hieh Gas, Hish COz (s273)(s240)($2s2) 96 PacrrrConp -2017 IRP UPDATE CHAPTER 7 _ ENERGY VISIoN 2O2O UPDATE price-policy scenarios. Importantly, both models continue to show that the net benefits from the wind repowering project are robust across a range of price-policy assumptions. The wind repowering project creates these benefits by: . Increasing energy production from the wind facilities by approximately 25-7 percenq. Reducing ongoing operating costs associated with aging wind turbines;. Extending the useful lives of the wind facilities by at least l0 years;. Increasing the output of renewable energy from existing assets, while avoiding the environmental impacts and view-shed issues associated with new facilities;. Reducing customer costs by requalifying the wind facilities for PTCs for an additional l0 years; and. Improving the ability of the wind facilities to deliver cost-effective renewable energy into the transmission system through enhanced voltage support and power quality. These benefit trends hold true for annual data over the period 2017 through 2050. Table 7.6 summarizes the updated PVRR(d) results for each price-policy scenario calculated off of the change in annual nominal revenue requirement through 2050. Table 7.6 - Nominal Revenue of Wind million When system costs and benefits from the wind repowering project are extended through 2050, covering the full depreciable life of the repowered wind facilities, the wind repowering project reduces customer costs in all nine price-policy scenarios. Customer benefits range from Sl21 million in the low natural gas, medium COz price-policy scenario to $466 million in the high natural gas, high COz price-policy scenario. Under the central price-policy scenario, assuming medium natural-gas prices and medium COz prices, the PVRR(d) benefits of the wind repowering project are $273 million. While changes in federal income tax law have reduced net benefits relative to the economic analysis summarized prior to the passage of H.R. l, the wind repowering project continues to provide significant customer benefits in all price-policy scenarios, and the updated economic analysis reconfirms that upside benefits outweigh downside risks. Repowering Project Upside The PVRR(d) results presented in Table 7.1 throughTableT.6 do not reflect the potential renewable energy credits (REC) value of incremental energy output from the repowered facilities. Accounting Low Gas, Zero COz ($ I 27) Low Gas, Medium COz ($lzt; Low Gas, High COz ($223) Medium Gas, Zero COz ($224) ($273)Medium Gas, Medium COz Medium Gas, High COz (s321) High Gas, Zero COz ($38e) Hieh Gas, Medium COz ($386) High Gas, High COz (s466) 97 Price-Policy Scenario Annual Revenue Requirement PVRR(d) CHAPTER 7 - ENERGY VISION 2O2O UPOaTT for the updated performance estimates discussed above, customer benefits for all price-policy scenarios would improve by approximately $6 million for every dollar assigned to the incremental RECs that will be generated from the repowered facilities through 2036. Benefits for all price- policy scenarios would improve by approximately $12 million for every dollar assigned to the incremental RECs that will be generated from the repowered f-acilities through 2050. Quantifying the potential upside associated with incremental REC revenues is intended to simply communicate that the net benefits from the repowering project could improve if the incremental RECs can be monetized in the market. Moreover, as noted earlier, none of the economic analyses account for the capacity value of the repowered wind facilities in the period when they would have otherwise hit the end of their depreciable lives (i.e., beyond 2036). New Wind and Transmission (Combined Projects) Analysis conducted in the 2017 IRP covered a wide range of studies, including regional haze cases, price-policy cases and sensitivities. Wyoming wind was consistently selected in the optimized portfolios of nearly all cases, up to the maximum capacity of Wyoming wind capable of interconnecting to the transmission system without incremental investment in Energy Gateway transmission infrastructure. Based on these results, PacifiCorp further analyzed Energy Gateway sensitivities. This analysis showed that the combination of new wind and new transmission resulted in the least-cost, least-risk combination of resources to meet load and resource needs over the 2}-year planning horizon. Enabled by the transmission projects described later in this chapter, and based on the results of PacifiCorp's 201 7R RFP, 1,3 I I MW of new wind resources will be placed in service by the end of 2020, creating substantial benefits for customers. Wind Projects Extension of federal PTCs created a time-limited opportunity for PacifiCorp to acquire significant cost-effective, zero-fuel cost wind resources, generating PTCs from the Wind Projects that will help meet projected capacity needs and provide substantial benefits for customers. The additional capacity from the Wind Projects will reduce reliance on more costly and less certain resources, in particular uncommitted front office transactions (market purchases) over the near term and defer the need for higher-cost resource alternatives over the long term. While not valued as part of this analysis, the new wind energy will also produce additional RECs, further increasing the value of these new resources. To achieve the full customer benefits of the PTCs, PacifiCorp must develop the Wind Projects with the Transmission Projects and bring them into service together. The Wind Projects are not economic without the Transmission Projects, which are needed to relieve existing congestion and to interconnect new PTC-eligible wind facilities in high-wind areas of Wyoming. The Transmission Projects are not economic without incremental cost-effective wind facilities producing zero-fuel-cost energy and PTCs. 2017R RFP The 2017 IRP Update preferred portfolio relies on the extensive analysis conducted in the Company's 2017R RFP, and advances PacifiCorp's commitment to low-cost energy with plans to 98 PACIFICORP - 20 I7 IRP Upoerp PACIFICoRP 20I7 IRP UPOnrg CrreprER 7 ENERGY VISIoN 2O2O UpoarE add 1,3 1 I MW of new Wyoming wind resources by the end of 2020.4 These new zero-emission wind facilities will connect to a new 14O-mile, 500 kV transmission line running from the Aeolus substation near Medicine Bow, Wyoming, to the Jim Bridger power plant (a sub-segment of the Energy Gateway West transmission project). In addition to providing significant economic benefits for PacifiCorp's customers, the wind and transmission project will reduce market reliance, improve transmission reliability, and provide economic development benefits. PacifiCorp received initial bids for Wyoming wind projects on October 17,2017, and initial bids for non-Wyoming wind projects on October 24, 2017 . The 2017R RFP was well received by the market, as indicated by the fact the company received Wyoming wind proposals from nine bidders offering 49bid alternatives for 13 wind projects. PacifiCorp also received non-Wyoming wind proposals from five bidders offering l5 bid alternatives for six wind projects. In aggregate,5,2l9 MW of new wind resource capacity was bid into the 2017R P.FP (4,624 MW of Wyoming wind and 595 MW of non-Wyoming wind). The 2017R RFP was monitored by two independent evaluators-one retained by PacifiCorp and appointed by the Public Utility Commission of Oregon and one retained by the Public Service Commission of Utah-and resulted in a final shortlist consisting of four projects: (l) the TB Flats I & II project providing 500 MW of capacity in Carbon and Albany Counties, Wyoming; (2) the Cedar Springs project providing 400 MW of capacity in Converse County, Wyoming; (3) the Ekola Flats project providing 250 MW of capacity in Carbon County, Wyoming; and (4) the Uinta project providing l6l MW of capacity in Uinta County, Wyoming. Together, these least-cost, least-risk projects will provide l,3ll MW of zero-fuel cost, emission-free generation to serve PacifiCorp's customers. Approximately 1,150 MW of this capacity (TB Flats I & II, Cedar Springs, and Ekola Flats) is located within the transmission-constrained area of PacifiCorp's transmission system in eastern Wyoming and is enabled by the Aeolus-to-Bridger/Anticline transmission line. The remaining 161 MW of capacity (Uinta) is located in westem Wyoming. PacifiCorp selected the final-shortlist projects after performing detailed and comprehensive economic analysis of all bids received. Using the same models and methodology used in the2017 IRP, PacifiCorp determined the optimum combination of bids to maximize customer benefits. Extensive modeling confirms that the final shortlist resources meet both near-term and long-term resource needs and are the least-cost, least-risk path available to serve PacifiCorp's customers. PacifiCorp's risk assessment further demonstrates that the final-shortlist resources provide substantial customer benefits across nearly every natural gas and COz price-policy scenarios studied. Relative to the 201 7 IRP, the 2017R RFP results demonstrate increased customer benefits from the new wind resources, in combination with construction of the Aeolus-to-Bridger/Anticline 500-kV transmission line and associated infrastructure (transmission project). Transmission Projects While the Aeolus-to-Bridger/Anticline transmission line has long been recognized as an integral component of PacifiCorp's long-term transmission planning, its construction and that of the other components of the Transmission Projects has not been economic until now. The Transmission Projects will contribute to meeting PacifiCorp's short- and long-term capacity need and will strengthen the overall reliability of the existing transmission system. 120t7 Wind IRP issued September 27,2011 , approved by the Public Service Commission of Utah on September 22, 2017 , and the Public Utility Commission of Oregon on September 27 , 20ll 99 PACIFICoRP _ 2017 IRP Upoarg CHaprpn 7 - ENsncy VISIoN 2020 Upnem Congestion on the current transmission system in eastern Wyoming limits the ability to deliver energy from eastem Wyoming to the Jim Bridger area. The Aeolus-to-Bridger/Anticline line will relieve this congestion and increase the transmission capacity across Wyoming by approximately 950 MW.s The Transmission Projects will allow PacifiCorp to interconnect 1,3 I 1 MW of wind resources and create substantial benefits for customers throughout its service area. Construction of the Transmission Projects will also enable PacifiCorp to more efficiently use existing generation resources in Wyoming to serve loads in Utah, Wyoming, Idaho, and the Pacific Northwest. The Transmission Projects also better position PacifiCorp to interconnect future resources in southeastern Wyoming and provide greater flexibility in managing existing resources. In addition to increasing the transmission capacity out of southeastern Wyoming, the Transmission Projects will also provide critical voltage support to the Wyoming transmission network and enhance the overall reliability of the transmission system by adding incremental new transmission capacity westbound between the company's existing thermal and renewable facilities, the proposed Wind Projects in eastern Wyoming, and other sources of energy in northern Utah. Additional transmission paths will mitigate the impact of outages on the existing system. The Transmission Projects will also enhance PacifiCorp's ability to comply with mandated North American Electric Reliability Corporation and Western Electricity Coordinating Council reliability and performance standards. The Aeolus-to-Bridger/Anticline line is also an important component of PacifiCorp's Energy Gateway Transmission project and has long been recognized as a key transmission segment in the region's long-term transmission planning. By acting on this time-limited opportunity to develop the Transmission Projects and the associated Wind Projects, PacifiCorp can deliver substantial benefits for its customers. Wyoming CPCNs On April 12,2018, PacifiCorp received conditional CPCNs for the Aeolus-to-Bridger/Anticline transmission line, the TB Flats I & II wind project, the Cedar Springs wind project, the Ekola Flats wind project, and associated network upgrades from the Wyoming Public Service Commission. These CPCNs are required to secure the necessary rights-of-ways, which has been initiated, before construction begins. Production Tax Credits and Customer Benefits The substantial customer benefits resulting from the acquisition of the Wind Projects reflects the fact that these facilities can qualify for 100 percent of federal PTCs by achieving commercial operation by December 31, 2020. PacifiCorp's approach to the Combined Projects is to mitigate risk and ensure that appropriate off- ramps exist in the project review, approval, and implementation processes before significant capital outlays or commitments are made in case the necessary approvals are not received, project economic benefits erode, or the associated benefits are placed at risk. With timely regulatory 5 The updated economic analysis assumes the incremental transfer capability is 750 MW. Subsequent transmission studies have confirmed the transfer capability is 950 MW. Consequently, the economic analysis presented in this chapter is conservative. 