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Home My WebLink About20150715Hearing Transcript Exhibits II-IV.pdfBEFORE THE IDAHO PUBLIC UTILITIES COMM]SSION rN THE MATTER OF IDAHO POWER COMPANYIS PETITION TO MODIFY TERMS AND CONDITIONS OF PURPA PURCHASE AGREEMENTS CASE NO. IPC-E-15-O]- IN THE MATTER OF AVISTA CORPORATIONIS PETITTON TO MODIEY TERMS AND CONDITIONS OF PURPA PURCHASE AGREEMENTS CASE NO. AVU-E-15-O]- IN THE MATTER OF ROCKY MOUNTAIN POWER COMPANY'S PETITION TO MODIFY TERMS AND CONDITIONS OF PURPA PURCHASE AGREEMENTS CASE NO. PAC-E-15-03 Exhibi ts BEFORE COMMISSIONER PAUL KJELLANDER (Presiding) COMMISSIONER KRISTINE RAPER PLACE ' Z;l-il::i"il":;il;t3"*3iT...Boise, Idaho DATES: June 29-30, 2015 VOLUME Ir-IV - Pages 81 1027 CSB REPORTING Certilied Shorthand Reporters Post Offrce Box9774 Boise,Idaho 83707 csbreporting@heritaeewifi .com Ph: 208-890-5198 Fa<: l-888-623-6899 Reporter: Constance Bucy, CSR ORIGINAL BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION GASE NO. IPC-E-I5-01 IDAHO POWER COMPANY ALLPHINN DI TESTIMONY EXHIBIT NO.1 ts = sI 3 3 ts ra 3 3o aI o= 3T =!^4,EIEE =4 3E cei d!l , 3; F- = 33 33 e ; II 3 Exhibit No. 1 Case No. IPC-E-15-01 R. Allphin, IPC Page 1 ofl turi / =€ ut c,.Y aoea ca o6I 6co Eoeot,EC a,a eo(J 3Ec =O(,oEo- o-E, =o- I III II I I IIII II I IIItII I I IIII E!ja ;;l Fidt'rl =t5!i:6r Er 5!5rEI5rg,tral&r<lpr =lo-1 I I =- ct $i t/l,it C'GIoirE) 6 =coa oo0EoooCLo o-!,E6 a,6 Eo(, ot,c =t C'oo o- o-c, =r aaaooaooooooooosiNo@(o:tNFl Ft -{ oor.o F{ oo€d (ml'u) sUemetaUU E.,toco =$EE 9s Hg85o! Eg.-E &5E ooot\ ooNN BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION GASE NO. IPC-E-I5-01 IDAHO POWER COMPANY ALLPHIN, DI TESTIMONY EXHIBIT NO.2 ldaho Power Gompany Renewable Energy Gontrac{s List SUMMARY PURPA Projects OregonSolar Projects Non PURPA Projects SUMMARY BY FAGILITYTYPE 133 60 3 1,302.08 MW 0.46 MW 135.65 MW 196 1,438.19 MW Biomass CoGen Thermal Hydro Wind 10 1 3 64 27 29.45 MW 15.90 MW 15.00 MW 143.70 MW 576.92 MW 780.97 MW 19 4 5 Solar Hydro Wind 2 1 461.00 MW 10.11 MW 50.00 MW 28 521.11 MW OR Solar 55 0.42 MW 55 0.42 MW OR Solar 0.04 MW 0.04 Mw Geothermal Wind 35.00 MW 100.65 MW 135.65 MW Exhibit No. 2 Case No. IPC-E-15-01 R. Allphin, IPC Page 1 of6 196 1,438.19 MW ldaho Power Gompany Renewable Energy Gontracts List PROJECT DETAILS PURPAPROJECTS ONLINE 31616150 Biomass 41365515 Biomass31615100 Biomass 31616100 Biomass 31616115 Biomass21865113 Biomass21615100 Biomass 41455091 Biomass 31616110 Biomass 11766002 Biomass Total Bioma$ Prolec{s: 10 41866113 CoGen Total Cocen Prolects: 1 31765150 Thermal 21662100 Thermal 31616082 Thermal Total Thermal PropcG: 3 21615205 Hydro 21615078 Hydro 31214058 Hydro 31415065 Hydro 31615140 Hydro 31416013 Hydrg 31515100 Hydro 31715126 Hydro 31416020 Hydro 31616081 Hydro 31516014 Hydro 31615057 Hydro 31415023 Hydro 31615106 Hydro 443S5973 Hydro 11615077 Hydro 41717137 Hydro 2'16't5215 Hydro 3161512'l Hydro 31415134 Hydro 31615098 Hydro 31315093 Hydro 31715128 Hydrc31715140 Hydro 11715'1.44 Hydro 31415094 Hydro 31615031 Hydro 31615030 Hydro 31615056 Hydro 31316015 Hyq1o 3'1615105 Hydro 31515107 Hydro 31715099 Hydro 31615130 Hydro 316,l5125 HyCro 317'15123 Hydo 31515009 Hydro 31615117 Hydro 31615154 Hydro 12618250 Hydro BG Anaerobic Di9991e1 Bannock County Landfill Bettencourt Dry Creek BioFactory, LLC Big Sly Wes! D !ry Digester (DF-AP #1, LLC) Double A Dige-sler P1gjgct Fighting Creek Landfill Gas to Energy Station Hidden Hollorv Landfill Gas Pocatello Wasle Rock Creek Dairy Tamarack Cspp Simplot Pocatello Magic Valley Tasco - Nampa Tasco - Twin Falls Arena Drop BaQel Dqm Birch Creek Black Canyon #3 Blind Canyon Box Canyon Briggs Creek Bypass Canyon Springs Ced{-Qr4v Clear Springs Trout Crystal Springs Curry Cattle Company Dietrich Drop Eightmile Hydro Project Elk Creek Falls River Fargo Drop Hydroelectric Faulkner Ranch Fisheries Dev. Geo.Bon #2 Hailey Cspp Hazelton A Hazelton B Horseshoe Bend Hydro Jim ltuight lGsel & Witherspoon Koyle Small Hydro Lateral # '10 Lemoyne Little Wood Rvr Res Littleuood / Arkoosh Lor Line Canal Low Line Midway Hydro Lowljne #2 Magic Reservoir Malad River Marco Ranches Mile 28 Mill Creek Hydroelectric ID to ID !D ID ID ID ID ID ID Gooding Bannock County Twin Falls Good!ng Linco!n Kootenai Ada Bannock Twin Falls Adams Po,ver Minadoka Canyon Twin Falls Canyon Ada Gooding Gooding Gooding Twin Falls Twin Falls Jerome Twin Falls Twin Falls Twin Falls Twin Falls Twin Falls Jerome Lemhi ldaho Fremont Canyon Gooding Gooding Lincoln Blaine Jerome Jerome Boise Gooding Twin Falls Gooding Twin Falls Gooding Blaine Lincoln Twin Falls Twin Falls Twin Falls Blaine Gooding Jerome Jerome Union 2.28 3.20 225 1.sq 1.qq 906 3.20 0.,16 4.00 5.00 29.'05 15.90 1s.90 'r0.00 2.00 3.00 15.00 0.45 9.70 0.05 0.14 1.63 0.36 0.60 9.96 0.13 1.55 0.52 2.44 0.?? 4.50 0.36 2.00 9.10 1.27 9.870.26 0.93 0.06 8.10 7.60 9.50 0.34 0.90 1.25 2.06 0.08 2.85 0.87 7.97 2.50 2.79 9.07 0.62 1.20 1.50 0.80 ID ID ID ID ID IP ID ID ID ID ID !P ID ID ID ID ID iD ID ID ID ID ID ID ID ID ID ID ID ID ID ID ID ID ID to ID ID ID ID ID ID ID OR Exhibit No. 2 Case No. IPC-E-15-01 R. Allphin, IPC Page 2 of 6 ldaho Power Company Renewable Energy Contracts List 12614070 Hydro Mitchell Butle 21615200 Hydro Mora Drop Small Hydroelectric Facility 31515004 Hydro Mud CreeUS & S 31414111 Hydro Mud Creek/White12616071 Hydro Owyhee Dam Cspp 31615067 Hydro Pigeon Cove 31415164 Hydro Pristine Springs #131415165 Hydro Pristine Springs Hydro #3 214151'19 Hydro Reynolds lnigation 31615003 Hydro Rock Creek #1 31615104 Hydro Rock Creek #2 31515103 Hydro Sagebrush 31617100 Hydro Sahko Hydro 4'1515122 Hydro Schaffner'11415009 Hydro Shingle Creek 3'1615158 Hydro Shoshone #2 31416001 Hydro Shoshone Cspp31315021 Hydro Snake RiverPottery 31414075 Hydro Snedigar 417'17139 Hydro Tiber Dam 31415027 Hydro Trout-Co 12616072 Hydro Tunnel #1 31315029 Hydro White Water Ranch 31715141 Hydro Wilson Lake Hydro Total Hydro Projects: 64 21615101 Wind 31765170 Wind31315050 Wind 31318100 Wind 21615115 Wind 2',t615120 Wind31315035 Wind 31765160 Wind 216'15125 Wind 31315130 Wind41718140 Wind 21615105 Wind 126'18200 Wind21615130 Wind 31720190 Wind 31315075 Wind 31315060 Wind31315045 Wind 4'1455300 Wind 21615135 Wind 31618100 Wind21615110 Wind 31315055 Wind 31315065 Wind 31315150 Wind 216'15140 Wind31315070 Wind Total Wlnd Proiec{sr 27 Bennett Creek Wind Farm Burley Bufte Wind Park Camp Reed Wind Park Cassia Wind Farm LLC Cold Springs Windfarm Desert Meadow Windfarm Fossil Gulch Wind Golden Valley Wind Park Hammett Hill Windfarm High Mesa Wind Project Horseshoe Bend Wind Hot Springs Wind Farm Lime Wind Energy Mainline Windfarm Milner Dam Wind Oregon Trail Wind Park Payne's Ferry Wind Park Pilgrim Stage Station Wind Park Rockland Wind Farm Ryegrass Windfarm Salmon Falls Wind Sawtooth Wind Project Thousand Springs Wind Park Tuana Gulch Wind Park Tuana Springs Expansion Turo Ponds Windfarm Yahoo Creek Wind Park lVlalheur Ada Twin Falls Twin Falls Malheur Twin Falls Jerome Jerome Canyon Twin Falls Twin Falls Lincoln Twin Falls Lemhi Adams Lincoln Lincoln Gooalng Twin Falls Liberty County Gooding Malheur Gooding Jerome Elmore Cassia Elmore Twin Falls Elmore Elmore Twin Falls Cassia Elmore 2.09 1.85 0.52 0.21 5.90 1.89 0.13 0.20 0.26 2.05 1.90 0.43 0.50 0.53 o.22 0.58 0.37 0.07 0.54 7.50 o.24 7.00 0.16 8.49 113.70 21.00 21.30 22.fi 10.50 23.00 23.00 10.50 12.W 23.00 Twin Falls/Elmore 40.00Cascade 9.00Elmore 21.00Baker 3.OOElmore 23.00Cassia 19.92 Twin Falls 13.50 Twin Falls 21.00 Twin Falls 10.50Power 80.00Elmore 23.@ Twin Falls 22.00Elmore 22.00 Twin Falls 12.00 Twin Falls 10.50 Twin Falls 35.70Elmore 23.00 Twin Falls 21.00 s76.92 OR ID ID ID OR tL) ID ID ID ID ID ID ID ID ID ID ID ID ID MT ID OR ID ID ID ID ID ID ID ID ID ID ID ID MT ID OR ID ID ID ID ID ID ID ID ID ID ID ID ID ID Exhibit No.2 Case No. IPC-E-15-0'l R. Allphin, IPC Page 3 of6 ldaho Power Company Renewable Energy Contrac{a List PURPA PROJECTS UNDER GONTRACT NOT YET ONLINE ?qq86937 Solar 255916/t4 Solar 25088520 Solar25244913 Solar 25253149 Solar 25261338 Solar25289173 Solar 12616100 Solar 12727358 Solar 12739324 Solar25031625 Solar 2552419A Solar '127052'19 Solar 25573998 Solar25075329 Solar 1274'1175 Solar 25580735 Solar 12745920 Solar 12719362 Solar Total Solar Prolects: 19 20140708 Hydro 20140601 Hydp 20140328 Hydro 31515110 Hydrq Tota! Hydro Prolects: 4 12618240 Wind 126't8230 Wind '12618220 Wind 12618210 Wind12618245 Wind Total WInd Prolects: 5 American Fallg $olar ll, LLC American Falls Solar, LLC Boise City Solar, LLC Clalk Solar 1, LLC Clark Solar 2, LLC Clark Solar 3,.LLC Clark Solar 4, LLC Grand View PV Solar Two Grove Solar GniCr, LLC Hyline Solar Ce{er, LLC Mountain Home Solar, LLC Murphy Flat Porer, LLC Open Range Solir Center, LLC Orchard Ranch Solar, LLC Pocatello.Solar 1, LLC Railroad Solar Center, LLC Simco Solar, L_Lg Thunderegg So,lar Center, LLC Vale Air Solar Center, LLC Black Canyon Bliss Hydro Clark Canyon Hy-droelectric Head of U Canal Project Little Wood River Ranch ll Benson Creek WindJarm Durbin Creek {indfarm Jett Creek Windfarm Prospector Windfarm Willow Spring Windfarm ID ID ID ID ID ID tb ID on ORq ID OR ID D OR ID OR OR ID MT ID ID OR OR OR OR OR Power PoYver Ada Elmore Elmore Elmore Elmore Elmore Malheur Malheur Elmore O,vhyee Malheur Ada Power Malheur Elmore Malfeur Malheur $oo{ing Beaverhead Jgrome Shoshone Baker Baker 6aker Baker Baker 12t1tzwq 121112016 1t16t2016 1A31nU6 1A31n016 1U31t2016iisirzoia 91112016 12t31t2016 12131120',t6 1uait2o16,rarEda tztitlio'ta 12t1,i2316 1Us'.V2010 1213112016 't?1!?016 1437n016 12131t2016 11t1512014 ahpott q1D0't5 6t112015 fiB-1nO16 1?31t20161ay!291Q 1213112016 12t31t2016 20.00 2O.Oq 40.00 71.9Q 20.00 30.9q 20.00 80.00 10.00 10.00 20.00 20.00 10.00 ?0.00 20.00 10.00 20.00 10.0Q 10.00 ,t61.00 0.03 7.55 1.28 1.25l0.tt 10.00 10.00 10.00 10.00 r0.00 50.00 Exhibit No.2 Case No. IPC-E-I5-01 R. Allphin, IPC Page 4 of6 ldaho Power Gompany Renewable Energy Contracts List 90001311 OR Solar 7 kW Shaffer Solar 90001416 OR Solar Chamberlain DairygOOO14l3 OR Solar Chamberlain House 90000028 OR Solar Cliff and Pat Looney 90000005 OR Solar Clinton Kennington 9OOOOO79 OR Solar Dean Mackey-79 9OOO0O25 OR Solar Findley Family Trust - Findley Land and LrvestocK 9OOO0O75 OR Solar Findley -Land and Livestock-7s 90000081 QR Sglar Findley _Llnd- ald ,Liye9!o9k_Ql90000006 OR Solar GaryTay'or_0690000003 OR Solar Gordon D. Luther_03 90000007 OR Solar Godon Dale Luther_O7 90000077 OR Solar Jason Peters_77 90001301 OR Solar Jensen Farms LLC_I301 90001302 OR Solar Jensen Farms LLC_I302 90001303 OR Solar Jensen Farms LLC_I303 90001307 OR Solar Jensen Farms LL.-C_I307 90001310 ORSolar Jensen Farms LLC-1310 9OOOOO43 OR Solar Jensen Farms LLC-43 90000045 OR Solar Jensen Farms LLC_45 90000046 OR Solar Jensen Farms LLC_46 90000047 OR Solar Jensen Farms LLC_47 90000048 OR Solar Jensen Farms LLC 48 9OOO0O5O OR Solar Jensen Farms LLC:50 90000052 OR Solar Jensen Farms LLC_52 90000054 OR Solar Jensen Farms LLC_54 90000056 ORSolar Jensen Farms LLC_56 90000057 OR Solar Jensen Farms LLC_57 90000060 OR Solar Jensen Farms LLC-60 90000076 OR Solar Jensen Farms LLC-/6 90000044 OR Solar Kenneth Jensen_44 90001306 OR Solar Malheur County Fairgrounds #1 9000131 3 OR Solar Malheur County Fairgrounds #2 90001315 OR Solar Malheur County Fairgrounds #3 90000073 OR Solar Mark Wettstein_73 90000088 OR Solar Mark Wettstein_8890001414 OR Solar Michael McGourty 90001312 OR Solar Onion Storage_'1312 90000063 OR Solar Ontario City Hall-.163 90000072 OR Solar Ontario Golf Clubhouge_72 90000062 OR Solar Ontario Public Works Shop_62 90000059 OR Solar Ontario WTP East Bldg_S9 90000055 OR Solar Ontario WTP West PondsJ5 90000080 OR Solar Ontario WWTP Aerators_80 90000084 OR Solar Ontario WWTP Building-84 90000086 OR Solar Ontario WWTP Lift Station_86 90000051 OR Solar Pine Eagle High School 90000064 OR Solar Pine Eagle Middle School 90000078 OR Solar Pine Eagle Pump Station90000001 OR Solar Randy Bauer 90000067 OR Sohr Robert Mairs-67 9OO0OOO2 OR Solar Roger Findley 90000061 OR Solar Roger Findley_61 90001309 OR Solar Schuster 90000004 OR Solar Treasure Valley Community College Tot ! OR Solar Prolectt: 55 OR OR OR OR OR OR OR 9B OR on OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR OR 6n 9R OR OR Malheur Malheur Malheur Malheur Malheur Malheur Malheur lul?ligur i4athqqr Malheur Malheur Malheur Malheur Malheur Malhuer Malheur Mqlluer Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Malheur Baker Baker Baker Malheur Malheur Malheur Malheur Malheur Malheur 0.ql 0.91 9.01 0.01 0.01 0.01 0.01 9,qg Q,90- 0.01 q.gl 0.01 o 9'! 0.00 q,q1 0.01 0.90 0.01 0,01 9.01 0.01 Q.0'l 0.01 0.01 o.o1 0.01 0.01 g.0t 9.01 Q.0r 091 9.01 0.01 o:ol 0.01 0.01 0.01 0.01 o.o1 0q1 0.01qol q.gl 0.01 I q'! 0.01 0.01 0.01 0.01 0..91 0.gl 0.ql 0.01 0.01 0.01 0.12 Exhibit No. 2 Case No. IPC-E-15-01 R. Allphin, IPC Page 5 of6 ldaho Power Gompany Renewable Energy Gontracts Llst PROJECTS UNDER CONTRACT NOT YET ONLINE 90001412 OR Solar 90001411 OR Solar 90001415 OR Solar 90001410 OR Solar 90001417 OR Solar Total OR Solar Prolects: 5 Clark - 51h Ave Pivot Clark - 6th Ave Rental Clark - Jake's House Clark - New House Jackie Hansen gg0 0.01 o.ol 0.01 0.01 0.0,t OR OR on OR OR Malheur Malheur Maihuer Malheur Malheur Malheur Cassia Union 22.00 13.00 35.00 loii qQ r00.6lt 10000003 Geothermal Neal Hot Springs Unit #1 10000002 Geothermal Raft River Unit #1 Tota! Geothermal ProlecB: 2 1OOOOO01 Wind Elkhom Wind Project Total Wlnd Prolects: I OR ID OR Non PURPA PROJECTS ONLINE Exhibit No. 2 Case No. IPC-E-15-01 R. Allphin, IPC Page 6 of6 BEFORE THE IDAHO PUBLIC UTILITIES GOMMISSION cAsE NO. IPC-E-15-01 IDAHO POWER COMPANY ALLPHIN, DI TESTITUIONY EXHIBIT NO.3 1 2 3 4 5 5 7 8 9 10 11 12 13 14 15 15 t7 18 19 20 2t 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 ts hi,Poulrcgoparry PrcDord PiRPA Sobr - Ac of tanuery 20, 2015 id.ho Project Name Proiect Develop€l MW.c Term {Yearsl State Estimatcd Op€ration Oate Estimatcd Oblitation (includes intcgration) Estimatrd 2 Ycar Obligation (ircludes i-o6rEai^*l Proiect A1 Oeveloper A 80 20 ldaho izloLlt6 5794,O97,771 s9,903,s6s Proiect A2 Deveioper A 28 20 ldaho t2loLlL6 s67.364.680 s3,418,565 Pro.iect A3 Oeveloper A 30 20 ldaho LzltLi,6 ss8,638,038 s2,s61.s12 Project 44 Oeveloper A 30 20 ldaho t2l3u15 ss7,091,198 s2,43s,210 Project 81 Developer I 70 20 ldaho L0/30116 548,LL7,629 52,441,832 Proiect 82 Developer B 20 20 ldaho t0l30lt5 s47,758,118 S2,413,450 Project C1 Developer C 20 20 ldaho Lzl3u16 553,382,246 s2,318,923 Proiect C2 Developer C 20 20 ldaho t2/3Lh5 ss3,283,030 52,337,229 Project C3 Developer C 20 20 ldaho L2l31h6 s49,203,954 s2,150,196 Proiect C4 Developer C 20 20 ldaho 12/3Ll16 s49.360.962 s2,148,558 Project C5 Developer C 20 20 ldaho L2l3LlL5 s48,760,343 s2,084,643 Project C5 Developer C 20 20 ldaho L2/31/L5 ss1,485,s58 52,208,70s Project C7 Developer C 20 20 ldaho 12/3tlL6 5s1,493,788 52.L78,763 Project C8 Developer C 20 20 ldaho 72l3tlt6 ss1,3ss,246 52,169,s41 Project C9 Developer C 20 20 ldaho t2l31lt6 5sL,797,624 s2,148,385 Project C10 Developer C 20 20 ldaho L2l3LlL6 s48,438,230 s2,048,049 Pro.iect Dl Developer D 5 20 ldaho L2l3tlL6 s13,450,419 S6s2,s1 1 Project D2 Developer D 7.5 20 ldaho L2llLlL6 S18,813,024 581s,639 Project D3 Developer D 10 20 ldaho 121371t6 522,4t7,366 S1.087.s19 Project D4 Developer D 10 20 ldaho 12l3Llt5 522,4t7,366 s1,087,s19 Project E1 Developer E 13 20 ldaho 12/3t/16 s29,142,575 sL,413,775 Project E2 Developer E 20 20 ldaho t2l3L/16 s44.834.731 s2,175,038 Project E3 Developer E 13 20 ldaho 12l3LlL6 s29,L42,575 5L,413,77s Proiect E4 Developer E 20 20 ldaho t2/3L/16 s44,O77,867 s2.113.s43 Project E5 Developer E 20 20 ldaho t2l3tlt5 s43,254,238 52,047,317 Project E5 Developer E 20 20 ldaho 72131/L6 543,264,238 52,047,1r7 Project E7 Developer E 20 20 ldaho L2l3L/L5 543,264,238 52,047,3L7 Proiect E8 Developer E 20 20 ldaho L2llLlL5 543,264,238 s2,047,317 Proiect E9 Developer E zo 20 ldaho 12l3UL6 s42.3s6.002 sL,972.,577 Project E10 Developer E 20 20 ldaho L2l3t/16 54t.372,O78 s1,893,105 Project E1l Developer E 20 20 ldaho 12/3th6 54L,372,078 S1,893,105 Proiect E12 Developer E 13 20 ldaho 12/3L/L6 s26.891.851 s1,230,519 Project Fl Developer F 70 20 ldaho L2l31l16 s138.908,196 S5.14s,735 Project G1 Developer G 3 20 ldaho t2l3Llt6 Ss.853,804 s2s6,1s1 Proiect H1 Developer H 1 20 ldaho t2/3L/15 s1.818,839 s74,31s Project l1 Developer I 20 20 ldaho L2l3t/t6 536,376,776 5r,486,292 51,711,!r41,939 s7&867,s15 Exhibit No. 3 No. IPC-E-15-01 R. Allphin, IPC Page 1 of2 Subtotal 755 Case 37 38 39 40 47 42 43 44 45 46 47 48 SrlE PoicrcoEuany Prolo3rd PURPA Sobr - Ar of ,ail.ry fO 2015 Ollron Proiect Name Prolect llevcloper MWac T€rm (Yearsl State Schrdulcd Operatlon l).i. Estimated Oblltation (includes intetration) Estlmated 2 Year Obllgatbn (includes lnl.ralianl Project Jl Developer J 10 20 Oregon 06,lLslL6 s30.282.970 s2,004,849 Project E13 Developer E 20 20 Oregon t2/3tl15 541,372,O78 s1,893,106 Proiect K1 Developer K 10 20 Oregon 12l3LlL6 531,889,203 s2.084,319 Project K2 Developer K 10 20 Oregon 1213l/16 s31,889,203 s2,084,319 Pro.iect K3 Developer K 10 20 Oregon L2l3tlL6 531,889,203 S2,084,319 Project K4 Developer K 10 20 Oregon t2ltLh6 s31,889,203 s2,084,319 Project K5 Developer K 10 20 Oregon t?'137/16 s31,889,203 S2,084,31s Project K5 Developer K 10 20 Oregon t2l3tlL6 s31,889,203 s2,084,319 Proiect K7 Developer K 10 20 Oregon L2/3L/L6 s31,889,203 s2,084,319 Proiect K8 Developer K 10 20 Oregon L2/lLh6 531,889,203 s2,084,319 Proiect K9 Developer K 10 20 Oregon L2137/76 S31,889,203 s2,084,319 Project K10 Developer K 10 20 Oregon 72131/76 s31,889,203 52,084,319 subtotal 130 s390,s47,080 $24,74r,18 Total 885 s2,102,489,019 $103,608,664 Exhibit No. 3 Case No. IPC-E-15-01 R. Allphin, IPC Page2 ot2 l BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION GASE NO. IPC.E.15.O1 IDAHO POWER COMPANY ALLPHIN, DI TESTIMONY EXHIBIT NO.4 sl rolon1 d FI r.]otbl.:t F-31 c -liet q El s I'1 b-C'I C)-l - :lertt rttlrtltl riNI G' Itl 11'(rl c,-l- =l=rol I! HS dldC'I C'-l' I' ]. EaTBEEJ 3. st 36ll itC'I C'tst+ ul s L-E EggEe s F Exhibit No. 4 Case No. IPC-E-I5-01 R. Allphin, IPC Page 1 of 1 croor-lot ol AlN g) O F cllcr, +l N6- \(l-.oJq t\J ar_O N Gtlao ol !lN oClFlO Fl 6(O lll F 6lN lol a6t' 6iat6ilc,i J dF F FIN -l rrlG (OlO rot +G JJ Jt!i-l- u\ ii 6 c, 6a rr rolo ol r.r6. C) O F ratl.t Nl aoll, F O lOlO -l CtJ 6i+c,tld -1 JG' O ry) Fl+ {l 6FOOIIO?lOd d old Jrio N ol{ rol .De-lFCl--l- l- rtt c, ro o colo ol r-- An (O F Ol(.) Ol at!l O o FIN Gtl .of rj d 3t1.,t ts1 dl\ O g) Olao aol 6(oooloFl{d oo' -.Id o1 dO B EI: EI E1- I- ttocroclo ol orF gi c, F FIN c.il aoc, Gt 6t ol (o ]\l aYts.; ct+.olf ro1 dN a g) CtlN aDl .aa.l F 6lC! -l *J d c{lc,t ,rfl oi'N Ctlt tl .O09?l?6lF -l-l- ooo-olo ol r-GlSGtt6ale ol oF { 6 ailcn ol .rid J sf 6ilh: tfl ..it Gtt-lN Fl 6ri F OlOi (ol ao; $sflg q3l-l- cr + o ro olro ol rood,NoGil(o tll 6OF?F!tlc, I 68=r5818 I IOFNFFIag I (|,d6ddro16i l^i6a c) 6l!t I +o0ctit-l-l- N t rt crr ol- rol roa.t6llOflo 6l ar)o- \ o- o- toJq oJ o_CrFFN6alt 6l Ala G Ct A CtlI' dll atGti\(\aO?lt Nl 6dodddl+ ra1 d6l F F Ollt (Ol 6F c'! 3) -lao (ol G'0 e c.il.{ -1 +1- 5l 6 EE H=^E E E E65 EEd E.=O>Er= O(D(,Er-5 0 c'l I BEI I EEI Iotl3Fl I EE EI I')rl I EEI I HEiI Ilrl I iFl I g=EI I-:lEFI I E'EII -tlsFl I EE EI I-rl I _tl 'lElolslolrlgtlol co o Eo Ht P rg3 .9 hiLA-bd g ot LtE ! !EoE 6 =a6 E =rtE E -9i E EgE 6 e IE otroE"oo BEFORE THE IDAHO PUBLIC UTILITIES GOMMISSION GASE NO. IPC.E.15.O1 IDAHO POWER GOMPANY ALLPHIN, DI TESTIMONY EXHIBIT NO.5 c$t{GF5 .1,rat LrrlEi6 60dGR>z (,6Aail -€r.d5 t, Rga; I)EdGOr'i .9 E*,aketBEE003ego EE EE.gogE 8fr EgE>BUItro. =E9;gE 8Evol/'Eop ItETE€aE'lE *EE*!fi :EE*fifi *EEEeE E3 b HEE Exhibit No. 5 Case No.|PC-E-15-01 R. Allphin, lPC Page I of I a*8f**IR*A)FAocrtrrocloctocrcr(,CCr{tFg6rtrnilF'(qmnl ltraul aprmueu & pe$dr5 (q,Snl peol gsrrg ro% BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION GASE NO. IPC-E-15-01 IDAHO POWER GOMPANY ALLPHIN, DI TESTIMONY EXHIBIT NO.6 ldaho Power Company Estimated [oad, Must run Resources, Utility PPAs and PURPA Calendar Years of 2016 and 2017 L4% 17,544 Hours 2,492 Hours Totalhours in 2016 and 2O1-7 IPCO Only - Must run and take from Utility PPAs lF@ Must Run, must take from t tility PPA$ plus*ll PURFA under cofltract tinduding solar) Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 'l of 25 aid RrsGt !. sdI EE }E t, HiiE adcat .llt 5ofl.tt G c ca i,iEi,ili 3IG ,iJll Iad Iq aa tcl.O Ir e -e.}.;L!otgI€Lo GIca,gt3 E TIDttrlitoLolr art>tCoJEoEUIllIeollboiog oso! {=>a -a -I;r>.5 F f-q-/I -5 >>rd Z > -il q > ar.ffix -) q ffi q _=@Et ExhiHtNo.6 Casa No. IPC-E-l5-{lt R. Alhhin, IPC Page2d26 i : i ;?i o= : e ;*Z E = + E:${'*iEi-a = 3 E i i* t+ I = E = AX EE2.=ii; .R 3 t E ZZ E=9 4 < .t = <o e - + E E = E o o? a-Y f I == Y Yj :i;= ' i I- I == T rO od aa I o o!a 3 =g o g oco(, o-x(!F oc Jd t^ EEo lioIo ott an !oo !o ot!Io ou.sq 3oo o!(! ! o: "i9;z*9 oJ9ER3:Et, i-EL @o o'ra to c'd d !a oo, !,L o€ j /vlw oooN oo N (too6 Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 3 of 25 "r"4 ! < I qn ii { 't i : : ,5 t et\rr=---)t --u 1 - .Z< - ,-r SIq.-r E = i :?-! : j t iY3 s E + r: =E.YZo=6;t ; E ; 2 El 69= i i ! .i *z ;>c 6 > ! -- =4=3 * I ! = E9 -9n= E E E! a O 9 O6i f f f = :a Yj !61 g o er * == +IIf; I G. RE D:::zEq, 0aotUdO33 EiI o o ts I = € oil o z o oN an_ I = 10o N = o -. 3 E .9 o oco(9 o.v,a!F o tr Jd tt !o ti(!Uo ol! 6 T'oo :qo UIo o oll o 3oooEo3 oo ..i Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 4 of25 r E ! i €gs i : * E: E : P ! O.i IE = = E ' iE ;E + E i a =2, =]E 3 t 6 E li E =1 { < .< =. Bo C ^?&ddEooYo6i f f f = Y Yj !:' = i i- I == I 6 oNri o. aoN @ q 3 =tro o oco(, oJ(!F oc u Ut E !o t,oIo oII vl Eoo !o U!o(Jo ou. o 3oo o !GE oZo9al<o, oI9E:R3a;E.! r<Li € oN e o o qc @Io eoo a\i Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 5 of 25 i z X r?; i ; t .EgE 9 E * E:g -: g E Y6 E3 i = E = Ex E=1.=3= ; i ! .i. *z i>C6>a--=aQ =9 4 q 4 = !o o -i E a =! o oF o€i f f f = Y Y4 !€q g 4 er = == =I lr I @_ dcn-O-EEor o @(Ud 6.,R= >rt =ir oo m I = Exhibit No.6 Case No. IPC-E-15-01 R. Allphin, IPC Page 6 of 25 Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC PageT of25 r E E $ Ef3 9 : t E:S c 3 ; E= zE ! 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L= =3E A 7 d = ei Eqq 4 4 4 = qo o - + E e E i o 6! 6-i: I I f = Y Y3 !-: ' i l- i == T aZ 3=og oJ:ER}i6oE rO oN l\ o I o o o €o o ood ^i o 6 od o 3 =tr .9 o oco rJ, oIt!F o tr =d IA !o ti(EIo ott ln !oo 'qo l,oIo otl Lo 3or o!o = Exhibit No.6 Case No. IPC-E-15-01 R. Allphin, IPC Page 11 of25 E- =, * ;sa i I :oi ; I H: --:EZ-O.;E1 o = z ER :a-=-; < ! s *: ts>o-.-=44* * * 3 5E 9& d E! O Oy Ot - -= 9 J3 Jtrr I E + ao 6i G eN F.' o 3 E g .9 (! ogo(, oJ(!F o =d l, =Eo tA(!Io oII aA -,oo To vtolJo oll o3oo oEGa, 0 C,da o oE "i9E:z0) oIsER3;EZr @ o o2 ooNci oz 0 od o2o0 Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 12 of 25 i E z i ;sE i _: 4 !:! i 3 ; t= zE : P ! 9i Ea : = € : :E E; + E i z != Ii; 3 i a E 9E E =3 ! ! 4 = =9 I ^+ E E E; 6 a! ocoi > f f= Y Yj J:= ' i l- i == I GoH F.- a6 oN @ oa 3 E c .9 o oco(9 o:t!l- oc u Ut Eo It(!go oll r^ 1Joo .g o oo o olr o 3oe oEG! o- oE;9 r:2ct q, 0 59UR=:;a:OL o 0 6' ct roo .n IEI @ oGl d. ao Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 13 of25 itrra th'Ca tt -!GI EE ts-g tI Hg iE 6d $'r aid GIGa e Ca + E : i tgg,;EiEEiE Ei $ r $; E Es ilrltl$l gt fiIrl CIc6ia t6Gl {too-G 3 E tro+.g {,co(t sg rrotI AEut:l =!o.4,or!tto o1& ai5uoo !otI5ll(,oLoltiLo3o&o.C,o = a L-l ->! 4l a <--.!>q -/ J ---...- c d f I ] eJ ,i{ a fr --- {a ( --a r a -TEqtv Exhirbit No.6 Case No.lPC€-15-01 R. Allphin, IPC Page 14 of25 otia a!4 trH "f I Eo Ei9cua I i E I E Ig E*lEI,iI!lllll* 3 =toiPll oCo(t -gg LocJc,tyIt:, E xal,oIo olt d !rrloJEo.J0ili)oLoTLLotoAo-to3 Exhitrit No. 6 Casc No.|PC-E-|5-01 R. Allphin,IPC Pagc 15 of25 i Z x i.q 3 € 4 !;c j ; ;? ; = s :i oG 4a .i = =9 Y1 = E = E:i b1 .= i z A= =6 > A -* =a €4 4 .r =. io q E = = i 6 o! 6 III I }Eao @i ts- REci9:>Eq, o rlUa (1,R} Eii oN N t = F o o a = 3 E c .9 o oco(9 o t!F o tr =u UI J Eto r^oIo ol! ti T'oo ?o l,ouo ott o 3oB oE G3 ts Idtri tr = rod.i a = Fo .i o0 ^i Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 16 of25 BE TE'-g ;a Hg $E s E I t fi fuI E I,i Ii!tltllfi I 3 =Co,E EoCot -gg totit4att5E !oJY6t!CIoLot[ t !,Co -ato,.r,5tt,oLoltLtDIog oEl!3 EdribitNo.6 Ce3s No. IPC-E-15{1 R. Allphin,lPC Page 17 o,f 25 * E E E EE EE,;EiEEiiEi $ E $; E ig Ilrlll$l t\o3r\.tT oG' raIE 5.sEE s3tro tarOis $E dC)atil IT o0r'iE (latll at B E co,yCgco(, .Eg Lo CtGl Jl' =1'oal,TIIJosolt l'>Eio.JEo.1,5oIoL0tlLo 'oB oE,og Exhibl't No.6 Caae No.|PGE-15-01 R. Allphin, IPC Pege 1E of25 .E E- z i ;eE E = I E:< i t ; i= a*+-r= ! =' ! '9; ;E i = ! 5 EE EE : .a a :i a= =;E ; i E = ca E cag-arrEl<soo:'ocoi ) f l5 Y Yj !!= - i i' I == T F o E FoN @' eJ 3 E co o oco(9 o.Yt!F o tr u, tnf !o t,oIo oII a; !oo !o ooIo olr o 3oo o-co = o= ;-oc23r0, 0 }ER3;eJi< ts I di E c) c = ts o c€oo. /v\l l Exhibit No.6 Case No. IPC-E-15-01 R. Allphin, IPC Page 19 of25 ! : .I :?n , a t E:": ? € + i:$ € a ! ,9i r==.=E : ! = , EE :=lr=--i= E ; ? .g *: ;>of>o==atEE s * 4 = E9 I- + E = =; o oF oco i : = f = Y ^J j :attr I F o od€ 3 E tr .9 o oco(9 oJr!l- oc d oJ E !o t^(!go ot& 1^ Eoo !o UIo(Jo oII o3og o-c(! = tsrc o-*-5gE-o o OJ:.eR'JE F o NoN d ts o oo {i Exhibit No.6 Case No. IPC-E-15-01 R. Allphin, IPC Page 20 of 25 i E z s ;:3 0 : { E:f b ; ; 6= aE E P i 9; !E i = = , ;R EE ! = i 7 T: ;]I .? ] 6 = =e r =3 * S ! 3 E9 9-+ E = ;i o oE o.I l 3 == Y Y3 !!= = i l' I == T h- otl Bg<o* o :E'R=rgE <E od FI:L<i N C'N @IlI<i hoHci f h c)ld N a N 0ilj Ia E =c .9 o oto(9 o.x(!F oca &, a^ =Eo 6oIo otl vi a,oo T,o lio(,o oll o 3oB oso! ooo- oooo l\i o0o_6 o0ri Exhibit No. 6 Case No. IPC-E-I5-01 R. Allphin, IPC Page2l ot25 ("W ,rF' I h._ ,t,I lr= I hh -Li @ ,, '': iii{t \-@ ry p; -- i I hi--L @ -:h--.E l L@\ry lf\Tx ry--.r * E E E itg,iEEEEEE El E E i; E Eg ilrltlxl ItG'ri!t 3 E co.Po g o(o Eg l-0 Etd,a,o3 E!oogt Gto olt l, oG'daag gE $EgErtt p I\I \I = -I _.1rH-! 4 -->-: --J -)_ -a -! ;q (ail 7 - arE8E;EslL o GlAI C}d o,a6otj tDtnrf 8atat' 6o5C !ooJrtroi9olllJo ottLo3oB o-co! ,utfi E:dribit No. 6 Gass No. lPe-E-l5-01 R. Allphin, IFC Page2?ol25 E z i r?i i ! r E:a 6 = q ion . . * 9a4 E ; ; iZ zE E P : C.; !: = 5 : =6 Y- - ! ; e &n 6=lr=i: i ? ; i tE i =3 { { I = E9 I ^ + A A E a o a! oEi ) ) Ja Y :- :€a c 4 c6 = == +ltt I o= Iioo,t oIIER39fio'; F oN h- o ts 0d€ o F o !i o o o N{o o 3z tr .9 o oco(9 oJ(!F og Jd tif =to tAolJo olr t5 Eoo !o UIo(Jo oE o3oo o-co3 Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 23 of 25 i=i;iE .: J E E:o ; ? t Ior i F * !a = : a = -,a yi = ! € ;e rE r Z = ' Ed oir 3 5 ; E iZ ; =E { { t = E9 9-.+ E E ;; o o^= 6ei I I l= :- Ys :I'I I h- o= "i9Be=o)e : o ;g,NIUiruR=:Eo.=ZL rod o2 F o ii oz ts odj o2 tsofl Fa o2 N Id 02 3 E g .9 o oCo(, o (!t- o trfd, t,J =Eo tat!Io ol! tn T'oo 'roouo o oE (u 3oG o (!3 Exhibit No. 6 Case No. IPC-E-15-01 R. Allphin, IPC Page 24 of 25 r E E $ EIa : = { ;-og I a i s= EE : = E i ER ":E 1 E i z A= :}E 3 7 d = 'i E =6 t ! t 5 EE 9 a*Ge<!ooYOei I I l= Y Yj !€g g c g6 = == ={tlll oN F.' aa 3 E g .9 t! oco(9 oI(!l.- og u ti J =!o tioIo otl vt !oo !o r,oIo otl Lo 3oc o o3 F C'd a6 N-oEa9:z6g,E 0!:ER3 o lrta:clL F o 6' fo h c, l6 F o6a a6 Exhibit No.6 Case No. IPC-E-15-01 R. Allphin, IPC Page 25 of 25 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION GASE NO. IPC-E-15-01 IDAHO POWER COMPANY ALLPHIN, DI TESTIMONY EXHIBIT NO. 7 'he % % "r+ %,% n'he .5'% %" % % % % % %r, % rattb,co E IU CL st3 EL Lo 3oo-o-c$EI oocoC)O'nCl^al rl suotlllN $ Exhibit No.7 Case No. IPC-E-15-01 R. Allphin, IPC Page 1 of 1 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION GASE NO. IPC-E-15-01 IDAHO POWER COMPANY ALLPHIN, DI TESTIHIONY EXHIBIT NO.8 Approved Net Power Supply Expense in Base Rates (Normalized) FERC Account Account 501, Coal Account 547, Gas Account 555, Purchases (Non-PURPA) Account 555, Purchases (PURPA) Account 447. Surolus Sales 5 (92,6q2,Lt4 2,755,646.4 Expense 5 t67,7t$,og4 5 6,062,472 S 66,689,601 S G2,851,454 Energy 7,169,601.0 42,552.4 1,110,756.0 7,043,642.0 s/Mwhs 23.3s S 142.47 S oo.o+ S ao.zz s 33.62 FERC AccOuNt Account 501, Coal Account 547, Gas Account 555, Purchases (Non-PURPA) Account 555, Purchases (PURPA) Account 447. Surolus Sales S (724,9t6,153 (3,518,491.2 Expense 5 L67,L92,7M S 51,934,201 S 45,510,093 s 62,851,+54 Energy 7,145,609.2 1,176,35L.8 763,793.t L,O43,642.0 s/Mwhs 23.40 s 44.1s S sg.sa 5 60.22 s 3s.so FERC Account Account 501, Coal Account 547,Gas Account 555, Purchases (Non-PURPA) Account 555, Purchases (PURPA) Account 447, Surplus Sales S (51,735,153),309,045.6) Expense s 108,503,180 s 33,362,563 S 62,506,593 s 133,853,869 Energy 4,759,957.7 993,970.8 7,236,373.4 2,t4L,849.4 $/Mwh5 zz.tg S 33.s7 S so.ea S ez.ag 5 22.41 Note: Accou nr547, e as S/tUWn include total variable expense plus all fixed expenses Exhibit No. 8 Case No. IPC-E-15-01 R. Allphin, IPC Page 1 of 1 BEFORE THE IDAHO PUBLIC UTILITIES GOMMISSION GASE NO. IPC-E-I5-01 IDAHO POWER COMPANY ALLPHIN, DI TESTIMONY EXHIBIT NO.9 Prolect Name MWac Term (Yearsl State Scheduled Operatlon Oate Estlmated Obllgation (includes lntegration) Estimated 2 ycar ObliBation (lncludes lntegration) Grandview PV Solar Two, LLC 80 20 ldaho 09lo1/L6 5312,729,719 s21,36s,030 Boise City Solar, LLC 40 20 ldaho oLloy16 51s6,299,294 s10,34s,907 Mountain Home Solar, LLC 20 20 ldaho L2l3uL6 s79,877,543 s4,310,801 Pocatello Solar 1, LLC 20 20 ldaho 12131/L6 574,712,9s6 54,0ss,s63 Clark Solar 1, LLC 7L 20 ldaho t2l31h6 5243,227,3t2 SLz,ts2,964 Clark Solar 2, LLC 20 20 ldaho t2l3!16 569,245,830 S3,70s,o3o Clark Solar 3, LLC 30 20 ldaho r2l3tlt6 5102,774,966 Ss,444,983 Clark Solar 4, LLC 20 20 ldaho t2/3tlL6 s67,990,610 s3,533,830 Murphy Flat Power, LLC 20 20 ldaho LzlOUt6 s59,184,146 s2,860,894 Simco Solar, LLC 20 20 ldaho LZ|OL|76 s69,9s1,24s 52,887,904 American Falls Solar, LLC 20 20 ldaho 12lo1,lt6 s6s,313,902 52,62L,8L3 American Falls Solar ll, LLC 20 20 ldaho LLlOu76 s62,494,248 s2,378,384 Orchard Ranch Solar, LLC 20 20 ldaho tzlout6 s5s,60s.413 s2,s31,99s ldaho PowerCompany PURPA Solar projects under contract - As oflanuary 20, 2015 Subtotal 0L S1/t39,4o8,18s S78,915,G)8 Subtotal 60 s22s,830,701 s13,919,334 S1,58s,238,8E6 592,93/.,432 Exhibit No. 9 Case No. IPC-E-15-01 R. Allphin, IPC Page 1 of 1 Prolect Name MWac Term (Years)State Scheduled Operation Date Estimated Obllgation (includes lntegratlon) Estlmated 2 year Obligation (lncludes lnteerationl Grove Solar Center, LLC 10 20 Oregon 72137176 s37,538,4s0 s2,319,889 Hyline Solar Center, LLC 10 20 Oregon L2l3Ut6 s37,538,4s0 s2,319,889 Open Range Solar Center, LLC 10 20 Oregon L2/3t/16 s37,638,4s0 s2,319,889 Railroad Solar Center, LLC 10 20 Oregon tzl3tlt5 s37,538,4s0 s2,319,889 Thunderegg Solar Center, LLC 10 20 Oregon Lzl3tlt6 s37,638,4s0 s2,319,889 Vale Air Solar Center, LLC 10 20 Oregon t2/3L176 537,638,4s0 s2,319,889 Total 461 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION cAsE NO. IPC-E-15-01 IDAHO POWER COMPANY ALLPHIN, DI TESTIMONY EXHIBIT NO. 10 t.t.r,I .rEd"=RE E.9 N EAS EtdF-=-;<lliR q;E E=€l: c rO o oI:-g do- o!I .toliiad EF-= 4d i3vaI =EE =dB llc tttii*, ]tI xt,tc T =o t,(,EnfGfA.oBe[, I I I I I I I I tOI t t I t t t r I t r t t I l r r I r,--++++-+-I-+--FF+-r-r-+-F] 3lfi 6 ',t ,t 6 6 6 6 6dor€lFC6<d)a{?t Exhibit No. 10 No. IPC-E-I5-01 R. Allphin, IPC Page 1 ofl snn/f PURPh Soler profgcts ldaho Powcr Company under contr.ct - As of Jansa# April 22, 2OL5 Prorect N.mc MWrc Tcrm lYcrrsl St tc Schcdulcd Opcntlon D.t. Estim.tcd Obllt.tlon (lncludcs lntcff.tlonl Ertimrtcd 2 ycrr Obll3rtlon {lndudcs Intrtr.tionl Grandview PV Solar Two, LLC 80 20 ldaho 09loll76 $1L2,729,7L9 s21,36s,030 Boise City Solar, LLC 40 20 ldaho otlotlT6 sts6,299,294 s10,345,907 Mountain Home Solar, LLC 20 20 ldaho t2l3ut6 579;877,5a3 s4,310,801 Pocatello Solar 1, LLC 20 20 ldaho r2l3ut6 574,7L2,956 s4,0ss,s53 ela*{da++;+e f+3€ld€h€a#+++6 *E+7t++2 $H4p4 eU+*SeU+er+fg 2€2e 'ld€h€slz4a.6 $6W ffi eU+*Sote++;++e 3e 2e ldehe +2#+l+6 $+w14.8ffi $s.4649et eU+*Seta+4+fe 2e 2e ld€h€+?