100 PACIFICORP 2OI7 IRPUPOATT,CuapTER 7 - ENERGY VISION 2O2O UPDATE reviews and approvals, and successful transmission rights of way (ROW) acquisition, PacifiCorp fully expects it will successfully meet the requirements necessary to ensure eligibility for 100 percent of the PTCs. Updated Data and Assumptions During the period between the April 4,2017 filing of the 20ll IRP and the preparation of this 2017 IRP Update, PacifiCorp has continued to refine its economic analysis supporting the Combined Projects. In addition to the assumption updates summarized earlier in this chapter, the updated analysis of the Combined Projects incorporates the most current cost-and-performance assumptions. Wind Projects Table 7.7 presents the winning wind bids from the 2017R RFP. The updated best-and-final pricing received on December 21,2077 was used in the model analysis to establish the winning projects, and the model results are presented later in this chapter. The total capacity of the winning bids is 1,31 I MW, assuming commercial operation by the end of 2021. Table 7.7 - 2017R RFP Final Shortlist The TB Flats I & II and Ekola Flats projects are company-benchmark resources that will be developed under engineer, procure, and construction (EPC) agreements. The Uinta project is being developed by Invenergy Wind Development under a build-transfer agreement (BTA). The Cedar Springs project is being developed by NextEra Energy Acquisitions as a 50-percent BTA and a 5O-percent power-purchase agreement (PPA). In total, the updated final shortlist includes 361 MW that will be developed under BTAs, 750 MW of benchmark capacity that will be developed under EPC agreements, and 200 MW that will deliver energy and capacity under a PPA. In aggregate, the winning bids are expected to operate at a capacity-weighted average annual capacity factor of39.4 percent. Transmission Interconnection-Restudy Process Separate from the 2017R RFP process, the company completed an interconnection-restudy process to ensure that interconnection studies reflected the most current long-term transmission plan to construct the Aeolus-to-Bridger/Anticline D.2 segment of the Energy Gateway project by the end of 2020. PacifiCorp transmission restudied, in serial interconnection-queue order, interconnection requests that do not already have an interconnection agreement to determine whether the staging TB Flats I & II (PacifiCorp)Carbon & Albany Counties, WY 500 Cedar Springs (NextEra Energy Acquisitions)Converse County, WY 400 Ekola Flats (PacifiCorp)Carbon County, WY 250 Uinta (Invenergy Wind Development)Uinta County, WY 161 101 Proiect Name (Bidder)Location Capacity (MW) PacrprConp - 2017 IRP UpoaTp CnAp l'[ri 7 ENr:ncv VrsroN 2020 Uppn'r r of the Energy Gateway West project would affect the cost or timing of projects whose previous interconnection studies depended on Gateway West in its entirety. Affected projects located in the constrained area of PacifiCorp's transmission system in eastem Wyoming were restudied through the point in the interconnection queue where additional segments of the Energy Gateway project beyond just the Aeolus-to-Bridger/Anticline D.2 segment would be required to interconnect. PacifiCorp transmission posted the restudied system-impact studies (SISs) on PacifiCorp's open access same-time information system on January 29,2018, as well as certain updated restudied SISs on February 9, 2018. The interconnection-restudy process showed that the Aeolus-to-Bridger/Anticline transmission line will enable interconnection of up to 1,5 l0 MW of new wind capacity within the constrained area of PacifiCorp's transmission system in eastern Wyoming. However, to honor an executed interconnection agreement with a 240 MW qualifying facility (QF) project in the area, PacifiCorp must reserve sufficient interconnection capacity for this QF's interconnection, which results in an incremental capacity of 1,270 MW. This is up from the 1,030 MW assumed in previous studies. The interconnection-restudy process confirms that all bids selected to the 2017R final shortlist can secure interconnection service either because they hold an interconnection-queue position that does not require Energy Gateway South (Ekola Flats, TB Flats I and II, and Cedar Springs) or because the project is not located in the constrained area of the company's eastern Wyoming transmission system (Uinta). New Wind and Transmission Results As a component of the 2017R RFP, PacifiCorp produced updated portfolio-development studies using the SO model to create a bid portfolio containing the least-cost combination of viable bids. In choosing the least-cost combination of bids, the SO model was configured to select from all viable bid altematives. Consistent with the increased interconnection capability identified during the interconnection-restudy process, the SO model was also configured to select up to 1,270 MW of bids located in this area of PacifiCorp's transmission system. Table 7.8 summarizes the updated PVRR(d) results for each price-policy scenario. The PVRR(d) between cases with and without the Combined Projects, reflecting the final shortlist from the 2017R RFP, are shown for the SO model and for PaR, which was used to calculate both the stochastic-mean PVRR(d) and the risk-adjusted PVRR(d). 102 PecrprConp -2017 IRP Upoars CIIAP.I.I|R 7 ENI|RGY VISION 2O2O UPDA II. Table 7.8 - SO Model and PaR PVRR(d) (Benefit)/Cost of the Combined ects Over a Zl-year period, the Combined Projects reduce customer costs in all nine price-policy scenarios. This outcome is consistent in both the SO model and PaR results. Under the central price-policy scenario, when applying medium natural gas, medium COz price-policy assumptions, the PVRR(d) net benefits range between $357 million, when derived from PaR stochastic-mean results, and $405 million, when derived from SO model results. The Combined Projects create these benefits by: . Reducing customer costs by generating significant PTC benefits;. Contributing to meeting system capacity needs, thereby reducing reliance on uncommitted front office transactions (market purchases) in the near term and deferring the need for higher cost resource alternatives over the long term;. Reducing system fuel costs;. Increasing transmission capability in a constrained area, enabling better use of resources;. Avoiding emissions costs in the medium and high COz price scenarios; Table 7.9 summarizes the updated PVRR(d) results for each price-policy scenario calculated off of the change in annual nominal revenue requirement through 2050. Low Gas, Zero COz (185)(ls0)(156) Low Gas, Medium COz (208)(t7e)(1 88) Low Gas, Hieh COz (370)(337\(355) Medium Gas, Zero COz (377\(3le)(334) (40s)Medium Gas, Medium COz (3s7)(386) Medium Gas, Hieh COz (48e)(448)(46e) High Gas, Zero COz (6ee)(s68)(se6) (716)High Gas, Medium COz (603)(633) Hieh Gas, Hieh COz (781)(6e4)(728) 103 Price-Policy Scenario SO Model PVRR(d) PaR Stochastic- Mean PVRR(d) PaR Risk-Adjusted PVRR(d) Table 7.9 - Nominal Revenue Requirement PVRR(d) (Benefit)/Cost of the Combined ects million When system costs and benefits from the Combined Projects are extended out through 2050, covering the full depreciable life of the owned-wind projects included in the updated 2017R RFP final shortlist, the Combined Projects reduce customer costs in seven out of nine price-policy scenarios. In those price-policy scenarios showing net benefits, customer net benefits range from $92 million in the medium natural gas, zero COz price-policy scenario to $635 million in the high natural gas, high COz price-policy scenario. Under the central price-policy scenario, when applying medium natural gas, medium COz price-policy assumptions, the PVRR(d) benefits of the Combined Projects are $167 million. The Combined Projects provide significant customer benefits in all price-policy scenarios, and the net benefits are unfavorable only when low natural-gas prices are paired with zero or medium COz prices. These results continue to show that upside benefits far outweigh downside risks. Potential Wind Projects Upside The PVRR(d) results presented in Table 7.8 andTable 7.9 do not reflect the potential value of RECs generated by the incremental energy output from the Wind Projects. Accounting for the performance estimates from these wind facilities, customer benefits for all price-policy scenarios would improve by approximately $34 million for every dollar assigned to the incremental RECs that will be generated from the winning bids through2036. When calculated from expected wind generation through 2050, customer benefits would increase by approximately $43 million in all price-policy scenarios. Quantifying the potential upside associated with incremental REC revenues is simply intended to communicate that the net benefits from the winning bids could improve if the incremental RECs can be monetized in the market. Also, projects with large wind turbines are expected to require less O&M costs because there are fewer turbines on a given site. The default O&M assumptions applied to BTA and benchmark- EPC bids in the updated economic analysis are based on the company's experience in operating and maintaining the existing fleet of owned-wind facilities, and do not reflect expected cost savings associated with operating and maintaining wind facilities proposing to use larger wind turbines. Three of the winning bids--Invenergy Wind Development's Uinta project, the company's TB Flats I & II project, and the company's Ekola Flats project--will use larger equipment for a portion of the wind turbines at each facility. If the O&M cost elements applicable to the larger-turbine 104 Price-Policy Scenario Annual Revenue Requirement PVRR(d) Low Gas, Zero COz 184 Low Gas, Medium COz 127 Low Gas, High COz (147) Medium Gas, Zero COz (e2) Medium Gas, Medium COz (167) Medium Gas. Hieh COz (304) High Gas, Zero COz (448) High Gas, Medium COz (4ee) High Gas, High COz (63s) Pe,crprConp - 2017 IRP UPDAIE CTIAPTER 7 - ENERGY VISION 2O2O UponT.E PecInIConp -2017 IRP UPDATE Cueprr,R 7 - ENERGY VISIoN 2O2O UPDATE equipment are reduced by 42 percent, which is equivalent to an approximately l8-percent reduction in total O&M costs, beyond the proposed O&M agreement period, customff benefits calculated through 2036 for all price-policy scenarios would improve by approximately $19 million. Finally, the updated economic analysis assumes the incremental transfer capability associated with the Aeolus-to-Bridger/Anticline transmission line is 750 MW. Subsequent transmission studies have confirmed the transfer capability is 950 MW. Consequently, the economic analysis presented in this chapter is conservative. PacifiCorp continues to pursue regulatory approvals for the Energy Vision 2020 projects, consistent with the timing of the associated action plan items further described in Chapter 10. The updated economic analysis of the wind repowering project supports repowering just over 999 MW of existing wind resource capacity located in Wyoming, Oregon, and Washington. The updated economic analysis shows significant net customer benefits in all of the scenarios analyzed. The wind repowering project will replace equipment at existing wind facilities with modern technology to improve efficiency, increase energy production, extend the operational life, reduce run-rate operating costs, reduce net power costs, and deliver substantial federal PTC benefits that will be passed on to customers. The results of the 2017R RFP confirm that the Combined Projects are the least-cost, least-risk resources available to serve PacifiCorp's customers. The substantial volume of bids that were submitted into the 2017R RFP produced competitive project costs, allowing PacifiCorp to obtain greater wind generating capacity at lower overall capital costs, with increased net benefits for customers. The Combined Projects show net customer benefits under all price-policy scenarios through 2036 and in seven of nine scenarios through 2050. 105 Conclusion PRcrprConp -2011 tRP Upoalg Cunprpn 7 - Eur:ncv VISIoN 2020 UpDATE [This page is intentionally left blank] 106 PACIFICoRP - 2OI7 IRP UPDATE Cuaplrn 8 Pon'r'r,or.ro DEVELopMr.N r CgaprER 8 - PonrFoLIo Dr,vEroPMENT PacifiCorp used the System Optimizer (SO) model to develop an updated preferred portfolio based on inputs and assumptions updated since the 2017 Integrated Resource Plan (IRP) was filed April 4, 2017. This updated resource portfolio is consistent with PacifiCorp's most recent load-and- resource balance as described in Chapter 4. This chapter presents the 2017 IRP Update preferred portfolio and a comparison of changes relative to the 2017 IRP preferred portfolio. This chapter also includes a sensitivity comparing the 2017 IRP Update preferred portfolio to the fall2017 business plan. The2017 IRP Update focuses on changes that occurred after PacifiCorp filed its 2017 IRP. These include updates to load forecasts, changes in existing resources, any additions to PacifiCorp's contracts with other entities, and changes to Energy Vision 2020 resources. Table 8.1 summarizes the annual capacity in the 2017 IRP Update relative to the 2017 IRP preferred portfolio for the l0-year period 2018 through 2027- Consistent with the change in PacifiCorp's load-and-resource balance, the reduction in peak loads decreases the need to add new resources relative the 2017 IRP. The reduction in load reduces front-office transaction (FOT) and demand-side management (DSM) resources. An additional2ll MW of new wind is added as part of Energy Vision 2020 new wind resources described in Chapter 7. The level of summer FOTs in 2027 is 493 MW, which is lower than in the 20l7IRP and below the assumed 1,575-MW FOT limit. PacifiCorp has not updated its FOT limits for the 2017 IRP Update but will review its FOT limits during the 2019 IRP public process. The updated portfolio does not include any natural gas resources through the 2}-year planning horizon. Table 8.2 (summer) and Table 8.3 (winter) summarizes the 2017 IRP Update load and resource balance, inclusive of incremental resources, for 2018-2036, and Table 8.4 presents the2017 IRP Update preferred portfolio through 2036. Class 2 DSM selections in the 2077 IRP Update were updated to reflect more current information on actual and projected acquisitions in the near-term (2018-2020) and the value of Class 2 DSM resources to the system. For 2018-2020, Oregon and Washington projections were modified to reflect current Energy Trust of Oregon projections and the approved "Demand Side Management 2018-2019 Business Plan" filed with the Washington Utilities and Transportation Commission (WUTC).' For Utah, 2018-2020 projections match the 2017 IRP preferred portfolio selections. 2018-2020 projections for California align with forecasted achievements in2018 and the 2017 IRP preferred portfolio selections for 2019 and 2020. For 2018-2020 Wyoming Class 2 DSM was updated to reflect proposed targets currently under review by the Wyoming Public Service Commission. From 2021 on, the SO model optimized Class 2 DSM selections to reflect the updated load-and-resource balance, and the associated value of Class 2 DSM in relation to other resource alternatives over the medium and long term. 1 Washington Utilities and Transportation Commission, Docket UE-171092, Order 01, January 12,2018. 107 Introduction @ ;l i El:l 3l ^l-i l'l 'l] ? t ! e ? F a , I z I :- c II cL r d I _o Lo ! r d o I 3 I r N qa G a06)=a tr q)LL.q) 6) r- 6l 0) D r- t\ a, U I 6o CEF I ) F d : liil"l l'll'*l I l tl iL=. tl .:!- .l3l"l I I I I tl 1l tl "t al >ic .al,I l I I tl I I a .t 3l"l ! I' I ! tl "tg 6l :trl ;i,l I "lt 1l tl *ll I Ell"tl I tl tl I i ll ll ! I lt FZtr.l Jtr.l tr.laoJ EF I oo &tr.lF (, tr.lF o D lJi t-- c\l I 0r Qtl O i: ,j l'l''l I I I : I 'll,li t1 4 I 'll I I :_ I , I a , ll ll I I lll l'l' =ll.l Il t"l I I I I tl t' I' I I' 'll l.'ll PACTFTCoRP - 20 17 IRP Upoars Crraprsn 8 - Ponrpolro Devgloprr,rpNr Table 8.2 - 2017 IRP Update Summer Capacity Load and Resource Balance (Megawatts) ( alendar Yc.rr 20 I a 20 l 9 2ll2ll 21121 21122 21123 21121 Zll25 2llzar 2027 Erst Thel:l:ml Hydrcelectric Qualirying Facilities Class I DSM Sales Non-Owned Reserves TmnsfeB 6,43 t07 I 249 644 323 (6s5) (3s) 62 7294 o o o o o o o 7,29,i 6,853 (loa) o (les) o o (l ra) 6.432 462 462 6,123 I l4 194 249 69r 323 ( 4r55 ) (-15) 231 7,235 o o o o o I I a 236 6,91 I(16) o (res) o o < tTat 637,i 455 455 (r, I 23 l14 t99 21.) 713 f 2-l 142 4,203 o o o o o I I 7,2O1 6.972 t l()l) o o o ( ll(,) 6349 5,736 lt4 197 221 735 321 ( t7s) (35)(s) a,oza o o 207 o o I 204 7,236 7,O30 (2r3) o (195) o o (273) 6344 a5l 851 5.736 tt4 t90 22t 734 323 (ta5) (3s) (77) 7,O35 o o 207 o o I 2()4 7,243 7,t04 (22O) o ( res) o o (3r9) 637lJ 453 as3 5,736 I 14 190 221 734 323 (| 75) (-15) (7 t> '7,O3'7 o o 207 o o I 204 '7.243 7,172 (226) o ( res) o o (-r6S) 6346 456 as6 5,736 93 t90 221 679 38 ( l4a) (3s)(r) '7,'J6l) o o 207 o o I 2()4 7,26'i 7,248 <231) o (r9s) o o (4lo) 6,4tJ9 459 459 5,736 93 190 t2t 674 323 (r+a) loa 7,'J63 7,3U) (142 ) o ( l<)5) o o (fd)) 6,112 459 459 5,654 93 lao t2t 670 323 <(fi, (3s) 56 6,997 o o 207 o o I 204 '7,2O5 7,31O 1252, o (t95) o o (s(r)) 6354 a5l a5l 5,654 93 lao t2t 66 323((,) (3s) 3a 6,975 o o 207 o o I 20a 7,t a3 7,354 (269) o ( 195) o o (555) 6,334 449 449 &st &isting Resources Frcnt Office T@nsactions Gs Solar Class I DSM Other Eist Total Resources Private eneEtion kisting Resources: Intelruptible Class 2 DSM New Resources: Class 2 DSM E st oHigrtion Plannins ksewes ( l3ol/o) o o 207 o o I 204 7,24I a5l a5t &st OHigation + Reserws &st Position tut Reserw Nhrgin 7,294 4 13"/o 7,233 4 I 3"/o 7,2OO 3 I 30/o 7,199 36 I 40/o 7,223 20 I 1"/o 7,211 4 I 3"/" 7,264 (0) I 3"/" 7,271 (() ) | 3./" 7,205 (o) I 3"/" 7,1 a3 (o) 1 3"/" Thel:lml Hydrcelectric Qualirying Facilities Class I DSM Sales Non-O\med kseryes Tansfe6 \ryest E(lsting Resourc€s Frcnt Office TEnsactions Gs r'r/ ind Sohr Class r DSM Other West PlannGd Resources west Tobl Resources I-ad Pdvate CeneEtion kisting Resources: Intelruptible Class 2 DSM New Resources: Class 2 DSM Wcat oHigrtlon Plannina kserves ( I 3olo) West Re3eres west loblagation + Reierws WGst Pcition West Re3ere krgin 2,254 861s la 235 3 (r65)(r) ( (i-l ) 3,23 r 3,234 (13) o o o o(e) 3,161 4l I 4ll 2,254 747 aa I 220 3 (t65) (3) (232) 2,913 2,2* 79.) 95 I 227 3 ( 165) (:l) ( l4-3) 3,06O 2,254 ffi 95 I 203 o(r6r) (3) aa 3,122 655o I la5 o (ao) (-3) (o) 454 o o o o o 454 3,526 3,36 (44) o o o o (lea) 3,t 20 4M 406 2,254 655 m I 184 o ( ao) (f) (loe) 2,963 570 o o o o o 57lJ 3,533 3,395 ( ss) o o o o (214) 3,126 46 406 229 645 59 I ta2 o (ao) (3 ) (s7) 3,OO r 529 o o o o o 529 3,53() 2,254 654 5a I 150 o ( ao) (3) (40) 2,999 3,436 (71t o o o o (f4:) 3,123 46 406 2,254 624 65 I la7 o(t lO) (-3 ) 70 2,254 547 65 I t94 o(lro) (3) 76 530 o o o o o 53() 3,329 444 o o o o o 444 419 o o o o o 419 3,064 3.0a8 3-1172 334 o o o o o 334 3,569 4% o o o o o 490 471 o o o o o 4at o o o o o I 3,542({) t30/" 3,554({) I 3"/o 3,545 (3) I 30/" 3,539(r) I 30/o 3,535({) I 30/o 3,526 o | 3'/o 3,533 (o) l3o/o 3,329 o 13"/o 3530 (o) I 3o/o 3.544 3.279 ( le) o o o o (<)1) 3,r66 4t2 412 3'57a (4) t30/o 3,293 (25) o o o o (l2f) 3,1 46 3,541 3,3t2 (31 ) o o o o (le) 3,137 {a 4()4 3,33 I (-17) o o o o (t63) 3,t32 3,35 I (41) o o o o (rar) 3,129 407 407 3.415 o o o o (rla) 3,121 46 406 3,551 3,5J5 3,532 ry 409 aa 407 ro,a67 9.594 1,273 lo,a67 o t 30/" lo,8l I 9.5'l4 1.26 lo,al I o | 30/o I O,755 9,495 1,260 I o,755 (()) I 30/" 10.747 9,445 t,254 to.74 33 11"/" to,a79 9,5o2 |,261 1o,762 t7 t30/o to,777 9,515 t,262 to,777 (o) 130/. t 0.794 1,2& to,a93 o I 3"/o lo,ag 9,539 t_265 lo,a& (o) I 3o/o 1o,735 9,4a8 1,2s7 I 0,735 (o) 130/o to.7 t2 9,454 1,255 to,7 t2 (()) I 3"/o OHigation ReserEs Obligetion + Reserws System Position ReserE M.rgin 109 Sv3tcm PecIrrCOnr _2011 tRP UPDATE Cuepren 8 - Ponrpolro DeveLopnarut Table 8.2 (Cont.) (Megawatts) 2017 IRP Update Summer Capacity Load and Resource Balance 2024 2lt2.'2 0JO 203 1 2033 2031 20J5 2(1362113 2 Thelrul Hydrcelectdc Qualifying Facilities Class I DSM Sales Non-tued Reserues TEnsfere Fast Erlsttng Resources Front Office Transactions Cas Solar Class I DSM Other &st Planned Re F-st Totat Faesources 16ad hvate eneEtion ExistinS Resources: Intelmptible Class 2 DSM New ksources: Chss 2 DSM East obligation Plann ins Resewes ( I 3olo) l5l o 207 o o I 359 3la o 353 177 too I 1,249 307 o 353 477 l5l o r,aa 4,492 93 lao l2t 662 323 ( 6(;) (15) 670 6,441 4,492 93 lao t2t 655 323 (66) (3s) 457 652t 3ra o 207 o 72 I s99 4,219 7,5tO (3O3) o (tes) o o(as) 6367 453 453 4,535 93 158 l2l 652 32f (66) (3s) 437 6,614 3la o 226 o 72 I 6la 4,236 7,5q (324) o (re5) o o (6eo) 634 I 855 855 4,459 93 126 t2t 644 323 o (-rs) 466 6,602 3la o 226 o 72 I 6la 72r9 7,531 (236) o ( | 9-s) o o(731) 6,366 453 a53 4,459 93 t26 t2t 634 323 o (-15) 917 6,642 3la o 226 o -72 I 6ta 7,624 (tr(,1) o (le5) o o(771' 6,4o2 a5a a5a 4,102 93 t26 t2l 605 323 o 692 6,O29 4,t02 93 126 t2l 549 323 o(:5) 69t 6,O12 4,O2t 93 t26 t2t 544 323 o (35) 7o3 5,934 3ta o 353 4ao 246 o t .396 1,O2t 93 t26 t2t 532 323 o 453 5,935 3la o 376 4ao 254 o r,432 470 470 7371 (4) l3o/o a,2oo 7,2 59 7,27 8 7.299 a 333 7 J6a 4,433 (2aa) o (l9s) o o(602) 6,349 a5l 451 7-7O5 (ra+) o ( t.r5) o o ( ao5) 6,42 | 460 460 7,778 ( -loa) o (res) o o (a-f5) 6,440 462 462 4,86t o (1.)5) o o ( a('-l ) 6,4'7O 466 466 4,941 ( 154) o ( les) o o (ae2) 6,5O I &st OHigation + Reserres Fsst Position &st Reserw Margin 7,199 o I 3'/o 7,22O (ar) I 3o/o 7,236 (o) 130/o 7,219 o | 3'/o 7,281 (J) I 3"/o 7,3O2 (f,) I 3'/o 7,336 (3) 136/o 7 259 (()) I 30/. Thercl Hydrcelectric Quarirying Facilities Class I DSM Sales Non-Ormed Reserves TEns fere West Btsting Rcsources Front OfTice Trans action s Gs Solar Class I DSM Gher West Plrnned Faesources West -foat Elesources laad Priwate Gneration Hsthg ksources: Intemptible Class 2 DSM New Resources: Class 2 DSM West olrligation Planning Reseryes ( l3o,/o) 2,2s4 653 5S I 149 o (ao) (3) (67 t) 2359 l,900 653 53 I 132 o (74) (3) (466) 1.793 1,541 653 53 I 97 o (7a) (-l) (6e2) 1,572 t,54 1 653 53 I 96 o ( 7a) (3) <704> 1 ,56() I,900 653 54 I l3a o (74) (-3) (4sa) 2,2O't 1,3s2 o o o o o | ,352 3,560 3,503 (46) o o o o (264) 3,15() 4to 4ro I,900 653 54 I t33 o <aa) (-3) (437) I ,423 t.352 o o 3s3 o o l.a05 3,524 1,495 (e3) o o o o (2ao) 3.r22 406 406 I,900 653 53 I 99 o (74) (-3) <9 l7') 1.7()4 3.532 ( a()) o o o o ( -l(,1 ) 3,149 4@ 4.)9 t,541 653 53 I 97 o (74) (3) (6e3) I,Sa2 I,541 653 53 I o (24) (3) (7 51) 1.561 t,t7t o o o o o l,l7t 3,53() 1,352 o o 414 o o 1.766 3,559 r,352 o o49 o o I ,A5O 3,559 1,3s2 o o 613 25 o I ,949 1,352 o o 613 25 o I ,949 3,562 o 39 613 25 o 1,996 1,352 o 39 6r3 25 o 2,O29 3,349 ,3 r9 3,562 3,554 3,457 (74) o o o o (2ss) 3.124 406 406 3,513 (72) o o o o (291) 3,r 50 4aD 409 3,554 (ae) o o o o (llr) 3,152 3,575(loo) o o o o (322' 3,1 52 4to 4to 3,620(llt) o o o o (3-3 2 ) 3,t46 413 413 3,612 < 122) o o o o ( -142 ) 3,149 4@ 409 4to 4lo West OHiAetion + Reserws West Pcition west Reserw krgin 3,530 o t 30/o 3,56O o I 3o/o 3,524 o t 36/. 