/1+l+6 $+sg€ff s3#3*3€ Murphy Flat Power, LLC 20 20 ldaho r2lout6 s69,184,145 s2,860,894 Simco Solar, LLC 20 20 ldaho 72lO1lt6 s69,951,245 s2,887,904 American Falls Solar, LLC 20 20 ldaho tzlo7lt6 s6s,313,902 s2,621,813 American Falls Solar ll, LLC 20 20 ldaho L2lOLlt6 s62,494,248 s2,378,384 Orchard Ranch Solar, LLC 20 20 ldaho 72lOUt6 s6s,60s,413 s2,s31,99s Subtot.l g 260 Subtota!50 Srr43gr4eSr]as 5956,158,465 $7ap15pe8 Ss3,3s8,2e1 $::s#eleo s22s,s73,4s8 $tw s13,e28,1s4 $AZ,WA*L $67,286,44s Exhabit No. 11 ase Nos. IPC-E-1il1 AVU.E-1$01 PAC-E-Iil3 R. Allphin, IPC Page?ot 4 Proi.ct N.mc MWac Term flcrrs]St te Schcdulcd Opcrrtlon D.tc E3tlm.t.d Obllt.tion (lncludcs lnt:rmtlonl Eitim.tcd 2 ycrr Obllgrtion llndudx Inirrretlml Grove Solar Center, LLC 10 20 Oregon 12l3tlt6 ttsta63&*5e 537,662,243 52,31.s,889 52,327,3s9 Hyline Solar Center, LLC 10 20 Oregon r2l3tl16 $ua$8#e 537,662,243 52,379,889 52,327,3s9 Open Range Solar Center, LLC 10 20 Oregon 72l3th6 $37'638'450 537,662,243 52,319,889 52,327,3s9 Railroad Solar Center, LLC 10 20 Oregon t2l3t/16 $3r'63€o45g s37,662,243 52,319,889 52,327,3s9 Thunderegg Solar Center, LLC 10 20 Oregon t2l3llt6 *+e*.Ase 537,662,243 52,319,889 52,321,3s9 Vale Air Solar Center, LLC 10 20 Oregon 7213t116 $zta6z&;Eo $37,662,243 s2,319,889 52,32t,3s9 Totel 44 32O $11665*381885 st,782,14l,923 It 8,gIi IE!€i!e€ rEtE,A I o .U R R =A oaa E €IAo Eat Eoo a!c3 It,a EfEe I I L I I I I I-f I I I I =. ottc{ii R Fi o' oon !oto.!o a. !cn olltoo o!c:,aooo' o. 6-E, e I I I_t aaaooaaoooc)(troooaooooaooooo,-66@roqNoAro+c.tc)66+&a{f{a{Ntrl?t?{r{F{rt (mn) sllemetayy Exhibit No. 11 Casc Nos. IPC-E-1illAW€-l5{1 PAGE-I5{3 R. Allphin, IPC Pego 1 of tt II tI 5I tI ts tI 3tI tZt3t: $ !..oitAO .:L A!til*eI!:^EierbII-ttZ 3 tI .3 tt .c ttt tI tI ! tI tI ,\ 1 2 3 1 5 5 7 8 9 11 L2 14 1 2l 22 21 3l 32 4t l. f.foteu.rCotrlfft tropocrd ilIttA toh - fr o,Jraga,+fCi0r5 A??il22,2oLs tsrh. ftli.ct tl.m.PQl.ct Dd.bp.t MWrC Tcrm (Yornl ttt E ftt|.d OD.r.dolt Edm.tcd OblL.don lhdud6 l'ttqnti,on) E tlm.t d zYriloblfrdon (lndsd6 lntcfntlonl Projcct A1 Oe\rrloprr A 80 g)20 ldrho l2loaL6 $+943ai-lt+ 5213,1s9,62s s9pe3,56s s9,0s2,344 Projrct A2 Darclopcr A 28 28 20 ldaho 12loaL6 $67i6+68e 562,482,t3o 52,8{3,077 Projcct A3 Darclopcr A 30 :m 20 ldaho t2l3LlL6 ss8#a8pe8 s40,316,768 $e,s6+s4+ s2,110,838 Projcct A/l Dcvelopcr A :10 :x)20 ldaho tzl3tlL6 557p91+9a 540,316,768 s2r€s#e s2,110,838 Proiect 81 Daraloprr g 20 20 20 ldaho 70l:3rJ,lt6 s4€,r47€29 548,378,647 52,408,L24 Proicci 82 Dcvcloplr B 20 20 20 ldaho tol30lL6 $4H58+18 s4s,s49,07s $:r4+3r45g 52,277,533 Project B3 Developer B 20 5 ldaho t2l3r/16 542,s88,21s s2,059,783 Project 84 Developer B 20 5 ldaho t2l3il16 542,4t5,239 52,O53,461 Project 85 Developer B 50 5 ldaho Lzl3U76 5103,7s0,04s 54,820,801 Project B6 Developer B 40 5 ld aho 72/3tlL6 580,232,480 53,666,449 Projrct C1 Dlvcloprr C 20 20 20 ld.ho 1,2l3,,l,5 $s3,382,246 $s3,382,245 s2,318,923 s2,318,923 Projcct C2 Dcveloper C 20 20 20 ld.ho rzl?tl16 ss3,283,030 5s3,283,olto 52,317,229 57,3t7,229 Project C3 Devalopcr C 20 20 20 ld.ho t2l3U16 s49,203,964 $49,203,964 $2,1s0,196 S2,1s0,196 Project C4 Developer C 20 20 20 ldaho 7213l/t5 S49,360,962 S49,350,952 52,1118,558 s2,148,558 Projcct C5 Drvllopcr C 20 20 20 ldaho tzltu76 s48,750,343 s48,750,343 S2,084,543 S2,084,643 Project C6 Dcv.loper C 20 20 20 ldaho 12l1L/16 S51,485,s58 Ss1,486,s88 s2,208,705 5?,2N,70s Project C7 Drv?lop!r C 20 20 20 ld.ho L2ltrlt6 t51,493,768 ss1,493,788 s2,L18,763 52,L78,753 Projcct C8 Dlvlloper C 20 20 20 ld.ho t2ltut6 95r,3ss,246 951,3s5,245 s2,159,s41 s2,159,541 Proj.ct C9 Devcloper C 20 20 20 ld.ho L2B!76 5sL,797,624 55L,797,624 s2,1tl8,385 s2,1t18,385 Proi.ct C10 Darcloprr c 20 20 20 ldaho r2l3L/16 S.8,43t 230 548,438 230 52,048,049 52,(x6,u9 Proilct Dl Drvelopcr D 6 6 20 ld.ho L2l3LlL6 s8,063,3s4 s65+51+ 5422,168 Proiect Dz Dcvclopcr D 7.5 7.5 20 ld.ho r2BLl76 $w s10,07e,1e2 $8++539 5s27,709 Proiact D3 o.v!lop.r D 10 10 20 ldaho LU3LIL6 #A1W 514,413,193 $+p87+1e 5810,27e Projed Dtl Drvcloprr D 10 10 20 ld.ho r2l3LlL6 $1p87r5r9 5806,68s Project D5 Developer D 10 20 ldaho L2/31/L6 519,3i7,901 s1,001,813 Project D6 Developer D 10 20 ldaho 1213t/L6 s18.700.s25 s968.550 Proiact El Dcvcloplr E 13 13 20 ldaho r2BUt6 *#2#5 s17,470,600 $+A++it+ 5914,696 Proiaci E2 Drvcloper E 20 20 20 ld.ho L2l3!16 $44r814f,1+ 526,877,845 *+7W 5i.,4o7,225 Projcct E3 Devrloprr E 13 13 20 ldaho LutLlLs sl9+4r,5+s s17.470.600 $W Se14,5e5 Proiect E4 Dev.loprr E 20 20 20 ldrho LzBLIL6 6,t1,977,867 526.877.846 t7J42541 51.407.22s Proicct E5 Dlvcloper E 20 20 20 ldaho \2l3llL6 $W 526.871.846 tzp4134 51.407.22s Proj.ct E6 Dav.lop.r E 20 20 20 ldaho L2l3uL6 w 526,877,846 *wt 51.40i.22s Projcct E7 Devcloprr E 20 20 20 ldaho L2l1UL6 $€,164*38 526,877.A46 *p41)1f 5L,407,225 Project E8 Devlloper E 20 20 20 ldaho r2l1vL6 $4W 526.877.845 *AW7 51.407,22s Projacr Eg Drv?lopar E 20 20 20 ldaho r2l3vL6 s4#56S0+ 526.877.846 $+97151+ s1,407,225 Project E10 Dareloper E 20 20 20 ldaho r2RUt6 $4W 526,877.846 $+#z# 51,407,22s Proiect E11 Devrlopar E 20 20 20 ldaho t2l3ilL6 *1r1119t9 526.877.846 sr,89+m6 57.407,22s Proicct 812 Devrloprr E 13 13 20 ldaho 72l1tlL6 sr6,89+,851 577,470,600 54+30519 5914,696 Proi.d F1 Da\raloper F 70 70 20 ldaho Lu3!L6 #3e908+96 594.072,460 $6*48f,16 54,92s,289 Project Gl Dcvcloper G 3 3 20 ldaho 12i3ilt6 95?853r8e4 54,031,617 s+s#l 5211,084 Proiect Hl Dcvelopcr H I 1 20 ldeho x2l1vL6 51,s+&839 5r,343,892 $1431s s70,351 Project 11 Oaceloprr I 20 ?o 20 ldaho rutaL6 *q4$i1t8 526,877,846 slr486l93 5t,407,225 Project L1 Developer L 28 20 ldaho t2131./16 s37.628.984 51,970,11s Proied L2 Developer L 2a 20 ldaho 1213't/16 537,628,984 s1.970.115 Proiect L3 Developer L 80 20 ldaho 12/31.h6 5r.07.511.382 ss,628,901 Proiect 01 Developer O 20 20 ldaho t2/3L/L6 526,87?,846 sr.407.225 Project 02 Developer O 20 20 ldaho 72/3L/76 s26,a77,846 s7.407,22s 1,081 Ss4,r4o,to1 Exhibit No. 11 Case Nos. IPC-E-1$,01 AVU.E-.lil1 PAC-E-15{3 R. Allphin, IPC Page 3 of 4 S.rbtobl $r,7i*r4rfa9 s1,969,960,770 $78f57#il6 f.hcfor.'CoilFrry ,!opo.ad XntA Sol.? - fc dlaaceryi0rf0$ Aptil22,2ol5 Orun P.ol.ct il.m.Proirct Davalop.r MWrc Tcnn (Yrenl 3tt Sd!.frlLd Opontiolr E tlnEt.d Obllt tlcn (lncludc hqntlonl E ilm.rcd 2 vC.? Otll.ltlon (lnclud6 lnt lr.tlonl Proiect.,l DcYeloprr J 10 10 20 Oralo.06lrsh6 $ei82rre 530,32s,79s 52p04*49 52,008,451 Projccl E13 Developrr E 20 20 20 Orcgor 72r3U76 $4W 526,877,846 s+,893+96 5t,407,22s Projrct Kl Devclopcr K 10 10 20 Orlgor 72l3ut6 9J+r889r:e+ 531,934,668 5rp84r19 52,186,583 Projcct K2 Oeveloper l(10 10 20 Or?tor 72Erlt6 931,8891€3 531,934,668 s2s84,3+9 52,186,s83 Proiect K3 Daveloper K 10 10 20 Oregon tzBLl76 s3+'88+2o3 s31,934,668 $rp84,3+9 52,186,s83 Project K4 Drvelopcr K 10 10 20 Orcton tzlSLlL6 $+€8re 531,934,668 srp84#9 s2,186,s83 Prolect K5 Developer K 10 10 20 Oreton L2l3r/16 sJ1,889,t€3 531,934,668 *p843r9 52,185,s83 Project K5 Developrr K 10 10 20 Orogon t?l31lL6 5r+88re 531,934,668 $2p843+9 s2,186,583 Prolect K7 Developer K 10 t0 20 Orcgon L2l!71L6 sa.1*89'2e+ 531,934,668 s2p84r3+g 52,186,583 Project K8 Developer K 10 10 20 OraSon L213!16 5e+889l4] 531,934,668 $2p8431e s2,186,s83 Project K9 Dcveloper K 10 10 20 Oreton LLl3!16 99r88+r4] 531,934,668 5210841319 52,185,583 Project K10 Dcveloper K 10 10 20 Oregon t2l3!76 se+8891o3 531,934,568 s2p84'3+9 s2,185,s83 Project M1 Developer M 5 20 Oregon t2/31/16 s 15,967,334 s7,093,292 Project M2 Developer M 10 20 Oregon 12/3),/16 s31,934,668 52,186,583 Project M3 Developer M 10 20 Oregon t2llL/L6 s3 1,934,658 52,186,s83 Project M4 Developer M 5 20 Oregon t2/3L/16 51,5,967,334 S1,093,292 Project M5 Developer M 10 20 Oregon L2l3t/76 531.934.668 s2,186,s83 Project N1 Developer N 5 20 Oregon D/3r/76 Sts,967,334 51,093,292 Project N2 Developer N 10 20 Oregon L2/31./1.6 s31.934.658 s2,186,s83 Project N3 Developer N 10 20 Oregon t2/31-/L6 s31.934.658 s2,186,s83 Pro,ect N4 Developer N 10 20 Oregon t2/3L/t6 s31,934,568 s2,186,s83 Proiect N5 Developer N 10 20 Oregon 12/3L/16 s3 1.934,658 52,186,s83 Proiect N6 Developer N 10 20 Oregon t2/3L/L6 s31.934.668 52,186,s83 Project P1 Developer P 10 20 Oreton t2/3t/1.6 53 1,934,668 s2.186,583 Project QL Developer Q 5 20 Oregon 12/31/16 515,967,334 s1,093,292 Projert Q2 Developer Q 5 20 Oregon t2131116 515,961,334 57,O93,292 Subtot l rto 245 $30or547rC8e 5743,799,003 $.1i'it,t48 $50,427,223 Totrl 885 1,126 *+o2r48gn0r8 s2,771,7s9,771 t1O3fO9554 5144,567,317 Exhibit No. 11 Case Nos. IPC-E-1il1 AVU-E-15-01 PAGE-1S3 R. Allphin, IPC Page 4 of 4 Expiration of PURPA Contracts Over Time 100 €80q, P60la-340o -ct E20z 0.f C ,$ C C "p' "rdf dP dF "rd} "S r"" rttl ,,rllll ,illl ,rillll ,rritillilll llilI|il ExhibirNo. l0l Case No. IPC-E-15-01 AVU-E-15-01 PAC-E-15-03 R. Sterling, Staff 4123n5 BEFORE THE TDAHO PUBLIC UTILITTES COMMTSSTON CASE NOS. IPC.E.I5-01, AVU-E.I 5.0I, PAC.E.I5-03 J.R. SIMPLOT COMPANY AND CLEARWATER PAPER CORPORATION READING, DI TESTIMONY EXHIBITNO.2OI Don C. Reading Ptesent positiot y'ice President and Consulting Economist Educatiot 3.S., Economics; Utah State University VI.S., Economics; University of Oregon ?h.d., Economics; Utah State University Delta Epsilon, NSF Fellowship Johnson Associates, Inc.: 1989 Vice President 986 Consulting Ecooomist Public Utilities Commis ston: I 98 1 -86 F.conomist/Director of Policy and Administration eaching: 980-81 Associate Professor, University of Hawaii-Hrlo 970-80 Associate and Assisant Professor, Idaho State University 968-70 Assistant Professor, Middle Tennessee Sate Uruversity . Reading provides expert testimony concerning economic and regulatory issues. has testified on more than 35 occasions before utility regulatory commissrons rn laska, California, Colorado, the District of Columbia, Hawaii, ldaho, Nevada, N koa, North Carolina, Oregon, Texas, Utah, Wyoming, and Washington. Reading has more than 35 years experience in the 6eld of economics. He has icipated in the development of indices reflecting economic trends, GNP growth foreign exchange markets, the money supply, stock market levels, and inflati has analyzed such public policy issues as the minimum wage, federal spending and import/export balances. Dr. Reading is one of four economists iding yearly fotecasts of statewide personal income to the State of Idaho for of esablishing state personal income tax rates. n the field of telecommunications, Dr. Reading has provided expert testimony on of marginal cost, price elasticity, and measured service. Dr. Reading prepared te-specific study of the price elasticity of demand for local telephone servlce rn and recently conducted research for, and directed the preparation of, a repott Idaho legislature regarding the stahrs of telecommunications competition in that te. Exhibit No. 201 Case Nos. IPC-E- l5-0 I , AVU-E- l 5-0 I , PAC-E- I 5-03 D. Read ing, S implot/Clearwater Page I r. Reading's areas of expertise rn the field of electric power include demand tng, long-range planning, price elasticity, marginal and average cost pricing, ion-simulation modeling, and econometric modeling. Among his recent ca an electdc rate design analysis for the Industrial Customers of Idaho Power. Dr Jing is curently a consultant to the Idaho Legislature=s Committee on Elecuic ng. the past three years Dr. Reading has been a consultant to Idaho Connec n Line (ICON), a virtual charter school, providing data analysis and statisti ln addition to building a model that replicated the ldaho's Star Rati he completed a study focused on the demographic and socioeconomi ctetistics of the school's population and academic achievements. He is y working with the measurement of ICON's Mission Specific goals he 207 4-2075 school year. 1999 Dr. Reading has been afEliated with the Climate Impact Group (CIG) at University of Washington. His work with the CIG has involved an analysis of impact of Global Warming on the hydo facilities on the Snake River. It also ludes an investigation into water markets in the Northwest and Florida. In dition he has analyzed the economics of snowmaking for ski atea's impacted by Warming. Dr. Reading's recent projects are a FERC hydropower relicensing study (for Skokomish Indian Tribe) and an analysis of Northern States Power's North kota rate design proposals affecting large industrial customers (for J.R. Simplot ). Dr. Readrng has also performed analysis for the Idaho Governor's O the impact on the Northwest Power Grid of various plans to increase salmon the Columbia River Basin. Reading has prepared econometric forecasts for the Southeast Idaho Council of nts and the Revenue Projection Committee of the Idaho State Legislature has also been a member of several Northwest Power Planning Council Statistical visory Committees and was vice chairman of the Govemor's Economic Research in Idaho at Idaho State University, Dr. Read:ng performed demographic studies using survival model and sevetal economic impact studies using input/output is. He has also provided expert testimony in cases concerning loss of income lting from wrongful death, injury, or employment discrimination . Reading has recendy completed a public interest water rights transfer case. He also just completed an economic impact analysis of dre of the proposed Boulder Clouds National Monument. Exhibit No. 201 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 2 Energizing ldaho", Idaho Issues Online, Boise Sate University, Fall 2006-D-----O ---'-----./' - --'.boisestate.edu/tustory/issuesonline/ fal2006 issues/index.htrnl Economic Impact of the 2001 Salmon Season In ldaho, Idaho Fish Wildlife Foundation, April 2003. Economic Impact of a Restored Salmon Fishery in Idaho, Idaho Fish Wildlife Foundation, Apd, 1999. Economic Impact of Steelhead Fishing and the Return of Salmon ishing in Idaho, Idaho Fish and Wildlife Foundation, September, 1997. Savings from Nuclear Resources Reform: An Econometric Model with E. Ray Canterbery and BenJohnson) SoatberuEtvnomicJounal,Spn t996. Visitor Analysis for a Birds of Prey Pub[c Attraction, Peregrine Fund, nc., Novembet, 1988. nvestigation of a Capialization Rate for Idaho Hydroelectric Projects, ho State Tax Commission,June, 1988. Post-PURPA Views," In Proceedings of the NARUC Biennial Regula ,1983. n Input-Output Analysis of the Impact ftom Proposed Mining in the Area (with R. Davies). Public Policy Research Center, Idaho State niversity, February 1 980. and Soilheast: A Socio Earomic Analtis (with J. Eyre, et al). Research Institute of Idaho State University and the st Idaho Council of Governments, August 1975. 'matirgGeneralFurd Reaenuw of the State of ldabo (with S. Ghazanfar andD ley). Center for Business and Econornic Research, Boise State niversity, June 1975. A Note on the Distribution of Federal Expenditures: An Interstate omparison, 1.933-1939 and 1967-7965." InThe Arueian Ennonist, ol. XVIIL No. 2 (Fall 197a), pp. 125-128. New Deal Acnvity and the States, 1933-7939." In Joumal of Etvnomic istoty,Yol. X)OilII, December 1973, pp. 792-810. Exhibit No. 201 Case Nos. IPC-E- l5-01, AVU-E- l5-01, PAC-E- 15-03 D. Reading, Simplot/Clearwater Page 3 BEFORE TFM TDAHO PUBLIC UTILITIES COMMISSION CASE NOS. IPC.E.15.OI, AVU.E.I5-01, PAC.E.15.O3 J.R. SIMPLOT COMPANY AND CLEARWATER PAPER CORPORATION READING, DI TESTIMONY EXHIBITNO.2O2 Oawek/e,rbf $ 292.304 Rates iurr purclrases., l8 C.F'"R. $ 1,1:,2.3[t4 Code of Federal Regulations Title 18. Conservation of Power and Water Resources Chapter I. Federal Energy Regulatory Commission, Department of Energy Subchapter K. Regulations Under the Public Utility Regulatory Policies Act of 1978 Paft 292. Regulations Under Sections zor and zro of the Fublic Utility Regulatory Policies Act of rgZS with Regard to Small Power Production and Cogeneration. (Refs &Annos) Subpart C. Arrangements Between Electric Utilities and Qualifring Cogeneration and Small Power Production Facilities Under Section zro of the Public Utillty Regulatory Policies Act of rgZ8 (Refs &Annos) 18 C.F.R. S zgz.3o4 9 zgz.go4 Rates for purchases. Currentness (a) Rates for purchases. ( I ) Rates for purchases shall: (i) Bejust and reasonable to the electric consumer ofthe electric utility and in the public interest; and (ii) Not discriminate against quali$ing cogeneration and small power production facilities. (2) Nothing in this subpart requires any electric utility to pay more than the avoided costs for purchases. (b) Relationship to avoided costs. ( I ) For purposes ofthis paragraph, "new capacity" means any purchase from capacity ofa qualifuing facility, construction of which was commenced on or after November 9, 1978. (2) Subject to paragraph (b)(3) ofthis section, a rate for purchases satisfies the requirements ofparagraph (a) ofthis section ifthe rate equals the avoided costs determined after consideration ofthe facton set forth in paragraph (e) ofthis section (3) A rate for purchases (other than from new capacity) may be less than the avoided cost ifthe State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or the nonregulated electric utility determines that a lower rate is consistent with paragraph (a) of this section, and is sufTicient to encourage cogeneration and small power production. (4) Rates for purchases from new capacity shall be in accordance with paragraph (bX2) of this section, regardless of whether the electric utility making such purchases is simultaneously making sales to the qualifying facility. Exhibit No. 202 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Read ing, S i mplot/Clearwater Page I iVesttaw[',lert $i ?92.Jd4 F{.lies i'orr pur'chasr+s., il$ Cj.lF"fil. $ 2\);2..lt:i4 (5) In the case in which the rates for purchases are based upon estimates ofavoided costs over the specific term ofthe contract or other legally enforceable obligation, the rates for such purchases do not violate this subpart ifthe rates for such purchases differ from avoided costs at the time of delivery. (c) Standard rates for purchases. ( I ) There shall be put into effect (with respect to each electric utility) standard rates for purchases from qualifring facilities with a design capacity of 100 kilowatts or less. (2) There may be put into effect standard rates for purchases from qualifying facilities with a design capacity of more than 100 kilowatts. (3) The standard rates for purchases under this paragraph: (i) Shall be consistent with paragraphs (a) and (e) ofthis section; and (ii) May differentiate among qualifying facilities using various technologies on the basis of the supply characteristics of the different technologi es. (d) Purchases "as available" or pursuant to a legally enforceable obligation. Each qualifring facility shall have the option either: (l) To provide energy as the qualiffing facility determines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the purchasing utility's avoided costs calculated at the time of delivery; or (2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery ofenergy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the qualifuing facility exercised prior to the beginning of the specified term, be based on either: (i) The avoided costs calculated at the time of delivery; or (ii) The avoided costs calculated at the time the obligation is incurred. (e) Factors affecting rates for purchases. [n determining avoided costs, the following factors shall, to the extent practicable, be taken into account: (l ) The data provided pursuant to $ 292.302(b), (c), or (d), including State review ofany such data; Exhibit No. 202 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 2 'vn/est Iayv[.^ler t $ 292.304 [lates for purc['las+s., l8 t].*:.R. $ f9:2.3{i4 (2) The availability ofcapacity or energy from a qualifying facility during the system daily and seasonal peak periods, including: (i) The ability of the utility to dispatch the qualifuing facility; (ii) The expected or demonstrated reliability of the qualifying facility; (iii) The terms of any contract or other legally enforceable obligation, including the duration of the obligation, termination notice requirement and sanctions for non-compliance; (iv) The extent to which scheduled outages of the quali$ing facility can be usefully coordinated with scheduled outages of the utility's facilities; (v) The usefulness of energy and capacity supplied from a qualifring facility during system emergencies, including its ability to separate its load from its generation; (vi) The individual and aggregate value of energy and capacity from qualif,ing facilities on the electric utility's system;and (vii) The smaller capacity increments and the shorter lead times available with additions of capacity from qualifying facilities; and (3) The relationship of the availability of energy or capacity from the qualifting facility as derived in paragraph (e)(2) of this section, to the ability ofthe electric utility to avoid costs, including the deferral ofcapacity additions and the reduction offossil fuel use; and (4) The costs or savings resulting from variations in line losses from those that would have existed in the absence of purchases from a qualifring facility, if the purchasing electric utility generated an equivalent amount of energy itself or purchased an equivalent amount ofelectric energy or capacity. (0 Periods during which purchases not required. (l) Any electric utility which gives notice pursuant to paragraph (0(2) of this section will not be required to purchase electric energy or capacity during any period during which, due to operational circumstances, purchases from qualifting facilities will result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount ofenergy itself. (2) Any electric utility seeking to invoke paragraph (0(l) of this section must noti$, in accordance with applicable State law or regulation, each affected qualifoing facility in time for the qualifuing facility to cease the delivery of energy or capacity to the electric utility. Exhibit No. 202 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 3 !^/estiawFJert $ 292.304 Rates ior punchases", {E C.F.fR. $ 292.30r!. (3) Any electric utility which fails to comply with the provisions of paragraph (0(2) of this section will be required to pay the same rate for such purchase ofenergy or capacity as would be required had the period described in paragraph (f) (l) ofthis section not occurred. (4) A claim by an electric utility that such a period has occurred or will occur is subject to such verification by its State regulatory authority as the State regulatory authority determines necessary or appropriate, either before or after the occurTence. SOURCE: 44 FR 65746, Nov. 15, 1979;45 PR 12234, Feb. 25, 1980; 50 FR 40358, Oct. 3, 1985; 52 FR 5280, Feb. 20, 1987; 52FR28467, July 30, 1987;53 FR 15381, April29,l988;53 FR.27002, July 18, 1988;53 FR.40724, Oct. 18, 1988;57 FR 2l734,May 22, 1992;60 FR 4856, Jan.25, 1995, unless otherwise noted. AUTHORITY: l6 U.S.C. 791a-825r,2601J,645;31 U.S.C. 9701;42 U.S.C. 7l0l-7352.; Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601 et seq., Energy Supply and Environmental Coordination Act, l5 U.S.C. 791 et seq. Federal Power Act, l6 U.S.C. 792 et seq., Departrnent of Energy Organization Act,42 U.S.C. 7l0l et seq., E.O. 12009, 42 FR 46267. Notes of Decisions (120) Current through April 9, 2015; 80 FR 19036 lt nl, {}, t}t!t{ rnrtlll Exhibit No. 202 Case Nos. IPC-E- l5-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 4 West[+;vlrle:{t BEFORE TFM IDAHO PUBLIC UTILITIES COMMTSSION CASE NOS. IPC.E-15.01, AVU.E.I 5-01, PAC.E.I 5-03 J.R. SIMPLOT COMPANY AND CLEARWATER PAPER CORPORATION READING, DI TESTIMONY EXHIBITNO.2O3 ehuctural failure of the airframe, acctimplish a comprehensive inspection of all areas Eodified bynre Raisbeck Group. as follorvsr A. Befoie further flight, lncpect for devlatious ftom the supplemental type design in accordance with Paragraphe I lhrcughIV. and VJ, ofFAA approvedRaisbeck Sepice Bulletin No.25. Inspect for discrepancies such "i.tluggedhot", 2. Obloug, eggshaped, overslzed, or irregular holes 3. Tapered holes 4, Excers holes 5. Inadequate edge distances B. Gougee 7. Improper fastenes (lype and number) 8. Imlroper clearaacea 9. Any other lrregularities whlch arc not conglstent wlth etanilsxl aircraft practicc E. Be[oE accunriladon of 4000 fligftthours time-ln geMce after modification by StrC $A087NW lnepect the hortontal slabillzer and elevator ln accordance witL Paragraphs V(A) and V[Bl of FAAapproveilRaisbeck $ervice Bullefin No.25. Repeat lhis iospectioo at lntewalo not 6l6ssrling 5,0(l flight boun tlme.ln aervlce thereaflen C, Before accunulation of2,000 llighthours lime.in eerrice afterrnodiliealion by SIC 9A087NW or STG SAt47NW. inepec,t ihe wlng leadlng'bdge inhccordance with Parograph V(D) of FAA approveil Raisbeck $ervice Sullelin No. 25. Repeat thlq lnepeclion at intervale nol gx6gsdiqg S,uro lllg[thours tlme-ln-rendoe thereafter.a, Eefore accumulatioo oIlOlXt0 flieht' e lime-ln 8eflicd after modilication by ..j SA087NW or STC SA8{7NW, inspect the ovenvlng morliEcation in accordance irith Paragraph V(Q of FAA apprwed Raiabeck Scn'ice Bulletin No. 2& Repeat thls labpection at lnteruala not exceeditrg 1Q000 flight hours lime-in-sendce thercaft en E. [nepectlono are to be conducled at facilitiee apecifi cdly a'uthorized by the Chief, Engineerlng anrl Mauufacturing Branch. FAA NorlhrvestRegion.'F. Diacrepanciea dlscovered as a result of lhe inspections are to bereported to the Ghicf, Engineering anil Manufacturing Branch, PAANorthrvest Region. Repalr or modificallons requlred besauge of these probleme are toSe FAA approvrid by &e. Chief, Bngineering aud l\lanufacturing Branch, PAA. Northwest Region or specilically authorized DERs. G..Afulanee maybe feuied; in accorilaace ruith FAR ?1.199, to a maintenancebaee, for the purpose of complylng wilh thls AD. H. The lnspections not€d herehnay be accomplished as notedl or in a manner approved by the Chtef, Englneering 6nd Manulacturing Brauch, FAA, Norlhrvest Region. L Areae previously lnspected io. accordunce rvith Amendmeut 39-3680may be excluded from lhe inspections required bl this AD. The manufaoturet'e specifications and procedurea ldentlfieil anil describeil in this dlroctive are lncorporated herein and made a ^qrt hereof pumuant to 5 U.S.C.552(81(1), ll peraone allected by lhls direclive who e not already recelved lhese documents. &om the sranufacturer. may obtain copies upon Equest to ltre Raisbecl< Gtotp,Tilil1 Perimeter Road, Seattle, Washington 9810&. Thls amendment becomes elfective upon publlcatiori in the Federal Regirter atrd rvas elfective earlier to all recipients ofthe telegraphic AII TB(FNW-Z dated lanuary 17. 198r'. [Se6, A3(1), 60r, and 603, Federal Aviation Act of 1958, as ameniled Po U.S.C 138r({, 1{zC, anA lltil3) and Section 6(c) of lhe. Department of Traneportation dct Fg U.S.C 1055(cD; and 14 CFR 11.89) Note-Ite FAAbac determlned that lbis document involver I regulafotr which ts nol consldered to be slgnificant under the provisions ofBrecutlve Order 12044 and as implemented by DepartneDt of ftansportattoa.Regulato$, Polioies-aad hocedurea (r!