3,559 o I 30/o 3,562 (o ) 130/- 3,549 (0) 136/o 3,554 (l) I 30/. 3,559 o I 3'/o 3,562 (I ) 130/. ll0 Totsl Resources OHigation Res errs OHigotion + Reserws System PGition Reserw Margin 1o.730 9,473 r,257 1o,729 o 13"/o 1o,779 9,517 1,263 1o.779 (()) | 3o/o I o,763 9,503 r,26t to,763 o I 3'/o to,77a 9,5 l6 t.262 to,77a o 130/. lo,8t8 9,55 l |,264 IO,8t8 o I 3o/o I o,439 9,543 t,2ao lo,a43 (3) llo/. to,a6 I 1,242 ro,864 (-r) 130/. I 0,922 9.646 1,279 10,923 (+) l3o/o I O,925 9,650 l ,2ao 1o.929 (5) I 3'/o Calcndar Year kst PncmrConr - 2017 IRP UPDATE CHapren 8 - Ponrpolto DEVELopMENT Table 8.3 - 2017 IRP Update Winter Capacity Load and Resource Balance (Megawatts) Calendar Year 21121)202t 2022 2023 2024 2025 2o26 2024 Hydroelectdc Qualiryina Facilities Class I DSM Sales Non-O\^med ReseNes 6,5 l3 72 196 734 691 o (173) (35 ) 3 a,ool 5,846 72 190 23s 745 o (173) (f5) (14r) 6,734&st E\isiiDg Rcsurrccs 6,233 72 t99 434 442 o (t7l) ( l5) 7 a,aa9 6,233 a2 197 734 740 o (t73) (35) 3l '7.799 5,U6 190 235 736 o (l7f) ( l5) ( l{) 6,727 5,aM 72 190 235 82 o (r7f) ( 146) 6,67O o o 207 o o I 204 6,.t7'i 5,44 72 t{ t2t 6aa o (r4a) (-15 ) ( t_15) 6,549 5,% 72 r90 t2t 643 o ( l4a) ( l5) (r"6) 6,592 5.763 72 tao t2l 6a o (l16) 6saa 5,763 72 lao t2t @ o (4,6) (35) ( 143) 6$54 Frcnt OfFrce Tansactions Cas Sola. Class I DSM Oth er o o o o o I I '7,'7AO o o o o o o o ot4 o o I 145 7,941 6.916 6,935 5,617 (o) o ( le5) o o(ltt)s3r2 o o 204 o o I 204 207 o o o o I o o 207 o o I 204 o o 207 o o I 204 6,797 o o 207 o o I 204 o o 204 o o I 204 6,785 2(la a,()o I 6,8()O 6,765 bad Pdwate Gneation kisting tusources: Intemptible Class 2 DSM New ksources: Class 2 DSM tut oHig.tion Plannins kserves ( I3olo) &3t Reserws 5,590 (o) o (t95) o o(e) 5'3l I 7t6 716 5,654 (o) o (t95) o o (t471s;r6 5,7t 8 o o o 5,341 5,774 (o) o ( 195) o o (2la) 3'36 T 5,81 I (0) o ( I.r5 ) o o 5,363 5,46 (o) o ( 195) o o (291 ) 53aO 5.792 (o) o ( l<)5) o o ( 324) s269 7to 7to 5,414 (o) o (195) o o ( 363) 5,255 5,so (o) o ( 195) o o ( 56) sSro at6 716 716 7t6 716 720 720 722 722 723 723 725 725 f(r9 709 &st OUigation + Reserws &s t Pos ition &st Reserw krgin 6,O25 I,976 51"/o 6,O26 l,a s3 4"/o 6,O24 1,916 sG/" 6,O32 914 310/o 6,O6O a7s 3O"/o 6,O43 793 2ao/o 6,O457tt 270/" 6,r 05 695 260/" 5,979 ao6 2q/" 5,964 aor 290/0 Thellrel Hydrcelectric Qualiryins Facilities Class I DSM Sales Non-Ol^ned kseryes Tmnsfe6 west Exlstlng Resources 2,316 w 95 I 220 o ( 154) (3) (32) 3343 2,316 7AS 95 I t95 o(ls4) (3) l{ 3,375 2,316 9t7 90 I 224 o (162) (3) <4)33ao 3,342 o o o o o (ss) 3246 424 427 2,316 943 95 I 2lt o (t62) (3) (8) 3'395 321 o o o o o 321 3J t6 3,376 (o) o o o o (ao) 3293 2,3 t6 743 a I 176 o (al) (3) 133 33as 3-473 (o) o o o o (r93) 3,24O 426 426 2,316 747 59 I 175 o (al) (,r ) t25 3;74 2,316 7U 5a I t7t o (al ) (.r ) 125 3,371 349 o o o o o 349 3,42t 2,316 a% 56 I t4 o (al) (3) ta 3'36a 3g o o o o o 364 3,7 32 3,547 (o) o o o o(24t 33()3 429 429 336 o o o o o 336 322 o o o o o 322 2.316 786 65 I t77 o ( r r-l) (l) t45 3,373 329 o o o o o 329 3,7O2 2,3t6 744 65 I la3 o (lrf) (3) t42 3343 o o o o o 323 3,694 126 426 Frcnt Offce TEnsactions Gs Solar Class I DSM Other Wcat Phnned Resourccg 326 o o o o o 326 3,4o6 314 o o o o o 314 321 o o o o o 32t 3,6963,69a 3.a07 3.7 I { Pfrwate CeneBtion E*sting Resources: Intetruptible Class 2 DSM New Resources: Class 2 DSM Plannins kserves ( l3olo) West Reserws 424 424 426 126 426 126 3,3U (o) o o o o ( l05) 32aa 3,4ss (o) o o o o < 173' 3,282 427 427 3,4')9 (a) 130/. 3,494 (o) o o o o (2r l) 3,287 427 424 3.521 (o) o o o o (22A) 3,293 424 424 West Total Rcaources West oUigltion 3_44 (o) o o o o (l30) 3,274 3,431 (o) o o o o (152) 3279 west Ouigation + Reserws West Pcition West Reserw krgin 3,413 (a> r3o/o 3,7 23 (1t I 3"/" 3,705 (7\ t 30/o 3,7O1 (a) I 3'/o 3,7O5 <at l3o/o 3,707 o t30/a 3,711 o I 30/o 3,72t (o) I 3'/o 3,732 o | 3"/o OHigation Reserws OHigation + Reserres Sys tem Pos ition Res€rw Margin I r,704 4,596 I,143 9.739 r,964 360/" ll,4% 4,66 t,l4 9,750 t,746 340/" I I,gt a,5s 1,142 9,732t,w 36"/o tqa2 a,5q t,143 9,736 96 24"/o 10.633 4,619 I,t46 9,765 467 230/" I O,5aO a.a3 t.149 9,792 7aa lo,s& a,a3 l,149 7t I I O,5 l4 4,667 1,1 52 9.4t9 695 10.497 4,554 I,l3a 9,6% aol 23"/o lo,so6 4,561 I,138 9,7N ao6 23./o lll 20ta &st Table 8.3 (Cont.) ly,"::::"::") 2017 IRP Update Winter Capacity Load and Resource Balance PACIFICORP 2017 IRP Upoare Cueprpn 8 -Ponrpolto DEVELoPMENT 2024 2lt2.t 2 0JO 203 I 5,OO l 72 lao t2l 657 o (6) (,ls) (r46) s.744 5,OO I 72 ta t2t 653 o (15) (97',) 5,41 4 o o 207 o o I 204 6,O22 5,93 I (()) o ( 195) o o (42()) 53()4 7t5 7ls 4,564 72 126 t2l 635 o o (-r5) 367 5,454 4,212 72 126 r2r 590 o o(rs) 202 s,2aa 4,212 72 126 t2t 547 o o (3s) 247 5,33O 4,130 72 t26 t2t s70 o o (fs) 70 s,os4 318 o 3s3 4ao o o I,15() 6,2O4 6257(o) o ( I <)5) o o ( -s94) 5,468 736 '736 2 6,227 4,130 72 126 t2l t75 o o (15) & 5,O54 3ra o 376 4ao o ol,ta4 2032 Thel:l:ml Hy d ro e le ctric QuaIirying Facilities Class I DSM Sales Non-Omed Reseres Tmnsfere kt Edsting Flesources 4,& 72 126 t2t 650 o (l-s) 291 5,4o3 4.564 72 126 t2t a6 o o (js) 331 5,429 Front office Transactions CEs Solar Class I DSM Other o o 207 o o I 204 5,992 o o 226 o o I 227 o o 226 o o I 227 o o 226 o o I o o 3s3 177 o I a3l 6,O57 o o 353 477 o .o430 6,160 6_197 (o) o (res) o o (571) 5,429 731 731 6,2O4 (0) 130/o 6,160 o I 3'/o 6,Oa I o I 3o/o kisting Resources: Intelruptible Class 2 DSM New ksources: Class 2 DSM tut oHigafion Plannins Resewes ( I 3olo) Fsst ReserEs &st OHigation + Faeseres &st Posidon Fssa R.eserw VLrgin 5,872 (o) o ( | 9-s) o o (397) s2ao 7t2 712 6,O81 6,O79 (()) o(les) o o (52s) s'3s9 6,1 l9 6, l3a (o) o (res) o o(ssl) s392 kt Totat Gaesources Private Gene€tion 6,O3O 5-972 (o) o (r9s) o o (46-l) s ,3t4 -716 716 6,O29 (o) o (r9s) o o (497 '3334 6,29 (o) o ( te5) o o (6r5) 5,444 739 739719 422 722 726 426 5,992 (o) I 30/. 6,O23 (()) | 3o/o 6,O3O (()) l3'/o 6,O56 o I 3'/o 6,1 l8 o | 3./. 6,224 o I 3o/o Theml Hydroelectric Qualit/ing Facilities Class t DSM Sales Non-Omed ReseNes r,962 7a8 34 I 133 o (74) (3) (292) 2,s6s |,962 7aa 53 I to2 o (74) (3) (332) 2.494 t,@2 7aa 53 I ll o (74) (3) (46s) I ,91O 2,316 7aa 55 I 143 o (al )(3) 145 3364 431 43t 1,962 78a 34 I t34 o (74) (-l ) 96 2,9 53 I,962 748 53 I 9a o ( 7a) ( -1) (367 t2,434 t,@2 aaa 53 I 97 o (74) (3) (203) 2,259 920 o o 613 o o I ,533 3,791 3,684 (o) o o o o (329) 3Jss 436 436 t.602 7aa 53 I 96 o (74) (3) (244) 2,212 9AO o o 6t3 o o 1,s92 3,4O5 3,704 (o) o o o o (-34 r )3364 434 434 1,602 7aa 53 I 95 o (74) (3) (70) 2,3a9 775 o 39 613 o o I A2a 3€r 7 3,73r (o) o o o o (_l5,1) 3377 439 439 3,817 o 130/o Front Office Transactions Cas Sotar Class 1 DSM Gher West Pl.nned Re 349 o o o o o 379 3,7 43 West &isting Resources West'lirtrl Resources 423 o o o o I .322 | _257 o 39 613 o o I ,9O9 3,41 9 a03 o o o o o a()3 3,asa 841 o o 353 o o 1.t94 4f2 132 132 432 3,657 (o) o o o o (3 r6) 3'34t 4fl 433 434 434 a5a o o 414 o o | ,272 bad Private GneEtion &isting Resouroes: Intelruptible Class 2 DSM New Resources: Class 2 DSM West oHigafion Planning Reserues ( I 3olo) west Fleseres 3.572 (()) o o o o ( l(n)) 3J l2 3,59 (o) o o o o <274)3325 3,4s9 3,615 (o) o o o o (2aa) 3324 3,467 3,636 (o) o o o o (3O2 )3333 3,776 3.746 (o) o o o o (-36s) 33AO 439 439 West OHigation + ReserEs West Posidon West Reserw M.rgin 3.743 (o) 13./" 3,asa (0) I 3d/o 3,759 o | 30/o 3,766 o I 3'/o 3,74 5 o t 30/o 3,79r (o) l3'/o 3,4o5 (o) l3'/o 3,420(o) l3o/o Toaal Resources OHig.tion Reserws OHigation + Reserws System PGition Reserw Margin 9,735 8,593 1,142 9,735 (o) l3'/o 9,779 8,632 | ,147 9.779 (()) 130/o 9.749 a.&l 1,149 9.789 ( ()) I 30/o 9.423 4,670 1,t52 9.423 o I 30/o 9.457 a,7m I, 156 9,457 o I 3o/o 9,91O 4.447 1,163 9,91O ( ()) I 3'/o 9,94 8,796 t,t 69 9.965 (()) 136/o l o,o2 l 4,445 t,175 I O,O2 I o I 30/- to,M7 4,469 l,l7a to_Ma (()) I 3'/o n2 &st ca 6l a..t oo -o o oo bo d o -oCO o oo o o a0 xo o\ bo o B o.o O ,o oo- o ,oo o CB o.f &r (\ o F e ? n i Pr ,l !; 9 I E 9 ! E I It I ) o t 0) lr.() q) o G o -l) r- 6l a U (J CE I$€q) ctF -zE] oJE] ElIJ J F o. I @ rl.]F U lrl fo. t-- a-n I o(-) Ir. U E tI xI PACIFICoRP - 20 I 7 IRP Uponrr CHAPTER 8 PoRTFoLIO DEVELOPENT Figure 8.1 shows PacifiCorp's RPS compliance forecast for Califomia, Oregon, and Washington after accounting for Energy Vision 2020 projects and new renewable resources in the preferred portfolio. While these resources are included in the preferred portfolio as cost-effective system resources, they also contribute to meeting state-RPS. Oregon RPS compliance is achieved through 2036 with the addition of repowered wind and new renewable resources in the 2017 IRP Update preferred portfolio. As shown in Figure 8.1, no additional REC purchases are required to achieve Oregon RPS compliance through2036. The Califomia RPS compliance position is also improved by the addition of repowered wind and new renewable resources in the 2017 IRP Update preferred portfolio. As RPS targets increase, California requires some level of unbundled REC purchases (under 167,000 RECs per year) to achieve compliance through the planning horizon. In the 2017 IRP, California RPS Requirement targets were developed around three-year compliance periods. For the 2017 IRP Update, annual compliance targets are used, producing consistent incremental changes from year-to-year. Washington RPS compliance is achieved with the benefit of the repowered wind assets located in the west side-Marengo I and II, Goodnoe Hills, and Leaning Juniper-as well as new renewable resources added to the west side beginning 2030, and unbundled REC purchases (under 290,000 RECs per year). Under the current allocation mechanisms, Washington customers do not benefit from the remainder of the repowered wind or new renewable resources added to the east side of PacifiCorp's system. Under an alternative allocation mechanism, in which Washington would receive its system-allocated share of repowered wind and new wind located in Wyoming, the state's RPS targets could be met without the need for any incremental unbundled REC purchases throughout the 20-year planning period. While not shown in Figure 8.1, Pacif,rCorp meets the Utah 2025 state target to supply 20 percent of adjusted retail sales with eligible renewable resources with existing owned and contracted resources before considering the addition of repowered wind and new renewable resources in the 2017 IRP Update preferred portfolio. tt4 Renewable Portfolio Standards (RPS) PncrprConr - 20 l7 IRP Upoarp Cnapren 8 - PoRTFoLIo DeveloprrasNt 8.1 - Annual State RPS C ,liance Forecast 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 "$.ti"dit"d,,""$"{P"{F"$"{F"s,t"$"{F"{F"s""F}"p"N}"e""{i"&" I -rIIIIIIIIII 0 O F OIr-] RPS -Bundled SurrenderedI Bundled Bank SurrenderedIYear-end Bundled Bank Balance*Requirement rs Unbundled Surrendered t=rs.r Unbundled Bank Surrendered Iir'-Tn Year-end Unbundled Bank BalanceIShortfall California RPS o O F OQri 0 "$ "dF""t.1p""9"{P"F'} "$"$ "$,""$ "s,""{F "$""$"d}"$"$""dt "s"nqlsq Unbundled Surrendered Fs.!s Unbundled Bank Surrendered r'r-:Fr Year-end Unbundled Bank BalanceIShortfall I Bundled Surrenderedr Bundled Bank SurrenderedI Year-end Bundled Bank Balance*Requirement RPS2,500 000 500 000 s00 3t =l F, oQf-l 0 "$ "$""$"t "{,,""$"{r'"dP"s}"{F ",pt"$ "{.r,""P "F,""$"N}"$ "$""S "e"rls [-[nSundled Surrendered r;5=;r Unbundled Bank Surrendered F---r=l Year-end Unbundled Bank BalanceIShortfall I Bundled SurrenderedI Bundled Bank SurrenderedI Year-end Bundled Bank Balance*Requirement I l5 ) 500 400 300 200 100 PA.CmICOnp -2011 IRP UPDATE cHAPTER 8 - Ponrpouo DevelopeNr The 2017 IRP Update preferred portfolio continues to reflect PacifiCorp's on-going efforts to provide cost-effective clean energy solutions for our customers and accordingly reflects a continued trajectory of declining COz emissions. PacifiCorp's emissions have been declining and continue to decline as a result of a number of factors including, PacifiCorp's participation in the energy imbalance market, which reduces customer costs and maximizes use of clean energy, PacifiCorp's on-going expansion of renewable resources, and regionalhaze compliance strategies that leverage flexibility. Figure 8.2 compares projected annual COz emissions between the 2017 IRP Update preferred portfolio and the 2017 IRP preferred portfolios (as reported by PaR). Over the first l0 years of the planning horizon, average annual COz emissions are down by over 4.6 million tons (11 percent) relative to the 2017 IRP. By the end of the planning horizon, system COz emissions are projected to fall from 39.5 million tons in 2017 to 30.8 million tons in 2036-a reduction of 22 percent. Figure 8.2 - Comparison of COz Emission Forecasts between the2017 IRP Update Preferred Portfolio and the 2017IRP Preferred Portfolio 50 45 A40(.)J) "308,'ts e20 ErsEro 5 0 "$.,o.r$nSr$n$n$n$.t'"uet$ro"r"n)"uoorslnsl"uof "s,""srrs,'.2011 tRP Update r2017lRP Figure 8.3 shows how PacifiCorp's system energy mix is projected to change over time. In developing this figure, purchased power is reported in identifiable resource categories where possible. Figure 8.3 is based upon base price curve assumptions. Renewable generation reflects categorization by technology type and not disposition of renewable energy attributes for regulatory compliance requirements.2 On an energy basis, coal generation drops below 45 percent by 2025, 2The projected PacifiCorp 20l7lRP Update preferred portfolio'renergy mix" is based on energy production and not resource capability, capacity or delivered energy. All or some of the renewable energy attributes associated with wind, biomass, geothermal and qualifying hydro facilities in PacifiCorp's energy mix may be: (a) used in future years to comply with renewable portfolio standards or other regulatory requirements; (b) sold to third parties in the fbrm of renewable energy credits or other environmental commodities; or (c) excluded fiom energy purchased. PacifiCorp's 2017 IRP Update portfolio energy mix includes owned resources and purchases from third parties. ll6 Carbon Dioxide Emissions Proiected Enersy Mix J I J IT r _t _l I _.1 J PacmrConp - 20 I 7 tRP UpoRre CITnpTER 8 PonrroIIo DEVELOPMENT drops below 40 percent by 2030, and declines to 32 percent by the end of the planning period. This result reflects relatively low natural gas natural gas prices prior to 2025 and coal retirements thereafter. Reduced energy from coal is offset primarily by increased energy from renewable resources and DSM resources. No new natural gas generating units are included in the 20l7IRP Update preferred portfolio through the entire Z)-year planning period. 8.3 -Mix with 2017 IRP Preferred Portfolio Resources Business Plan Sensitivity Figure 8.4 shows a comparison of the resource portfolio from the business plan sensitivity with the 2017 IRP Update preferred portfolio. This sensitivity complies with requirements to perform a business plan sensitivity in accordance with the Public Service Commission of Utah's order in Docket No. l5-035-04, which is summarized as follows: a Over the first three years, resources align with those assumed in PacifiCorp's fall2017 business plan. Beyond the first three years of the study period, unit retirement assumptions are aligned with the preferred portfolio. All other resources are optimized. a a 100% 90% 80% 70% 60% 50% 40% 30% 20% t0% 0% 2018 2019 2020 2021 2022 2023 2024 202s 2026 2027 2028 2029 2030 2031 2032 2033 2034 203s 2036 rCoal tGas rHydroelectric rRenerable rClasslDSM+lntenuptibles rNewClas2DSM zExistingPurchases aFrontOfficeTransactions tt7 Sensitivitv Studies '10/o 80A 9t/o 9%l0%l0o/o llo/o llo/o taot t2%l2Yo t3%l3oio I6-0r I 60,i,t8 7% 110 l i0t0t59rtl 0 ]J 230i )10110 )g'fl9qo 'li)9.;..i09t, l8% 5Yo r8%1896 10/ 300k 2lo/o 3096 22Yo30%250h 230/o 730h 1 10,210210/o 28% I 99;200/o 1996 4AYo 36%10?i,1l%3l1o 350/o 34o/o 35%389;45%44%40Vo 36%360/o 33Yo 33Yo 32Yo 320k t.a (J6lg ctlQ q) U 400 300 200 100 (l 00) (200) ,$r**r*ero"uord|rdProrlnof ,Sr&br$r&*rsreorslnelrof nCrof ,e6 r DSM r FOTs I Gas { Renewable r Gas Conversion Other I Early Retirement ! Retirement PACIFICORP - 20 I7 IRP UPDATE CHAPTER 8 - PoRTFoLIo DEVELOPENT Figure 8.4 - Cumulative Increase/(Decrease) in 2017 Business Plan and 2017 IRP Update Preferred Portfolio Key differences between the Business Plan sensitivity and the 2017 IRP Update preferred portfolio include timing and assumptions around Energy Vision 2020 projects, wind repowering, and Class 2 DSM, as described below: The Energy Vision 2020 new wind and transmission projects that are included in the fall 201 7 business plan reflect proxy wind resources totalin g 1,182 MW, which includes a 320 MW proxy PPA. These proxy assumptions were developed before the 2017R Request for Proposals (RFP) was finalized. The 2017 IRP Update preferred portfolio includes Energy Vision 2020 new wind totaling l,3l I MW, consistent with the final shortlist from the 2017R RFP (see Chapter 7). The fall 2017 business plan includes repowering existing wind resources at a slightly different capacity than what is assumed in the 2017 IRP Update. This difference in capacity is driven by interconnection limits. The business plan also reflected an earlier version of repowering equipment at certain facilities that had assumed lower incremental energy output relative to the 2017 IRP Update. With less new wind and less incremental energy from wind repowering, DSM resources in the fall2017 business plan are slightly higher relative to the 2017 IRP Update preferred portfolio. FOT resources are higher in the fall20l7 business plan beginning 2020. There is a reduction in FOTs in2036 with the addition of incremental renewable resources. a a a Table 8.5 shows the impact of the business plan sensitivity with the initial estimate of 1,182 MW of new wind versus the 2017 IRP Update preferred portfolio with 1,3 I I MW of Energy Vision 2020 new wind. ll8 '-'r tt!I lttt lltt a PACIFICoRP - 20 I 7 IRP UPOATE CHapTgn 8 - PoRTFoLIo DEVELoPMENT Table 8.5 - PVRR Cost/(Benefit) of the Business Plan Relative to the 2017 IRP Update Preferred Portfolio The SO model PVRR(d) is a reflection of higher QF wind project costs, higher fuel costs from lower renewables, higher fixed costs, higher DSM costs, and higher system balancing purchase costs. The PaR PVRR(d) is a reflection of higher QF wind project costs, higher fuel costs from lower renewables, higher fixed costs, and higher DSM costs, offset by system balancing sales. Foote Creek I Sensitivity Preliminary assessment of Foote Creek I shows potential for customer benefits by acquiring the remaining portion of Foote Creek I, which is co-owned with the Eugene Water & Electric Board, and repowering this wind facility. Foote Creek I is the oldest wind facility in PacifiCorp's wind fleet, having been brought online in 1999. PacifiCorp will explore this opportunity further in the 20l9IRP. Change from l7 IRP Update Pref-Port s422 $233 ll9 Medium Gas - Medium COz System Optimizer PaR Stochastic Mean Pa,crptConp - 2017 IRP Upoa'rp crrAprER 8 - Ponrpolro Dsver-opp,Nr [This page is intentionally left blank] 120 PACIFICoRP 20I7 IRPUPOATE CHeprsn 9 - TneNsurssroN Sruores CuaprER 9 - TnaNSMrssroN SruorE,s The 2017 Integrated Resource Plan (IRP) action plan identifies specific resource actions PacifiCorp will take over the next two to four years to deliver resources included in the 2017 IRP preferred portfolio. Action items are based on the type and timing of resources in the preferred portfolio, which is selected based on analysis completed during the development of the 2017 IRP. This chapter discusses transmission studies completed in response to the following action item (please refer to the 2017 IRP, Volume I, Table 1.4): o Complete planning studies that include proposed coal unit retirement assumptions from the 2017 IRP preferred portfolio and two other scenarios.o Summarize studies in the 2017 IRP Update. In the 2017 IRP proceeding, PacifiCorp was required by the Public Utility Commission of Oregon to provide Dave Johnston early retirement transmission analysis to the commission and panies in that proceeding.l The information provided in scenarios two and three of this chapter are in response to that directive. In recognition of the transmission planning process and the planning tools available for such an analysis, various coal retirement scenarios were assessed to provide a response to this action item based on prior studies, system knowledge and new study efforts. These coal units are synchronous machines with large spinning shafts that provide higher inertia and help to provide stable and reliable operation, particularly during system disturbances. Proposed retirement of those plants in the 2017 IRP preferred portfolio that are directly interconnected to PacifiCorp's transmission system were considered. Cholla Unit 4 and Hayden Units I and2,located in Arizona and Colorado, respectively, are not directly connected to PacifiCorp's transmission system and hence, their retirement does not directly impact transmission-system operations. It is noted that additional detailed studies will accompany any final coal retirement decision(s) and results may be different than those identified herein. Table 9.1 lists the assumed coal-unit retirements in the 2017 IRP preferred portfolio that inform the transmission system assessment summarized in this chapter. Four scenarios are considered: 1. Scenario I reflects the following coal-unit retirement and Energy Vision 2020 assumptions: o Jim Bridger Unit I at the end of 2028 . Jim Bridger Unit2 at the end of 2032 o Naughton Unit 3 at the end of 2018 . Cholla Unit 4 at the end of 2020 I See the Public Utility Commission of Oregon's 2017 IRP acknowledgement order issued April 27,2018, Docket LC 61. t2t Introduction Transmission Studies Energy Vision 2020 projects, including the Aeolus-to-Bridger/Anticline transmission line (sub-segmentD.2), are online by the end of 2020. 