{ FR 11034: February 26, 1979). ksued ln Seattla Washington, on Febnrary 13,1S80. Nota-Ilhe incorpolation by reference pmvisions lo the doctmeat were approvetl by &e Dhactor of the Federal Register ou fune19,1967. C.B.Wdhfr. Dircctor, Northwes t Region. lttr Ih& 80{038 f lled 2-ar€G e$ @l B[.L'ltc coDE a9t0-13-t 12214 Federal Regieter / Vol. 45, No. 38 / Monday, February 25, 1980 /.Rules and Regulations Representatlve, 1800 G Street, NW., lVishlngton, D.C. 20506. (202) 395-3402, Accordingly, esch reference t0 "lhe Olfice of lh'e Speclal Representallve for Trade NemHations" contslnod wlthln Chapter *( of Title 15 of the Code of Federal Regulallone, includlng tho heading, is changed lo "lhe Ofllco of tho UnitedBtates Trade Representatlvo".' Bachreference to "the Spoclol Representative Ior Trade Neeotlatlons" coitained rvtthln the chapter-ls chungod to "the Unlted $tates Trhde Representative". Eoch referencc to lho "special Representative" and to tho "Deputy Special Representallve" lg changed to the'llrade Representutivo" and to lhe "Deputy Trade Representative" reepectively. Robert G Cassidy. CenemlCounsel. lFn Doa 8o.StO5 Fllcd 2-024 &CS anl BlruNG ooDE 3teo{Ln OFFICE iFTHE UNITED STATES TBADE BEPBESEI{TATIVE ISCFB ChapterXX GFF GhapterHeading and Nomenclature Change Febmary 19,198{r. AGEr{cY: OfEce of the United States Trad.e Representative, AsaON:Einalrula DEPARTi,IENTOF ENERGY Federal Energy Begulaiory Gommlsslon 18 CFR Partzgz lDocket t{o. Rlr79-55, Ordcr No.69) Small Power Productlon and Gogeneratlon Facllltle$ Regulallono lmplementlng Sectlon 210 ot tho Publlo Utility Regulatory Pollclee.Act of 1978 AGENcY: federal Energy Rogulatory Commission.Asno[:Finalmle. -- __ suMtfAnn The Federal Energy Regulatory Commission heroby adopte regulauons that lmplement sectlon 210 of the PublicUtility Regulatory Pollclos Act of 1978 (Pt RPA). The nrloe requlru electric utllities to purchase eleclrlc power from anil eell eleclric polver lo qualifying coSeneratlon ond smallBorvur production facilities, and provide for tho qxemption of qualifylrU facllitles from dertain federal and State regulatlon. Implementation of these rules ls reserved lo Stale regulatory authorltleu and nonregulated eloctric utilities. EFrEcrtvE DATE: March 2O 1080. FOB FUBTHER lNFORtrlAIlOll GOiITACT: Ross Aln, OIfice of lhe Genoral Counsol, Federal Energy Regulatory Commlsslon, 825 North Capitol Streol, N.E., Waoblngton, D.C. ANzB,20a{87+fc5, lohn O'Sullivan, OIIice of lho General Counsel, Federol Energr Regutotory Commlsslon,825 North Cupltol Slrool. N.E.. Wa shing ton, D. C. ?.Cd;28, 202-35l-847 7, Adam Wennen Oflice oI tho Gonual Counsol Federal Encrgy Regululory Gommission, SzS North Capttol Strool, N.E,, Washington, D.C, 2C{.28, 202-957-{t030. SU;uAny: ltis rule changes Chapter )C( ofTitle 15, Code ofFederal Regulalions, from "Oftce of the Special Representative for Trade Negotiations" to "Of{ice of ihe United States Trade Representative." Withinthe body of the Chapter )O(, all references to the "Office of the Special Representative for Trade Negotiations", to lhe "Special Representative for Trade Negoliafi one", anil to the "Special Representatve" or "Deputy Special Representative" are 6finlged to tte "Olfice of the United States Trade Representdtive'1 to "the United States tade Representatlve", and the "Trade Represenlative" or' "Deputy Trade Representative" respeatively. These chenges are authorized as part of Reorganization Plan No. 3 of1979 (44 ER 09273) rvhich was inplemeuted by Executive Order No. 12188 of lanuary 2, 1980 [45 fR 989). EFFECTTVE DATe February 25, 1980. FOR FUB?HEB INFORIIATIO}I COIITACI: Alice Zalik, General Council's Office, Office of the United States Trade Exhibit No. 203 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater HeinOnline -- 45 Fed. Reg. 12214 1980 Page I u224FederalReglsterlvol,45'No.aa/ivIonday,Febnrary.25,1980/3uleeqn@ Many connenterg at the Commission'g public heaings andin urttten comments recomnended ttrat the Commission ehould require the eatablishment of 'het energy bifllng!: for small qualifuing facilitiee. Uniler this bllling meiho4 the outputfrom a - qualifying facility reverees the elechic meter useal to measurg sales ftomthe electric utility to the gualifying facility.lte CrortrEission believes that this btlling methodmay be an appropriate way of approdmatingtvoided cost in gome circumetiance8, but doec not believe that this is the onlypractical or appropriate method to eatablish rates for small quallfylng facilitles. Ite Commlselon obsepes that net energy btlling is likely to be appropriate when the rctail rates are narginal coet-baee4 tlme-ofday rates. Accordingly, the Conrmission will leave to ttre State regulatory authorides and the nonregulated elecbic u[litiea the determination as to whether to inetitute net energybilling. Paragraph (c)(sl(t) proviiles ihst etandard reteg for pn$hase shouliltake lnto account the factore set forth ia paragraph (e). ltrese factorg relate to tte quality of powerfromthe qualifying facilis, anditc ability to fit into the purchasing utilttyle generating mix Paragraph [el(vi) ia ofparticular elgniftcance for faciliEea of 100kW or lesa. Thie paragraph providee that rates forpurohaie ahall take into account "the lndlvtdual and aggregate value ofenerry and capacity from qualifying facillties on the electsic uttltt3/s syoten. . .". Several commenters presentetl pereuasive evidence ehowing that an effective amount of capacity may be provtde{ by dieperaetl emall aystems, even in the case where delivery of energy from any parHcular facility iB etochastic. Similarly, qualifying facilitiea'may be able to enter into op€rating agreements with each other by which they are able to inc,rease the aaeureil availability of capacity to tbe utility !y coordlnating scheduled maintenance and providirrg mutual back-up aervice. To the extent that thle aSgregate capacity value can be reasonably estmale4 it must be rellected in standsrd rates for purchaees. Several commenters obsen ed that the patterns of availability of perticular '- energy Bources can and ehould be reflected in atandard ratee. An example of thls phenomenon is the availability of wind and photovoltaic energy on a eummer peaking system. If it can be shown that syatem peak occurg when there is bright eun and no wind, ratee for purchase could provide a higher capacity.payment for photovoltaic cells thanfor wlnd eiergl conversion systems. For eyetems peaHng on dark wiudy days, the reverse right be hue. Subparagraph (3)(ii) thus pmvides lhat gtandard rates lor pumhases may difrerendate anong qualifyirS facillties on the basie oflhe supply oharacteristics of the particulu technolory. Sg 828a @)$) and (d) Icsally enforcable obligpti ons. Paragrdphs (bJ(sl and [d) are intended to reconcile therequirement that lhe rates for purchasee equal tte utilitles' avoided iost wi& the neeilfor quali&tugfadlldee to be able to entet lnto contraetud commihe.nts based, by necessity, onegtimates of future avoided costs. Some of the comments received regardi4g tbig section slated lhat ilthe avoided coet of energy at the rime it ia supplieil is leas thal theprice provided in ihe coubact or obligation, tha purchaeing udlity would be requlred to pay a ratafor purchaaee that would subgidize the guali$ingfacility at the e:rpenee of the utilig/a other ratepayer*lte Coumission recognizeo lbia possibility, butls cognizaat thatln other case8, the required rate will turn out to be lower lhanthe avoided cost at the time of purchase.Ite Gomnlselon does notbelievethat the refenence in thr statute to the lneemental cost of alteraafive eneqgy wac intended to require a minute-by-minute evaluation of cost8 which would be checked againstrates established in long tero conhscts between qudi$ng facilides and elechtc uHlities. lvlany comminters have atresaed the need for certaintywithregard to return on inveshent ia new technologiea. The Commiaslon agrees with these latter argummts, anii believeg that, in the'long run, "overegfimations" and "underegtlEaHons" of avoided costg will balance out. Paragraph (bJ(5) adikcsses the eihration inwhich a qualifyilg facility has enteredinto a conhact-wiih an electric utility, or where the gualifyfu facility has agreed to obligate ltself to deliverat a futnre date energy apd capacity to the elecEic utility.lhe import of tbis section is to easure that a qualiffrng facility which has obtained the certainty of an arrangement ls not depriyed of the benefits ofits commihent as a result of changed circumstances. ltis provision can also work to preserve the bargain entered into by the electric utility; ehould the actual avolded cost be highep than those- conbactGd for, the elechic utility is nevertheless entitled to retain the begilit ofits contracteil fon or otherwise legally enforceable, Iower price for purchases from the quallfylng-facility. fhia eubparagraph wlll &us ensure the certalnty ofralea for purchaseo from a quallfylng faclllty whlch enters lnto a commltmontto deliver eueryy or capaclty lo a utlllty. ParaeEapli(d)(1) plovldee lhat a quslifyfu facility may provlda oneryy or caoacitv on an "ab avallablg" boslg.1.0., withoufleeal obligation. Ihe proposod nrle nrovided lhat rates for euch ourchases should be based on "actuol"ivoided costs. Msny comments notsd thatbaging ratea foipurchases ln such cagos on tf,E utlllty'si'aclual avoldsd coets" ls'mlsleading and could requlro rehoactive ratemalilng. ln XSht of thoso Gomnenls, the Comnlsalon hag revlsed the rule to provide lhat lhe rateg for ourchasea are to be baoed on the'pruchaefu utilitfa avoided coab ietimatedit the timo of deltvery.r' Paragraph (d)tz) pErmlts a qualttyfng ' facilitv to anter inlo a conlraot or olhor legali enforceable otligatloh to provldo enirgy or capacig over a epedlled term. Uae ollhe term'lqally enlorceable obligalion" is lntended to frevenl a utility hom clrcnmventlng the requlrement that provldea capaclty crerlit for an ellgible quallfylng faclllty merely fur refuring to enter lnto a conhact -with the qualifying faclllty. Many commenteru noteil lhe aume problems for eatabliohlng ratsr for purc'hases under eubparagraph (zl ao ln eubparagraph (1). lhe Comrnlsslon trtenals ihai rates fot pruahaaes be based, al the option of the quallfying facllity, on either ths avolded costs ut the dme of delivery or the avolded costs calsulatedat the time the obllgatlon ls inmrred" Thlg chame enables a qualifylng fadlity to- eotablleh a llxed contractprice for ite energy and capacltyit the oulset of llo obllgatlon or to recefve the avolded costo dstemlned at the tlme of delivery. A facttity whtch edters lnto o long term conhact to provide €nsr8Y or capacity lo a utility may wlah to recolvo a greater peruentage of the total purchage-prlce durlng lhe beglnnlng of ihe obligaiion. For example, a lgvel payment schedule fmm the utillty to lho qualifying facility may be useal lo motch more closety the achealule of debt service of the facilitn So long ae the total payment over the duratlon of tho contract term does not exceed tho eslimEted avoided costs, nothlng ln these nrles would prohlblt a State regulatory authorlty or non-regulated eleotric utility tom approving auch un anangemen[. Case Nos. IIn addlllon lo lhe avoldod corls ofonorgy, lhuso costs muet lncluds lho proralod ohoro of lho aggregate capaclty valuo of such fucllllles. Exhibit No. 203 [PC-E- l5-0r, AVU-E-l 5-01, PAC-E-l 5-03 D. Reading, Simplot/Clearwater HeinOnline - 45 Fed. Reg.12224 1980 Page 2 Federal Register / Vol. 45, No. 38 / Monday, February e5, 1980 / Rules and Regulations 12225 9, W2.il4(c) Faetarc olfecting mtes fur\rchases. apacity Value An issue basic to thls paragraph is the question ofrecogpition of the capacity value of qualifying ficilities. In ihe proposed rule, the Gomnission adopted the argumeut set forth in the StafrDlscussion Paper that the proper interpretation of section A0(b) ot PUBPA requireg that the rates for pruchases indude recognition of the capacity value provided by quah$ing cggeaeration and suall power production facilitiea. The Commiesion aoted that language used in section 210 ofPtIRPA and the Confeence Reporl as rvell as ia the FederalPowerAct supports this propoeiEon ln &e poposed nrle, lhe Counissiou cited the firal paragraph of tbe Confrrcnce Report with r:gard to section210of Pt RPA lteconfereec e:qect that tbe Comtrisriort in iudgiDg whether tie elechicporar supplied by the cogenerator orirmdl polvcr pmdum will replae futuc pouer rhich the utility worid-otherwtse have to geocate itselfeither through existing capacitlr or adrlitions lo capacigl or puichaic fmm other sorces. will take iato aocount the rcllability of the porver nppliedby the oqcneutor or small power pmduoer by rcarou of ray lqgrly edorc€able obligation of ru&'rgenerator or sodl power pmduoer io rply tru power to lhe utility.rt In additioa to that citation the Commission notes that lhe Conferesce Repmt states that: I! btarpretiog lhe term "lncrulneatd orlr of altemetire euergl". the cqfcrecloqrocl tbat the Conoirsion and tbe Steter uey lool beyoad lhc coats of dtemativc rourccr which are instantaaeorsly arnilable to ihe utilily.to Several ootnmenters conteoded thal. since section210(a)(2) of Pt RPA provides that elechic utilities must 'purchase elechic euergr" hom qudifuing facilities, the rate forsuch purchaser should not include pa3ments for capacit5l. lte Gommission obeerues that the rtatutory language used in the Federal PowerAct uses ihe term "electric enerXpf'to describe lhe rates for sales for resale in interetate commerce. Demand or capaci$r palmeEts are a baditional part of such rates. lte tersr "electric enerry" is used tbmughout ihe Act to refer both to electric energ3r and capacity.The Comnission does not fin{any evidence that the tern "electric eneigy'in section 210 of PURPA was intendeii to rcfer only to fuel and operating ancl maintenance rsConleence Rcport on Ht- aota, Pulilic Utilitl Regulatory Policias Act of19lB. H. Rcp. !io. 1750.9&,- tth Cong; 2rL Scra 0970! 'Id- pp.9a.& expenies. inatead of all of lhe cosls associateal wifi the pmsision of eleclric seNice. In additiour. &e Commisrion noles lhat to interprct thir phrare to include only energy would leed to lhe conclusion that the rates for raleB ,o qualfylng facilitiee could only lnclude the energl componcnl of the rate since section ?10 dm refep to "electric energy" with rcgard to ruch rdes.Il is .the Gonnisrion'r belief Orat lhir was not the inteoded rcrull ltir pmvider an additional reeron to interyrel &e phrare "elechic encrry" lo include both enerXy andcapacity. In inphmenting thir atatutory standard. il ir belpful to rcview induslrS practice respecting ealer between utilitiea. Seler of eleclric power art ordinarily clarrilied er eilhrr firo rales. where ihe reller provider powcr at the customer's rtqucll ornon-Iinr power salea wherc lhe reller and not the buyer makce thc decirion whcther ornot power ir !o bc ayailebla Rater for lirrr porterpurcharer includc paymenlr for the cost of fuel and opcntilg expeile& andalro for lhe ixeil coatr drrocieted with the mnrlruclion of generatirg units needcd to providc poweral the purchararb dircrction. The degree of certainty of delivcrabilily required to conslitute "Sm power" can ordinarily bG obtsind only if a utility har reveral generating unib and adequsle reren'e capacity.Itre capacity paymenl or demand charye, will rellect the cort of lhe uHlity'r gcmreting unib. trn conharl tbc ability to pmyide electric power s1 &s 3gllilg utilityt discretion inporer no reguirement lhat the reller conrtrucl or retenre capacig In order topovide power to ortoners at the reller'r dircrctlou. lhe mlliqg ufility need only c,hargc for lhe corl o[ operatiqg ilr geoerating unib and adminishatlon lteee cortr, cellcd "etrerry" cDrtr, ordlnrrily ere lhe ones arsociaied withnon-firn mles of oon'er. Purtheaer of power fium qualifiing facilitiee will fall romewherc on the continuum bctwecn there two tlger of elecbic rrrice.Ihur. for cxample. wind machiner that fumiah power onty when wind velocily excaedr twelse miler per hour may bc ro uncertain in availebility of outpul that lhey would only pcrmit a utility to avoid generaling an equivalent amount of enerEy. In lh8t rituatioa the utility murt cpnlinue to pmuide capacity that is available to meet the needr of itr customere. Since lherc are no arolded capacity corts. ratel for such spondic purchases should thua be bascd on the utility slT tems avoided lncrcmental corl ofenergy. On lhe otherhand. testimony at the Gommisdon'a public hearings indicated that effective amounls of lirn capacity exist for dispersed wind ryslems, erren though eoch machine. Gontidercd separately, could not pmvide cepacity value. Ite sglfregate cepacityvalue of such facilities must be considered in lhe calculatiou of rates forpuchases, and thc paprent dirtrlbuted to lhe class providins lhe c8pacity.- Some lechnol4ier,ruchas pholovoltric cdb. dthoug! subject to come uncertainty in power ou[ut, hate the gcoerel rdsaotege of pmvidiqg their maximun power coincident rt'ith lhe syrlem pcakwb€n uaed ou a sunner pcakiqg syrten ltrcvalue of euc,h power ir greater to lbe utili$ thaa poner delivcrcd druing oE-peek pcriods. Since lhc need forcapacigis based, in parl oa rysleu peakr.the gudifyiqg facility'r colncideuce with the rystempeak should be retlected in the allowence of rona capacilr value aad sn cnEgf oonponcat thetr:Ilects the auoiiled eDcrgi coolr at 1f,9 rimg sf lhgperk A facility buaiqg municipal waete or biomars mry bc eble to operale Eore predictrtily end rtlieHy than solar or wind ryrlcuall crrr rchedule ils oulaSe! duri4 tinee when dcnand on thc utility'r ryaten ir low.If soch a unit demonrlntar r dcgrce of reliability that would pcrurit thc utility to defer or avoid courtruclion of e geaenftg unit or the purchare of fira Doweshou aDotber utilily, thcn tha ratc for rucL a puchase should bc brrcd on tbc avoidauce of both energl end cepacig cocts. In order to defer or cancel ihe construclion of uew gercratrln8 uEill, s utiliiymucl obteia a coooibcntfrom a qualifying facility that pmrlihe conlnctul or othcr legrlly euforceable aEluranoea tblt cepacity fron altemalivc rourcer wlll be arailable sulliclently rhced of the date on wbich the utility wurld oihcnyire hare to commititgelf lo thc construction on purctale of ncw capacity.If a guali$iog facility proviilcr ruch essrnaaces, it is entitled to rcceire rates based on tie capecity cocls that the utility can aroid as a result of its obtaining capacityfiom lhe qualify{ug facilig. Other couneutt with regard to the requbemcnt lo includc capacity palmenE ln aroidld costs generally traclt lhoea ret forth in the Staff Discuisim Bspcr and the pmposed mle. Ttre lhnut of thcrc conroents is lhaL in order lo recciue credit for capacity and to comply with the requirement ttrat rates for purr.hases not exceed tbe incmnental cost of altemative euergy, cspacity paluents can only be required nhen tha evaitability of capacity fron a qualifying facility or facilities actuallypemils the purchtsing utility to reduce Exhibit No. 203 Case Nos. IPC-E- l5-01, AVU-E- 15-01, PAC-E- l5-03 D. Reading, Simplot/Clearwater HeinOnline -- 45 Fed. Reg. 12225 1980 Page 3 12226.. Foderal Register / Yol. 45, No. 38 / Monday, February 25, 1980 / Rdes and Regulationi Its need to provide capacity by defering the constrdction ofnew plant or commitments to Iirm power purchase conlracts. In the prcposednrle, ttre Commlseion gtated that if a qualifying facllity olfers energy of sufficient reliability and with sufficient legally enforceable guaranteee of deliverability to permit the purchaeing elechic utility to avold the need to congtruct a generatlng plant, to'enable it to build a smallen lese expeneive plant, or to purchase less fim power hom another utility'than lt would otherwise have. purchaaed, then lhe rateg for purchaeps from lhe qualifytng facility muat include ' the avolded capacitSr anrl energy coets. discussion, the Commiseion continues to belleve that theaE principlec are valld and appropriate, and lhat they properly fulffll the mandate of the statute.the Commlsglon dso continues to believe, ag etated ln the proposed rule, that thic nrlemaktng repregente an effort to evolve concepts in a newly developlng area within certain etatutory conslraints. the Commisglon recognizee that the baniladon of the principle of avolded oapadty costa from theory into practice ls an exberrely dlfficult exercise, and is one which, by deflnltion, la based on estimatlon and forecaattng of fu ture occnrrences. Accordingly, the Commission aupports lhe recommendaHon made in the Staff Dtacusslon Paperthat it ehould leave to the States and nonregulated udlitieg "Ilexlbility for experimentation and accorrunodatlon of apecial circumstancer" with regard to lmplemantation of ratee for purchaeea. Therefore. to the extent that a method of cdculating the value of capacitytom quallfylng facllitlee reasonably accountq for the utility's avoided coste, and does notfail to provtde the required encouragcment of cogeneratiop and emall power production, it will be consldered as satiefactorily lmplementlng the Commiegion'e rules. 8 Nz,gM(e) Factots offecting mtes forpurehoses. As noted.prevlously. several commenters obsewed that ihe ulility system ooet data requlred under $ 292.302 cannot be direc0y applied to ratea for purchage. The Commission acknowledgee thie point and, es dlscuseed previously. has pmvided that theee data are to be used ae a starting point-for the calculation of an appropriate rate for purchaees equal to the utility'a avoided cost. Accordingly, the Commission has removed lhe reference to the utility system cost datq from the definition ofrates for' purchases, and haE ingerted the reference to these data in paragraph (e), ag one factor to be considered in calculating rates for purrhases. Subparagraph [r) states that 0rese data ehall, to the extent practicabls, be taken into account in the calculation of a rate for purchases Subparagraph (2) deals with the availability of capacity from a qualifying facility durlng eystem daily and seasonal peak periods. If a qualifying facility can provide energy to a uttltty druing peak periods when the electric utility ie nuuring its most expensive generating units, this energy has a highervalue to the utility than energy supplied during off-peak perlode, during which only units with lower runnlng costs are oueratine. the prenhble to-thg proposed rule provided that, to the extent that metering equipment is available, the State regulatoryauthorigr or nonregulated electric uUlitlr ehould take into account the time or aeason in which the purchare from the quslt&lry facility oocurs. SEveral comnrenters lnterpreted this etatement ae implying that by reirsfurg to install metering aquiilment, an elechic utility oould avoid the obligation to conslder lhe dme at vihich purchases occur.'lhis is not lhe intent of thir provision. Clearly, the more precieely the timeof purthace is recorded lhe more oract the calculation ofthe avoidid coits, and thus the rate ' for purchaees, can be. Rsther than'specifuing that exact ti-e-ofday or seaeond rateg for purchasee are required, horvever,' lhe Commieelon believes that the selection ofa methodology ie best left to the State reguletory authorities 8nd nouegulateil electric utilifies charged wtth the implementation of these provlsione. Clauses{iJ throueh [v) conceru varioue aspeots of the reliabtlity of aqualifufu facility. When an electric utility provides power from ite'own generating uirits orfiom lhose of another electric ufility, lt normdly controlsthe producffon of such power from a cenhal location the ability to so control power production enhances autility'e ability to respondlo chsnges in demand, and thereby enhances the value ofthat power to $e utility. A quali&tng,facility may be able to enter into an arrangement with the utility which gives the utility the advantage of dispatcblng the facility. By so doing it increases its value to the utility. Convepely. if a utility cannot dispatch a qualifying facilig, that facility may be of less value to the utility. Clause (ii) refers lo the expected or demonstrated reliability of a qualifying facility. A util$ cannot avoid the constuction or pruchase.of capacity if it is likely that lhe qualifylng faclllly whlch rvould claim to replace euch capaclty may go out of eervlco durlng the period when the utlllty needs lte power lo meet system demand. Baaod on the estimated or demonstraled reliabillty ofa quallfylng faclltty, tho rate for purchases from a quollfylng facility should bE adiusted to roflsct ltu value to the utlllty. Oauee (iii) refers to the length of tlmo dnrine whtch the quallfylng fablllly hor conlractually or otherwise guaranlood lhat tt wlll supply energy or copaclty to the elsctfic utlllty. A utlltty-owned Seneratlng unlt normally wlll eupply power forthe life of the plont, or unlll lt is replacedby more efliolent cupacity.ln contrast, a bogeneratton or small porvor productlon unit mtght cease to produoo power aB a result of changes ln the tnduslry or ln the industrlal procosgog utillzed. Accordingly, the valuo of tho senice &om the qualtfyfuU facllity to tho eleotrlc udllty may be affected by tho degree to whlch the qualifylng faolllty eusureg by contract or other tegally enforceable obligatlon that lt wlll continue toprovi-de power. tniludsd ln thls determlnatloft among other factotg, are the term of the commltmonL tho requlrement for uotlce prlor to terminatlon of the commltment, und ony penalty provigione for breaoh of the obllgatlon. In order to provlde capaolty votue to an electrlc utiltty a quallfylng facfily need not necessarily agree to provldo power for the llfe of the planl. A utlllty'e generatlon expansion plans often include purchasea of lirm polver from other utilltles in years lmmedlately precedlng the additlon of a major generation unlt lf a qualifylng taclllty contracts to dellver power, for examplo, for a one year perlod, it may enuble tho pruchaslng utillty to avold enterlng lnto a bulk power purchaae arrangemont with another utility. Ttre rate for such a purchaee ahould thug be based on tho price at whlch such power ls purchaeod, or can be expacted to be purchasod' based upon bona fide offors from ' another utility. Glauee (iv) addresses perlods durlng rvhlch a quali$tng faclllty ls unoblo to provide powen Electrlc utllltlss schodulo maintenance outages for thelr own generating unite during perlode rvhon demand is low.If a qualifylng faolllty can eimllarily achedule lts malntenunco outogeg durlng periods oflow demand, or durihg periods in which a utllity'o own capacity will be adequate to hondlo existing demand, it rvlll ensble ths utility to avold the expenses assoclutod with providing an equlvalent omount of Exhibit No. 203 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, S implot/Clearwater HeinOnline - 45 Fed. Reg. 12226 1980 Page 4 Federal Register I Vot. {5, No. 3& / Monday. February 25. 1980 / Ruler end Rcaulations TnUl capacigr. These savirrgc should bc rf,ected in the rate for purchaees. Clause [v) referr to a qualifying facility's ability and willingpess to proride capacity and energy dtuing syetem euqeuciee. Sectioa 2923(7 of these rqgulatioug concerrrs the prouirion ofelechic sercice druing system emergeucies" Itprovides that, to the extent that a qualifyiry facility is willing to forego ib orm ure of ener8r during syeteu emergeuclee and pmvide power to a utility's syeten. the rate for puchases from the qualifying facility shouldreflect the value of that service. Smdl power production and cogeneration facilities could provide rigpificant back-up capabllily to elechic syrtens duriug euergeucies. One benefit of the encourqgement of interconnected cogeneration and smell powerpmduction may be to increare overall system rcliability during aue.b emergency couilitibus. Auy zuch benefit shouldbe re8ected in tbe rate for pure.hases from such qualising facilities. Another relaterl lactor which afiects the capacifirvalue of a qualifuing facility ir its ability to separate itr load from its generation during system emergencies. Dtuing such emergencies an elecbic utilit5r may institute load 'heddiug proceilures whie;h may, anong hsl rhing& Equir€ that indusbial ..utomera or other large loads stop receiviugpower. As a result to pmvide optimd benefit to a udlity in ar enBrgeusy sibation a qualifyhg faEiUW might be reErircd to continue opLration of Erm power to the elechic uUlitl', the divenity of there facllitier roay tollectircly mmprire lhe equivalent of capacit3t Glause [vli) refcn to the fact that the lead timc euociated with the addition of capaclty ftom qualifylag facillUer may be l*r lhen the lead iime that wouldheYc been required lf tho purchaslng utllity had conotructed itr own gencreting unit Such rcduced lead tine nigbtpoducc ravingr in lhe utitttyl total power producEon corts. by permlttirg utilitler to avoid lhe "lumpitrett " end tcnporery excem capacit5r eroclated therewllb, which nornally occur whcn utilltler bring oo line larye gencralhg unlt!.In eddition. reduced leed tlmc provider Oe utility with grcetar llexibilily with whlch it can accomnodeb dengel ln forecartr of peak ilsmeail Subpamgraph (3) concernr lhe relationahlp of encrgy or capaclly &om aqualiffig facility to &e purcharing elecbic utililSt'r needfor ruch cncrgl or capacity. If rn alactrlc ulilily bar sullicient capedty to ucet ilr demand. and ir notplenniog to add any new capacity lo itr ryrten then lbe availability of capacig Aom qualifying facilitier will not inmediately cnable the ulility !o avoid aly capacity cortr. Howcyer, an electsic utili& ryrlem with exccss capacity nay neveriheless plaa !o atld new. morc etEcient capaclty to its system. If purcharea hom qualifying facilities enrblc a utility to ilefer or avoid lher uewplauned capacity additionr. the rate for ruch purchater should rellcct the avoirled codr of these adiliEonr However. as noted by reyeral commentlrr, &c deferral or avoldmce of such a unit will dro preneut ihe substitution of tbe lower energr costr lhat woulilhave accompanied the new capacity. Ar a rerult thc prico for lhe puchase of energl rnd capacity *orild rellect thcre lowcr avoided ele$y costs that the utiliSr would havc ineurred had the new caprcitybceu added. This ir uot !o ray ihat electric utililies which have excear capacity need nol make purcharer hom qualifying facilities; qudifying facilitia may obtainpalmentbared on lhe avoided energy coric on a purrhasiqg utilily'r r!'rtern. Llany ulility rystemr wi& excesr capacity have intermeiliatc or peaking units n'hlch ure high-cost focsil fuel Ar a resulL druing pealthoura thd energJt costs on lhe ryrtema are higb, and thus the rale lo a qudifying ulility from n'hich the electric utility purchases energy shoulil sinilarly be hieb. Subparagraph ({) addresses lhe costs or savingr resulting fmm line losser. An appropriala rate for purchases from aquali$ing facility should rellecl tho cost trringr eclually ecmring to the electric uUlitv. If enargyproduced &oma quolff iqg ficility undergoes lhe losses cuch thet lha dclivarcd powaris not equivrhnt to thc power that wordil haue bcen ddivgreil&om thc source ofpower it replecca thea &e qudifying facitity should not bc reimbursed for the dilference ln loeses. If &e load senled by the qualifyins facility ir doser to the qualifyiqt frcility lhan it is to lhe utility. it Is polible that thcra may be uet savingr rcrulting fioo reduced lise lorrci. [n ruch c$er. the Etes should be adiusled uprverds. llmlrrlf kriods ttuinsi'hiih purchoseannot rquind. the proporeil nrle provideil that an elcctric utility will not be required to purcherc aacrggr and capacity &om qurlifying fecilitier duiug periodr in wblch rrrch purchaccs will rcsult iEnet Inccased operahhg colts lo the deetsic ulility. Thir reclionwar htended to deal n ih e cartelo colditiou which caa occur during light loailiugperiods Ifa utility opcnting ouly bare load rmils duftu thcra pcriodr were forced. to sul back output&om ihe unilrrin orderto accomnodale purcharer Boro quali&iog facllitlee lhcre bare loaal uDits E ght not be eble to lacreare lheh output levd rapldly wban lhe rysteu. de'n"'il later incraan& Ar e resdll the utility would be nquted to utiliza lers eEdeut higher coat unitr with faster slart-up to meet the demonf thatwouldhavebeen oupplied by the lesr epensive base load unit hud lt bc€tr peraitteil lo opente 8t a constant outpullte rtrult of ruch e hansaction would be that relber lhan avoirliqg cpsts as a rtrult o[ the pumhase &ou a qudi$ilg facilitl', the purc,basing elecldc utility would lncurgreater costs than it would have hed lt not purchased energy or capacity bom the qualifying facilig'. A stricl applicatiou oftbe auoided cost principle ret for& in lhis section would aslcr lhere rddiliond costs as negativa rvoideil coslr which must be reimbnrsed by the qualifyils faAtty.ln order to rvoid thc anomalour rrsult of fotcing a qualifyilg u6lity to pay an electric ulility forpurchasing its outpul the Coramirciou propored ihat an electricutility be required to ideutify periodr during which this situation would occur. rc tbat lhe eudity!trSfacility could ceare ddivery of electricity duriog thore periods. Many o[ the comments nceived retlected r ruapicion ihat electric utillties would abuse lhis paragraph to circumvcnt thcir obligatiou to pruchasr from guatifying facilities. Ia order to minimize that poasibility, the Commission bas rerised this paragraph plaat while simultaneoualy ceasing operation as a load on the utilit5/s system. To the extent that a facilitv is unable to separate its load fiom its geueration, its value to ihe purrhaslng utility decrcases during eystem energencies. To rellect suc.h a possibili[r. clause (v) provides that the prnchasing utiligr may coasider the qualifying facility's abiligr to separate its loail fiom its generation during syatem mergencies in determining ihe value of the qualifying facility to the elecbicutilig. Ctause (vi) refera to the aggregate capability of capacigr hom qudifyins facilities to displace plauned utility capacity. In some instaoces. the rmdl amounts ofcapacity provided fromqualifyfu facilities takm individually might not enable a purc,hasiry utility to deferor avoid scheduled capacity additions. Ite aggrcgate capability of such purchases may, however, be sufficient to permit the defemal or avoidance ofa capacity addition.