2. Scenario 2 reflects the following coal-unit retirement and Energy Vision 2020 assumptions: o Dave Johnston Unit I at the end of 2021 o Dave Johnston Unit 2 at the end of 2027 o Dave Johnston Unit 3 at the end of 2027 o Dave Johnston Unit 4 at the end of 2027 . Energy Vision 2020 projects, without sub-segmentD.2, are online by the end of 2020, and 3. Scenario 3 reflects the following coal-unit retirement and Energy Vision 2020 assumptions: o Dave Johnston Unit I at the end of 2027 o Dave Johnston Unit 2 at the end of 2027 o Dave Johnston Unit 3 at the end of 2027 o Dave Johnston Unit 4 at the end of 2027 o No Energy Vision 2020 project 4. Scenario 4 reflects the following coal-unit retirement and Energy Vision 2020 assumptions: . Naughton Unit 1 at the endof 2029 . Naughton Unit 2 atthe end of 2029 o Energy Vision 2020 projects, including sub-segmentD.2, are online by the end of 2020. Table 9.1 - Assumed Coal-Unit Retirements in the 2017 IRP Preferred Portfolio a Coa! Unit PacifiCorp Percentage Ownership Share l%l State Assumed Retirement Year Summer Load and Resource Balance Capacity (MW) Naughton 3 100 2018 280 Cholla 4 100 AZ 2020 387 Craig 1 19 CO 2025 82 DJ1 100 2027 (end-of-life)105 DJ2 100 WY 2027 (end-of-life)106 DJ3 100 2027 (end-of-life)220 DJ4 100 WY 2027 (end-of-life)330 Bridger 1 67 WY 2028 354 Naughton 1 100 2029 (end-of-life)201 Naughton 2 100 2029 (end-of-life)280 Hayden 1 24 CO 2030 (end-of-life)45 Hayden 2 13 CO 2030 (end-of-life)33 Bridger 2 67 WY 2032 3s9 PacrprConr - 20 I 7 IRP Upoere Cr rAprER 9 - TnaNsvrssroN SrLlt)uis 122 PACTFTCoRP -2017 IRP Uppere Cnaprpn 9 - TRANSMrssroN Sruoms Transmission Impact Assessment - Scenario 1 The Aeolus West Transfer Capability Assessment (February 2018) was relied upon to identify the system impacts for Scenario l. This assessment includes the retirement of Jim Bridger Units I and 2.The Jim Bridger generation units are among the largest synchronous machines on the PacifiCorp system and play an integral role in voltage support and dynamic stability for the transmission system. Energy Vision 2020 projects were considered in service and include significant new wind generation, a new 140-mile 500-kV transmission line from the proposed Aeolus substation near Medicine Bow, Wyoming, to the Jim Bridger power plant, and subsystem facilities. The impact of retiring Jim Bridger Unit t had limited impact on voltage due to the support provided by the three remaining Bridger units as well as the presence of existing capacitor banks at the Bridger facility, which can be switched on to provide voltage support during outage conditions (typical line and major equipment outages aligned with NERC standards criteria). Retirement of both Jim Bridger Unit I and Unit 2 resulted in the remaining Jim Bridger units using close to their maximum reactive capability when near full output, with the existing capacitors online. Therefore, new reactive support to control voltage under outage conditions likely would be required if both units were retired. A dynamic voltage device, such as a static var compensator or synchronous condenser, at the Jim Bridger 345-kV bus is probable under this scenario. Due to the potential for sub-synchronous resonance at Jim Bridger, this analysis will be required for all unit retirements and proposed facility additions. With an assumed retirement of any of the Jim Bridger units, the Bridger remedial action scheme (RAS) would need to be modified accordingly. Currently, up to two Jim Bridger generation units are armed to trip under certain 345-kV transmission line outage conditions. Importantly, the study demonstrated that the Energy Vision 2020 transmission improvements and the new wind generation provide increased transmission capacity and power flow to support the existing 2,400 MW Bridger West transmission path rating, even if the two Jim Bridger units are retired. Retirement of Naughton Unit 3 did not have a significant impact on system performance. It is noted that this unit also is part of a tRAS and if the unit were retired, the Naughton RAS would need to be modified to reflect this change. Anticipated high-level system improvements for Scenario 1 include the following with a non- binding estimate of $45-S70 million: l. Install a new dynamic voltage device at or near Bridger 2. Modification of Bridger and Naughton RASs j This transmission system assessment was performed to assess the impacts of the full retirement of all four Dave Johnston coal units with a total capacity of 762 MW and determine if the end-of-life retirement (end of 2027) of Dave Johnston will require transmission system improvements. The Energy Gateway west D.2 transmission project was not considered; however, the new and repowered wind generation was assumed based on preliminary 2017 RFP shortlist resources. 123 PecnConr - 2017 IRP Upoere Cuaprr,n 9 - TRANsMrssroN Sruoms Study results indicated that under this scenario, various 230-kV transmission line segments between the Point of Rocks substation in central Wyoming and the Dave Johnston substation in eastern Wyoming, overload above their continuous ratings under normal conditions, and above emergency ratings under system outage conditions. Voltage levels outside of approved limits were also observed at multiple locations in eastem and central Wyoming under outage conditions. The new wind turbine technology provides improved reactive response, but cannot provide all of the required voltage support. To mitigate these issues the following system improvements were identified, with a high-level non-binding estimate of $810 million: 1. Build a new 140-mile 23O-kV line between Bridger-Latham-Freezeout. 2. Build a new 230-kV line between Freezeout-Shirley Basin-Windstar. 3. Rebuild the existing 230-kV lines from Point of Rocks to Freezeout substations (Point of Rocks-Bitter Creek-Bar X-Echo Springs-Latham-Platte-Standpipe-Freezeout). 4. Rebuild the following substations: Point of Rocks, Bitter Creek, Bar X, Echo Springs, Latham, Platte, Standpipe, Freezeout, Shirley Basin and Windstar to support higher transmission line capacity. 5. Install a +3501-125 MVAr Static Var Compensator (SVC) at Latham substation 6. Install five, 40 MVAr each switched shunt capacitors at Latham substation Replace the three existing 3451230-kV 200-MVA auto transforners at Jim Bridger substation with at least two 3451230 700-MVA auto transforrners. This scenario analyzed the impacts of the full retirement of all four Dave Johnston coal units in 2027 with no Energy Vision 2020 wind or transmission facilities. Study results indicate that retiring Dave Johnston with no generation additions, significantly changes the directional power flow in eastern Wyoming, which can result in west-to-east flows to meet load requirements versus the currently predominant east-to-west flows for this area. As more power from the Jim Bridger generation facility and other western Wyoming and Utah resources are needed to serve Wyoming loads, the three Jim Bridger 3451230-kV auto transformers overload under normal and outage conditions (typical line and major equipment outages aligned with NERC standards criteria). This change in power flow also results in decreased flows to the PacifiCorp-west system. The Dave Johnston plant retirement also impacts the ability to control voltages in the area; high voltages were observed during light load, no wind conditions and low voltages were observed during heavy load conditions. As such, reactive support in the form of capacitors and reactors would be required. A preliminary assessment of required facilities under this scenario is as follows with a high-level estimate of $23-$33 million: l. Replace the three existing 3451230 kV 200 MVA auto transforrners with at least two 700 MVA transformers. Note that replacement of one of the transformers is proposedby 2020 to resolve identified North American Electric Corporation (NERC) Planning Standard TPL-001-4 thermal overload issues. 2. Install a 3O-MVAr shunt capacitor and 5O-MVAr shunt reactor. 124 PacmrConp - 20 17 IRP Upnare Csaprgn 9 - TnaNsHarsstoN STUDTES Without the D.2 projects, the study noted that installation of a dispatchable replacement resource at Dave Johnston of approximately 650 MW dispatchable resource would mitigate the aforementioned impacts of the Jim Bridger transformer overload and would provide necessary voltage support. A high level non-binding cost estimate to replace Dave Johnston generation with a 650 MW dispatchable resource is $1,257lkilowatt for an approximate total of $817 million (this is based on a Combined Cycle Combustion Turbine in the 650 MW range, per Table 6.1 in the 20l7 rRP). This transmission system assessment considers the impact of an end-of-life retirement of Naughton Units I and 2 with a total capacity of 357 MW. Historically, the Naughton units have provided transmission operators the capability to control voltage on the Naughton 230-kV bus and the surrounding system under normal operation and outage conditions (typical line and major equipment outages aligned with NERC standards criteria). Area shunt capacitors are used to support post disturbance voltages. Naughton units being off line under normal conditions leads to the conclusion that additional shunt capacitors will be required in the area with the assumed retirement of Units I and2. Anticipated high-level system improvements for Scenario 4 include the following with a non- binding estimate of $6-$15 million: 1. Install two new 3O-MVAr capacitor banks near Naughton The system review shows that additional infrastructure will be required to maintain a safe reliably operating transmission system with the retirement of coal resources per the four scenarios reviewed. The addition of the D.2 transmission line provides needed transmission system support with and without the resource retirements and the addition of new wind resources per the 2017 IRP preferred portfolio. The addition of new wind from Energy Vision 2020 using new turbine technology does provide needed voltage support but cannot provide all of the system requirements absent the coal facilities. t25 Transmission Assessment - Scenario 4 Conclusions PacrprConp - 2017 IRP UPDATE Cgepren 9 Tna.NsvrssroN Sruores fThis page is intentionally left blank] 126 r-c.l (.) o o (g C) ,i (g F ,a Lr(.) t- -=orV 0.) r-Yr< o.OJas -o!./ > UX66orr o.E a0).g r- oo 6)=()r- P(Ja*.-r^Ug P; fr A.T)LH--- ^-9Uv -.r-.^V6'5o ob .o =otror--O=e6^Y,ctrx6()O X OJo.59SU H A:rO- a >trrl bo !' Eo.tr tj J SLCC(,a A =.'=,.9 = do;lO Q 9E!9--wPcE H o >,.9Ll-:- .-Oc)OAUULVAA,a 5i6 X -LIE()Ilo 0J- *.:l(F,> (B,JE'5oEsE !iod= XoX-si:\vHv9FOi O. C.l cB .= (H - !l@SrntEa 9.3 €.i q -g - 6- v-_-cqcs=-otEriH: ryEE;o- --Y bO'-.- - L r ---' L VE:Ed!= IX or oo: LF ^ U L - L .rE€ E E F 3 - O > ):58a^-v)FYAATAE(,;-qsdE d 9 HETa)U-.;'E: >6- t = B H *.IEE!'EEXE+T*EE0) o o a5 -E-oo9;,'c.l.= EF.,!rL*.F U'! lu ^vhr*-9'i E.A;EEE)^i 6:- U-=.: 6.X c6 qo_ E IE 6 g d.F^r/L>o Xi o.6€fl E.E B6 E LoO E *ol.g 3\) -^ r- ^,H.rPr,o c tr 5\JC).- =o_rE:EFs'IE.=Ertd HI --o! .-q€ ts E e=E ^* - JAa*-t.'lc*<diYE =-r-AOO->-r.I.{ cu (.) o Or ii o,EE€ QE E..r>U.iL*E ^- () (.) (Bo$.E88> Er2oaH.YogXdccs =2.aloE-9brAn = *o Ss o 9)E )'= >.F H3; B ? AiU) rr d Ftr q)(!.= urH (,s, -)6 E o ^(!^>--!5?Ebcrs.wt--,ri.l(r.i-Rv))E 9,Fi.9.8 E.i-vi^>-vO (d ri g.ul< C >.d E b &,3 3> .* *E =iE-;E;l ; .3=EiEI IqEgEES; + ;q.-ggJ 3 T:iEx *Es;.irii i EbEE>;i *e=EqrEe i gEggg EE$EgIEiBEi-iIIEEt-: [€ E:' ilaEEE6AEsHEEggEfIEflE.9lEE".*.c; I | | I -lo'- 5-gdE rR Bl . D q) (!a c! (J r- N I q) F. () otig U) v) o o C)(g L,o an c!3 cr)() t- or F- N U) a.li (-) C) O-(Ho (!3 F. o C) C) a U) (,) o(c (.) (,) cB€a d a€B - 0-)I-oa. l-loc) (c0) O#a.s.- t- Ht-{ oor )a DF Ha z J Orzo F() IO & rI]F0r U tflF o f,afF Faz J z FU I Ir.lF Q r!F H D t-- c..t I IlL U E ra a A) 9 o)g)L ahq) q) G q) c) o (J @N o€>,<* -oOvttrooo chA OJ:(.) (.) O6 oo<c coL I-.i ^r ! JNv6a a;'I oom!.= c)Ir o-r7rEth9 E.B lfr L li U)>ro3ti o.r(B:o. -Y()= H c.r 6^ oc) (so .E !.) aE o(B .=oijo oooqtrr,i =@9 5o!u O C.l:(r(J) ^-L\J -Q ,- a oo9-trE: a E o : ;>U€H-lo c o c)=o..oJ'= > L3 c;'E goob'E H<.F-$ E *.s69 5 9t'=;u . () O(.,(JEJ(€ e o eEg T F ry.HL !u ir ^ vit - ,; (, c,)l Y"'t* or6 8.9 0 H t Y =.9 00;^ :^e'- 6 CY Y a.; -^-:af9 3q E EAh^ 6J =J6)-v o /r!*v-E E e >-o ! J A€ JEES= q 9-PP+O.= cD--r:'--vQ-U)=..(i! o !.y -vL9-h^\Jll*=trlE a '' ,-'- ^:.l o.)=E =wE;= tr 9 QoO. El+=tI.-l .^ E * .,.,:,,.E9.o,; E aE;sE E5E ETE EfAEHEovE > - o EE E"}€ E H-u-g:58I9'.EE eu 5{= s: ELn'l B E 9.=.->^.!to o y l.i(d-=h1t1;i:B U Eoo - - dJ..3 -HrvF:eoeE=EKa.l cdJ< tr vtE ^iEL! 6Z-c,:;9fiU.og*A) =r-P9?-+L ', ;.Si lJ f:i-E I F g "i s E s $fi I aC)l-e+a or E l.E E'. Ioo€.=a.>E= 5Ceftr-o;ca- ==;tP':j6EB!-iE"^i.EEe,;*Y2.H==i: ? I i;9 a = o.r oaicoi-JEsEEASsEt[{(g X r.O_ = _ =() C E x;,b U; EE;i F.: -- u -Y'! bo-.=- >\v ^ics"qq#;'E FFP P, r= E.= F FE , ? e?. A !- c --c Yv" a a, E'===l.L.tsn!aJd ^ rir-- F- X.a C -* .9 c_ - c_.r ,u 9'.= =gIER qEiE= = = a-)= o Y - z-ctrc;trx9--E-E ge g c', 2 o s ; t* -+E i i dc_Eci, /,a.5*st_ .Jo EE or E U a&-c,H g h g; E &e,Q)rt)-l\!g6qalsE=!d 9: y,.l 6.E X H (ko lj6 (.) - Y() OQN'=NB -O0cntr tiLo0)3> 0,)o--.oo-goL'oOE o) -L^'ola I E E- -EE i, ,!ry E ",P EEs iZ; Eaa* ;3.=E=* gE =EE $Ei =Er= 4 r=EE Ei EEs iuE FEEE EfifE a=sE sE E}E i=i E.i g;r=i:EE ;Ei;=i;t*EE,*EI ii;*f;gEgg E?E iEuE ! iE E E if gE EE t a5 35i; s a) a) U)q) 0) a EiF =a =-j-az J z FU I i!F () - o f, t-- a\l I o(J t! O o.N() cn() o (.) CB C)l- o trt-.o *i0) L l- tt- u;r-ooo (Sa *6r) 0) 0-)-(.) : gB()6 EEdJ c) E6tr o i.9J(J--O C Xntrtr d d;!.1== r- !a ^A!*i *\J.o tr- 0)kxe> E 5 HSaA ct a -Ats-FpoOZ trtr.€ oqYdP'---:gSdco'd ar) Ei v A)a -u-'-_'---)eO-Uo !?-otallrcE.: E.o oo ^- c Je-E a Ot-'Eo-E-dt-UAor:..r - o (,- = = 6ca o) =.6E*ESsbXSULF-6Iu 6 6Z=t= -Q.! or.E.lL) j o o)U.-t-F.:uv-rdoz 9iI€ t H -EEE tr Bd, a E .9.q c- - a - t ',j .ot=.9s E-E.E 5 'E 6yn.7 ;5.9B * '; ?EE-.o.XrX3 Z a ;;,E=;tEEE:tr:.s = E EErz;;34i p r- I-S=oFts8g: E i-E:!Ei!r:A t E;gEE+iH!E=; r Ei=;Et!58;R= o d to P.= J =-:PEeX +;i\EiFa ryE=lEZ bb ='Ec 6ar E q aAEE €; i'!;;€ g 3'6+? .,.q E= H:E Fp5S= 3[aETEiEFE€EEaESA II ho.=\ul-i'P, fi -. qp,i=€ EH EJE-;$E*:EEEt !PHio'=tr'i'^€ Er + E s E : E * E-iE H E.El,:; EEETP:=EEtEltr9 !5=.E'! ? +;.E b EIEH l$t6ls=EEs EI F g H E fr: E E E TE E u EIE E H F E s ; e # E 5 H a tl tE :5aE:il=g€€:El=F f iE=f ii;T=E *I };EI:;Ei sEg€; E =ly 3 e EIE [r ' old,lo a) AF o f,af,F Faz J z F(.) I tL)F () < l r- ol U ao i-sBUUtro9e2?5:E=l--*v lgeP.i.;-a(R T 5 EH#ezAeZ - C > (H .l;d-o56 I 9or tr OF- O <B'= -^ - L,/ "' o-rXREg EIlr-,OPOoZ 65 o o ",.o*'.Nrnfr E a c*i'o tr.=df *rE E e-iAUF(ue: g: ai.3 a i g;gerEC) o-rr. E7c EcZ oaCAa'-'-<a:;!3r- # b I.?5p B'=:Z(.{ (t r. HHarb9ts S-EilfrE (.) t() --/(sc6 l-Li- q EE b0 () .':9:EYAF= a O.OO-- o.e O= o fiEBdP-(,-L.i=Ac sYoa99.ro c6A .= osaoSc0eFaE a-Q.a) l:t€ o.lEfi .* (Dr' (t (Sl4.lL-a& 0.) o (.) .i' -tr t6au) ta bE li()=- lO r-< oii:50it! UFOoA aror4a=UBE< (.)o>9!Hd-)::a< .iga A2ai tu :i.{xHor E'5 -CEAP-ioo S., 50 I.Ee;._cC)csoE B -(rH(J -)EE gI bos-.=co0 J-L5e-0)Je o-l .I a e-(J'aud.==9)o.! E -Evoxo() -'i'=o7 .vo(!tr 0)L( t) 0) o (.)L o! 6F =;o0ts95A\ A;cd .la) o,l -9og rv^ 6()3c)o)-o C-9 zr) C a)ihrzltBqU.i- C-t E, -z aE 9CEFFAdA-r\>.= -v;2.E 5.9 "i:'4 .c >. = aL cg3'F', *cd A X(ts (,;v^e9r.^ar ij 7i ca o0) r:.- E Og E E:P:Y-^UH C) v >i.Ho.E u : tj!troriiJ-s 3 3;riLra(J-H C) l. d) Eg s3 : 3tr.'E o ts 9r ^/Y1 = P ^oo T --o ar cE5FEF3]E PHt -X-OduF9.= =<l/E-]-i\vu.-t.. >ro triE > E ;e s q-r d-Q ^Aiiru\JkrjL+l G)c) trC)a C) -o o€s '- C\ -o5...- 0)cCL()-J 6boZrU.E q, >rc) 'd t!()^ aO O .t) L/c o-u obUco) te-L ) UH:'PC)-rE> = E o.r -( .6 =ts cg(ts' Q:LU f .- trJ)r! - r, --l(u-\Ji^ EI }E i ENI : 7): (g U).EI: H E, E EEl5oz.c t iiAl- .. i u: iir lIFE#HE sli T a: H dE E A E ?Ll- -^v 6) Egl P.qs€8el5'E q I cnorl* f *'= o- =l qr+; tdtl.b E;'; , 'lt hIE d Eglco d E > ; d)lillo o ,E -.€ E E,3Ee -3= (ts '.Ee I.E :lErEEEr!;6 e: iEEE;!:EKE.sesr =E Et =EEI-EFi:EFE 5= trE EEE;;i5;Ep,E =i FE ==:*Eri3EIi- E* ,Er EiIEEEi?*gEg,*F'igg :l i!Eg,E a El :=dcac6- GtN rl]F o Da F F(.n z Jo-z F(, I &q.lF f U E]F o Dor tr- a.l I d (J O rh a U) CJ .r)U) o clrrF 6I 0) I aaoo € [.r. a.E H* OOor Lr,dF!g HE.iiE:trd'6 e:E(t - d+.,i y >d,FAPI. EeE E.r'g^ ()'- -^ ^.=d€8X.38ard*^a)aEEEE E re - 5 e -S X a!-v*--; 6 i! - =-= 6rSEEEE:?atnO,''=-o-oE'69F60,;IEEgUf = e E-5 o;.! E.E.%oS€.=;EE.aEcESCt o.< o'i cn _EO;1 ,oEgQtEEiESp(j PF:.N 3'Eii.-UL-r.iq - ,r .- * lv F.iEi=So^!trx 0) box 9rr'= Hd:r< 3 5 do5. o0)9-0,)-+9,,' q'= Ei- H r <a !-9-:(,cg-(BHc.-, -.- - ^4LL<:Aci B; Eort C)'i =fln Es*e-J ia-c vl!A-^V)Elvvt4r^x 6 t ts.E 9) s $e g x 3'qL-IEur I or H l'h aE€E AE } E.E B"'; = o O..c L (J:-!o-.i-LU cU .- a) ^dr^->xutrv=. Y-E=BsatsEEd-qod'-kfo€c -^a--.L;rYaFUiio.r-\J I = oo av--i;-H f cr =c HE.Efl E S= !vo? a a-9, A.E U)CJ iJ .- ootrH -F9o o.=(..I g uicno- d+ H Hs b - ii o.r =oqvm CEIa.6a Ec o .F=F 9 or .9P qi:d)E-E (.) cg':-0rts6. =- o E1*.'=o E&€ 8 oN L(B aoLr oo 9. L) 0)C).o 0) ao Ya a6 0)!oI+0)(c FU ^(H >tr >'a -ua= cr-Xo(n.! ! -4.9. OJE>.9 ooq 5.H =orf XgO90)()X-v (o*Lo.d;!v)_rl 9E9'=,: 5 HHHO.rY trLl-otri:9.?; =(,tr9 !'50 '9El> E -2.\)x= sh= c E 6t(E c)ea9 --)^5.EE H E5 HJl 3..;X -l^e-5l 5-1 E :Zl EBEEI 'e'r =2lLb;FI '! 5r-l (s '; vI lzrP !l sf;*r xl I8:EEll Eooiz iI = E F:5l -,)iE EI gEE? bYl L - g-EI 5 E +-S =l c.t d'- fdlBl . (,)L(! _0)Xo) !o.o^ O-H9r- g UV()^t O.Xo.r ) oP-E e. a&'-!o-E.H'c t-i-EornCON.9.9 3 eEtsr-tJ-rt!-=ti^F! hnl O u)-- Y: ^ d-).=i,jyE 0t7=i3.91 s bc tzEl e.tr tr o) =l or 6 s.N Al 6.E.e kEdEgE E LIFle!.-l =.: L Ltrl-?tro=El q, J o.(,6l0.1.. L A^ a-(!9--qe{ H V F ;L-LVai,a.9.-6:=!/ * v -UAcst\ptro 6trc.t tr EE9olr(6--raFLLtr^d.9 [i> -t *l 'E .,ral l: (.)= ^lv-.a.EI f;d Hl .giEOIFH,! EI E EgFI RE'ol a a--.91 o-v 6tsl .=tr6ot 3 E'E-lo-xEl <55 LIfrl . OO€el<:E o- trS,5 H g .{ !b^ =: gE [; *s $€n+EEr ;A =_UEEEE,:"[E EE,E=gE:s=rE :f,EEFEtrE; si,iE;=€gE€;€EE: or -3 s i€ E E "i e € S E d g :El EEit:r:ir;+fi FI EtHgE=fi:sEiEE-, HEEggEEgE.tgE€E$UI .=E)E? | | rb{oEbI Uts El . (J 6l 6l (a6l tr.lF Da)-3az I ZCtr(, I EIF U Ll]F o 3 & r- N l CI,1 O q a cta O o 0,)q) (,) c)!L z tu (f) q) (.) c.tca or9q..=S -v *E ; = I e ; p [e E E E i€!> g E i:iiAs :=i;BE=;#:a: ;i€EEg+:gEET9':.=gHlE9.=E>E3=XIa9sE.eeHZ E;$tE!IiilEEr €E iE E{aitE:g 3 g. t: s s.F i a E H _,p aE.€Egr,:HpEp!E E >*p8.9 re e E i€E = e -ts i b = E i E I5[ ia O.* s oO Q ], q a A ACvF.''+CrEFv'5)'EE.5EEiH8aEH= €3€=E€=5ESEE €-8 r-1r= =rp] eEr g urEs, : €3 EE,EE':= E8i e6a_E9^P ,FHPd- f Le=9!,:.q EEad E;.iEEsE !i* SEIitFc3.E; fi E,:iE; ls;;€ EErllg-->F g i = E : E E x E i gE =,i P +,..tr - L.r q'i X , E s "; iIEgEEEEEPEE5E B;EEEilEE;EEE*Etr.o 6E6? I I I -v ! (.)Lro--o EIF Da)F Faz -l z =(, l qF U - f, & F- N l (-) - C) 0)Pl-vuo oij o.o5.gC)^ ()rr o. tl r*: 9 o) (\-e.E>> -r-A -$c.l3P rEET = ojvX bom 6 eN.H CB (,rE.=Lo)-E>(o9() E< H (h U)bo Or oL .)I aC) (d o t-r Pai UE o9.(tr0-O. cB r?=. 8 =-= .e E-oa 6 - tr==9EE u E P 3B - 1.Y <;= o ", o O Ffiii:ir E:st,,Jo-?- 6---O{ rEAi'= Ei E?S€aXi ? .Y =o o.+ =CH.= o(J <t--r o0'I E t ;.i g = :gE & 3.';,;.1 E t.b ; s g.g() d u (g (,)t- .C O'-= tr&d.(D-8.; :U E = ^rE 5,3:.a: fE EE lII E E; E: , H;f f €lt gt E E g =. E ; 5'f ?trs E s E ssi:EE 6Jl =l . a =lEI LcB o q50Eo'ao aO>- 9?$tso0)o.a )\ -r '" ao l! EL'is (gcB a9OFIEorr'a cB !^ -z - E.icqtre =orc{EIA<=u $ooc.l ca Na.l d- trv -E> =flu<: El $\o o\r-t--al q) r- N @ c\a{ a.t c\ iJbOO aL'i^vo= o_ tr O'l-;Or- tr o\-,/>.(-,sg5E8?H A'Pfl xIu I .vt-jv- u; EE* H{oEg;Eg.{ bot tr'6 d-.E c '= a-< 6o.looEc- 9oc: = E'; Yd.^.vaQat iJ 7 - c) (Ji a E t.t gE E q EE ij ib BEe LH.zinX€ ? El E H *E *; Xl +E: ; .e +ol )iq-i tr ca i: c)olq-0)6(tJcrC€cl Ql . 9 r- 2- E 6 tE-a q2E=(JtsRg ?ESHE CEt ra aoao F fafF Faz J zoF(.) I dglF Q q.lF D d t-- a.l IA (-) Q a CEa (, a a, o q) lraa €) oa0 6lt-ao a cn 0) .c (h () oI oq) G U ra q) () o I $aa ah ao0 HT () L g aC) o La. trc.; ,-' l oo.cg o- ca o) trd> -JXV,Ia.Y ii iE B';€o^/'= c)?--.---f io o-P;i:bH' 9 Eo.9 r6 dkHi 9 oo(r !/ .l' EO oq5p (J -.iEE:5;c, 6'e dF(g(ui< L e - .r ;ALL0),UJ;g=,E.9€ s., c 3- Y u)€Jl<0)io-IHEcU,o!F--9a.r- 3 iOO 6 PUN(J 5rE o ,.'Eoi !E - tr 'T. !,H.- * (U E= () - oots9Q()O-.!ME-= o-:- -J\o ts,-ct6 h ^.owpL:E O.o !3 ; sY d:u:= q,-orv.!G)cBa - 92O- oOHLo o.r e5 - a F,t-F 6.v-nC)ij^Eo. EFZ .= o-o 9)PPQHoJcg-=qv.FiE5glA H l,^/ ' Nisl-r I tsXir-Ec;- o. -^a+trx 9: _Y o/': E(J-(v o H(De.5.E N E -UEL a..l tli cd tr 0)L, aa (c o (B ooac/)(!ar !2 oo- ot i:= ??-ts o (.l LEEE.= .,E ^oE#s,s E 5e=EItr:\J dEEcP>) EE o \ ?, = 2.: c- tr = 3 s,iElgEP !.=".7-r-.iH.n Ig-E.gEEIJ I€Ei.=fE#E .:+iFgE E 5 : &E # e E;t*i?E =iIE;:lfUHEe.-gEiE €l,E a r P t; F €: a?l';*E;.5!"tr e EIfrEA!;Ei-l,rEg €l# E: E 5 { E E .H iE ril*la o -.--A.9HoJN-- O- .attr--N .=o.lE;.9E.E 5Et-I.iF- -o'='E=.= g "zZJf r S E € € E o-r< - -: F a + cna E 9 =p o.tr=aE.(i= .r€*;Ea-i F 3,eEss 5 3g E.<:'r. O O(r a cO-.= = Z=,.= I ra Fq*Es:Et ;i:gJETiEg;* -UE9IoE=76EfPx'ir=e\ =?Ebs:==R.IEEEEESEE fi E 5 ; = €E E;ez:=.E5E5e (t) .a -0) cg a FL-(HLro.9 -f v ,9 (€A a a L .- i' r-or* r rao0Ea* qg O, NI H tr = (u \-/ =iEa .. aFU;EE8 E EE O aN Y o# a,E: 5Eo.rclS 6 (J E cB = q c-.t l4 <)E,E E R'- S;U(ga A ar.) ;(T.E;-E N ti: b0a- E =60)= (-) c ^lll r- (d O -^E=-Eo0HEilg?>9 t-^ c:5o. qpr FYia E F"i E -UH.-Lu = >,.= o 0)E;i>&d; N CB o) 0) OJ L t aa la c)ra ra - af,t., a Z ,l z = I- s U o f, r- N l IEQ (r) anE]F Da)F F.az -ig z trt) I E,lF (, F o D r- a.t (-) U o(,r Ne(ttri! -6cJ(.rLL9^g I *!.-r\vE bo o.9T"9 E-E- Z \iE d !hrgQ-Yo-.^c q! 6hA6v-'- .L V'- !LJ(Er- 5 9.t ra- \ cho-&Xo.l-6cao(!^LLV U .- Ihn- ! !*o- (s 3 --u.E"; Ec --A.r9(6.Y =EE ?P ^ r Ua*.rPaJ c.rsH9 Fq99-*c,=6-L SiLdoF.-- 6:v^u,4 9 A.- = c-l a,).=? c.., HEA-Err YHeVrU H 0)t< ao (B o€ ic,l L6 -o>o. o. 6'\u>-Yd != 5bo.= o.q= C)CN.il (! $i! 9-'=(!ooLF_- gg{.- , !vd 00 0.o -atL:Ed c,P --g <hI H -ooa'"= -aE 36I.-S\J'; ! \-.,/ (lr ,F X 9r 9o-\ ao-MX o-l .-'0ca@6^! !v u r- JOOE H E! . trqr.9 o..t tr cI 6rYEEE 3a*.rPaJ O-SL9:o- o a,-)c,=6*L HLiOr'- 6i:U=e 5,- 9 6.- = ...t 0., .=H c KEo-tQ 6 a aa>' cd o O ath C) (.) lrq - C;) -o- Yl ^/ fr-0): E c.l (tsu (-)aZaE>. Q.ED ()H Er- C9o a.l<)6().= a- C)- d99Ao-Li' 0.) ml's Q -=l tr(n-Jl o ooelLr =oltE U f s EclZlo 98 E- E €o,E ;r.F: 580-i j*! E resEiSe: a = t i, = =: E = - b3"-;IE69E(r3?t ri?*stEEE;'-t 3Bg E $EE fi€BEEE9tE;{5E;EgE9=EAEo->=i..S-d F.: o I L! E ! s',J E'A liE;tcir€EEE siEBiEiEEgiFE* (LStrE o .!o-(s=-'=oaotE o o - E.=--.J^:r--E:-= -r-:E i trH * = 9'ah P o j: o E >.aE t I P s eEr= O_.= d E \, e cOclEt-(*(,i)(d3 s? FEE c 5p'^-; i U t 5:E H = d C) i._" .: _._a?: =F r E E BEE=JHEE,9N R S >;; E ; ST oT,Y) S= E 9'-E!€;EV;=EE=5! q c- a l o.tr tr^3.9.9r0.r3=:s'e?.0Ep9E=EE=StEE;IAEIJ 8'A = * g 3 ,','i 3l.CEg;TFEEF^I-, f;*:frEEF*EE s U 0)ra ra u0ra ca L DafF3-az J z =O I tL,lF Q F l r- c\l oU (., olr ao a. () :d O'c6 -o>a- 9.CoL _vd c= 5bo.= NLU- I = E -dt.=f - = tr. F.; '_ ru'- ? ) '. -uE-'? x:ilH Jbi ^ JJJ(\ ,_ ! a3 ? E E sE E $ E PX.=.^ i: (J; = (t o r = Pt 3 o 5 5 E 9 .j; e. Q 65 E E ;, H ;og6?;'96Ji;i.g':EUoF9;=g =(tr.coOX'-;jocO", F - a L " (.l'-E-o 5gE:ffF,EEiso-'" I c-r ts= Ttr Fo- = - = =; = = f i=sP:EEEB=6b-sE H E;! g: la .JFE::EE;Sgil E 3 t re &E;€EOJ cq (,) ra PRcrplConp - 2017 IRP Upoerp APPENDIx - ADDITIoNAL LOAD FORECAST DETAILS ApppNDIX _ AopITIONAL LOAD FORECAST DPTEU-S The load forecast presented in Chapter 4 represents the data used for capacity expansion modeling, and excludes load reductions from incremental energy efficiency resources (Class 2 DSM).The load forecast used in the 2017 IRP Update was produced in August 2017 . The average annual energy growth rate for the lO-year period (2018 through 2027) is 0.55 percent. Relative to the load forecast prepared for the 2017 IRP, PacifiCorp's 2027 forecasted energy requirement decreased in all jurisdictions other than Oregon and Idaho, while PacifiCorp system energy requirement decreased approximately 4.2 percent. Table A.1 and Table A.2 illustrate the annual load and coincident peak load forecast when not reducing load projections to account for new energy efficiency measures (Class 2 DSM).' Table A.1 - Forecasted Annual Load Growth, 2018 through 2027 (Megawatt-hours), at re-DSM 201 8 59,876,340 14,828,080 4,568,290 903,060 25,660,060 10,023,590 3,893,260 1 5,148,080 4,602,t70 899.340 25.87 r,850 10,006,200 3,920,890201960,448,530 2020 60,684,390 l 5,171,700 4,622,620 89 r,670 26,029,s00 rc,029,430 3,939,470 15,218,700 4,620,810 883,870 26,210,610 10,063,780 3,954,870202160,952,&0 2022 6 r,451,780 15,316,170 4,634,340 880,000 26,499,690 I 0,140, l 00 3,98 r,480 61,983,M0 15,423,000 4,652,580 876,680 26,802,770 10,216,900 4,011,1102023 4.045.980202462,662,000 15,570,800 4,689,t20 87s,620 27,16/',620 10,3 I 5,860 2025 63,004,770 b,629340 4,701,470 868,930 27,378,200 10,360,020 4,066,810 4.728.450 864.610 26.741.980 r0.429.410 4.092.430202662,578,260 t5,721,380 2018 -2027 2027 0.s5% 62.922,460 0.72',/, 15,817,000 Average Ar 4,75,1,180 nual Growtl 0.440h -0.53o/" 860,700 r Rate for 2l 16.u74,580 tt8-2027 0.52o/o 0.520h r0,498,300 4,I 17,500 0.620h I Class 2 DSM load reductions are included as resources in the System Optimizer model 137 Year Total OR WA CA UT WY ID PACIFICORP - 20I 7 IRP UpoeTg AppENDrx - ADDIrroNAI- Lono FoRECAST DETAILS Table A.2 - Forecasted Annual Coincident Peak Load (Megawatts) at Generation, pre- DSM Year Total OR WA CA UT WY ID 2018 9,971 2,326 752 r48 4,687 1,283 775 2019 10,005 ,'l5s 757 t47 4,685 1,280 780 2020 10,038 2,359 763 146 4,7M 1,284 782 2021 10,109 2.368 768 t45 4.750 1,289 789 2022 10,190 2,377 772 145 4,803 1,298 795 2023 10,266 2.386 778 146 4,850 1,306 800 2024 10,344 2,391 783 144 4,902 1,317 806 2025 10,419 2,406 791 t43 4,961 1.324 794 2026 10,422 2,414 797 142 4,922 1,332 8t6 2027 10.462 2.42t 803 t42 4,933 1,340 823 Avemge Annual Growth Rate for 2018-2027 2018 -2027 0.540h 0.450h 0.730h -0.490h 0.57"/"0.49o/o 0.67o/" Table A.3 and Table A.4 