- {or€wer, rhile an individual qualifying cility may notprovide the equivalent Exhibit No. 203 Case Nos. IPC-E- l5-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater HeinOnline - 45 Fed. Reg. I2227 1980 Page 5 BEFORE TFM IDAHO PUBLIC UTILITIES COMMISSION CASE NOS. IPC.E.I5-01, AVU-E-15-01, PAC.E.I 5.03 J.R. SIMPLOT COMPANY AND CLEARWATER PAPER CORPORATION READING, DI TESTIMONY EXHIBITNO.2O4 Exhibit No._(GND-7CT) Docket UE-I30043 Witness: Gregory N. Duvall BEFORE THE WASHINGTON UTILITIES AIID TRANSPORTATION COMMISSION Docket UE-I30043 PACIFICORP REDACTED REBUTTAL TESTIMONY OF GREGORY N. DUVALL August 212013 Exhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page I WASHTNGTON UTILITIES AND TRANSPORTATION COMMISS ION, v. PACIFICOM d/b/a Pacific Power & Light Company I should consider changes in this case as a part of the post-trial period review of the 2 WCA.r6 3 Q. Did parties accept any of the Company's proposed modilications to the WCA? 4 A. Yes. Staffexplicitly supported the Company's proposal to include the entire ldaho 5 Power PTP transmission contract in the WCA, apparently on the basis that it reduces 6 NPC.I7 While Boise challenged a list of what it characterized as the proposed 7 changes to the WCA and argued generally that changes to the WCA were not 8 reasonable at this juncture, it chose not to remove the change to the ldaho Power PTP 9 contract.ls l0 California and Oregon QF contracts I I a. Does any party support the Company's proposal to include the costs associated l2 with Oregon and California QF contracts in west control area NPC? l3 A. No. Staff, Boise, and Public Counseleach argue against inclusion of California and 14 Oregon QF contracts in west control area NPC.le In one form or another, the parties l5 all assert that allocating west control area QF contracts to Washington inappropriately l6 requires Washinglon customers to pay for QF-related policy choices made by Oregon 17 and California. I 8 a. Are all of the contested QF contracts from renewable resources? 19 A. Yes. The QF contracts are allconnected to renewable resoLlrces located in Oregon 20 and California. Because the QF oontracts do not include renewable energy credits t6 H.,n$9. '' Exhibit No._(DCG- I cr) at page 7 . '8 Exhibit No._(MCD-lCT) at pages 5-6. re See Exhibit No._(MCD-lCT) at pages 5-8; Exhibit No._ ICT) at pages l5-18. Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E- l5-01, AVU-E- l5-01, PAC-E- 15-03 D. Reading, Simplot/Clearwater Page 2 (DCG-lCT) at pages 8-13; Exhibit No._(SC- Exhibit No._(GND-7CT) Page 13 I 2 3 4 5 6 7 8 9 l0 ll t2 l3 l4 l5 l6 l7 l8 l9 a. A. a. A. (RECs), however, the Company may not use them to comply with the EIA.20 Is one of the goals of PURPA to support the development of renewable energy resources? Yes. FERC has observed that: "With PURPA, Congress was seeking to diversify the Nation's generation mix and promote more eflicient use of fossil fuels when they were used for generation by encouraging renewable technologies and cogeneration, in order to cushion against further price shock and reduce dependence on fossil fuels."2l Does Washington state policy promote the development and use of renewable energy? Yes. There are strong statements in support of renewable energy development and use in the declaration of policies included in the EIA and in the legislative findings that support the EPS.22 Did the Commission recently adopt policies to promote the development of small renewable generation? Yes. On July 19,2013, the Commission adopted new rules to simplify the process to connect small energy systems, which are often solar or wind generators, to the electrical system. In announcing the new rules, Commission Chairman David Danner said: "By streamlining these rules we are advancing Washington's policies that encourage renewable energy, including distributed generation. This is one more step a. A. 20 RCw 19.285 et seq.2t In re Southern California Edison, Tl F.E.R.C. P 61,269,62,079 (1995). 22 RCW t89.285.020; RCW 70.235.005;and RCW 80.80.005(lXd). Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 3 Exhibit No._(GND-7CT) Page 14 I 2 J 4 5 6 7 8 9 l0 ll t2 l3 t4 l5 t6 l7 l8 l9 20 2l a. to help Washington's citizens and businesses participate in our state's efforts to reduce greenhouse gas emissions."23 Is asking Washington customers to pay their allocated share of the Company's west control area QF contracts (while other west control area states also pay their allocated share of Washington's QF contracts) contrary to Washington state energy policy? No. Washington, like its neighbors in Oregon and California, clearly supports the underlying policy goals of PURPA. Indeed, continuing to single out QF contracts for different regulatory treatment than any other west control area resource discriminates against small, renewable resources in a manner that appears directly contrary to Washington energy policy. Has the number of Oregon and California QF contracts included in the Company's case decreased since its initial filing? Yes. Since the initial filing, four Oregon QF contracts were terminated. The impact of removing these contracts is included in the Company's rebuttalNPC. This update also reduces the impact of parties' proposed adjustments to exclude Oregon and Califomia QF contracts by approximately l0 percent. Does PURPA include specific provisions related to utility cost recovery for QF contracts? Yes. I understand that PURPA specifically requires that electric utilities "recover[] all prudently incurred costs associated with the purchase" of energy or capacity from A. a. A. a. A. 2r htto:ii www.utc.wa.gov/about(.lsr'Listsi N91yi/.!.EpllfgLg$I]1ll-28-9 Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E- l5-01, AVU-E- l5-01, PAC-E- I 5-03 D. Reading, S implot/Clearwater Page 4 Exhibit No._(GND-7CT) Page 15 I 2 3 4 5 6 7 8 9 r0 ll t2 l3 t4 l5 l6 t7 l8 l9 20 a QF contract.24 The Company's proposal in this case modifies the WCA to provide for the full cost recovery for QF contracts dictated by PURPA. What specific justilication does Staffprovide for the exclusion of the Company's contracts with QFs in Oregon and California? Staff first argues that inter-jurisdictional allocation is not based on actual power flow studies and therefore the fact that Oregon and Califomia QFs may physically deliver power to meet Washington load is irrelevant.2s Public Counsel makes the exact opposite argument.26 [t claims that PacifiCorp has failed to provide any analysis showing how Washington load is satisfied by QFs from outside the state and, without such a detailed power flow study, it is not possible to assign these costs to Washington customers. In other words, Staffclaims that allocation is not, and has never been, based on power flow studies, and Public Counsel claims that power flow studies are a necessary predicate to any inter-jurisdictional allocation methodology. llow do you respond to these arguments? The Commission has made clear that the Company does not need to "demonstrate each resource in the system provides a direct benefit, i.e., electron flow, to be considered used and useful for service in this state.o'21 Pubtic Counsel's claim that a detailed power flow study is necessary is incorrect. However, Staffis also incorrect that the physical location of the Oregon and Califomia QFs within the west control area is irrelevant to their inclusion in west control area NPC. 2o r6 u.s.c. g 82aa-3(m)(7). " Exhibit No._(DCG-lcr) at page 10. 'u Exhibit No._(SC-lcT) at page 17.'' ll/ash. Utils. & Transp. Comm'n v. PacifiCorp d/b/a/ PaciJic Pawer & Light Company, Docket UE-050684, Order 04, 1J68 (April 17,2006). Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D, Reading, SimploVClearwater Page 5 a. A. a. A. Exhibit No._(GND-7CT) Page 16 I 2 aJ 4 5 6 7 8 9 l0 ll t2 l3 t4 l5 l6 l7 l8 l9 20 Please explain. The underlying premise of the WCA is that all generation resources located in the west control area are used and useful to Washington customers and are therefore included in Washington rates. When approving the WCA, the Commission observed: "Based as it is on the generation resources that are actually used to keep the west control area in balance with its neighboring control areas, the WCA method is a solid foundation for determining the resources that actually serve load in Washington.2s The fact that the Oregon and California QFs are located in the west control area means that, like all other west control area generation resources (including PPAs with non-QF generators), the costs and benefits of these contracts should be included in Washington rates. Does Staff provide any other justification for the exclusion of costs associated with Oregon and California QF contracts from west control area NPC? Yes. Staff claims that the requirements, size of etigible resources, contract term lengths, and pricing for QF contracts are determined entirely by state-specific policies.2e As discussed above, Staff argues that Washington customers should not be subject to the policy decisions of other states related to QF contracts. Do other parties make similar arguments? Yes. Boise also argues that Washington customers should be protected from other states' policies on QF contracts.30 28 Wash. Lltils. & Transp. Comm'n v. PacifiCorp d/b/a Pacific Power & Light Company. Docket UE-061546, Order 08, fl 53 (June 21,2007\. 'n Exhibit No._(DCG-lcT) at page 10. 'o Exhibit No._(MCD-lcr) at page7. Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 6 a" A. a. A. a. A. Exhibit No._(GND-7CT) Page 17 I 2 3 4 5 6 7 8 9 r0 ll l2 l3 t4 t5 l6 t7 t8 l9 Is Staffcorrect that the requirements, size of eligible resources, contract term lengths, and pricing for QF contracts are driven entirely by state-specific policies? No. I understand that PURPA-a federal statute-requires the Company to enter into QF contracts and makes clear the price paid to a QF cannot exceed the utility's avoided costs.3l I also understand that FERC regulations govern the specific requirements regarding the types of resources that are eligible for a QF contract,32 the size of resources eligible for QF contracts,33 and the methodology for determining avoided cost prices for purposes of QF contracting.3a Staffclaims that Commission policy dictates shorter contract lengths and smaller capacity sizes than Oregon and California to better protect customers.3s Do you agree? No. StafPs testimony states that the Commission has established policies that strictly limit QF eligibility for standard contracts and strictly timits standard contract length.36 However, Staff s claims are at odds with the Commission's rules and Commission- approved PURPA tariffs. First, Staffstates that WAC 480-107-095 limits eligibility for standard contracts to QFs that have a capacity of 2 megawatts (MW) or less.37 WAC 480-107- 095 does not include a cap, however, stating only that "utilities must file a standard t' See, e.g.,l6 U.S.C. $$ 824a-3(b), (d); l8 C.F.R.5292.304(2); American Paper lnstitute, Inc. v. American Elec. Power Senice Corp.,46 I U.S. 402, 413 ( I 983). " See, e.s., l8 C.F.R. $$ 292.203-.205. " See, e.g.,l8 C.F.R. 5292.304(c). 'n See, e.g., l8 C.F.R. g 292.304. '5 Exhibit No._(DCG-lcr) at page 13. 36 Id. atn,29.3t Id. Redacted RebuttalTestimony of Gregory N. Duvall Exhibit No.204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater PageT a. A. 0. A. Exhibit No._(GND-7CT) Page 18 I 2 J 4 5 6 7 8 9 l0 ll l2 l3 l4 l5 l6 t7 r8 l9 20 2l 22 a. A. tariff for purchases from qualifying facilities rated at one megawatt or less." Currently, both PSE's Schedule 9l and Avista's Schedule 62 provide standard offer contracts for QFs with capacities up to 5 MW; PacifiCorp's Schedule 37 provides standard contracts for QFs with capacities up to 2 MW. Second, Staff states that WAC 480- 107-095 provides for fixed pricing for a term of only five years.38 Again, that rule says nothing about fixed prices or the length of a contract. WAC 480-107-095 merely states that prices may "not exceed the utility's avoided costs for such electric energy, electric capacity, or both," and that the tariff "may be based upon market prices and include incremental costs associated with purchasing small quantities of power." PacifiCorp's current Schedule 37 publishes a lO-year stream of fixed prices available for a contract term of five years. PSE's tariff specifies that to receive fixed prices, contracts must be at least five years in length, and the tariff reflects l5 years of fixed prices. Of note, current Washington prices, which were set in PacifiCorp's 201I general rate case, Docket UE-l I I190, include the end of aZl-year QF contract with the City of Walla Walla with calendar year 2014 prices of $156.90 per MWh. Staffargues that the longer terms of QF contracts in Oregon and California expose customers to increased risks from decreasing avoided cost rates in recent years.3e How do you respond? Staff overstates this risk by understating the number of Oregon and California contracts entered in the last five years. Staff claims that approximately 34 percent of the QF contracts are post-2009; in fact, of the expected QF generation in 2014 38 Id. " Exhibit No._(DCG-lCT) at pages l2-13. Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 8 Exhibit No._(GND-7CT) Page 19 I 2 3 4 5 6 7 8 9 l0 ll l2 l3 l4 l5 l6 t7 l8 t9 20 2t a. A. included in this case, over 76 percent is from contracts entered in the last five years.a0 The vast majority of the contracts that are included in NPC in this case have boen in place five years or less. Does Boise identify any specific state policies from Oregon and California that it claims are in conflict with Washington policies? Yes. Boise claims that Oregon and California have fixed price standard offer contracts for QFs, but Washington does not.al Boise claims that Washington customers should not be exposed to the risk associated with these types of policy decisions made in other states. Does this argument have merit? No. Boise's argument is premised on an incorrect understanding of Washington's implementation of PURPA. As described earlier, the Company's Schedule 37 tariff in Washington provides a fixed price standard offer option for QFs up to 2 MW of capacity. Other than the incorrect reference to the lack of a fixed price contract in Washington, does Boise provide any other examples of QF policies in Oregon or California that differ from those in Washington? No. Boise's claims that Washington customers are exposed to harm caused by decisions made by the states of Oregon and California are unsubstantiated. Are Washington customers harmed by other states' determination of QF prices? No. As I described in my direct testimony, prices paid to QFs are determined based a0 This includes the impact of removing the terminated Butter Creek wind QFs. Before removing the Butter Creek QFs, 74 percent of the Company's expected QF generation in the Company's initial filing was from contracts entered in the last five years. o' Exhibit No._(MCD- I cr) at page 6. 0. A. a. A. a. A. Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E-15-01, AVU-E- l5-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 9 Exhibit No._(GND-7CT) Page20 I on a utility's avoided cost of energy and capacity, in compliance with PUMA. Each 2 state has an approved method for calculating these avoided costs, and the resulting 3 prices are heavily scrutinized and ultimately approved by the respective commissions. 4 The avoided cost calculation is designed to set QF contract prices at a level where 5 customers are indifferent between a utility purchasing from the QF or obtaining 6 energy and capacity from the next available resource. No party has provided 7 evidence that the avoided cost prices in Oregon or California exceed the Company's 8 actual avoided costs in violation of PUMA. 9 Q. What justification does Public Counsel provide for the exclusion of the l0 Company's contracts with QFs in Oregon and California? I I A. In addition to the arguments addressed above regarding the Company's lack of power l2 flow studies, Public Counsel claims that Oregon and California QF contracts are 13 priced higher than other long term purchase power costs for 2014.42 14 a. How do you respond to this argument? l5 A. It is improper for ratemaking purposes to compare the avoided cost price in QF 16 contracts that are several years old with the cost of other purchases in the current 17 NPC study. Such a comparison does not account for the information available at the l8 time the various contracts were entered. Nevertheless, the difference in price cited by l9 Public Counsel was less than seven percent. In addition, allof the long-term 20 contracts included in the comparison were executed more than l0 years ago, 2l including two low-cost contracts entered in l96l and I 989 that were based on cost- o'Exhibit No._(SC-lCT) at page 17. Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No._(GND-7CT) Exhibit No. 204 Page 2l Case Nos. [PC-E-l 5-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page l0 I 2 3 4 5 6 7 8 9 l0 ll t2 l3 l4 l5 l6 t7 l8 l9 20 2t 22 a. A. 0. A. a. A. of-service rates. It is unreasonable to compare recent avoided cost prices with that of a contract entered more than 50 years ago. Public Counsel also claims that the Company perceives the Oregon and California QF contracts as local or state.specific matters.a3 Is this correct? No. For every state served by the Company other than Washington, the Company allocates the cost of QF purchases located in all states (including Washington's QF contracts) to alljurisdictions. Washington is the only state served by PacifiCorp that does not reflect their allocated share of other states' QF contracts in NPC. Boise argues that excluding the Oregon and California QF contracts from west control area NPC is equivalent to replacing these resources with market purchases in GRID.aa Do agree this is a reasonable approach? No. Boise's argument is based on the incorrect premise that current market prices are an appropriate proxy for avoided cost. Schedule 37 requires the Company to pay QFs in Washington a payment for both energy and capacity, with energy payments reflecting the Company's incremental cost of market transactions and thermal output, and capacity payments reflecting the fixed costs associated with a simple cycle combustion turbine for three months per year. The inclusion of capacity payments in avoided costs indicates that market prices alone are not equivalent to avoided cost prices. What does the Company recommend regarding the treatment of California and Oregon QF contracts in west control area NPC? The Company recommends that the Commission allow the Company to include a3 Id. at 16. oa Exhibit No._(MCD- ICT) at page 7. Redacted RebuttalTestimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E-t5-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page I I Exhibit No._(GND-7CT) Page22 I 2 J 4 5 6 7 8 9 l0 ll t2 l3 l4 l5 l6 t7 l8 l9 20 2t Califomia and Oregon QF contracts in the determination of west control area NPC in the same manner as all other west control area generation resources, with a portion of the costs allocated to Washington customers. East Control Area Sale a. How do parties respond to the Company's proposal to remove from the NPC calculation the assumed sales from PacifiCorp's west control area to its east control area? A. Boise and Staffeach recommend that the Commission reject the Company's proposal and recommend that west control area NPC continue to include an assumed east control area sale.as What is the basis for Boise's opposition to the Company's proposal? Boise provides no factual argument, but instead rejects the proposalto remove the east control area sale because the parties to the collaborative process did not agree to the change.ou Fo. the same reasons discussed above, this argument is unpersuasive. What basis does Staff provide for the inclusion of the east control area sale? Staffls argues that the imputed east control area sale remains an integral and crucial part of the WCA and should therefore not be modified.aT When the Commission adopted the WCA, what did it say with respect to the east control area sale? The Commission noted that the Company accepted the east control area sale subject to further scrutiny in the future and approved the establishment of a monitoring ot Exhibit No._(DCG- I CT) at pages I 3- l 6; Exhibit No._(MCD- l CT) at page 8. nu Exhibit No._(MCD-tCT) at page 8.a'Exhibit No._(DCC-lcT) at page 16. a. A. a. A. a. A. Redacted Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204 Case Nos. IPC-E- 15-01, AVU-E- l5-01, PAC-E- 15-03 D. Reading, Simplot/C learwater Page 12 Exhibit No._(GND-7CT) Page23 CONFIDENTIAL PER WAC 480-07.160 Exhibit No._(GND-lcT) Docket UE-14_ WiEress: Gregory N. Duvall BEFORE THE WASHINGTON UTILITIES AI\[D TRANSPORTATION COMMISSION Docket UE-14 PACIFIC POWER & LIGHT COMPANY REDACTED DIRECT TESTIMONY OF GREGORY N. DUVALL May 2014 Exhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 13 WASHTNGTON UTILITIES AND TRANSPORTATION COMMI SS ION, v. PACIFIC POWER & LIGHT COMPANY, a division of PacifiCorp I 2 5 4 5Q. 6 7A. 8 9 l0 a. ll A. l2 t3 a. t4 15 A. l6 l7 l8 l9 20 2t 22 23 24 25 26 27 28 differences in west control area loads and resources by reducing actual short-term balancing purchase or sales transactions. PROPOSED TREATMENT OF QF RESOURCES IN THE WEST CONTROL AREA Please explain the Company's proposed treatment of PPAs with west control area QFs. In this case, the Company renews its proposal to include Washington's share of the costs and benefits associated with all PACW (Oregon, California, and Washington) QF PPAs in the calculation of west control area NPC. Did the Company originally propose this treatment in the 2013 Rate Case? Yes. The Commission rejected this proposal in Order 05 the 2013 Rate Case, and the Company sought judicial review of this issue. Why is the Company again asking to include the cost of PPAs with QFs in Oregon and California in this case? The Company respectfully asks the Commission to reconsider its approach to including PPAs with west control area QFs in Washington rates for the following reasons: Including all PPAs with QFs in the west control area in the NPC calculation is consistent with the treatment of other generation resources under the WCA and is a more accurate representation of the Company's operations in the west control area because these resources are all located in the west control area, physically deliver power to meet Washington load in the same manner as any other west control area resource, and provide direct benefits to Washington customers. There are now a material number of QFs serving Washington customers, but the costs of the PPAs with these QFs are not reflected in Washington rates. In the pro forma period, Oregon and California QFs are projected to supply 806,799 megawatt-hours (MWh) of generation in the west control area. Collectively, west control area QFs provide a significant source of power supply to Washington - . .Direct^[qstimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 14 Exhibit No._(GND-lCT) Page 8 I 2 aJ 4 5 6 7 8 9 l0ll t2 l3 t4 l5 t6 a. l7 l8 customers, but Washington customers only pay for PPAs with QFs located in Washington. r Including west control area QF PPAs in Washington rates is consistent with the Public Utility Regulatory Policy Act of 1978 (PURPA). The QF PPAs included in this case were executed at avoided cost prices calculated under PURPA, and no party has ever alleged that the prices exceed the Company's actual avoided costs at the time the PPAs were executed. PURPA explicitly requires FERC to "ensure that an electric utility that purchases electric energy or capacity froqr a tQF] . . . recovers all prudently incurred costs associated with the purchase."r o All of the Oregon and Califomia PPAs are with QFs that are eligible resources under Washington's Energy Independence Act (ElA). Allowing the Company to recover the costs of these Oregon and California QF PPAs in rates implements the EIA's policy of encouraging renewable resource development on a regional basis and diversifying the portfolio of renewable resources serving Washington customers. ln the 2013 Rate Case, the Commission reasoned that the Company's proposal was the equivalent of adopting the Revised Protocol method just for QF ,"rources.3 Do you agree? No. The Company's proposalto include the costs of PPAs with QFs in Oregon and Califomia in the calculation of west control area NPC is consistent with the WCA and strictly tracks the Commission's underlying rationale for the WCA. As reiterated in the 2013 Rate Case Order, the WCA is based "on the generation resources that are actually used to keep the west control area in balance with its neighboring control areas."4 Oregon and Califomia QFs are used to keep the west control area in balance just like all other west controlarea generation resources. The only distinguishing A.l9 20 2t 22 23 24 25 't6U.S.C. g 82aa-3(m)(7)(A);see alsoFreeholdCogenerationAssocs., L.P.v. Bd. of RegulatoryComm'rsof the state of N.J.,44 F.3d I 178, I 194 (3d Cir. 1995) ("[Alny action or order by the [state commission] to reconsider its approval or to deny the passage ofthose rates to [the utility's] consumers under purported state authority was preempted by federal law.").3 Wash. Utils. & Transp. Comm'n v. PacifiCorp d/b/a Pacific Power & Light Co., Docket UE-130043, Order 05,fl Il0(Dec.4,2013).o Order 05 tl I l0 (quoting Wash. Utits. & Transp. Comm'nv. Pacific Power & Light Co., Docket UE-061546, Order 08, '!f 53 (June 21,2007). e_r,,rfii5ftSlz6?stimony of Gregory N. Duvall Exhibit No._(GND-lcT) Page 9Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 15 I 2 J 4 5 6 7 8 9 l0 ll t2 l3 l4 l5 l6 l7 l8 l9 20 2l 22 23 a. A. factor between QF resources and all other west control area resources is the fact that PURPA requires the Company to purchase power from QFs at prices established by regulators in west control area states. This mandate makes recovery of the costs of these resources more appropriate under the WCA, not less. In addition, the 2010 Protocol, which is the current inter-jurisdictional allocation methodology used in the PacifiCorp's other five state jurisdictions, allocates the costs of QF PPAs across PacifiCorp's system. ln this case, the Company is not proposing to system-allocate PPAs with QFs in all six states served by the Company. Are Washington customers harmed because west control area NPC is higher when all PPAs with west control area QFs are included? No. Washington customers are not harmed by paying rates that more accurately represent the cost to serve them. These resources are used in providing service to Washington customers, and including the costs of these resources in rates is fair, not harmful. Furthermore, while including all west control area QF PPAs increases Washington-allocated NPC by approximately $10.0 million, this only shows that the prices paid for Oregon and California QF resources are higher than the variable cost of market purchases and other resources used to balance the GRID study. QF prices, on the other hand, are established in advance, consistent with PURPA, and are fixed for a number of years over the term of the PPA. Long-term contract prices will inevitably be different from short-term market prices as time progresses. QF prices may also include a capacity component in addition to payment for energy. In _ . .Direct:lqstimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E- l5-01, AVU-E- l5-0 I, PAC-E- I 5-03 D. Reading, Simplot/Clearwater Page 16 Exhibit No._(GND-lcT) Page l0 I 2 J 4 5 6 7 8 9 l0 lt t2 l3 t4 l5 l6 t7 l8 l9 20 2t 22 .t) a. A. Washington, for example, Schedule 37 rates compensate QFs for both energy and capacity, with energy payments based on the incremental eost of nnarket transaotions and thermal output, and capacity payments reflecting the fixed costs of a simple eycle combustion turbine for three months per year. If avoided cost prices are greater than market prices years after the PPA was signed, it does not mean that the avoided cost prices in the QF PPA are excessive or otherwise violate PURPA's strict requirements. PUR.PA requires that the prices paid to QFs be equal to a utility's avoided cost of energy and capacity. Each state has an approved method for calculating these avoided costs, and the resulting prices are heavily scrutinized and ultimately approved by the respective regulatory commissions. The avoided cost calculation is intended to ensure that customers are indifferent to QF generation, i.e., that the price paid to the QF is the same as the price the utility would otherwise incur if it was generating the electricity itself. Comparing QF PPA prices for a single test year to the variable cost of market purchases or the Company's existing resources is insufficient to determine whether QF prices are reasonable and prudent from a ratemaking standpoint. In response to Onder 05 in the 2013 Rate Caseo did the Cornpamy amalyze other approaches to addressing Oregon and California QF PPAs in Washingtorn? Yes. In an effort to respond to the Commission's concerns in Order 05 about including the energy and capacity costs of all west control area QF PPAs in the determination of west control area NPC, the Company examined two alternative approaches to addressing the Oregon and California QF PPAs: I ) A "load decrement" approach, which excludes the costs and energy of Oregon and California QF PPAs from the NFC calculation, and excludes an equivalent - . .llitect:lqstimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 17 Exhibit No._(GND-lCT) Fage I I I 2 3 4 5 6 7 8 9 l0 ll t2 l3 l4 t5 l6 l7 l8 l9 20 a. A. amount of QF output from WCA loads used to calculate NPC and inter- jurisdictional allocation factors; and 2) A "Washington re-pricing" approach, which includes Oregon and California QF PPAs in the NPC calculation but re-prices them using the Washington avoided cost rates in effect at the time of PPA execution. Table 2 below compares the revenue requirement impact of these two alternative approaches with the Company's proposal to include all west control area QF PPAs as west control area resources. This table, and supporting detail, is provided in Exhibit No._(NCS-7) accompanying Ms. Siores testimony. Table 2 Revenue Requirement Variance from Filed As Filed $27.2 mil lon Washinston Re-Pricins 524.9 mil lon ($2.3 million) Load Decrement $23.1mil lon ($4.1 million'l Situs Assiened (exclude OR and CA OF PPAs)$17.2 mi ton (S10.0 million) Please explain the load decrement approach. Under this approach, Oregon and California QF PPAs are deemed to serve customers in those states, consistent with the situs treatment ordered by the Commission in the 2013 Rate Case. Because Oregon and California QF PPAs are not recognized as WCA resources, the costs and related energy are removed from the calculation of west control area NPC. Next, because Oregon and California QF PPAs are deemed to serve customers in those states, the retail load in those states served by these resources is also removed from the calculation of west control area NPC. Finally, the retail load in Oregon and California served by QF resources is subtracted (i.e. decremented) from the energy and peak loads used to determine each state's allocation factors under the WCA. ^ . .Ditect:lestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, S implot/Clearwater Page 18 Exhibit No._(GND-lCT) Page 12 I 2 aJ 4 5 6 7 8 9 l0 ll t2 l3 l4 l5 l6 17 l8 l9 20 2l 22 23 a. A. a. A. a. A. What is the impact to Washington of rernoving Oregon and California QF PFAs and load? Removing Oregon and California QF PPAs and load reduces west control area NPC and reduces the total load served by west control area resources. The allocation of remaining west control area costs is adjusted to account for the decremented load- i.e. the share of the total costs allocated to Oregon and California is decreased reflecting the reduced requirement to serve customers in those states. Washington's allocated share of remaining WCA costs is increased as a result of the QF-PPA- related decrements to Oregon and California load. The net impact is a reduction to the Company's current filing of approximately $4.1 million. Why is an adjustment to the inter-jurisdictional allocation factors required under the load decrement approach? Adjusting the inter-jurisdictional allocation factors under the load decrement approach ensures that the full impact of treating QF PPAs as situs resources is reflected in Washington revenue requirement. If Oregon and Califomia customers are being served by specific resources, they shoirld not also be allocated the cost of the remaining west control area resources. Decrementing Oregon and California load for allocation purposes appropriately reduces the share of west control area costs allocated to those states. Please explain the alternative approach of re-pricing Oregon and California QF PPAs using Washington avoided costs. Under this alternative, the Oregon and California QF PPAs are included in west control area NPC but are re-priced using Washington avoided cost rates that were - . .Directlqstimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E- l5-01, AVU-E- l5-01, PAC-E- l5-03 D. Reading, Simplot/Clearwater Page 19 Exhibit No._(GND-lcT) Page 13 I 2 J 4 5 6 7 8 9 l0 ll t2 t3 l4 l5 l6 l7 r8 l9 20 2t 22 a. A. calculated at the time the PPA was signed. This alternative removes the impact of differences in individual state commission approaches to determining avoided cost prices. Some of the Oregon and California QF PPAs have contract terms that extend beyond the last year for which the Company had calculated avoided cost prices in Washington. For example, an Oregon QF PPA signed in June 2009 would be priced using the Washington Schedule 37 prices approved by the Commission in February 2009, which were only calculated through 2013. In examples such as this, the last annual price was escalated with inflation through the pro forma period. Several Oregon and Califomia QF PPAs in the pro forma period were signed in the early 1980s, and one was signed in the early 1990s. At that time, the Company also had two-long term QF PPAs in Washington, one with the City of Walla Walla (signed in 1984) and one with Yakima-Tieton Irrigation District (signed in 1985). Prices paid under the Walla Walla PPAs were applied to the early- 1980s contracts in Oregon and Califomia, and prices paid under the Yakima Tieton PPA were applied to the PPA signed in 1993. Currently, the Company's Schedule 37 only allows fixed-price contracts for a term of up to five years. Has that always been the case? No. Schedule 37 was first implemented in 2004, and it included a five-year limit on fixed-price contracts. However, the two long-term Washington QF PPA contracts signed in the 1980s mentioned above were for terms of 25 and20 years, respectively. Washington's current administrative rules allow a utility to sign contracts for electricity purchases for any term up to twenty years.s 5 wAC 480-r07-075(3). - . .Ditect:lgstimonv of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 20 Exhibit No._(GND-rcT) Page 14 --l I 2 3 4 5 6 7 8 9 l0 ll l2 l3 t4 l5 t6 l7 t8 t9 20 2t a. A. a. A. a. A. What is the impact to Washington NPC of re-pricing all of the Oregon and California QF PPAs? As shown in Table 2, the impact of re-pricing all of the Oregon and California QF PPAs using contemporaneous Washington avoided cost rates is a reduction to the Company's current filing of approximately $2.3 million. Why is the Company discussing these alternative methods in this case? The Company's proposal for treatment of west control area QF PPAs in this case is the same as in the Company's 2013 Rate Case-full recognition of the costs of the Company's PPAs with Oregon and California QFs in Washington rates. The Company renews this proposal because it best captures the prudent and reasonable costs to serve Washington customers. But in response to the Commission's past criticism of its proposal, the Company provides the altemative methods as a middle ground between fullrecovery or fulldisallowance of the costs of all west controlarea QFs in Washington NPC. CHAIIGES IN SALES AND LOADS Please summarize the changes in Washington sales in this case compared to the Company's 2013 Rate Case. As shown in Table 3 below, the Company's Washington sales in the historicaltest period (the l2 months ended December 31,2013) were 9,549 MWh, or 0.2 percent higher than the sales included in the 2013 Rate Case on a weather-normalized basis.6 The increase in sales is largely driven by increased sales to the commercial class and 6 In this case, the Company calculated temperature normalization for the residential, commercial, and irrigation customers consistently with the methodology approved by the Commission in the Company's 2005 general rate case, Docket UE-050684, 2006 general rate case, Docket UE-090205, and the Company's 2013 Rate Case, Docket UE-130043. - . .Ditect:lqstimonv of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D, Reading, Simplot/Clearwater Page 2 I Exhibit No._(GND-lcT) Page 15 Exhibit No. GND-47 Docket UE-140762 et al. Witness: Gregory N. Duvall BEFORE THE WASHINGTON UTILITIES AI\[D TRANSPORTATION COMMISSION WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION, Complainant, v. PACIFIC POWER & LIGHT COMPANY, Respondent. In the Matter of the Petition of PACIFIC POWER & LIGHT COMPANY, For an Order Approving Deferral of Costs Related to Colstrip Outage" In the Matter of the Petition of PACIFIC POWER & LIGHT COMPANY, For an Order Approving Deferral of Costs Related to Declining Hydro Generation. Exhibit No. 204 November 2014 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 22 DOCKETS UE-140762 and UE-140617 (consolidatedl DOCKET UE-131384 (consolidated) DOCKET UE-140094 (consolidated) PACIFIC POWER & LIGHT COMPANY REBUTTAL TESTIMONY OF GREGORY N. DUVALL I 2 aJ 4 5 6 7 8 9 l0 ll t2 l3 t4 l5 r6 t7 l8 l9 20 its members, "including the Packaging Corporation of America, f/k/a Boise White Paper, L.L.C. (PCA), PacifiCorp's largest customer in Washington[,]"la and further stated that "ICNU indirectly participated in PacifiCorp's most recent general rate case (UE- I 30043) as PCA[.]"rs Given that this update is occurring in your rebuttal testimony, does the Company object to allowing the parties an opportunity to provide responsive testimony on this issue? No. The Company does not object to parties addressing the Company's NPC update in supplemental pre-filed testimony or in testimony at the hearing, provided the Company has a chance to respond to this testimony. COMPANY RESPONSES TO PROPOSED NPC ADJUSTMENTS Exclusion of California and Oregon QF PPAs a. Does any party support the Company's proposal to include the costs associated with Oregon and California QF PPAs in west control area NPC? A. No. Staff, Boise, and Public Counsel each reject including California and Oregon and QF PPAs in west control area NPC.16 Similar to arguments made in the Company's 20 I 3 general rute case, Staff and Boise assert that allocating west control area QF PPAs to Washington inappropriately requires Washington customers to pay for QF- related policy choices made by California and Oregon. Public Counsel does not address the appropriate allocation of Califomia and Oregon QF PPAs, but indicates ta See Wash. Utils. & Transp. Comm'n v. PacifiCorp, Docket No. UE-I40617, Petition to lntervene and Opposition of the Industrial Customers of Northwest Utilities, ![ 3 (Apr. 25,2014).tt Id.,n4. 16 See Testimony of David C. Gomez, Exhibit No. DCG- I CT at 9- l0; Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM- lCT at23. e_r,i$?ktsttgd/estimony of Gregory N. Duvall Exhibit No. GND-47 Page 12Case Nos. IPC-E- l5-01, AVU-E- 15-01, PAC-E- l5-03 D. Reading, Simplot/Clearwater Page23 a. A. I 2 3 4 5 6 7 8 9 IO ll l2 l3 l4 l5 l6 t7 l8 a. A. that Public Counsel supports the Commission's findings in Docket UE-130043 (2013 Rate Case) and removes the cost of these QFs from west control area NPC. Is the Company's proposal in this case exactly the same as in the Company's 2013 Rate Case? No. While the Company's main proposal in this case is similar to the 2013 Rate Case in that the costs associated with Califomia and Oregon QF PPAs are included in west control area NPC, the Company also provided two alternative approaches that would reasonably reflect the impact of California and Oregon QF PPAs on NPC. First, the Company proposed re-pricing the out-of-state QFs at Washington avoided cost prices, so that the costs associated with the QFs reflected Washington state policy choices. This proposal would decrease Washington revenue requirement by $2.2 million. Second, the Company proposed a load decrement approach to QF pricing that would remove the costs of the out-of-state QF PPAs and also offset each west control area states' load with the QFs in that state for purposes of allocating costs and benefits under the WCA. This proposal would decrease Washington revenue requirement by $3.9 million. The rebuttal testimony of Ms. Natasha C. Siores provides the detailed revenue requirement impact of each proposal. I reproduced her summary table here for ease of reference. | 7 TABLE 1 Reven ue Requ t rem ant S um m ary ilCS-11, Page 1.' NGS-12, Page 2 NCS-12, Page 3 NCS-12, Page 4 r7 Rebuttal Testimony of Natasha Siores, Exhibit No. ^ . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 24 Exhibit No. GND-47 Page 13 22,181,879 NCS- I 2. I 2 aJ 4 5 6 7 8 9 l0 ll t2 l3 t4 l5 l6 l7 l8 t9 20 2t a. A. a. A. Did the parties address the Company's alternative proposals? Yes. Both Staff and Boise dismissed the Company's altemative proposals as inconsistent with the Commission's decision in the 2013 Rate Case. What is the parties' primary argument against Pacific Power's proposals? Based on the Commission's order in the 2013 Rate Case, Staffand Boise argue that excluding the California and Oregon QF PPAs from the west control area NPC is equivalent to replacing these resources with market purchases in GRID.ls Staffand Boise claim that re-pricing the QF PPAs at market prices protects Washington customers from policy decisions made by other states and is consistent with the cost causation principles underlying the WCA. Is re-pricing the out-of-state QF PPAs at current market prices consistent with PURPA? No. It is my understanding that re-pricing the out-of-state QF PPAs at current spot market prices is inconsistent with PURPA's requirement, as interpreted by the Commission in the Company's Schedule 37,that utilities purchase allenergy and capacity made available by QFs at the utility's avoided cost. Why is re-pricing the out-of-state QF PPAS at current market rates inconsistent with PURPA's avoided cost requirements? There are two primary reasons. First, simply relying on market prices does not reflect Pacific Power's actual avoided costs as determined by the Commission because it fails to account for the impact of a QF on the Company's existing resources or the " See,e.g.,Testimonyof DavidC.Comez, ExhibitNo. DCG-lCTat ll;ResponsiveTestimonyof BradleyG. Mullins, Exhibit No. BGM- I CT at 25-26. a. A. a. A. ,*,*?Rtlridfestimony of Gregory N. Duvall Case Nos. IPC-E- l5-01, AVU-E- l5-01, PAC-E- 15-03 D. Reading, Simplot/C learwater Page25 Exhibit No. GND-47 Page 14 I 2 3 4 5 6 7 8 9 l0 ll t2 l3 l4 l5 t6 t7 l8 l9 20 2l 22 23 a. A. QF's ability to defer future capacity additions. PURPA requires the Company to purchase energy and capacity made available by QFs. Second, the current market price does not accurately reflect Pacific Power's avoided cost of energy included in long-term QF PPAs that were executed years ago with avoided cost prices determined at the time of execution. PURPA allows QFs to enter into long-term PPAs with utilities and, at the option of the QF, the avoided cost prices in those PPAs can be determined at the time the PPA is executed, not at the time that the energy is delivered to the utility. The Commission's decision to price out-of-state QF PPAs at the current market price ignores the Company's obligation under PURPA to pay a fixed avoided cost price over the life of the QF PPA. Thus, even if market prices accurately reflected Pacific Poweros avoided cost of energy, the relevant market prices were those that were forecast at the time the QF PPAs were executed, not current spot market prices. Has the Commission recognized that avoided cost prices must account for both energy and capacity? Yes. Pacific Power's current Schedule 37 requires the Company to pay QFs in Washington for both energy and capacity, with energy payments reflecting the Company's incremental cost of market transactions and thermal output, and capacity payments reflecting the fixed costs associated with a simple cycle combustion turbine for three months per year. The inclusion of capacity payments in Washington's avoided cost calculation demonstrates that, in the current view of the Commission, market prices alone are not equivalent to avoided cost prices. - . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E- 15-01, AVU-E- l5-01, PAC-E- I 5-03 D. Reading, Simplot/Clearwater Page 26 Exhibit No. GND-47 Page 15 I 2 3 4 5 6 7 8 9 l0 ll t2 r3 t4 l5 l6 l7 t8 l9 20 2t a. A. a. A. o. A. Has Staff recognized that wind resources provide capacity value to Washington customers? Yes. Staff s cost of service testimony expressly recognizes that wind resources provide capacity to meet the Company's peak load.le As described in the cost of service testimony of Ms. Joelle R. Steward, the Company's west control area wind resources, including the out-of-state QFs, contribute 25.4 percent of their nameplate capacity to meet total system peak load. Why is it necessary for the avoided cost prices to account for both energy and capacity? It is my understanding that PURPA mandates the use of avoided cost prices to ensure customer indifference to the QF transaction. In other words, customers should be no better or worse offbecause Pacific Power is purchasing its energy and capacity from a QF rather than from another source. However, if Washington customers are paying for only the energy from out-of-state QFs, Washington customers are benefiting from the capacity value provided by the QFs without paying for it. Therefore, re-pricing the out-of-state QF PPAs at market prices does not result in customer indifference. Has the Commission previously recognized the importance of ensuring customer indifference? Yes. The Commission has observed that "[b]y its own terms, PURPA was meant to protect the ratepayers. Avoided cost prices should be established to be no greater than that which the ratepayers would be expected to pay without PURPA."20 re Testimony of Jeremy B. Twitchell, Exhibit No. JBT-lT at l5- 16. 20 Spokane Energt, Inc. v. Wash. llater Power Co., Cause No. U-86-l 14, - . .R.eb-uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E- l5-01, AVU-E- l5-01, PAC-E- l5-03 D. Reading, Simplot/Clearwater Page27 1987 WL 1498338 ({pr.22,1987). Exhibit No. GND-47 Page 16 I 2 3 4 5 6 7 8 9 l0 ll t2 l3 t4 l5 l6 l7 l8 l9 20 2t a. A. How do current market prices compare with the market prices at the time the QFs were executed? The majority of the out-of-state QFs were executed within the last six years. During that time, market prices have decreased by more than half. Thus, even if the Commission's re-pricing method was reasonable for purposes of determining the avoided cost of energy, the contracts must be re-priced at the higher market prices that were anticipated at the time each PPA was executed. The Company's re-pricing proposal effectively captures the relevant forward prices and demonstrates the declining market prices. Staffclaims that the Company provided only vague assertions regarding the benelits provided by the out-of-state QFs to Washington customerr." Boise claims that the Company did not identiS any direct benefit provided by these QFs that would support full cost.ecovery." What benefits are provided by the out-of-state QFs? In addition to providing the capacity benefits discussed above, the out-of-state QFs provide significant benefits because they are renewable, emission-free generators. Washington state policymakers have been clear that renewable generation provides significant environmental, cultural, economic, and health benefits to Washington residents. Thus, the state has taken extensive measures to mandate and promote the development of exactly the types of resources that Staff and Boise claim provide no benefit to Washington. a. A. 2r Testimony of David C. Gomez, Exhibit No. DCG-lCT at 9.22 Responsive Testimony of Bradley C. Mullins, Exhibit No. BGM-lCT at26. - . .Reb.uttal Testimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 28 Exhibit No. GND-47 Page 17 I 2 J 4 5 6Q. 7A, 8 9 t0 ll t2 l3 t4 l5 l6 t7 a. l8 A. l9 20 2t 22 a. 23 A. Emission-free resources may act as a hedge against future carbon regulation, the exact nature of which is currently unknown. In fact, the Commission has acknowledged that future carbon regulation may have a significant impact on the Company's operations.23 The out-of-state QFs, like allof the Company's renewable resources, will help to mitigate that impact. What other benefits are provided by the out-of-state QFs? The QFs provide diversity to the Company's resource portfolio, which can act to reduce risk. Indeed, in this case Mr. Mullins testified on behalf of Boise about the many benefits provided by wind resources, including the out-of-state QFs: Portfolio diversification is one of the fundamental principles relied on by utilities in order to develop a least-cost, least-risk portfolio . . . . For purposes of utility planning, this means that a utility will benefit from procuring power supplies that are dependent on many different fuel and resource types.2a Thus, Mr. Mullins concluded that the Company's "overall system is benefiting as a result of the diverse nature of all the resources in its portfolio."2s Do the QFs allow the Company to avoid other costs? Yes. Without the energy and capacity provided by the QFs, Facific Power may have had to procure additional resources. These additional resources may or may not have been renewable, yet under the WCA these resources would have been included in Washington rates. Are there any other benefits provided by QFs? Yes. In a docket before the Public Utility Commission of Oregon (OPUC), Boise's 23 See, e.g., PacifiCorp's 20 t 3 Electric Integrated Resource Plan, Docket No. UE-120416, Commission Acknowledgement Letter (Nov. 25, 20 I 3). 2a Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at 57. " [d. at 58. u_',rfi?Rtsttfl/estimony of Gregory N. Duvall Case Nos. IPC-E- l5-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 29 Exhibit No. GND-47 Page 18 4 5 6 7 8 22 23 24 25 26 9 l0il l2 l3 t4 l5 l6 l7 r8 l9 20 2l 28 29 A. 30 3l energy trade association ICNU submitted testimony from its expert Mr. Donald W. Schoenbeck. ICNU's testimony identified I I different benefits provided by QFs, including the following: The second benefit is reliability. A system of 50 smaller generators of 200 MW each is significantly more reliable than a similar size system of 20 larger generators of 500 MW each. The smaller unit system is 100 times less likely to lose 1,000 MW of capacity simultaneously. *,8* The fourth benefit is system diversity. Because they distribute electrical generation among smaller, more efficient generating facilities, policies that promote cogeneration increase the reliability of an energy portfolio in the same way a diversified investment strategy protects investors. *!N(* The fifth benefit is transmission reliability. Cogeneration provides a major source of distributed generation for the electric grid which is a significant operating benefit. By providing multiple power sources throughout the state, the demand on the state's electrical grid and the risks of losing power when centralized generating facilities fail is reduced. The eighth benefit is reduced transmission losses. Cogeneration conserves electricity by producing power near the places it is consumed. This reduces transmission losses and saves an additional amount of fuel from being burned.26 Boise also claims that whether or not the out-of-state QF prices are excessive is irrelevant to cost allocation under the WCA.27 How do you respond? PURPA makes the QF prices extremely relevant. PURPA requires the Company to contract with the out-of-state QFs at prices equal to Pacific Power's avoided cost. The fact that not a single party in this case has argued that the QF PPA prices exceed a.27 26 lnvestigalion Relating to Electric Utility Purchases from Quatifying Facilities, OPUC Docket No. UM I 129, Direct Testimony of Donald W. Schoenbeck on Behalf of the Industrial Customers of Northwest Utilities at 6-7 (Aug. 3, 2004).2'Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at26. ^ ..Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 30 Exhibit No. GND-47 Page 19 I 1 2 3 4 5 6 7 8 9 l0 ll l2 l3 t4 l5 l6 t7 l8 l9 20 2t 22 Pacific Power's avoided cost prices is significant because, without such a finding, it is unreasonable to exclude the QF PPAs from rates. Staffand Boise also argue that the out-of-state QF PPA prices are driven by policies and decisions made by other states to encourage QF development that should not impact Washington rates.28 Boise further claims that states have significant leeway in implementing PURPA to 6'set avoided cost rates at higher or lower levels to reflect state renewable energy policies."2e How do you respond to these claims? I disagree with Staffand Boise for several reasons. First, I disagree with the implication that California and Oregon have inflated the avoided cost prices in the QF PPAs as a reflection of those states' renewable energy policies. It is my understanding that states cannot set an avoided cost price that includes a o'bonus" or "adder" intended to encourage renewable development. FERC has stated: [T]the State can pursue its policy choices concerning particular generation technologies consistent with the requirements of PURPA and our regulations, so long as such action does not result in rates above avoided cost.ru Moreover, no party to this case demonstrated or even alleged that the avoided cost prices included in the out-of-state QF PPAs are greater than the Company's actual avoided costs as of the time the PPAs were executed. Thus, there is no basis to conclude that California and Oregon are manipulating the avoided cost prices to promote state-specific energy or environmental policies. 28 Testimony of David C. Gomez, Exhibit No. DCG-lCT at 9-10; Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at24. 2e Responsive Testimony of Bradley G. Mullins, ExhibitNo. BGM-lCT at27. 'o Re,So. Calif. Edison Co.,70 F.E.R.C. n6l,2l5 at61,676 (1995) (emphasis added). ,_n,*fRtsltfdfestimony of Gregory N. Duvall Exhibit No. GND-47 Page20Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 3 I a. A. I 2 J 4 5 6 7 8 9 l0 ll t2 l3 l4 l5 l6 t7 l8 l9 20 2l 22 Second, it is my understanding that PURPA is specifically intended to encourage QF development. Therefore, Staff s and Boise's argument has merit only if one assumes that Washington has decided to not encourage QF development, a decision that would be contrary to the fundamental purpose of PURPA and contrary to the Commission's prior statements. Third, as I discussed previously in my testimony, the states' energy policies are strikingly similar and Washington has taken a decidedly regional approach to encouraging renewable energy development. Both Oregon and Washington, for example, have used PURPA development to promote distributed generation. Therefore, the policy differences perceived by Staff and Boise are not as extensive as they claim. Fourth, if the Commission remains concerned that the avoided cost prices of the California and Oregon in the QF PPAs reflect those states' policy decisions, then the Commission should approve the Company's altemative recommendation to re- price the QF PPAs at avoided cost prices determined according to Washington state policy. As described in more detail below, this re-pricing proposal effectively removes any perceived differences in PURPA implementation and results in Washington rates that indisputably reflect Washington state policy decisions. Staff and Boise claim that the Company's proposal is based on the "physical flow of power" and not cost causation.3t How do you respond? I disagree with this characteization. In my testimony, I stress the fact that the out-of- state QFs provide energy and capacity to serve Washington customers because that 3r Testimony of David C. Gomez, Exhibit No. DCG- I CT at I 0; Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at25. a. A, - . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 32 Exhibit No. GND-47 Page 2l I I 2 3 4 5 6 7 8 9 t0 il t2 l3 t4 l5 l6 t7 l8 a. fact-which is undisputed-demonstrates that Washington customers are benefiting from the QFs. As I discuss above, if Washington customers are receiving energy and capacity from these QFs, along with all of the other benefits discussed, then it is reasonable for Washington customers to pay the full costs of the QF PPAs. Otherwise, Washington customers are receiving the benefits without paying the associated costs. Thus, the Company's proposal is consistent with principles of cost- causation. Staffalso discounts the fact that the Commission has allowed Avista Corporation dlbla Avista Utilities (Avista) to recover the full costs of out-of-state QF PPAs in Washington rates, claiming that the Commission has not always relied on cost causation when allocating costs across multiple states.32 Staff claims that the Company's out-of-state QF costs are higher than Avista's and therefore must be situs assigned. Do you agree? No. There is no principled basis to allow one Washington utility to recover out-of- state QF costs while denying Pacific Power recovery of the same types of costs. PURPA contains no materiality threshold governing cost recovery. Consistency in regulation requires consistent treatment for all utilities. Simply pointing out that Avista has had fewer out-of-state QFs does not support differing treatment. 12 Testimony of David C. Gomez, Exhibit No. DCc- I CT at 13. A. - . .ff,eS.uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 33 Exhibit No. GND-47 Page 22 I 2 3 4 5 6 7 8 9 l0 ll l2 l3 t4 l5 l6 l7 l8 l9 20 Staff also claims that the Commission can disregard cost causation based on the degree to which state-specific policies may be driving the avoided cost prices. To support this claim, Staff relies on a 1983 Washington Water Power Company order regarding the allocation of costs for an Idaho QF PPA.33 Does that order support Staf?s position in this case? No. Contrary to Staffls claim that the Commission situs assigned the Idaho QF PPA costs to ldaho, a careful reading of the Commission's order shows that the Commission did not situs assign the QF costs at all. Rather, the Commission determined that the avoided costs in the QF PPA were excessive and disallowed cost recovery of the amounts that exceeded Washington Water Power's avoided costs. In other words, the Commission applied the Company's altemative proposaland re- priced the QF PPA at Washington avoided cost prices. What is the basis for your conclusion that the Commission re-priced the QF PPA at Washington's avoided cost prices? The issue presented in the case was whether Washington Water Power's proposed rate revision, which would have included the full Washington-allocated costs of the QF PPA, was just and reasonable. The Commission observed that, "[i]n reaching this ultimate determination, the commission must make the underlying determination whether the proposed purchase agreement is based on a proper methodology to calculate the avoided cost as defined by federal and state laws and rules."34 Thus, the 3r Testimony of David C. Comez, Exhibit No. DCG-lCT at l0 (citing lltash. Utils. & Transp. Comm'n v. llash. Water Power Co., Cause No. U-83-14, Second Suppl. Order, 56 P.U.R.4th 615 (Nov. 9, 1983)). 1a Wash. [Jtils. & Transp. Comm'n v. Wash. Waler Power Co., Cause No. U-83- 14, Second Suppl. Order, 56 P.U.R.4th 615, t983 WL 909042 at 2 (Nov. 9, 1983). - . .Reb-uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E- I 5-0 I , AVU-E- I 5-01 , PAC-E- I 5-03 D, Reading, Simplot/Clearwater Page 34 a. A. a. A. Exhibit No. GND-47 Page 23 I 2 3 4 5 6 7 8 9 l0 lr t2 t3 t4 l5 l6 t7 l8 t9 20 2l 22 a. A. a. A. Commission analyzed whether the avoided cost prices in the QF PPA were consistent with PURPA. The Commission did not simply situs assign the costs to ldaho. In the Washington Water Power case, Staff concluded that the rates in the QF PPA were higher than Washington Water Power's avoided cost and therefore inappropriate. The Commission agreed, concluding that the "amount to be paid under the purchase agreement is in excess of properly determined avoided costs."35 Thus, the Commission disallowed cost recovery of the amounts that exceeded the avoided cost price as determined by the Commission. Applying the same standard to this case would require approval of the Company's Washington re-pricing proposal. Stafftestifies that in the Washington Water Power case, the QF PPA "pricing and terms were driven by Idaho state policies at the time."36 Do you agree with this characterization of the order? No. Nowhere in the order does it suggest that the avoided cost price in the QF PPA was the result of ldaho state policies. [n addition, Staff testifies in this case that once the Commission chose to situs assign the costs to ldaho, the ldaho commission accepted that decision. Again, however, the Commission did not situs assign the costs to ldaho, and the order says nothing about how the Idaho commission responded to the Commission's order. Staffand Boise reject the Company's alternative proposal to re-price the out-oG state QF PPAs as if they were Washington QF PPAs. What is the basis for their rejection of this proposal? The parties argue that this proposal is inconsistent with cost causation and merely 3s Id. at t. 36 Testimony of David C. Gomez, Exhibit No. DCG- I CT at 13 n. 24. ,_n,*?Rts1tfd/estimony of Gregory N. Duvall Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 35 Exhibit No. GND-47 Page 24 I 2 3 4 5 6 7 8 9 l0 ll t2 l3 t4 l5 t6 l7 l8 l9 20 2t discounts the cost impact of state policy decisions made by California and Oregon.37 Boise also claims that the Washington re-pricing proposal still burdens Washington customers with other states' energy policies because there is no way to know if the out-of-state QFs would have been developed if they had been subject to Washington's PURPA policies.3s Does the Companyos re-pricing proposal require Washington customers to pay rates that reflect policy decisions made by other states? No. Re-pricing the QF PPAs at Washington avoided cost prices mitigates concerns that the avoided cost prices for the QF FPAs are driven by policy choices made by other states. The use of the avoided cost pricing for QF PPAs is intended to keep customers indifferent to the QF transaction. If the QF PPAs are re-priced at the amount that this Commission has found will result in customer indifference, then customers will be no better or worse off than they would be without the QF PPA. The parties' concerns that the re-pricing proposal still reflects other state's policy decisions has merit only if one assumes that the Commission's avoided cost prices are excessive. The re-pricing proposal, therefore, ensures that Washington rates reflect only the decisions of Washington policy makers. Doesn't the fact that customers rates will increase by $7.6 million under your re- pricing alternative suggest that the parties' concern has merit? No. The fact that customer rates will increase if they pay the avoided cost prices determined by the Commission suggests that situs assignment of California and 37 Testimony of David C. Gomez, Exhibit No. DCG- I CT at I 5- I 6; Responsive Testimony of Bradley G. Mullins, Exhibit No. BCM-lCT at29-30. 38 Responsive Testimony of Bradley C. Mullins, Exhibit No. BGM- I CT at 30. - . .Reb,uttal Jestimony of Gregory N. DuvallExhibit No. 204 Exhibit No. GND-47 Page 25Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 36 a. A. o. A. I 2 3 4 5 6 7 8 9 l0 ll t2 l3 t4 l5 l6 t7 l8 l9 20 a. A. Oregon QF FFAs has allowed Washington customers to receive benefits for whieh they have not paid. Is there any precedent for this type of re-pricing? Yes. As discussed above, the Commission used this approach in the 1983 Washington Water Fower case relied on by Staff. It is also my understanding that the North Carolina Utilities Commission (NCUC) took this same approach to a QF' FPA that was approved by the Virginia State Corporation Commission (VSCC). The NCUC analyzed the QF FPA and concluded that the pricing exceeded the utility's actual avoided costs.3e The NCUC therefore denied cost recovery of the amount that the NCUC found to be greater than the utility's avoided costs. It is my understanding that on judicial review, the North Carolina Supreme Court affirmed the NCUC's order, concluding that the disallowance "does not violate PURPA to the extent it only excludes the amount above avoided costs."40 I also understand that the OPUC approved a stipulation for ldaho Power Company that required Idaho Fowerto re-price its ldaho QF PPAs to reflect Oregon's non-level ized pricing pol icy.a I Has any party alleged that the Washington avoided cost prices used im the re- pricing alternative pnoposal do not accurately reflect the Comrnission's avof,ded cost prices in effect at the tirne the out-of-state QFs were executed? No. There is no basis in the record to conclude that the re-pricing does not reflect the 'n Re N. Carolina Power,E-22,SIJB 333, 1993 WL216264 (Feb. 26, 1993) aff'd sub nom. N. Carolina Power, 450 S.E.2d 896. oo State ex rel. Lltilities Comm'n v. N. Carolina Power,338 N.C. 412,450 S.E.2d 896, 900 ( I994). Importantly, as I discuss above, since this case, FERC has been clear that PURPA prohibits inflating the avoided cost pi'ice as the VSCC apparently did to promote state policies. ot Re tdaho Power Co. , Docket No. UE 257 , Order No. I 3- I 66 (May 6, 20 I 3 ). o. A. - . .Reb.uttal Jestimony of Gregory N. DuvallExhibit No. 204 Case Nos. IPC-E- I 5-01, AVU-E- l5-01, PAC-E- l5-03 D. Reading, Simplot/Clearwater Page 37 Exhibit No. GND-47 Page 26 I costs that would have been incurred if the out-of-state QF PPAs had been executed in 2 Washington. 3 Q. Staffand Boise both reject the Company's alternative load decrement proposal 4 because they claim it is based on power flows, not cost causation.42 How do you 5 respond? 6 A. The load deoement approach is consistent with cost causation. No party disputes that 7 the out-of-state QFs serve Washington customers. Washington customers, however, 8 are not paying their fair share of the costs by paying only current market prices. The 9 load decrement altemative is intended to account for this fact by allocating additional l0 costs to Washington to reflect the benefits Washington customers receive. I I a. Boise claims that the load decrement approach is unreasonable because it would l2 assign more transmission costs to Washington customers even though the l3 presence of QFs in California and Oregon does not reduce those states' use of l4 the Company's transmission network.a3 Does this claim have merit? l5 A. No. Again, no party disputes that the QFs located in Califomia and Oregon serve l6 Washington customers. As discussed above, Boise's trade group, ICNU, previously 17 testified before the OPUC that distributed generation, like the out-of-state QFs, l8 typically decreases the need for transmission because the electricity is generated l9 closer to load. This is particularly true for the out-of-state QFs because they are 20 typically located closer to California and Oregon load and therefore use less 2l transmission to serve that load. So it is reasonable to credit out-of-state customers for 22 reduced transmission usage due to the QF development in those states. a2 Testimony of David C. Gomez, Exhibit No. DCG- ICT at l5; Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lcT at29. o3 Responsive Testimony of Bradley C. Mullins, Exhibit No. BGM-lCT at29. _ . .Reb.uttal Jestimony of Gregory N. Duvall Exhibit No. GND-47Exhibit No. 204 case Nos. Ipc-E-15-01, AVU-E-15-01, PAC-E-15-03 Page27 D. Reading, Simplot/Clearwater Page 38 I 2 3 4 5 6 7 8 9 r0 ll l2 l3 t4 l5 l6 t7 l8 l9 20 2l 22 23 Boise claims that it would be unjust, unreasonable, and illegal to include the costs of the out-of-state QF PPAs in rates, in part, because the Commission does not have jurisdiction over the QFs.nn Is it your understanding that the Commission must have jurisdiction over PPA counterparties to allow cost recovery of the PPAs in rates? No. Most, if not all, of the Company's long-term PPAs are with counterparties that are not public utilities regulated by the Commission. Nevertheless, the costs of these PPAs are regularly recovered in rates. In addition, PURPA specifically exempts QFs from regulation by state utility commissions. What is the Company's recommended treatment of the costs associated with California and Oregon QF PPAs in west control area NPC? A. The Company recommends that the Commission allow the Company to include the costs of California and Oregon QF PPAs in west control area NPC in the same manner as all other west control area generation resources, with a portion of the costs allocated to Washington customers. Altematively, the Company proposes the out-of- state QF PPAs be re-priced using Washington avoided cost prices and then included in the determination of west control area NPC or that the Commission adopt the proposed load decrement adjustment. Energy Imbalance Market a. Please describe Boise's adjustment to NPC related to the EIM. t A. Boise proposes to reduce Washington NPC by more than $5 million based on the Company's participation in the EIM, while also including certain EIM-related costs. Boise proposed this NPC reduction in October 2014 before the EIM even began oa Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-lCT at25. ,_nrfi,$t1t1dfestimony of Gregory N. Duvall Exhibit No. GND-47 Page 28Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/Clearwater Page 39 a. A. o. a. A. Does this conclude your rebuttal testimony? Yes. ,_r,fi?ktsgEfestimony of Gregory N. Duvall Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, Simplot/C leanrater Page 40 ExhibitNo. GND-47 Page 67 BEFORE TTIE IDAHO PUBLIC UTILITIES COMMISSION CASE NOS. IPC.E.I5.OI, AVU.E-I5-O 1, PAC-E.I5-03 J.R. STMPLOT COMPANY AND CLEARWATER PAPER CORPORATION READING, DI TESTIMONY EXHIBITNO.2OS TTffi An lol\coRP company DOi{OVAN E.WALKER loed Gounrel dwal ltar0dahooowea corr April 15,2015 VIA HAND DELIVERY Jean D. Jewell, Secretary ldaho Public Utilities Commiesion 472 West Washingrton Street Boise, ldaho 83702 Re: Energy Sales Agreements Terminations Case No. IPC-E-1+28, Glark Solar 1, LLC Case No. IPGE-14-29, Clark Solar 2, LLC Case No. IPC-E-14-30, Clark Solar 3, LLC Case No. IPGE-1+3'|., ClarkSolar4, LLC Dear Ms. Jeuoll: On April 6, 2015, ldaho Power Company ("ldaho Pouref) terminated the Public Utility Regulatory Policies Act of 1978 ("PURPA") Energy Sales Agreements ('ESAs') with each of the above-referenced PURPA qualiffing faclllties ("QF"). Each of the rsferenced QF ESAs was approved by the ldaho Public Utilities Commission ('Commission') by Order, as noted in the table below. ProJect Gase Number Order Number Date of Oder Clark Solar 1, LLC IPC-E-14-28 Order No. 33208 01108/15 ClarkSolar2, LLC IPC-E-14-29 OrderNo.33209 01/08/15 Clark Solar 3, LLC IPGE-1+30 Order No. 33204 01/08/15 Clark Solar 4, LLC !PGE-14-31 Order No. 33205 01/08/15 Enatas to Order Nos. 33208 and 33209 were issued on January 9,2015. The ESAs require that a Security Deposit be posted within 30 days of final non- appealable Commission orderc approving the ESAs. The required Security Deposits were not paid, and ldaho Power provided Notice of Default and Material Breach on March 2,2015. Subsequently, ldaho Power and the projects' developer, lntermountain Enegy Partners, LLC, entered into an agreement (attached hereto as Attachnrent 1) 1121 W ldaho 5t. (83702) P'o' Box 7o Exhibit No. 205 Case Nos. r pc-E- r s -o f,"AVB-t113-o r, pAC-E- I s-03 D. Reading, Simplot/Clearwater Page I Jean D. Jewell April 15,2015 Page 2ot2 setting forth the agreed to provisions by which the projects were to cure the Material Breach of the ESAs. The Security Deposits werc not so posted for the above- referenced Clark Solar prcjectsi thus, the associated ESAs werc termlnated as of April 6, 2015. The Security Deposits for the Mountain Home Solar and Pocatello Solar projects were paid according to this agreement and thus were not terminated. To keep the Commission apprised of these terminations, ldaho Power has enclosd an original and four (4) courtesy copies of this letter and its attachment for your convenience. Please contact me if you have any comments, questions, or @n@ms. DEW:csb Enclosurescc: Dean J. Miller (dencl.) - via e-mail Rick Sterling (w/encl.) - via e-mail Donald L. Howell, ll (w/encl.) - via e-mail onovan E. Walker Exhibit No. 205 Case Nos. IPC-E- l5-01, AVU-E- 15-01, PAC-E- l5-03 D. Reading, S implot/Clearwater Page 2 .:: ] ::.:: r r..,rii., J4 7ii, :' i.:. :r: ' ftffi*. An roACOnP Comprny DONOVAI{ E.WALKERLrd Gounrol@ March 17,2015 loe@ mcdevit-mlller. om Dean J. Mller licDevitt & Mlller LLP 42OW. Bannock Strset P.O. Box 2564-83701 Boise, ldaho 83702 VIA ELEGTRONIC MAIL Re: Securfi Deposlts - Mountein Home Solar 1, Pocatello Solar 1, Clart Solar 1, Clark Solar2, Clark Solar 3, Claft Solar4. Joe: ldaho Power ls in recelpt of the memo from Mark van Gulik dated March 17, 2015, regardlng the speclflc amangements being pursued by lntermountain Energy Partnere ("lEP') to curo the material brsach d the Energy Sales Agreements ('ESA') fur each of the aborre rcferenced solar proiects "aa expeditlously as posslble." ldaho Power will accept your proposed sch€dule of erents outlined ln your tvlarch 17, 2015, memo urhlch outlirps rctlvltles startlng today to securc the neceseary deposits and continulng throtlgh the strated deadllnes of March 31, 2015, br Mountaln Home Solarand Pocatelb Solar- and AprllS, 2015, for Glark Solar 1 though 4. ldaho Porer will further accept the proposal of a "Non-Appealable- agrcement and provlslon that lf the deposlts ere not pald ln acoordance wlth lhese dates, that the Energy Sales Agraements wlll immedlately termlnate, and that IEP will not conbet he termlnation at the ldaho Publlc utillties Corynisslon, or elsewhere. Because of the shortness of tlme before tomonords ESA termlnatlon deadllne, please let thle letter sorve as botr parties'wrttten acknodedgement of thls agrcement: Consequently, both ldaho Power Company and lnternrountaln Energy Partners hereby agr€e that the final ard deflnitfua deadllne with wtrich IEP ls to cure th€ meterial breach of the ESAs for each of the above rcfenonced solar profects under contract wlth ldaho Power is March 31, 2015, for Mountaln Home Solar and Pocatello Solar - and April 3, 2015, for Clark Solar 1 through 4, as set forth ln lEPs March 17,2A15, mofilo, incorporated herein by thls refer€nce. IEP ehall cause the approprlate amount of security deposit, as referened ln each propd's respectlve ESA, as well as in ldaho Power's March 2,2015, Notlce of I 22 I w ldaho 5l (81702) P.O 8or r0 8oise, lO 83?07 Exhibit No. 205 Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 D. Reading, SimPlot/Cleanvater Page 4 Dean J. Mller March 17,2015 Page?ot 2 Default Material Breach - and ldaho Porve/s Ularch 4,2015, Notle to Tarmlnate, to be poeted on or before 5:00 p.m., rpuntaln tlme, on Tuesday, Mardt 31, 2015,6rthe Mountraln l-lome Solar and Pocatello Solar projects - and on or before April 3, 2015. for Clail Solar I, Clark Solar 2, Chrk Solar 3, and Clark Solar 4. lf lhe required security deposit ls not paid by these deadlinee, then each assoclated ESA will immediately terminate. IEP rrdllacoept eald temlnatlon and shall not contest said termination in any manner vutrat-so-ever, elther ln law or equlty, before the ldaho Public Utlllties Commlsslon or any ottrerforum. ldalp Poruer undertards from lEFe March 17,2015, m€rlo, and fiom lts conv€rsatlons wlth Mr. uan Gulik, and Mr. Mlller, that the rcqulred securfry wlll be posted in cash. lf an alternatiw mehod ls utllizod (1.e., lette(s) of credit or parent guarantees) then the neeseary arangemenb and apprcvale of such alternath€ methode must be completed on or before the deadllne, or the deadllne shall bE deerned to haw NOT been met. lf thls ls agrceable, please execute thls letter below and retum a slgned copy back to me. Lead Counsel ldaho Power Company Agr€ed to and Acceiled by, on behatf of lntemountain Energy Parhers: DElfi/:csb CG: Exhibit No. 205 Case Nos. IPC-E-15-01, AVU-E-t5-01' PAC-E-15-03 D. Reading, SimPlot/Clearwater Page 5 REQHFSJ EgR PRODUCTIOi|.iIO.22: ReErence the Gornpanfs reoponse to J.R. Simplot Co.'s produc'tion request no. 4(a)-(c), indilrting that of fie 48 prospective solar QFs comprising the 885 MW of solar QFs that werc in the quoue at the time ldaho Porer filed the application in his @s, 23 had not ernn provUed enough Information b ob0ain indicatlve prlcing and only one prcjec.t had provlded enough lnformation to ldaho Porerb obtaln a drd FESA underthe IPUC tar]ff. a. Please prcvide an update to the bble supplled in Esponse to rcquet no. 4(a)-(c) and for the prcje6 that have not prwided enough informatbn to etren oHain lndlcaWe prlcing please also erqlain what lnfurmatbn uns supplied to ldaho Pouerthat leds lt to belleve the project rvas llkely to be constructed and soll lts ou$ut to ldaho Porrer. Please also provide an update of the number of prolrts and ltMl capacity hat are stll ln the PURPA queue and adlvely seeking FESAS. b. Please staE the number of poieds and irW of capaci$ that have provided ldaho Power with widence that they pooseee slte contol in the foim of real property rights trc develop the project. c. Does ldaho Power agl€e that herc h hsuffident irfrrmation to conclude fiat the 880 [rfW of proJeds are likely to be bullt and sell thak output to ldaho Pqruer? lf not, please erglain ruhat information or basis ldaho Pqrcr relies upon and provide all supporting documenG. RESPCIilSE TO REQUEST FOR PRODUCTIOil NO. 2?: ldaho Porrer obiects to the premise of thie Requct that ldaho Poiler has made any asse$sment as to the viability of any proioct. ldaho Power prcvided a list of pCIecG seeking ES&. ldaho Power is unable to reconcib the ruferenced teblewtth the count of 23 projects identifted. IDAHO PdI'ER COMPAiIY'S RESPONSES TO THE SECOND PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPAI.IY . O Exh Case Nos. IPC-E-15-01, AVU-E-l: Witness: _ The table rebrenced includes proposed qualifying facility ('OF') proitcts in both the sffie of ldaho and Oregon; 22 of the ldaho ploiecls rruerc identificd as having nd rcceived indicative pdcing and 11 of the Oregon prcjects had not rcceived indicatiw pricing at the tlme lhe information was collected for this table, a. The updabd tabl€ is provHed below, the ltems highlighted in yellow are revisione to the table as originally provided in ldaho Pouuer's rExiponse b Simplofs Request for Production Nos. '1.a4.c. ldaho Porer includes on this listing, not only he proiects hat have prcvided enough irrformetlon to obhln lndlcatlve pricing, but also proiect requests that have provided inbrmation beyond an initial lnqulry that fiE proiect has potential d being viable. This infurmation is in numerous forms: complete or partial Scherlule 73 or 85 applications, detailed contrac't questions beyond initlal lnquiry, +mails or letters of apparent intent, detailed phone inquir'ns, interconnection inquiries, etc. ln many instances, a single piece sf information does not wenant including a propoocd prciest on this list, but a snbination of various pieces accurnulabd that suggest a proiec{ may be viable. The last part this Request asks br infurmation on poiecb that are "etill in the PURPA queue and actively seeking FESAS.' The updated lbt prcvidcd in rcsponsc b the iniUal pert of this RequeEt is a list of PURPA proiects that have srcntected ldaho Povrcr with varying degrees of interest and that are e€eking PURPA contracrts with ldaho Porer. The levpl of 'activitt' sf each of thee proposed projects differs by project and by day. This updaEd list includes an additlonal 15 proiects for 331 ltIW of potential project that have contacted ldaho Power since the preparation of fie hble provided in IDAFIO POA'ER COMPANYS RESPONSES TO THE SECOND PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY. T Exhibit No. Case Nos. IPC-E-l 5-01, AVU-E-15-01, PAC-E-15-03 Witness: the Company'e response to Simplot's Requeet fur Produdlon No. 4. The btal number of pobntial PURPA proiece is nor 73 proiecrts for 1,326 MW. ld.ho ltwtf Comprny Frcpo..d.PURPA Solrr. & or&il.+le# Apdl 22, r01S Proulded All lnhrmeUon as requlred ln Scheduh 73 to obtaln lndlcadrc Prldng (Sdedule 73 ltems l.a.Frlv, pa[Bs 4 and 5) or equlvalent lf proddcd bcfore Schedule 7il process lnluated SE Prorlded All lnbrmatlon as rcqulred ln fthedule 73to otrrln a draft energy sales agreement (Sdtdule 73 items 1.e.1+v, pageg 5 and 6!or equivalent lf provlded before Schedule 73 process lnltated ProJectAl Prorcct Az Profed A3 ProJsct M Prolect 81 ProJcst 82 ProJect Cl Pdectc2 Prolect Gl Prolect C4 Project Cs Protct C6 ProJect Cl Project C8 ProlctCE PmJect clo Prolect Dl Prolect Dz Prolect D3 IDAHO POVI'ER COMPAT.IYS RESPONSES TO THE SECOND PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY. E Prolect is ln compllance wlth Sdredule 73 P*Ft, subpart 1.n or equlvalent lf process was lnltlated before Schedule 73 prccess was lnlfleted tnterconncctlon Queue fi 1 2 3 4 5 6 7 t 9 t0 11 t2 13 t4 15 15 77 18 19 Yrs Yes Yes Yes Yes Yes Ye3 Yes Yes Yes Yee Yes Yes Yes Yes Yes Yes Yes Yes Ycs No No No No No No No No No No NO NO NO No No l{o No No Ycs Yes No No Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Ves Y, si Ilca Exhibit No. Case Nos. IPC-E- I 5-0 l, AVU-E- l5-01 , PAC-E- I 5-03 Witness: z0 2t 22 23 24 E 26 n 28 4' 30 31 t2 :t3 34 35 36 37 38 39 /o 4L 42 'lil u 4ti 6 4t IDN{O POWER COMPANYS RESPONSES TO T}IE SECOND PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPAf'|Y - 9 Exhibit No. Case Nos. IPC-E- I 5-01 , AVU-E- l5-01, PAC-E- l5-03 Witness: Project D4 i ProJect El Project E2 Prolect E3 Project E4 Proiect E5 ProleEt E6 Prolect E7 Pmrect E8 Pro.lect E9 Prolect E10 Proiect El1 Profect E12 Profect F1 ProJect Gl ProJect H1 No No NO NO No Irlo NO Irlo No No No No No No No NO No ilo No No No No No No No No No No No No No Yes Yes Yes Yes Yes Y6 Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Proiect l1 No No Yes PropttBB Ilo Yrs tl84 Y63 tl0i Ycs llo Yes Prclect D5 Yce Ilo Yer Prof.Gt D6 Ycs llo Ycc ProlGcl tl llo l{o Ycs to Yas Ilo Yes Prolect Ol t{o ilo Yes tl8g ldaho ?ounrGompmy hepos.d runPA So|er - Ar of l.rnrre$f,t}l}Aprfl ZZ, t0t5 Orut Sdrcdub 73lr nc rpplbbh tn OtCmProjcciflamc ProJectJl Prolect E13 Prolect n Prgject (2 ProFCfS Pml€ct K4 Prclest tG ProJect (6 Proloct ro Plolect ft Frolect rg ProJect t(10 Prolccr Ml Prolect IUZ Prclect Mi Prol€ct M4 P.roisct tVtS PmFcUr ProfECt tlZ Prolecr f,t P6lc.ct t{a Prol.qt I{5 Prolcct ttl6 Eotcr Pl PlolectQr Prolrt,Gl2 Yes -Sdredule 85 Publlshed Rates No NO No No No No No NO NO No No Ilo to llo t{o Ito llo llo l{o ilo l{o ilo ilo ilo ilo Yes. Sdredule8li Process No No No Ns No No N9 NO No No Irlo ilo ilo ilo llo ilQ ilo llo t{o NO l{o No No ilo ilo 479 o4 47L 4'-n {75 4ro 4gt ffi 8t .188 fvA N/A 1{/A fvA N/A N/A N/A NIA N/A N/A N/A N/A rv,l il/A tr/r n/A ryA il/n il/E rv^ lUe N/A r'uA ilrA iyA il/A 458 4r8 4tl {8 49 50 51 52 53 54 55 55 57 5t 59 50 61 62 63 6t 6t 66 61 6E 69 ,0 7t 72 7t IOAHO POVI'ER COMPANYS RESPONSES TO THE SECoi.ID PRODUCTION REQUESTS OF THE J. R. STMPLOT COMPANY . 1O Exhibit No. Case Nos. IPC-E-l 5-01, AVU-E- I 5-01, PAC-E-l 5-03 Witness: b. None of the projects Ilsted in the uNabd table profited in the Compan/s response to Simplots Request for Production No. 22.a have prcvided specific inbrmation on site control. As this bble indlcates, only one draft contac{ has been prolded and the request ftr that dmft contract was made prior to Schedule 73 being approved by the Commiaeion. Schedule 73 eehblighd the speciflc requircment to provide evidence of site control prior to a drd contract being provided. c. This Requeat rebrcnes 880 lUl l of proiectg. Thb msponse is based on an assumption that the Request intended to rehrenoe he 885 lvMl etated earlbr in thls Request. No, ldaho Porrer doeE not agree. In addltion, as indlcated in the Companfs response to Simplof Request br Produclion No. 22.a, the 885 tllMl has norv grown to 1,326 lvtw. lndividual QF prcjects are in sole control of the viability, contractirq prooeoo, construc{ion prooess, and time lines of fteir specific proFsts and ldaho Porpr has no infurmation to definitive[ determine what propooed projec{s do not inbnd to comphile their respective prcjects. The response to thie Request is sponsored by Randy Allphin, Energy Contracts Coordinator Leader, ldaho Power Company. IDAHO POWER COMPANYS RESPONSES TO THE SECOND PRODUCTION REQUESTS OF THE J. R. SIMPLOTCOMPAI.IY -'11 Exhibit No. Case Nos. IPC-E-l 5-01, AVU-E-15-01, PAC-E-l 5-03 Witness: REQUEST ilO. 11: For each PURPA contrac{ where the price wae set (or b be tet) uslng an IRP Uldrodology, phaee proWe the fullowlng: a. fne Oate that fie QF orlglnally submltted a reqrret fur confiact approrral: b. The date that the contnac't urae apprcv€d by the Commlsslon; c. The Comrnisgion case numbeG d. The nameplab capacity; e. The type of prclec{ (wird, solar, cogoneration, etc.); and f. The contracted prlm turthe purchas of the wtput of the facility. BESPOilSE,,TOi,RFQUEST,U.O,? lf : hbrmation for 'set (or trc be sd)' ls requested; horevar, itenr a thmugh f rcquest infunnatbn ln rugads b slgnd and Gommisslon-appmvad contracts and muc{r of the rcquested lnbmatlon does not yet ExiS fur oontracts hat prices ang 'b be sst' Thenrbrc, ldaho Povusr has provlded inbnnation fur only proiects hat lndude IRP methodolory priclng, have been slgned by both parties, and submitted to the Gommiedon Equeding it to elther amept or reject the contract. a. The qualifying fadity does not submit a request fior corrtnct apprcval wltr the Gommlsslon as sugpested in this Request" lnstead, after both parties harra executed a contract, ldaho Porer pr€par€B an application and fllee thls wlth the Commlssbn rcquestlng lt b elther accept or mJec't the contnct. ThE table below lists pofects submitted to the Gommlsslon b dab. rffi Amerlcan Falb Solar, LLC Bolsa Clty Sol*, LLC Oark Sdar I, LLC ClarkSdar 2, LLC OarkSolar 3, LLC IDA}IO POWER COMPANY'S RESPONSE TO THE IDAHO 1W?oA0/.4 07nffiofi 1U17nO14 1U172.014 w17m14 IRRIGAT]ON PUMPERS ASSOCIATION, INC.'S FIRST DATA REQUEST.lT E 'a20TCase Nos. IPC-E-I5-01, AVU-E-I Fe. The trble below llsts prolects approwd by the Cornmission to date. Gommhrlon l{ernopldr Typr of Prclrd ilmc AnprwelDdc Gfi? t{u,Fber Crprclty (ltlw}, Plpfect'AmerlcanFills solar ll, LLC 1i2ruil2e;11 lltc-E-11-35 20.00 solar Clark Solar 4, LLC GmndVleur W SolarTrro Mqnhln HomeSolar, LLC Murphy Flat Porrver, LLC Or*ard Ranch Solar, LLC Poca6[o Solar 1, LLC SlmoSolar, LLC Tuana Spings Erpanslon Rockl*rdWind Farm HBh Mesa Wlnd Proiect Amelican Falls Solar, LLC Boise CltySolat LLC Clark Sohr 1, LLC Oark Solar 2, LLC Oark Solar 3, LLC Oark Solar4, LLC Gnard Vlenltr PV SolarTulo Murphy Flet Porer, LLG Orchard Randr Solar, LLC PocatelloSdarl, LLC Slrnso Solar, LLC Tuana Sprlngs Expanslon Rockland Wlnd Farm Hlgh lulesaWlnd Pn{r.t $tflnofi s?nd2014 lUfin0/.4 $n0m11 $nw,,J14 lW'.En0,.4 $120m14 0u11200s 09,0El2010 fnun11 1Pliltfnl4 |PC.E-!4-34 20.00 Solar 1111412014 IFGE-14-20 /O.0O Sdsr 01rc12015 IPGE-14.28 71.00 Solar 01O1/2015 IPGE-1'|-29 20.00 Soler 01O112015 IPGE-14-30 30.00 Sol* 01,0112015 IPGE-14-31 20.00 Solar11n4nffi4 PGE-1'I-19 80.00 Solar fin$2{014 IFC-E-1+3,! 20.00 Solar 1A292.014 IPC-E-1tl-36 20,00 Sohr 011082015 IPGE-1'|-27 20.00 Solarlzngn0il |PGE-1/[€3 20.00 Sdar 10O5,2009 IPGE{9-24 35.70 Wind 11nffZ010 PGE-10-24 80.00 WrdOAfimlz |PC-E-11-26 40.00 Wnd Mountraln Home Solar, LLC 01/012015 IPGE-14-20 20.00 Sohr f. All of the contrac'ts llsted above contain a flxed schedule of non{ewlized prices; therefore, there are dlfferent prices fur each y€ar and, ln eome cases, fur eadr month and br heavy load and light load hours. Provided below aro estimetEd levellzed prices that are calculated baeed upon the non-levelized scheduls of prices mntained in each of the abovelistod oontrac$. These levellzed prlces ate not speclfically stated in the oonhach but are commonly used to provlde general inbrmation. IDAHO POWER COMPAhIYS RESPONSE TO THE IDAHO IRRIGATION PIJMPERS ASSOCIATION, INC.'S FIRST DATA REQUEST.lE Exhibit No._ Case Nos. IPC-E-l 5-01, AVU-E-15-01, PAC-E-15-03 Witness: _-Prplrct Nlme Gdflld.d L.EIE d R*. (fntWhl Amorlcan Falle tlolar ll, LLC $02.06 Amedcan Falls Sdar, LLC Bohe City Solar, LLC OakSd* 1, LLC ClarkSda2, LLC Clark Sdar 3, LLC Clark Solar4, LLC Grand Vlew PV Sdar Ttro Mo.rnbln HomeSolar, LLG Murphy FlatPorcr, LLG orcirard Ranch Solar, LLC Pocatello Solar 1, LLC SlmooSolar, LLC Tuana Spilngs Expanslon ' RocklandWlnd Fam Hbh MesaWlnd ProJect $63.01 $72.15 059.07 s61.03 $60,07 $40.87 $73.41 $81.43 $0it,e, w.21 $E1.33 $63.94 $75.5i1 $71.29 $56.40 *Nots: The Tuana Sprllqe Epanslon $,ss a nsgotletod combhetlon of an exbtlng contact wlh a narconbactfuraxpamlon dthe odrffng proFct ln tltae n€gotle0ons, he rralue of he exlailng conbact rva melnElned and the oeanelon was valued at an IRP-baeed value and ttre tuo prlcq ruere then blendqd togeths to crpsto the monthly energy prlcc. The value lletsd b UE le\,€lized value d thle ncgotlated blended value. The responee to thie Request is sponsored by Randy Allphin, Enelgy Contracts Coordinator Leader, ldaho Poriler Company. DATED at Boise, tdaho, this 11h day of l/*.\_ DONOVAN E. WALKER Atbmey br ldaho Power Gompany Exhibit No. Case Nos. IPC-E-15-0 1, AVU-E- I 5-01, PAC-E- l5-03 Witness: IDAHO PO/I,ER COMPANY'S RESPONSE TO THE IDAI-IO IRRIGATION PUMPERS ASSOCIATION, IT{C.'S FIRST DATA REQUEST - 19 REOUEST NO. 0: Ploase provlde a copy of all 20-year hvellzed avoldd cost indlcathrc prie,es prcvlded b the developers of any or all of he solar pmfects oomprlslng the 885lvlw of potential nor prcJects rebned to ln ldaho Povrc/s Petition. RE9FOI'ISE TO REQUEST 1{O. 9: Of the 885 tulW of potentlal prolects, 16 prolects for 368 [vlW have been provided some ftrm of avoided ost indlcatlve prldrU. Two of the solar prolec'ts were povided 20-yEar avoided cost lndlcatiw pncing prlor b the fillng of this case. Prclect Name as Gontrincd Wlthln Allphln Exhlbit No.3 Estlmabd lowllzed lrtlUtrt ProleetAl $52.83ProJectA2 $54.10 The responee to ttrls Request is sponsorcd by Randy Allphin, Energy Contracts Coodinabr Leader, ldaho Power Company. IDAHO POWER COMPANY'S RESPONSE TOTHE FIRST PRODUfiION RECIT'EST OF THE COMMISSION STAFF. ,I5 Exhibit No. Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03 Witness: IDAIIO PflUER@IFAT$r AVOIDED COST RATES FORWIND PROJECTS Juna l,2016 l,illlrt/h Neu Gonl}rctt and Reohoament Confrnct rrrlthari Fu[ Craeclt Prvmsntr Ellglb{ll[ for thccc tab! lr llmlted to pmlccte 100 kW or amallcr. LB'ELtrED ilOIII.LEVELtrED ON.LINE YEAR CONTRACT Y.EAEI NONSI..ilELtrED RATEs LEIIGTHftfatrsr 2015 z0t6 2{J17 zol8 z01s *20 I 2 3 4 3I 7 8 t, '10It 12 t3 l,[ 15 IE 17 l8 te 20 !l:!.36 03.70 3s.s2 34.31 36.17 38.24 3?.46 3E.06to.l0 41,0S 42.08 42.E8 /03,80 r14.50 43.13 45.70 8.278.4 17.* 47,68 34.00 u.2g 34,66 35.zl 36.S6 98.@ 10.04 41.r1 42.311 43.1t5 14.U 45.20 45.S' ,|6.57 t7.18 47,14 48.31 48,87 40.42 49.97 u.42 35,0t sE 36 t7.u s9.77 41,35 42.e7 43.7E 44.t5 45.t6 i16.78 41,62 48.t7 18.77 40.3t6 19.94 50,51 51.07 51.65 3r2.A 35.68 37.{0 :n.17 41.3e '[3.@41.17 tl6,Eg {8.8E 47.73 '16.ts{s.t? 50.0t 50.60 5t.19 51.76 5r.35 52.92 68.51 54.10 6tt,6t m37 ,4.0541.14 .15.9943.61 17.66t15.33 4t.Eea.88 ae.8a47.75 50.86 {t 6'1 51.8748.44 EiL71il.tt 33.375'.1.12 33.94s2.00 il.475e60 65.0253.t7 55.5033.75 36.15%.92 *.73 stt 89 5?,8355.{S t.9556.0S 5E.5.t58.87 59.1757.28 59.8s s15 ?J'.l6 fr17 2018 20ts 2020 2021 N:82 M:E ?0i21n2sNNtxfl mzB ?,,2gmfi 2031 8:t2 zn3 2fit4 2035 2036 2037 203E 2039 2040 0s.t6 t4.08 u.42 Eti.E9 39.37 {s.05 {0.t7 5t.a0 59.28 54.50 s7,2il 6S,e1 60.E6 ci.00 6i.t8 e,9t e4.s6 67.39 G9.48 7r.e3 75.fi 78.6'l E0.s5 84.E6 e0.07 95.53 Not6: Th€86 rabs wlll be furth€rdjudsd wlh he appllcau! lnbgralbn durgs. Not€: The rat€s sho$rn ln thh tsble have bsen computEd uslng the U.S. Eneny lnfrcn.tlon Admlnl.ttadon (EA)'s Mnud Engey Ou0ook 2015, ntaaod Apdl 14 20.15. Sco Annual Eneqry Outbok 2015, T.bl. 3.E EnG,ly Ptlcae b, Sasbr-ilhlxrtein st htlp:/ivrrw.eia. govlbracarls/rao/labler-raf .cfin#iuPplemenu IoAHO POWER COMPANYPTg€ 1 Case Nos. IPC-E-15-01, AVU-E-l5r Exhi baaWitness: tDAlto PotilERcouPAitY AVOIDED COST RATEg FOR SOLAR PRq'ECTS June l,20{5 lrlluth New Gontccils and Rcolacement Contncts wlthout Full Caoecltr Pavmentg Ellglblllty for theee tatee 18 ltnlbd to proloctr 100 kW or amrller, LEVEI.IZED NOI{.l.B/EUZED ON.LINE YEAR @NIRACTIfiAEI NON-TEVELIZED RATES LENGTH ,YFAPII 2015 2018 2017 mt8 2010 2n26 1 2 3 4 5I 7II 't0 1t 12 ta l4 15 16 1T t8 19 20 3t.38 33.?0 33.92 34.31 35.17 *.24 10.!N 4.1.69 17,76 50.32 5257 54-50 58.S5 57.8€ 59.,t9 60.39 61.51 6i1.56 fi,.55 84.49 3{.