show the forecast changes relative to the 2017 IRP load forecast for loads and coincident system peak, respectively. The 2017 IRP Update incorporates a methodological update for the treatment of private generation and how it affects the coincident peak. In previous IRPs, the load forecast summed the hourly kW for seven different private generation sources to produce the hourly private generation shape within each state. For the 20l7IRP Update, since a high percentage of forecasted private generation is solar (>90yo), a more appropriate methodology was adopted where the seven individual private generation sources were weighted by annual MW. The result was that the aggregated hourly shapes for each state better reflect the individual contribution for each ofthese private generation sources. As such, the improved methodology results in the coincident peak being lower than it would have been using the unweighted approach. For example, when holding all else constant, the improved methodology results in the coincident peak for 2018 to be 49 MW (0.5%) lower, while the coincident peak for 2027 is 149 MW (l-4%) lower when compared to the unweighted private generation methodology used in the 2017 IRP. Table A.3 - Annual Load Growth Change: 2017IRP Forecast less 2017IRP Update Forecast watt-hours at Generation re-DSM Year Total OR WA CA UT WY ID 201 8 (794.1 10)9l,380 70.860 (1,160)(977.630)(27.330)49,770 2019 (8s2,840)266,4s0 6s,360 (2,550)( r,084,6s0)(144,390)46,940 2020 ( l. r78.910)219,920 59,380 (6, r60)( r.230.920)(263.410)42,280 2021 ( r,344,560)198,830 35,300 (8,270)( r,336,400)(270,360)36,340 2022 ( l.ss5.250)171,360 19.2s0 (e.e00)i.462.450)(304.960)3 1,450 2023 ( 1,816,690)146,830 5,680 ( l 1,240)( 1,s9s,700)(390,030)27,770 2024 ( 1.948.360)t22,770 (3.360)02.390)0.731.800)(347.940)24,360 2025 (2,t66,790)94,580 (re,Mo)( 13,880)( 1,846,430)(403,s40)2t,520 2026 (2,604,720)86,460 (24,730)(14,670)(2,1s2,220)(5 r8,4s0) 2027 (2,761,t90)77,190 (3 r,860)(ls,1s0)(2,283,320)(s2s,070)r7,020 138 18,890 Appguotx - ADDTTToNAL Loao FoRncasr DETAILS Table A.4 - Annual Coincident Peak Growth Change: 2017 IRP Forecast less 2017 IRP U te Forecast M at Generation,re-DSM Table A.5 and Table ,{.6 provide total system and state-level forecasted retail sales summaries measured at the customer meter by customer class including retail load reduction projections from new energy efficiency measures from the 2017 IRP Update preferred portfolio. Table A.5 - System Annual Retail Sales Forecast 2018 through 2027 (Megawatt-hours), ost-DSM Year Total OR WA CA UT WY ID l8201 8 (2s4)28 (3)(383)36 5l 20t9 (30s)6 l8 (5)(412)35 53 2020 (365)(0r 2t (6)(448)l6 52 2021 (40e)(6)20 (6)(466)10 39 2022 (434)( 14)20 (7)(478)6 39 2023 (440)(21)20 (5)(491)4 53 2021 (46r)(34)20 (7)(s07)l3 54 2025 (s00)(37)23 (8)(s21)6 37 (44)2026 (50e)24 (8)(524)(11)54 2027 (5se)(51)25 (8)(s46)( l8)40 System Retail Sales - Megawatt-hours (M.Wh) Year Residential Commercial Industrial Irrigation Lighting Total 2018 r5,842,460 17,655,267 18,840,636 1,472,t63 139.346 53,949,872 2019 15,666,962 t],776,306 18,904,216 I,468,159 138,470 53,954,173 2020 15.3t7,343 t7,799,587 18,95t,777 1,463,425 137,705 53,669,838 2021 15,139,3 t 9 17,776,502 18,979,641 t.459,882 136,290 53,491,634 2022 15,103,151 17,824,771 19,029,805 1,456,569 135,254 53,549,550 15.101,463 17.887.3892023 19,o76,640 1,453,4r4 t34,294 53,653,199 2024 15.17 I,r 17 r 7,991,108 19.151.692 t.449.714 133,771 53,897,4O2 2025 15,109,350 17,980,093 19,152,679 1"445.707 \32,3s5 53,820.183 t8.oo7.4692026l5,l 14,358 18,331,019 1.442,171 13t,322 53,O26,339 2027 t5,139,947 18,026,O99 18.378.406 1,438,641 130,355 53,113,447 Average Annual Grorvth Rate 2018-27 -O.5"/"O.2"/"-O-3"/n -O.3o/o -O.7"/o -O.2o/o 139 PACIFICoRP - 20 I7 IRP UPDA.|E Year Res idential Commercial Industrial Irrigation Liehtine Total (t40.147)2018 177,449 273,632 (666,108)79,206 (3,727) 2019 13t.349 330.248 (738.992)86.81l (4.72r)(l9s.3o4) 2020 (4s.432)284.O28 (843.91r)94,O82 (s.946')(s17,179) 2021 (7 t.403)233,291 (866.246')t02,o42 (6,983)(609,300) (8.033)(754.199)2022 ( r r 3,880)196,864 (938,71s)r08,965 2023 (r21.4s3)r60.865 0.084.944)1t6"707 (8.999)(937.824') 2024 04r.892)130,274 (l.101.119)127,O23 (e,e30)(99s,@.5) 2025 (96.134)53,616 (1.269,773)154,074 ( 10,943)( 1,169,160) /L1.976)(l.540.876)2026 (98,987)( 15,380)(1,612,8s4)198,321 2027 ( 101.065)(85.816)(r.682.937)244.120 /r2.943)(1.638.91) PACIFICORP - 20I 7 IRP UpoRrs APPENDIX - ADDITIONAL LOeo FORECeST DETAILS Table 4.6 - Annual Load Growth Change: 2017IRP Forecast less 2017 IRP Update Forecast (Megawatt-hours) at Retail, Post-DSM Residential Over the 2018-2027 timeframe, the average annual growth of the residential class sales forecast declined from -0.3 percent in the 2017 IRP to -0.5 percent in the 2017 IRP Update. The number of residential customers across PacifiCorp's system is expected to grow at an annual average rate of 1.0 percent, reaching approximately 1.8 million customers in2027, with Rocky Mountain Power states adding 1.4 percent per year and Pacific Power states adding 0.4 percent per year. It is expected that residential customers are likely to use more efficient appliances, which is having an adverse impact on the residential forecast, relative to the 2017 IRP load forecast. Commercial Average annual growth of the commercial class sales forecast declined from 0.5 percent annual average growth in the 2017 IRP to 0.2 percent expected average annual growth in the 2017 IRP Update. The number of commercial customers across PacifiCorp's system is expected to grow at an annual average rate of I .0 percent, reaching approximat ely 229 ,000 customers in 2027 , wrth Rocky Mountain Power states adding 1.3 percent per year and Pacific Power states adding 0.5 percent per year. Relative to the 2017 IRP, the Company increased its commercial forecast in the earlier years of the 20l7IRP Update load forecast, but lowered its commercial load expectations in the later years of the forecast. This is attributable to a more optimistic outlook for the commercial sector in Oregon and Washington, and a relatively less favorable outlook for the sector over the long-term in Utah. Industrial Average annual growth of the industrial class sales forecast declined from 0.3 percent annual average growth in the 2017 IRP to -0.3 percent expected annual groMh in the 2017 IRP Update. A portion of the Company's industrial load is in the extractive industry in Utah and Wyoming. The Company has seen several large industrial customers lower their expectations for load growth given less favorable conditions within their particular sectors. Table A.7 through Table A.12 provide additional detail for the class level forecast within each jurisdiction. 140 Svstem Retail Sales - Megawatt-hours (M\Vh) PacrprCoRr -2017 IRP Upoarr,APPENDIX - ADDITIONAL LOAD FoRECAST DETAILS Table A.7 - Forecasted Retail Sales Growth in Table A.8 - Forecasted Retail Sales Growth in Washi ost-DSM t-DSM Oregon Retail Sales - Megawatt-hours (MWh) Year Res idential Cornrnercial Industrial Irrigation Liehtine Total 201 8 5.583,761 s,243,692 1.707.309 328, r 53 36,758 12,899,673 2019 5,563,312 5,301,661 1,786,249 327.434 36,67s t3,o21337 2020 5,4&,674 5,2&,941 1,784,727 326,@4 36.627 12.877.613 2021 5,397,546 5,248,tO7 1,789,182 326,267 36,467 12,797,570 5.252.99620225,375,546 1,789,987 326,187 36,460 12,781,177 2023 5,367,170 5,259.993 1.793.616 326,273 36,483 12,783,535 2024 5,385,442 5,219,OO2 1,797,358 326,26s 36.634 12.424.700 2025 5,360,638 5,273,844 1,800,475 326,259 36,6r I 12,797,826 5.283.11420265,355,60s t,803,726 326,317 36,722 12,806,095 2027 5,354,934 5,292.903 1,806,948 326,362 36.843 12,817,991 Average Annual Growth Rate 20ta-27 -O.460/o O.l0o/o O.630/o -O.O60/o O.O3o/o -O.O7"/" Washington Retail Sales - Megawatt-hours (MWh) Year Res idential Commercial Industrial Irrigation Liehtine Total 2018 I,583,963 1,53 1,076 754.506 t59,634 r0,095 4,O39,274 2019 1.s18.843 l,538,986 745,572 t59.279 to,o27 4,O32,706 2020 1,561,096 I ,55 l,553 736.309 159,035 10,005 4,O17,998 2021 1,s46,875 1,551,753 719,218 I 58,91 8 9.947 3,986,7r r 2022 1,543,783 1,558,459 700,585 158,885 9,933 3,971,644 2023 154L4M 1,566,41I 683.400 158,920 9,934 3,961,069 2024 1,548,222 t,579,063 61t,923 158,925 9,974 3.968.107 2025 1,54t,570 1,581,426 660,230 158,8 r 6 9,949 3,951,991 2026 1,541,584 1,589,087 652.O50 158,777 9,971 3,951,47O 2027 1,543,786 r,598,326 642.O80 158,835 l0.ol9 3.953.04s Average Annual Grorvth Rate 2018-27 -O.29o/o O-48"/n -1.78o/"-O.O60/o -O.O8"/"-O.24"/o t4l California Retail Sales - Meqawatt-hours (M\ilh) Year Residential Commercial lndustrial Irrigation Lighting Total 758.9452018316,905 226,895 57,71O 95,411 2,Ot9 2019 373.803 222.688 57 ?q5 95,533 2,OO3 751,420 2020 366,846 218,992 57.238 95,370 I,989 740,435 2021 361,570 2t4.662 56,850 95,O97 1,968 730,146 2022 722,812358,@6 21o,869 56,590 94,761 1,946 2023 3s6.306 207.O51 56.384 94.432 I,930 7l6,lo2 2024 355,551 203,762 56,276 94.O45 1,922 711,555 2025 35 1,8 l8 199,186 55,797 93.628 1.901 702,331 2026 349,659 r95,r59 55,472 93,254 1,888 695,432 2027 348.47 190.977 55.144 92.867 I,870 688,884 Average Annual Growth Rate 20ta-27 -O.887o -l.9Oo/o -O.5O"/"-O.3O"/"-0.850 -1.O7"/" PacmICoRp 20lT IRP UPDATE AppeNox - ADDITIONAL Loao FonECnST DETAILS Table A.9 - Forecasted Retail Sales Growth in California,t-DSM Table A.10 - Forecasted Retail Sales Growth in Uta DSM Utah Retail Sales - Mesawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Liehtine Total 20r8 6,s80,32s 8.150.826 1,726,3t8 220,942 76,102 23354,513 2019 6,449,969 8,797,719 7,770,7t6 220.356 75.601 23314360 2020 6.251.O58 8,841,81O 7.836.627 2t9.757 75.t19 23.230372 2021 6,186,442 8,834,148 7.873.530 219,125 74.180 23,188,025 2022 6.186.852 8.8&.904 7.919.273 218.567 73.441 23,263,O37 2023 6,202,O50 8,904.636 7,962,165 2t8,tt7 72,750 23359,718 2024 6,246,505 8,9&,872 8,O12,795 217,650 72,281 23,514,103 23.50637320256,233,228 8,962,794 8,O22,O97 216,990 71,2& 2026 6,251,555 8,979.066 7,188,909 2t6,3ss 70,443 22.706328 2027 6,280,581 8,983,885 7,224,382 215,778 69,658 22,774,284 Averaqe Annual Growth Rate 2018-27 4.52o/o O.29o/o -O.74o/o -O.260/o -O.98o/o -O.28"/" 142 PACIFICoRP -2017 IRP UPDATE APPENDIX - ADDITIONAL LOe.o FOn-eCaST DETAILS Table A.11 - Forecasted Retail Sales Growth in ldaho, post-DSM Table A.l2 - Forecasted Retail Sales Growth in Wyoming, post-DSM Idaho Retail Sales - Megawatt-hours (MWh) Year Res idential Commercial Industrial Irrigation Liehtine Total 2018 700,o24 5 19,58 I 1"713,474 &3,556 2.604 3,579,24O 2019 697,720 533,400 1.713,216 (At.t79 2,580 3,5gg,og4 2020 686.874 546,324 1,713.424 638.320 ? 55?3,597,495 2021 681,434 556.258 t,712,508 636,273 2,s2t 3,588,994 2022 681,551 568,547 t,712,418 634,07s 2,488 3,599,O79 2023 683,O92 58 1,261 1,712,128 631,689 2,449 3,610,619 2024 687,631 594.84t 1,712.500 628.961 2,416 3,626355 2025 685,857 604,016 t,7tt,o73 626.284 2.367 3.629.598 2026 687,235 614,O79 t,7to,4t6 623,895 2,327 3,637,953 2027 689,253 623.959 1,709,822 62t.396 2,288 3,646,719 Average Annual Grorvth Rate 20ta-27 -O.l7o/o 2.O5o/o -O.O2"/o -O.39"/"-1.42o/o O.2lo/o Wyoming Retail Sales - Megawatt-hours (MWh) Year Residential Commercial Industrial Irrigation Liehtine Total 2018 t,ot],483 1,383,t97 6,881,318 24.460 11,768 9.318,226 2019 1,003,316 1,375,846 6,83 1,130 24,379 r r.585 9,246,256 2020 980,796 1.375.968 6.823.453 24,298 I t,412 9,215,926 2021 965,4s3 1.370.915 6,828,353 24,20t 11,208 9,200,189 2022 956,174 1,368,994 6,850,953 24,O94 t0,986 9,21 I ,80O 2023 950,441 1,368,037 6,868,947 23,983 to,t46 9,222,155 2024 947.765 1.369,569 6,900,840 23.863 1o.544 9.252.582 2025 936,239 1,358,827 6,903,006 23,730 to.262 9,232,064 2026 928,719 1,346,363 6,920,445 23,573 9.971 g,22g,o7l 2027 923,366 1.336.049 6,940.030 23,403 9,617 9,232,524 Average Annual Grorrth Rate 2018-27 -l.O7o/o -O.38"/"O.O9o/o -O.49o/o -2.15"/o -O.lO"/o 143 PACII,TCoRP 2017 IRP UPDnrE,APPENDIx ADDITIONAL LOAD FORECAST. DI.I.,I.II,s [This page is intentionally left blank] 144