(E 34.2t 34,68 35.72 36.96 42.53 {6.E7 50,2E 5:r.05 5!t.48 5?,50 50.43 80.99 m.35 63.58 u,13 6Ii.60 86.81 67.n 88.70 u.42 35.03 36,36 3?.Btt 14.73 /t9.68 53.42 56.36 58.91 61. t3 83.01 6,t.59 65.97 67.20 6E,35 69.43 70.45 71..1t 72.35 73.27 35.69 37.46 39.17 47.a8 53.50 57.55 80.62 63.20 c5.44 67.3r 8&86 70.t9 7t.39 72.51 7S.57 71.57 75.52 ?8.{5n.# TC.U c9.3? 43.05{1.14 €0.0352.€0 €0.5058.90 fO.868.05 7L7A66.04 74.EE8E.52 78.6970.€5 78.197i2.41 70,4073.84 80.4375.07 81.377Ar7 82.26n,21 E0.t71E.21 84.037S.1€ E4.66t0.07 E5.73E0.96 E8.5881.87 87.39c2.71 dA.2283.56 69.07 2015 2016 N17 2018 2019 20at n21 fi22 ?o2' a,24 m25 N,I/BNN $28 20?s 2030 2031 fr82 203:t 203i1 2036 2036 Ng? 203E 2039 2040 t&s6 s4.06 34.42 it6.69 39.37 $.05 7!.40 0't.07 E3.35 8r,.12 aa22 91.95 c2.75 93,37 94.51 9C.23 98.70 101.69 1fx.,8 107.25 I 1,l.1,{ 1't4,08 117.4 122.31 120.05 134.07 Note: Those rstas will ba turthor adlusted with th6 applicable intsgrallon charg6. NoE: Th. rales shorrn in thiB trbl€ hsve besn oomput€d ustrg lhe U.S. En€rgy lnformauo{r,Mnrinlstrauon (ElA)'s Ann@l Enoqy Oullook 2015, rEhassd Apdl l4 2015. SE3 Annual Energy Outhok 20lS, Tabl6 3.S Energy Pdcas by llcc{or-Mounlah at htlp://www. eia. gov/forecaebla:dlaHes_mf .c{n#upplemenU TDAHO POWER COMPANY Psse 2 Exhibit No. Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-l 5-03 IDAHO POVI'ER GOIIIPANY AVOIDED COST RATES FOR NON€EASONAL HYDRO PROJECTS June l,2015 $dwh Ncw Contacb and Raolecameni Contrectr wlihout Full Caaaclhr Paymen6 Ellglbllity for these rebs h fimlted to prolecb Emaller thrn l0 aMW. I.EVELIZED NON.LE\'ELIZED ON.LINE YEAR CONTRACT rrEAE NON{EVELIZED trATF.S LENGTH IYFAP.CI 2015 2016 a)17 2018 2019 20tm 1 2 3 4 5 B 7 8 9 t0 11 12 13 l4 t5 t6 17 18 19 20 33.38 33.70 33.9'l 34.31 35.17 3A.24 10.o2 .14.13 47.O2 18,42 51.55 53.47 55.13 50.56 57.A s&97 80.00 81.tH 6't.98 62E8 34.ffi 34.23 3.1.88 35.72 :m.96 42.m 4s.21 4s.11 52.01 81.28 56.3'l 56.& 59.52 60.d2 61.9S 83.08 04.t I 45.07 65.9€ 68.E8 u.12 35.03 36.38 37.84 44.25 48,65 52,37 55.16 57.54 59.€5 61,43 a2.u u.24 65.41 €6.5't 67.54 6E.51 69.44 70.34 71.22 35.8S 37.46 3s.17 47.23 52.49 58.28 59.16 01.00 63.12 65.40 66.06 60.23 69.37 70.44 71.45 72.41 73.U 14.23 75.1 I 75.94 39,37 43.0541.14 50.675r.72 84.6757.58 68.1881,48 70.53u.27 72.5166.80 74.28E6.63 75.?270.30 76.E771.66 77,8672.E3 78.76?3.86 79.6374.88 80.s075.84 8't.33f6.75 82.1477.63 82.9778.50 83.80t9.37 E4.50eo.la 85.408r.01 E6.23 2015 2014 zAfi 2018 2010 2020 2021 2022 2flit3 2024 z02s 202fJ 2M7 mzB 2VZ9 2030 2qll ztB2 2033 2034 2035 2036 zo37 1046 2049 2040 33.36 34.08 31.42 i]5.69 39.37 t13.05 75.58 76.19 80.43 82.16 65,2'l 88.30 89.0!i 00.23 9,l.ilt 92.99 95.50 sE.36 100.9{, 103.82 t07.68 I 1 1.45 I 1 3.80 118-87 124.37.l30.33 Noia: The ratEs shown ln lhl8 tabl€ have baen computed using hc U.S. Encrgy lnlbrmationAdmlnlslrauon (ElAls Annual Engrgy Outlook 2015, releascd Aprll 14,2015. Sce Annual Energy Outlook 20i5, Tabh 3.8 Energy Prlces by S€ctor-Mountdn at htp:l,\wvw.eia. gov/6rlcasls/aeo/tab16s-rut cftn*supplomont/ IDAHO POWER COMPANY Page 3 Exhibit No._ Case Nos. IPC-E-l 5-01, AVU-E-15-01, PAC-E-l 5-03 Witness: t IDAHO POWERCOMPANY AVOIDED COST RATES FORSEASONAL HYDRO PROJECTS Junc l,2015 tin,h New Gontrectt and RcDlacemont Contrlcts wlthout Full Caoacltr Paymentr Ellglbltlty for theae nb! ls llmliad b profectr sm.llorlh.n l0 atllW. LA'ELIZED ilol.l{E'tELlzE[, CONTRAC'] LENOTH ,VFAtr.qI OIGLINEYEAR CONTRACT VEA tr NON.L6/EUZED PATES2016 20le ,nfl 2018 20te *7n 1 2 3 4 5 6 7II 10 1l 12 13 l4 t5 16 17 18 19 20 33.30 33.70 33,92 34.31 35.17 30.24 42.U 4C.03 52.29 55.70 5E.7.| 81.37 6it.66 65.E5 07.3S 88.98 70.40 71.75 73.00 71.17 34.06 3t0.23 :!t.a8 t5.72 36,96 44.00 50.E6 55.53 50.30 62,62 65.32 e7.72 6e.77 7r.56 73.18 7{.83 78.0.| 77.29 7t.48 79.83 94.42 35.03 36.3€ 37.84 47.8it 5f.51 ss.6E 03.72 87.fi 70.02 72.48 74.55 76.35 77.95 79.43 80.80 82.08 83.28 84.4t1 e5.54 1t5.09 37.16 39.17 51.63 59-57 65.18 60.ltg 72.4:i 75.7rIt.b 80.22 81.s7 E3.52 E4.U 60.28 87.52 EE.70 E9.64 90.s3 01.9€ 39.37 43.0511.14 A8.2257.84 77.4e68.61 82.d17Lt0 88,1170.72 6E.E500.01 01.1782.10 9:t.0685.08 e1,5E68.92 S5.69E5.51 07.0789.92 e8.189114 E0.n92.48 100.3093.65 101.309.1.76 i013{,95.6,t l0g.2E96.90 104.22s7.90 t05.t798.8S t06.r3 2015 2010 2017 2018 2019 WIN 2021 20?2 2023 mu n2s 2020 an7 2024 2029 2030 2031 zoul 2033 200.1 2035 201la m37 o38 203S 20/rO 3:r.36 3(06 91.12 35.89 39.37 tti,05 e5.45 06.37 t00.s0 104s3 r06.20 10r.69 t1't,35 112.24 I ,l3.87 I 15.66 I 1E.5{t 121.701A.* 1n.u 132.U 136.'l S r38.96 144.14 160.21 168.55 NotE: A "seasonal hydro pr{c{' ls delined Br a generalhn lhcllty whhh produce€ at l6sst 55% ot lb annuel ganeradon dudrg hc month3 of Junr, July, and August Ord€r a280il. Nol€i Fho raloB sho ,n in his tablo have b6.n mmputad using tho U.S. Energy lnformation Admlnlslradon (EtA)'s Annual Energy outlook 20i5, rslessid Apdl 14, 20.l5. 8e€ Annual Enoqy Oudook 2015, Tsble 3.8 Energy Prtces by s€c-tor-lvlounlain at http://trtrww'aia govlforeceris/e6o/tebl6s-rof'cftn#supPlam€nu rDA,to powER coMpANy page 4 Exhibit No. AVU-E-l 5-01, PAC-E- I 5-03 Witness: Case Nos. IPC-E-15-01, IDAHO POWER COIIIPANY AVOIDED COST RATES FOR OTHER PROJECTII June 1,2015 &nrwh New Gontracta and Replacement Contracb wilhout Full Gaoacitv PaymentB Ellglblllty for these ratea ls llmlted to prcfecte smsllerlhan l0 sMW. LEVETJZED NON.LEVELIZED ON.UNE YEAR CONTMCT YEAR NOII-LEVELIZED RATFS TENGTH IYFAP.cI 2015 201A 2117 2018 20te 2020 1 2 3 4 5 6 7I 9 10 11 12 13 14 15 16 17 18 19 20 33.36 33.70 33.{'2 34.31 35,'17 36.24 39.76 42.62 45.00 46.99 4.78 50,4.| 51.82 53.04 54.12 55.'10 56.01 56.89 57.71 58.4) 34.08 34"23 34.08 3s.72 s6.96 41.,l6 44.41 47.03 49.t9 51.09 52.81 54.30 55.56 68.66 57.63 58.60 5e.50 60.34 6 t.15 61.95 v.12 35.03 96.t6 37.U 42.U 46.66 49.t4 51.84 5:r.84 55.83 57.18 fi.41 59.55 60.56 8,l.50 62.41 63.26 64,08 64,8S 65.66 35.69 t7.4A 39.17 .15.52 49.7i1 52.83 55.20 57.24 59.05 60.57 61.83 42.s2 63.90 e4,82 65.71 66.56 67.37 88.18 60.98 69.73 39.37 43.0541.14 54.9749.35 59.705.+.0,l 62.5357.15 64.505e.45 66.2061.41 87.7463.15 6S.0084.s9 70.0185.76 70.8086.76 71.6767.87 72.4568.54 7\.ts6S.39 73.9870.20 74.7370.90 75.4971.79 76.2672.58 76.0913.92 77.7474.08 78.53 2015 2016 2017 2018 2019 m20 2f21 N22 m23 n24 2025 2026 ?0,27 2028 2UtS 2030 m31 2082 2033 NU 2035 2036 20s7 2038 2049 2M0 s3.!t6 :t4.06 u.42 35.89 39.37 43.05 67,86 70.37 72.50 74,11 71.05 fi.02 81.25 81.70 82.88 u.22 86.59 80.32 91.74 94.51 90.2:t t01.87 104. t4 r08,6'l 1 14.36 120.18 Note: .Oth€rproloct8"rofBrEtoprqedsotherthanwind,solar,non-eeasonalhydro,andEeasoflalhydroprojecls. ThEse"OtherproFcts' may include (but ere not limited to): cogeneratbn, biomass, biogas, landfill gas, or geolhermal pojects. Note: Ths rat€s shoiim in this table havs b€an computed using he U.S, Energy lnbfinationAdmhistration (ElA)'s Annual Energy Outlook2015,r6lo.sedApril14,2015. SeeAnnualEnorgyOutlook20lS,Table3.SEn€rgyPric6sbySector-Mountalnat http: //urvw.ela. gov/forBcasts/aeo/tsbles-ref . cfilr$Gupplern€nU IDAHO POWER COMPANY P.ge 5 Exhibit No. Case Nos. IPC-E-l 5-01, AVU-E- I 5-01, PAC-E-l 5-03 Witness: R. THOMAS BEACH Principal Consultant Page I Mr. Beach is principal consultant with the consulting firm Crossborder Energy. Crossborder Energy provides economic consulting services and strategic advice on market and regulatory issues concerning the natural gas and electric industries. The firm is based in Berkeley, California, and its practice focuses on the energF markets in California, the western U.S., Canada, and Mexico. Since 1989, Mr. Beach has participated actively in most of the major energF policy debates in California, including renewable energy development, the restructuring of the state's gas and electric industries, the addition of new natural gas pipeline and storage capacity, and a wide range of issues concerning California's large independent power community. From 1981 through 1989 he served at the California Public Utilities Commission, including five years as an advisor to three CPUC commissioners. While at the CPUC, he was a key advisor on the CPUC's restructuring of the natural gas industry in California, and worked extensively on the state's implementation of PURPA. AREAS OF EXPERTISE Renetyable Energy Issues: extensive experience assisting clients with issues concerning California's Renewable Portfolio Standard program, including the calculation of the state's Market Price Referent for new renewable generation. He has also worked for the solar industry on the creation of the California Solar Initiative (the Million Solar Roofs), as well as on a wide range of solar issues in other states. Restructuring the Natural Gas and Electric Industries: consulting and expert testimony on numerous issues involving the restructuring of the electric industry including the 2000 - 2001 Western energy crisis. Energy Markets: studies and consultation on the dynamics of natural gas and electric markets, including the impacts of new pipeline capacity on natural gas prices and of electric restructuring on wholesale electric prices. Qualifying Facility Issues: consulting with QF clients on a broad range of issues involving independent power facilities in the Western U.S. He is one of the leading experts in California on the calculation of avoided cost prices. Other QF issues on which he has worked include complex QF contract restructurings, electric transmission and interconnection issues, property tax matters, standby rates, QF efficiency standards, and natural gas rates for cogenerators. Crossborder Energy's QF clients include the full range of QF technologies, both fossil-fueled and renewable. Pricing Policy in Regulated Industries: consulting and expert testimony on natural gas pipeline rates and on marginal cost-based rates for natural gas and electric utilities. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club a a a a a R. THOMAS BEACH Principal Consultant Page2 EDUCATION Mr. Beach holds a B.A. in English and physics from Dartmouth College, and an M.E. in mechanical engineering from the University of California at Berkeley. ACADEMIC HONORS Graduated from Dartmouth with high honors in physics and honors in English. Chevron Fellowship, U.C. Berkeley, 1978-79 PROFESSIONAL ACCREDITATION Registered professional engineer in the state of California. EXPERT WITNESS TESTIMONY BEFORE THE CPUC Prepared Direct Testimony on Behalf of Pacific Gas & Electric Company/Pacific Gas Transmission (I. 88-12-027 - Iuly 15, 1989) . Competitive and environmental benefits of new natural gas pipeline capacity to California. a. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 89-08-024 -November 10, 1989)b. Prepared Rebuttal Testimony on Behalf of the Canadian Producer Group (A. 89-08-024 - November 30, 1989) - Natural gas procurement polic.y; gas cost forecasting. Prepared Direct Testimony on Behalf of the Canadian Producer Group (R. 88-08-018 -December 7,1989) . Brokering of interstate pipeline capacity. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-029 -November 1, 1990) . Natural gas procurement pokry; gas cost forecasting; brokerage fees. Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing Commission and the Canadian Producer Group (I. 86-06-005 - December 21, 1990) . Firm and interruptible rates for noncore natural gas users 2. 3. 4. 5. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant 6. 7. 8. 9. 10. 11. 12. t3. Pase 3 a. Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing Commission (R. 88-08-018 - January 25,1991)b. Prepared Responsive Testimony on Behalf of the Alberta Petroleum Marketing Commission (R. 88-08-018 - March 29,1991) . Brokering of interstate pipeline capacity; intrastate transportation policies. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-029lPhase II -April 17, l99l) . Natural gas brokerage and transport fees. Prepared Direct Testimony on Behalf of LUZ Partnership Management (A. 9I-0I-027 -fuly 15, 1991) . Natural gas parity rates for cogenerators and solar power plants. Prepared ]oint Testimony of R. Thomas Beach and Dr. Robert B. Weisenmiller on Behalf of the California Cogeneration Council (I. 89-07-004 - July 15, 1991) . ,\voided cost pricing; use of published natural gas price indices to set avoided cost prices for qualifying facilities. a. Prepared Direct Testimony on Behalf of the Indicated Erpansion Shippers (A. 89-04-033 - October 28,1991)b. Prepared Rebuttal Testimony on Behalf of the Indicated Expansion Shippers (A. 89-04-0033 - November 26,1991) . Natural gas pipeline rate design; cost/benefit analysis of rolled-in rates. Prepared Direct Testimony on Behalf of the Independent Petroleum Association of Canada (A. 91-04-003 - lanuary 17,1992) . Natural gas procurement pokcy; prudence of past gas purchases. a. Prepared Direct Testimony on Behalf of the California Cogeneration Council (I.86-06-005/Phase II - June 18,1992)b. Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council (t. 86-06-005/Phase II - fuly 2,1992) . Long-Run Marginal Cost (LRMC) rate design for natural gas utilities. Prepared Direct Testimony on Behalf of the California Cogeneration Council (A. 92-10-017 - February 19,1993) - Prrformance-based ratemaking for electric utilities. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant t4. t5 16. t7. 18. 19. 20. 21. Pase 4 Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-02-0141A.93-03-053 -May 21,1993) . Natural gas transportation sertice for wholesale customers. a. Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum Producers (A.92-12-0431 A.93-03-038 - June 28, 1993)b. Prepared Rebuttal Testimony of Behalf of the Canadian Association of Petroleum Producers (A.92-12-0431A.93-03-038 - July 8, 1993) . Natural gas pipeline rate design issues. a. Prepared Direct Testimony on Behalf of the SEGS Projects (C. 93-05-023 -November 10, 1993)b. Prepared Rebuttal Testimony on Behalf of the SEGS Projects (C. 93-05-023 -|anuary 10,7994) . Utility overcharges for natural gas service; cogeneration parity issues. Prepared Direct Testimony on Behalf of the City of Vernon (A. 93-09-006/A. 93-08-0221A. 93-09-048 - lune 17,1994) . Natural gas rate design for wholesale customers; retail competition issues. Prepared Direct Testimony of R. Thomas Beach on Behalf of the SEGS Projects (A. 94-01-021 - August 5, 1994) . Natural gas rate design issues; rate parity for solar power plants. Prepared Direct Testimony on Transition Cost Issues on Behalf of Watson Cogeneration Company (R. 94-04-03111.94-04-032 - December 5,1994) - Policy issues concerning the calculation, allocation, and recovery of transition costs asso ciated with electric industry restructuring. Prepared Direct Testimony on Nuclear Cost Recovery Issues on Behalf of the California Cogeneration Council (A.93-12-02511.94-02-002 - February 14, 1995) . Recovery of above-market nuclear plant costs under electric restructuring. Prepared Direct Testimony on Behalf of the Sacramento Municipal Utility Distria (A. 94-11-015 - Iune 16, 1995) . Natural gas rate design; unbundled mainline transportation rates. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant 22. 23. Page 5 Prepared Direct Testimony on Behalf of Watson Cogeneration Company (A. 95-05 -049 -September 11, 1995) . Incremental Energy Rates; air quality compliance costs. a. Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum Producers (A. 92- 12-043 I A. 93-03-038/A. 94-05-035 I A. 94-06-0341 A. 94-09-0561A. 94-06-044 - fanuary 30, 1996)b. Prepared Rebuttal Testimony on Behalf of the Canadian Association of Petroleum Producers (A.92-12-0431A.93-03-0381A.94-05-0351A.94-06-0341A.94-09-0561A. 94-06-044 - February 28,1996) . Natural gas market dynamics; gas pipeline rate design. Prepared Direct Testimony on Behalf of the California Cogeneration Council and Waison Cogeneration Company (A. 96-03-031 - Iuly 12,1996) - Natural gas rate design: parity rates for cogenerators. Prepared Direct Testimony on Behalf of the City of Vernon (A. 96-10-038 -August 6, reeT) . Impacts of a major utility merger on competition in natural gas and electric markets. Prepared Direct Testimony on Behalf of the Electricity Generation Coalition (A.97 -03-002 - December 18, 1997) Prepared Rebuttal Testimony on Behalf of the Electricity Generation Coalition (A.97-03-002 - fanuary 9, 1998) Natural gas rate design for gas-fired electric generators. Prepared Direct Testimony on Behalf of the City of Vernon (A.97-03-015 - Ianuary 16, 1ee8) . Natural gas service to Baja, California, Mexico. 24. 25. 26. a. b. 27. Crossborder Energy IPC-E-ls-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant Page 6 a. b. 28.Prepared Direct Testimony on Behalf of the California Cogeneration Council and Watson Cogeneration Company (A. 98 - 1 0-0 12 I A. 98 - L0-03 1 /A. 98-07-005 -March 4,1999). Prepared Direct Testimony on Behalf of the California Cogeneration Council (A. 98-10-0I2lA. 98-01-0311A.98-07-005 - March 15, 1999). Prepared Direct Testimonyon Behalf of the California Cogeneration Council (A. 98-10-012/A. 98-01-0311A.98-07-005 - Iune 25, 1999). Natural gas cost allocation and rate design for gas-fired electric generators. Prepared Direct Testimony on Behalf of the California Cogeneration Council and Watson Cogeneration Company (R. 99-l l-022 - February 11, 2000). Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council and Watson Cogeneration Company (R. 99-ll-022 - March 6, 2000). Prepared Direct Testimony on Line Loss Issues of behalf of the California Cogeneration Council (R. 99-l l-022 - April 28, 2000). Supplemental Direct Testimony in Response to ALJ Cooke's Request on behalf of the California Cogeneration Council and Watson Cogeneration Company (R. 99- ll-022 - April 28,2000). Prepared Rebuttal Testimony on Line Loss Issues on behalf of the California Cogeneration Council (R. 99-l l-022 - May 8, 2000). Market-based, avoided cost pricingfor the elearic output of gas-fired cogeneration facilities in the Califurnia market; electric line losses. Direct Testimony on behalf of the Indicated Electric Generators in Support of the Comprehensive Gas OII Settlement Agreement for Southern California Gas Company and San Diego Gas & Electric Company (I. 99-07-003 - May 5, 2000). Rebuttal Testimony in Support of the Comprehensive Settlement Agreement on behalf of the Indicated Electric Generators (I. 99-07-003 - May 19, 2000). Testimony in support of a comprehensive restructuring of natural gas rates and services on the Southern California Gas Company system. Natural gas cost allocation and rate design for gas-fired electric generators. Prepared Direct Testimony on the Cogeneration Gas Allowance on behalf of the California Cogeneration Council (A. 00-04-002 - September 1, 2000). Prepared Direct Testimony on behalf of Southern Energy California (A. 00-04-002 - September 1,2000). Natural gas cost allocation and rate design for gas-fired electric generators. 29. b. c. d. a- b. 30. 31. a. b. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant PaseT 32. a. b. 33. a. b. Prepared Direct Testimony on behalf of Watson Cogeneration Company (A. 00-06-032 - September 18,2000). Prepared Rebuttal Testimony on behalf of Watson Cogeneration Company (A. 00-06-032 - October 6,2000). Rate design for a natural gas "peaking service." Prepared Direct Testimony on behalf of PG&E National Energy Group & Calpine Corporation (I. 00- I 1 -002-Ap ril 25, 200 1 ). Prepared Rebuttal Testimony on behalf of PG&E National Energy Group & Calpine Corporation (I. 00-11-002-May 15, 2001). Terms and conditions of natural gas service to electric generators; gas curtailment policies. Prepared Direct Testimony on behalf of the California Cogeneration Council (R. 99 - | L -022-May 7, 2001). Prepared Rebuttal Testimony on behalf of the California Cogeneration Council (R. 99-11-022-May 30, 2001). - Avoided cost pricing for alternative energy producers in California. a. Prepared Direct Testimony of R. Thomas Beach in Support of the Application of Wild Goose Storage Inc. (A. 0l-06-029-lune 18,2001).b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Wild Goose Storage (A. 0 I -06-029-November 2, 2001 ) . Consumer benefits from expanded natural gas storage capacity in California. Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San Berhardino (I. 01 -06-0 47-December 14, 2001 ) . Reasonableness review of a natural gas utility's procurement practices and storage operations. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (R. 0 1 - I 0-024-M ay 3 l, 2002)b. Prepared Supplemental Testimonyof R. Thomas Beach on behalf of the California Cogeneration Council ( R. 0 I - 1 0-0 24-May 3 l, 2002) Electric procurement policies for California's electric utilities in the aftermath of the California energy crisis. 34. a. b. 35. 36. 37. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant Pase 8 38.Prepared Direct Testimony of R. Thomas Beach on behalf of the California Manufacturers & Technology Association (R. 02-0 1 -0 1 l-June 6, 2002) "Exit fees" for direct access customers in California. Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San Bernardino (A. 02-02-012 - August 5,2002) - Genqal rate case issues for a natural gas utility; reasonableness rcvievv of a natural gas utility's procurement practices. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Manufacturers and Technology Association (A. 98-07-003 - February 7,2003) Recovery of past utility procurement costs from direct access customers. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council, the California Manufacturers & Technology Association, Calpine Corporation, and Mirant Americas, Inc. (A 01-10-011 - February 28, 2003) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California Cogeneration Council, the California Manufacturers & Technology Association, Calpine Corporation, and Mirant Americas, Inc. (A 01-10-011 - March 24,2003) Rate design issues for Pacific Gas dy Electric's gas transmission system (Gas Accord II). Prepared Direct Testimony of R. Thomas Beach on behalf of the California Manufacturers & Technology Association; Calpine Corporation; Duke Energy North America; Mirant Americas, Inc.; Watson Cogeneration Company; and West Coast Power,Inc. (R. 02-06-041 - March 21,2003) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California Manufacturers & Technology Association; Calpine Corporation; Duke Energy North America; Mirant Americas, Inc.; Watson Cogeneration Company; and West Coast Power, Inc. (R. 02-06-04I - April 4,2003) Cost allocation of above-market interstate pipeline costs for the California natural gas utilities. 43.Prepared Direct Testimony of R. Thomas Beach and Nancy Rader on behalf of the California Wind EnergyAssociation (R. 01-10-024-April l, 2003) Design and implementation of a Renevvable Portfolio Standard in California. 39. 40. a.4t. a.42. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant Paee 9 44. a. b. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (R. 01- 10-024 - Iune 23,2003) Prepared Supplemental Testimony of R. Thomas Beach on behalf of the California Cogeneration Council ( R. 0 1 - 1 0-0 24 - lune 29, 2003) Power procurement policies for electric utilities in California. Prepared Direct Testimony of R. Thomas Beach on behalf of the Indicated Commercial Parties (02-05-004 - August 29,2003) Electric revenue allocation and rate design for commercial customers in southern California. a.Prepared Direct Testimony of R. Thomas Beach on behalf of Calpine Corporation and the California Cogeneration Council (A. 04-03-021-luly 16, 2004) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Calpine Corporation and the California Cogeneration Council (A. 04-03-02I -luly 26, 2004) . Policy and rate design issues for Pacrfic Gas (y Electric's gas transmission system (Gas Accord III). Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (A. 04-04-003 - August 6,2004) . Policy and contract issues concerning cogeneration QFs in California. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council and the California Manufacturers and Technology Association (A. 04-07-044 - fanuary 11, 2005) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California Cogeneration Council and the California Manufacturers and Technology Association (A. 04-07-044 -)anuary 28, 2005) Natural gas cost allocation and rate design for large transportation customers in northern California. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Manufacturers and Technology Association and the Indicated Commercial Parties (A. 04-06-024 - March 7, 2005) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California Manufacturers and Technology Association and the Indicated Commercial Parties (A. 04-06-024 - April 26, 2005) Electric marginal costs, revenue allocation, and rate design for commercial and industrial electric customers in northern California. 45. 46. 47. 48. b. 49. b. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant Pase l0 52. a. b. s0. 51. 55. 56. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Solar Energy Industries Association (R. 04-03-017 - April 28,2005) - Cost-effectiveness of the Million Solar Roofs Program. Prepared Direct Testimony of R. Thomas Beach on behalf of Watson Cogeneration Company, the Indicated Producers, and the California Manufacturing and Technology Association (A. 04- 12-004 - luly 29,2005) Natural gas rate design policy; integration of gas utility systems. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (R. 04-04-003/R. 04-04-025 - August 31, 2005) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (R. 04-04-003/R. 04-04-025 - October 28,2005) Avoided cost rates and contracting policies for QFs in Caffirnia Prepared Direct Testimony of R. Thomas Beach on behalf of the California Manufacturers and Technology Association and the Indicated Commercial Parties (A. 05-05-023 - fanuary 20,2006) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California Manufacturers and Technology Association and the Indicated Commercial Parties (A. 05-05-023 - February 24,2006) Electric marginal costs, rwenue allocation, and rate design for commercial and industrial electric customers in southern California. Prepared Direct Testimony of R. Thomas Beach on behalf of the CaliforniaProducers ( R. 04-08-018 - fanuary 30,2006) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the California Producers ( R. 04-08-018 - February 21,2006) . Transportation and balancing issues concerning California gas production. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Manufacturers and Technology Association and the Indicated Commercial Parties (A. 06-03-005 - October 27,2006) . Electric marginal costs, revenue allocation, and rate design for commercial and industrial electric customers in northern California. Prepared Direct Testimonyof R. Thomas Beach on behalf of the California Cogeneration Council (A. 05-12-030 - March 29,2006) Review and approttal of a new contract with a gas-fired cogeneration project. 53.a- 54. a. b. Crossborder Energlt IPC-E-15-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 10 R. THOMAS BEACH Principal Consultant Pase 11 57.Prepared Direct Testimony of R. Thomas Beach on behalf of Watson Cogeneration,Indicated Producers, the California Cogeneration Council, and the California Manufacturers and Technology Association (A.04-12-004 - ]uly 14, 2006) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Watson Cogeneration, Indicated Producers, the California Cogeneration Council, and the California Manufacturers and Technology Association (A. 04- 12-0 04 - |uly 3 I , 2006) Restructuring of the natural gas system in southern Cakfornia to include firm capacity righ*; unbundling of natural gas services; risk/reward issues for natural gas utilities. s8. 59. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (R. 06-02-013 - March2,2007) . Utility procurement policies concerning gas-fired cogeneration facilities. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.07-01-047 - August 10,2007)b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.07-01-047 - September 24,2007) Electric rate design issues that impact customers installing solar photovoltaic systems. Prepared Direct Testimony of R,. Thomas Beach on Behalf of Gas Transmission Northwest Corporation (A.07-12-021- May 15, 2008) Prepared Rebuttal Testimony of R,. Thomas Beach on Behalf of Gas Transmission Northwest Corporation (A. 07-12-021- |une 13,2008) Utility subscription to nq,v natural gas pipeline capacity serving California. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.08-03-015 - September 12,2008) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Solar Alliance (A. 08-03-015 - October 3, 2008) Issues concerning the design of a utility-sponsored program to install 500 MW of utility - and indep endently - owned solar photov oltaic sy st ems. 60. a. b. 61. a. b. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 R. THOMAS BEACH Principal Consultant Page 12 a. 62. 63. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A. 08-03-002 - October 31, 2008) 64. Elearic rate design issues that impact customers installing solar photovoltaic systems. Phase II Direct Testimony of R. Thomas Beach on behalf of Indicated Producers, the California Cogeneration Council, California Manufacturers and Technology Association, and Watson Cogeneration Company (A. 08-02-001 - December 23, 2oo8) Phase II Rebuttal Testimony of R. Thomas Beach on behalf of Indicated Producers, the California Cogeneration Council, California Manufacturers and Technology Association, and Watson Cogeneration Company (A. 08-02-001 - fanuary 27,2009) Natural gas cost allocation and rate design issues for large customers. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (A. 09-05-026 - November 4, 2009) Natural gas cost allocation and rate design issues for large customers. Prepared Direct Testimony of R. Thomas Beach on behalf of Indicated Producers and Watson Cogeneration Company (A. 10-03-028 - October 5, 2010) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Indicated Producers and Watson Cogeneration Company (A. 10-03-028 - October 26, 2010) 65. a. b. 66. 67. . Revisions to a program of firm backbone capacity nghts on natural gas pipelines. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A. 10-03-014 - October 6, 2010) . Electric rate design issues that impact customers installing solar photovoltaic systems. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Indicated Settling Parties (A. 09-09-013 - October 11, 2010) Testimony on proposed modifications to a broad-based settlement of rate-related issues on the Pacific Gas 6 Electric natural gas pipeline system. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club r2 Exhibir 301 R. THOMAS BEACH Principal Consultant Paee 13 68. a. b. Supplemental Prepared Direct Testimony of R. Thomas Beach on behalf of Sacramento Natural Gas Storage,LLC (A. 07-04-013 - December 6, 2010) Supplemental Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 13,2010) Supplemental Prepared Reply Testimony of R. Thomas Beach on behalf of Sacramento Natural Gas Storage, LLC (A. 07-04-013 - December 20,2010) Local reliability benefits of a new natural gas storage facility. Prepared Direct Testimony of R. Thomas Beach on behalf of The Vote Solar Initiative (A. 10-1 1-015-June 1, 201 1) . Distributed generation policies; utility distribution planning. Prepared Reply Testimony of R. Thomas Beach on behalf of the Solar Alliance (A. 1 0-03-0 14-August 5, 20Il) . Electric rate design for commercial 6 industrial solar customers. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries Association (A. 1 1-06-007-February 6, 2012) . Electric rate design for solar customers; marginal costs. a. Prepared Direct Testimony of R. Thomas Beach on behalf of the Northern California Indicated Producers ( R. 1 I -02 -0 1 9-|anuary 3 l, 2012) b. Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Northern California Indicated Producers (R. 1 1 -02-0 I 9-Februa ry 28, 2012) . Natural gas pipeline safety policies and costs Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries Association (A. 11-10-002-June 12, 2012) . Electric rate design for solar customers; marginal costs. Prepared Direct Testimony of R. Thomas Beach on behalf of the Southern California lndicated Producers and Watson Cogeneration Company (A. 11- 11-002-lune 19, 2012) . Natural gas pipeline safety policies and costs 69. 70. 7t. 72. / 3. 74. Crossborder Energy rPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club l3 Exhibit 301 R. THOMAS BEACH Principal Consultant a Pase 14 76. 77. 75.Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (R. 12-03-014-lune 25, 2012) Reply Testimony of R. Thomas Beach on behalf of the California Cogeneration Council (R. 12-03-0 t{-July 23, 2012) Ability of combined heat and power resources to serye local reliability needs in southern California. Prepared Testimony of R. Thomas Beach on behalf of the Southern California Indicated Producers and Watson Cogeneration Company (A. I I - 1 1-002, Phase 2-November 16,2012) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Southern California Indicated Producers and Watson Cogeneration Company (A. 1l- 11-002, Phase 2-December 14,2012) Allocation and recovery of natural gas pipeline safety costs. b. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries Association (A. I2-12-002-May 10, 2013) Electric rate design for commercial 6 industrial solar customers. EXPERT WITNESS TESTIMONT BEFORE THE COLORADO PUBLIC UTILITIES COMMISSION 1. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Colorado Solar Energy Industries Association and the Solar Alliance, (Docket No. 09AL-2998 - October 2, 2009). . Electric rate design policies to encourage the use of distributed solar generation. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Vote Solar Initiative and the Interstate Renewable Energy Council, (Docket No. 11A-418E - September 21, 201 1). Development of a community solar program for Xcel Energy. Crossborder Energy IPC-E-15-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 l4 t,a' 2. R. THOMAS BE,ACH Principal Consultant Pase 15 EXPERT WITNESS TESTIMONT BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION 1. Direct Testimony of R. Thomas Beach on behalf of the Idaho Conservation League (Case No. IPC-E- l2-27-May 10, 2013) . Costs and benefits of net energ)/ metering in Idaho. EXPERT WITNESS TESTIMONY BEFORE THE PUBLIC SERVICE COMMISSION OF NEVADA 1.Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council (Docket No. 97-200l-May 28,1997) . Avoided cost pricing for the electric output of geothermal generation facilities in Nevada. Pre-filed Direct Testimony on Behalf of Nevada Sun-Peak Limited Partnership (Docket No. 97-6008-September 5, 1997) Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council (Docket No. 98-2002 -llune 18, 1998) . Market-based, avoided cost pricing for the electric output of geothermal generation facilities in Ncvada. EXPERT WITNESS TESTIMONY BEFORE THE NEW MEXICO PUBLIC REGUTATION COMMISSION 1. Direct Testimony of R. Thomas Beach on Behalf of the Interstate Renewable Energy Council (Case No. 10-00086-UT-February 28, 20ll) . Testimony on proposed standby rates for new distributed generation projects; cost- effectiveness of DG in New Mexico. 2. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the New Mexico Independent Power Producers (Case No. 11-00265-UT, October 3, 201l) . Cost cap for the Renewable Portfolio Standard program in New Mexico Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra CIub Exhibit 301 l5 u-.'a R. THOMAS BEACH Principal Consultant Page 16 EXPERT WITNESS TESTIMONY BEFORE THE PUBLIC UTITITIES COMMISSION OF OREGON 1. a. Direct Testimony of Behalf of Weyerhaeuser Company (UM ll29 -August 3,2004)b. Surrebuttal Testimonyof Behalf of Weyerhaeuser Company (UM ll29 - October 14,2004) 2. a. Direct Testimony of Behalf of Weyerhaeuser Company and the Industrial Customers of Northwest Utilities (UM 1129 / Phase II -February 27,2006)b. Rebuttal Testimony of Behalf of Weyerhaeuser Company and the Industrial Customers of Northwest Utilities (UM 1129 i Phase II - April 7,2006) . Policies to promote the development of cogeneration and other qualifying facilities in Oregon. EXPERT WITNESS TESTIMONIY BEFORE THE VIRGINTA CORPORATION COMMISSION 1. Direct Testimony and Exhibits of R. Thomas Beach on Behalf of the Maryland - District of Columbia - Virginia Solar Energy Industries Association, (Case No. PUE- 201 l-00088, October 1 1, 201 1) . Standby rates for net-metered solar customers, and the cost-ffictiveness of net energ)/ metering. EXPERT WITNESS TESTIMONY BEFORE THE MINNESOTA PUBLIC UTILITIES COMMISSION l. Direct and Rebuttal Testimony of R. Thomas Beach on Behalf of Geronimo Energy, LLC. (In the Matter of the Petition of Northern States Power Company to Initiate a Competitive Resource Acquisition Process IOAH Docket No.8-2500-30760, MPUC Docket No. E002/CN-12-1240, September 27 and October 18,20131) . Testimony in support of a competitive bid from a distributed solar project in an all-source solicitation for generating capacity. EXPERT WITNESS TESTIMONY BEFORE THE NORTH CAROTINA UTILITIES COMMISSION 1. Direct, Response, and Rebuttal Testimony of R. Thomas Beach on Behalf of the North Carolina Sustainable Energy Association. (In the Matter of Biennial Determination of Avoided Cost Rates for Electric Utilitf Purchases from Qualifying Facilities - 2014; Docket E-100 Sub 140; April25, May 30, and June 20,201.4) . Testimony on avoided cost issues related to solar and renewable qualifying facilities in N orth Car okna. IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Crossborder Energy R. THOMAS BEACH Principal Consultant Pase 17 LITIGATION EXPERIENCE Mr. Beach has been retained as an expert in a variety of civil litigation matters. His work has included the preparation of reports on the following topics: . The calculation of damages in disputes over the pricing terms of natural gas sales contracts (2 separate cases). . The valuation of a contract for the purchase of power produced from wind generators. . The compliance of cogeneration facilities with the policies and regulations applicable to Qualifring Facilities (QFs) under PURPA in California. . Audit reports on the obligations of buyers and sellers under direct access electric contracts in the California market (2 separate cases). - The valuation of interstate pipeline capacity contracts (3 separate cases). In several of these matters, Mr. Beach was deposed by opposing counsel. Mr. Beach has also testified at trial in the bankruptcy of a major U.S. energy company, and has been retained as a consultant in anti-trust litigation concerning the California natural gas market in the period prior to and during the 2000-2001 California energy crisis. Crossborder Energy IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 301 a BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. CASE NO. CASE NO. IPC-E-1s-01 AVU-E-15-01 PAC-E-ls-03 Idaho Conservation League and the Sierra Club Direct Testimony of R. Thomas Beach Exhibit 302 Idaho Power Responses to: A. Commission StaffRequest No. 2 B. ICL/Sierra Club Request No. 5 C. Commission StaffRequest No. 18 D. I.R. Simplot Request No. 16 IPC-E-1s-0r BEACH, Di Idaho Conservation League and Sierra Club Exhibit 302 0 BEFORE THE IDAHO PUBTIC UfitITIES COMMISSION CA.SE NO. CASE NO. CA.SE NO. IPC-E-ls-01 A\ru-E-rs-01 PAC-E-15-03 Idaho Conservation League and the Sierra Club Direct Testimony of R. Thomas Beach Exhibit 302 Idatro Power Responses to: A. Commission StaffRequest No. 2 B. ICL/Siema Club Request No. 5 C. Commission StaffRequestNo. 18 D. I.R. Simplot Request No. 16 IPC-E-1s-01 BEACH, Di Idaho Conssvation League and Sierra Club Exhibit 302 0 D REOUEST NO. 2: Idaho Power's Petition states on page 2l "The continued and unchecked addition of extremely large amounts of intermittent wind and solar QF generation onto Idaho Power's system at long-term fixed rate prices when the Company has no need for additional generation inflates power supply costs borne by customers and degrades the reliability of the system." How does Idaho Power expect the recent addition of 461 MW of solar contracts to impact customers' retail rates? Does the Company expect rates will have to increase once the contracted solar projects are online and Idaho Power is purchasing the energy? If ldaho Power expects rates will increase, has the Company estimated the approximate rate or revenue requirement increase? [fso, please provide the estimate. RESPONSE TO REOUEST NO. 2: The Company expects 100 percent of the costs associated with the additional 461 MW of solar contracts to be collected from customers through retail rates. The extent to which retail rates would change as a result of the referenced solar contract costs requires a modeled forecast of power supply expenses that must include a comprehensive set of assumptions that is not known today and is subject to debate. To date, Idaho Power has not performed such an analysis. The Company's request in this case is to prospectively limit the contract term for projects above the established surrogate avoided resource ("SAR") eligibility cap and seeks to mitigate the risk of uncertain rate impacts that exist associated with additional generation that is not needed to satisff any near-term capacity or energy requirements. The response to this Request is sponsored by Mike Youngblood, Regulatory IPC-E-ls-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 302 I 5, Projects Manager, Idaho Power Company. REQUEST NO. 5: Please reference the Direct Testimony of Mr. Aliphin Exhibit No. 8 that shows certain FERC account expenses for the years 2010 , 20L2, and 2013: a. Do FERC Account Nos. 501 (coal) and 547 (gas) include either fixed O&M costs, incremental capital additions, or the costs associated with the return on rate base and associated taxes for Idaho Power-owned coal and gas plants? b. Please provide the fixed O&M costs, incremental capital additions, and the revenue requirements associated with the return on rate base and associated taxes for Idaho Power-owned coal and gas plants for the years 2010, 2012, and 2013. For gas plants, please also include gas pipeline capacity or reservation costs if not included in Account 547. c. If available, please provide the data in Exhibit No. 8, plus the data requested in Part (a) of this question, for the years 2011 and 2014. RESPONSE TO REQUEST NO. 5: a. No. The cost items that fall within Federal Energy Regulatory Commission ("FERC") Accounts 501 (coal) and 547 (gas) are those items which fall within the FERC Uniform System of Accounts definitions for those respective FERC accounts. In this case, they are fuel-related expenses for the production of steam for the generation of electricity (FERC Account 501) and cost of fuel delivered at the station of allfuel, such as gas, oil, kerosene, and gasoline used in other power generation (FERC Account 547). They do not include fixed operation and maintenance ("O&M") costs, incremental capital additions, or the costs associated with the return on rate base and associated taxes. IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 302 2 b. Fixed O&M costs, incremental capital additions, and the revenue requirements associated with the return on rate base and associated taxes for Idaho Power-owned coal and gas plants are included as part of a comprehensive cost-of- service study conducted in the preparation of a general rate case; they are not determined individually or on an annual basis. As such, these items were included in the comprehensive class cost-of-service studies filed in the Company's 2008 and 2011 general rate cases (Case Nos. IPC-E-08-10 and IPC-E-11-08, respectively), as well as the rate increase determination due to the inclusion of the Langley Gulch power plant (Case No. IPC-E-12-14). These studies can be found in the documents filed by the Company in the respective cases, which are located on the Commission's website at the following addresses: Year 2010- Case No. IPC-E-08-10 http://www.puc.idaho.qov/fiteroom/cases/summary/l PCEOSI O.htmI Year 2Ol2- f,a5g No. IPC-E- I 1-08 http://www.puc.idaho.qov/fi leroom/cases/summary/IPCEI I 08.html Year2Ol3-Case No. IPC-E-12-14 http :Ilwww.puc.idaho.gov/fileroom/cases/summary/l PCE1214.html c. The information requested for 2OI1 is equivalent to the information for 2010. The information requested for 2014 is equivalent to the information for 2013. The response to this Request is sponsored by Mike Youngblood, Regulatory Projects M anager,Idaho Power Company. IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 302 aJ t REOUEST NO. f 8: On page 22, the Petition states that " the risk and potential harm increases, the longer the price estimates are locked in." Does Idaho Power believe long-term, locked-in price estimates could potentially benefit Idaho Power in some circumstances? RESPONSE TO REOUEST NO. 18: No. The response to this Request is sponsored by Mike Youngblood, Regulatory Projects Manager, Idaho Power Company. IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 302 4 REQUEST FOR PRODUCTION NO. 16: Has the Company investigated the impacts of Idaho Power joining the PacifiCorp-California ISO energy imbalance market as a way to reduce costs associated with intermittent generation or for any other reasons? If not, why not? Please provide all studies or analyses of the impacts of Idaho Power joining the PacifiCorp-California ISO market. energy imbalance IAffirrp'R rO RpCIUp'Sr pOR pROnUCTTON NO. t d: Idaho Power has not studied participation in the PacifiCorp-CAISO energy imbalance market primarily because Idaho Power does not have any transmission rights that would allow it to participate in the PacifiCorp-CAISO energF imbalance market Idaho Power is participating in the Northwest Power Pool efforts to study the feasibility of an intra-hour market similar to an energy imbalance market referred to as the Security Constrained Economic Dispatch and will continue to evaluate the PacifiCorp-CAISO energy imbalance market and other market opportunities as they become available. The response to this Request is sponsored by Tess Park, Director Load Serving Operations, Idaho Power Company. IPC-E-ls-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 302 5 ( t BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. CASE NO. CASE NO. IPC-E-ls-01 AVU-E-15-01 PAC-E-1s-03 Idaho Conservation League and the Sierra Club Direct Testimony of R. Thomas Beach Exhibit 303 California ISO/NVEnergy Energy Imbalance Market Fact Sheet IPC-E-15-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 303 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-E-15-01 CASE NO. AVU-E-Is-OT CASE NO. PAC-E-15-03 Idaho Conservation League and the Sierra Club Direct Testimony of R. Thomas Beach Exhibit 303 California ISO/NVEnergy Energy Imbalance Market Fact Sheet IPC-E-1s-0r BEACH, Di Idaho Conservation League and Sierra Club Exhibit 303 Te(43L @cdih"I[jg"J"i,g ItlVEnergy Seven states participating in the Energy lmbalance Market Ihe /SO and PacifiCorp launched into the first western real-time energy balancing market into operation on November 1 , 2014. NV Energy has obtained approval from both the Federal Energy Regulatory Commission (FERC) and the Public Utilities Commrssion of Nevada (PUCN) and will go live with the Energy lmbalance Market (EIM) in fall of 2015. Sfudies conducted by both companies of their participation in EIM show significant economic and reliability benefits that accrue lo cusfomers in the NV Energy, PacifiCorp, and ISO areas. Participants in the EIM can leverage generation resources across the entire EIM region, with the added benefit of more frequent dispatching in real time to optimize available energy supplies. The EIM is an impoftant tool for operators across the rcgion to f ac i I itate i nc re a sed i nteg rat i o n of re new a b I e resources. Background Ihe /SO announced a paftnership with Poftland-based PacifiCorp in February 2013 to develop an EIM that would operate across pafticipating balancing areas. Following a robust public stakeholder process, fhe /SO developed a market design that was approved by the ISO Board in November 2013. PacifiCorp began padicipating in the EIM in November 2014. With NV Energy, the expanded EIM would cover seven sfafes and over 44 million people. Reliability benefits The EIM strengthens grid reliability by balancing supply and demand closer to when electricity is consumed and by allowing system jr"11'.i, r ' , .operators real-time visibility across neighboring grids. The /SO rs leveraging its existing market ,1.''. ;a rsis; 1sy.6fems to identify fluctuations in supply and 3,r ,i , {lY5(F; :demand, and then automatically find the best resource to meet current needs across a larger region. This, in turn, optimizes the interconnected high-voltage system as market syslems automatically manage congestion on transmission lines. Re n ewa b le i nteg rati o n b en efits While the nation's energy supply becomes more diverse, regional coordination and finely tuned dispatches become more important as chang i ng weather conditions produce variability in wind and solar power generation. An EIM improves the ability to manage resource output deviations, smoothing out power flows in real time so that renewable energy is effectively IPC-E-ls-01 BEACH, Di Idaho Conservatior. - -?gue Exhibit 303 I integrated onto the grid. By combining the NV Energy, PacifiCorp, and /SO's diverse poftfolio, the seven-sfafe EIM will make it possib/e to share more variable renewable resources such as wind or solar during times of under- or overgeneration. Easy and economical entry and exit Studies indicate that the benefits to all customers in the seven-sfale EIM footprint outweigh fhe costs of participating in the ElM. ln addition, an EIM participant can choose to leave the market at any time with no exit fees. Preserving autonomy EIM entities such as PacifiCorp, NV Energy and other parlicipating balancing authorities maintain operational control over their generating resources, retain all their obligations as a balancing area, and must still comply with all regional and national reliability standards. For example, obligations to provide reliability compliance, ancillary services, physical scheduling rights and bilateral trades do not change with ElM. A market-based solution Ihe /SO already operates a successfu/ real-time fifteen minute market with five-minute dispatch capability. Ihr's r's a tried and true service thal exr'sfs in a similar form in two-thirds of the United States, particularly in the Northeast and Midwest as well as much of Canada. This parlnership signals continuing interest from other balancing areas in joining what is already working effectively to lower costs and atthe same time expanding the pool of resources available to meet supply and demand needs in real time. lt is a voluntary and natural step toward the more efficient management of energy syslems for the benefit of customers. Governance Ihe /SO EIM expansion requires that all entities, whether inside or outside California, are given a voice in the decision-making process going fonuard. ln May 2014 the ISO Board of Governors appointed the EIM Transitional Committee that is working towards the development of a long term independent governance proposalthat will go through a stakeholderprocess in 2015. The Board advisory committee is composed of 9 members who were nominated by industry stakeholders and two representatives from PacifiCorp and NV Energy. They have committed to work in an open and transparent manner and be inclusive of a wide range of stakeholders making the EIM a truly western market and encourage broad parlicipation. Nexf steps Work is undenuay to integrate NV Energy into the EIM in October, 2015. Ihe /SO began publishing in February 2015 quarlerly reports of the actual EIM benefits based on actual operating data. Beginning in 2014 and continuing in 2015, NV Energy will conduct a stakeholder process for transmission customers and other stakeholders to make changes to its open access tariff in order to implement the ElM. They will then seek FERC acceptance in mid-2015. During 2015, the /SO will complete the stakeholder process for Year 1 Enhancemenfs to ElM, to address FERC compliance, commitments made during the original stakeholder process, and others identified during implementation. Continued stakeholder involvement will be criticalto lhe success of the EIM by offering valuable input and support to expand a market that can be leveraged to more effectively use resources in the West. IPC-E-1s-01 BEACH, Di Idaho Conservation League and Sierra Club Exhibit 303 BEFORE THE IDAHO PUBLTC UTILITIES COMMISSION CASENO. IPC-E-Is-OI CASENO. AW-E-I5-01 CASENO. PAC-E.I5.03 Idaho Conservation League and the Sierra Club Rebuttal Testimony of R. Thomas Beach Exhibit 304 Lisa Huber, Utility-scale Wind and Natural Gas Volatility: Unlocking the Hedge Value of Wind for Utilities and Their Customers (Rocky Mountain lnstitute, July 2012) (Executive Summary) I based on actual Mid-C prices in Year 11, which could be higher or low.er than the originally 2 forecasted $45 per MWh.r' 3 4 Q: Does this conclude your rebuttal testimony as of May 14, 2015? 5 A: Yes. " This simplified example uses annual prices. It is my understanding that the IRP method uses much more granular prices disaggregated by month and High Load/Low Load hours, so the calculation proposecl here would be , performed on that more granular basis. I rPC-E-1s-01 8 Beach, Rebuttal Idaho Conservation League and Sierra Club Utility-Scale Wind and Natural Gas Volatility Uncovering the Hedge Value of Wind For Utilities and Their Customers Lisa Huber I luly 20t2 RocKv MouNTAr't.r INSTITUTE' ROCKY MOUNTATN INSTITUTE I RMT.ORG 2317 Snowmass Creek Rd. Snowmass, CO 81654 Acknowledgements Special thanks to Amory Lovins, Dan Seif and fon Creyts of Rocky Mountain Institute, and the following individuals for their valuable insight: Will Babler, First Capitol Tom Beach and Patrick McGuire, Crossborder Energy Mark Bolinger, Lawrence Berkeley National Lab Tim Carter, Xcel Energy Gary Demasi, Google Michel DiCapua Charles Blanchard, and Stefan Linder, Bloomberg New Energy Finance fenny Heeter, NREL Dr. Taku lde, Koveva Buck Martinez and David Bates, Florida Power & Light Edward May, US Renewables Group Duncan Mclntyre, Altenex Will Shikani, Macquarie Steven Taub, GE Capital Kevin Walsh, GE Energy Financial Services Also, considerable appreciation is extended to the Stanback Internship Program at Duke University's Nicholas School of the Environment for making this research project possible. I Ri!1i org Table of Contents ACKNOWLEDGEMENTS EXECUTIVE SUMMARY BACKGROUND WHAT IS VOIIITILITY? HISTORICAL VOLATILITY IMPLIED V01ATI1ITY,............,. RISK DISTRIBUTION.,..................8 VOLATILITY PRICING UTILITY HEDGING STMTEGIES .,,,,,.,,,,12 SOLUTIONS 5 A 15 t7CASE STUDIES UTILITY: PUBLIC SERVICE COMPANY OF COLOMDO ......,.......,.....17 INDUSTRTALAND LARGE COMMERCTAL CUSTOTvTSRS: ALTENEX BUSTNESS M0DE1.......................................... L9 COI{ITERCIAI. AND RESIDENTIAL CUSTOMERS: AUSTIN ENERGY GREENCHOICE .....................19 CONCLUSION APPENDIX 20 2L IXECUTIVE SUMIvIqRY Prudent investors do not solely invest in junk bonds over treasury bonds; they do not purely chase yield without regard to risk. A portfolio approach applies not only to personal finances, but also to energy investments. While natural gas spot prices are low today, they remain volatile and present a number of risksl: . Unreliable natural gas and electricity market forecasts . Uncertain power generation costs for IPPs, utilities and regulators . Unpredictable costs for large customers, especially publicly traded companies that must report to shareholders and industrial consumers who buy directly from the market . Unexpected Fuel Cost Adjustments (FCA) for residential customers This paper explores methods of quantifying natural gas volatility by examining theoretical models as well as case studies of utility hedging strategies. Including these volatility risk premiums in the price of natural gas establishes a basis for even comparison with utility-scale wind contracts, which enables smarter decision analysis by regulatory agencies, utilities, and ratepayers. This analysis shows that even without the Federal Production Tax Credit [PTC) and Renewable Portfolio Standards [RPS) power pricing support, wind becomes competitive with natural gas years sooner than is commonly believed, and in many cases is the economic choice for new build generation2. Wind competitiveness can be realized without increasing utility hedging budgets by redirecting current hedging cash flows from short-term option strategies into long-term wind Power Purchase Agreements [PPA). Using this methodology, hedging benefits can also be realized at the customer level by large organizations signing direct PPAs and residential customers participating in effective green power programs [GPP). This paper will demonstrate the hedging benefits of utility-scale wind and present practical solutions for utilities and ratepayers alike to decrease risk and encourage further domestic wind development. r Roesser, Randy. "Natural Gas Price Volatility." Electricity Supply and Analysis Division, California Energy Commision, 2009. 2This paper underscores the importance of hedging against gas price volatility risk; however, short-term variability in wind mr-rst be acknowledged as an additional risk. PPA pricing models used in this analysis include an average $6/MWh cost to utilities for intermittency integration. A future analysis incorporating more specific costs and wind hedging instruments would be beneficial, as risks associated with wind variability and intermittency range widely by region. 4 Oftice of the Secr$ary Senice Dare Octsber 29, 2014 BEFORE IIIE IDAIO PIJBLIC TME.TITES COMMISSIION IN TIE MArrER OF TM APPT.ICATIoN Of EIAEOEIOfiIER COh'PAhiY EOR COi{I.IRMAI|ION OT' THE CAPAC TY owrerorcrPBIoD30B IIttcBB&l{rAL.co$f,,B_{TEGBATF,D RES0I RCE PLAN, AV(NIIED C(NTffi )) CASENOTC-E-H.ZI ) )) oRDDn NO, ffi159 ), ) Idabo lower Compaoy filed aa Application with thc Commission oa August 13, 2}ll,regrmting that ee Conmission isgp an fuer connfming &s sse of a Jp!y,2O2t cqpacity defieiency pgriod io the, qpprored **r"* cost, integnate{ rsgrr1cg Uf*r,"rnAm *u, mer@gr. ($,p.@otogy) aplicable. to aegotiatd avoided, csu rases br p*oposeA PURPA qudirying tacilities (Ss). , on S@€mber 4,?fr14, tb Comhissioo issued a Notice of dgt$icatioeand,Notice of Modified Proce&ne s€tiag a coarneot dedlirle of Septomber 30, 2Ol4 aad a repty rlxdtine of Octob€r 7,2o14. Idaho &oservatioa Leagtr (tCL) ald htqmCImtain Frrcrgy Partners LI.C p$itiooed for, p{ s re $etd, interveation- OrderNos. 33t35 -&4 33t45: '&'sepember 29,.., 2A14, [Cl.,fiIed,&don o exurdlhe coqmect deadlire,a dditid,sida]s. Idab Pocrcr opposed # iSeT tnt o@[,E-d as a {ryative to expe6i. aq lqp*srq extend the commt"&adline,to Octobr 6ad dlon' uotil.Octeber l0 for fu Cmpany;to fre a rep$. ICL arce@ Idaho .Poqcr's proposal to modify the scM*e. & Septer&a 30, 20td ttrc Comrission al4noved'tb dified schedule. ffier No. 33t47. By this @r, and c set otrt in greater detail below, we oafirm huly TI2l as Haho Porreris capacity &fciercy friod for pnrposes of ircrcrental avoided cost calclrlations.within eeRPmeffibgy. BACKGROT}ITD .:& Dember 18, 2012, tbe Comrnissioa'issued eder No. 32697 ar4horizing tb use of Hab Po-neris lncrerytal gogtmP @@t€.]1. Solar aod witrd QF fjgcts that exceed .1tS kilowans (kW) ad dt othff QF SeuatioE that exeeeds tO average megLwatts (*ilwl negCi*e avoi@ ?s.S bapd, oa the approygd racleqeqtat qq ne,uethoaofog, kr its Oder, &e Commissioa stated Te fruther find it apprceriare to i&iry each utility's c4acity o.345oRDER NO. 33159 FINDINGS AND CONCLUSIONS The Idabo Public Utitities Commission has juisdiction over Idaho Power, an elecric utility, and the issues raised in this matter pursuant to the authority and power grailed it under Title 61 of the Idaho Code and tb Public Utility Regulatory Pslicies Act of 1978 (PURPA). The Comnrission has au&ority under PLJRPA and the implementing regutations of the Federal Energy Rogutuory Commission (FERC) to set avoided costs, to order electric utilities to entcr into fixed-tcrm obligations for the prnchase of energy from qualified facilities (QFs) and to implerncnt FERC ruIes. PLJRPA requiras that utilities purchase generation produced by QFs under a federal rarc mechanism (i.e., avoided cost) that is established and implemented by state utility commissions. Ordsr No. 32697 x 7. The rarcs at which Idaho electric ut'lities purchase QF power must be appmved by this Commission. Idaho Power Co. v. Idalo Prblic Utilities Cownissbn, 155 Idaho 78O,789,316 P.3d 1278,17.87 (2013). The IRP methodology, at issue herc, takes into accouot meny different variables and prodrces a restlt based on tbe charactcristics of the generation and each individual utility's need for the resources. Spccifically withregard to capacity, we have previously stated that In calculating a QF's ability to contributc to a utility's need for capacity, we find it r€asonable for the utilities to only begin payrrents for capacity at such time that the utility becomes crry7acity deficient. If a utility is capacity sqrylus; then capacity is not being avoidcd by the purctrase of QF power. By including a capaclty pa,rment only when tb utility becomes capacity deficient, the utilities arc paylog rates that are a more accurate rcflection of.a tnre avoided tforthe QFpower. Ordsr No. 3X97 at 21. Consequen0y, it would be unreasonable o ignorc more than 400 lvfW of demand response r€sources when determining Idaho Power's capacity deficit as it pertains to the IRP methodology. We acknowledge that demand resportse was not a variable that this Commi;sion reco.gpized would be updated in the IRP methodology between IRP filing cycles (every nro years.) Orider No. 32697. However, because we are a regulatory agency that perfonns both judicial and legislative functions, we are not so rigdly bound by the doctrine of stare decisis. Idatto Power Co. v. Idaho PUC, l5S Idaho 780, 788, 316 P.gd 1278, t?fl6 (2013). Under ordinary circumstances, Idaho Power's dernand response resotrrces would have been considered within the Company's integrated resource planning process and aheady taken into account. oRDERNO. 33159 ldaho Power Company IDAHO PUBLIC UTILITIES COMMISSION Effectlve Jan. 1,2015t.p.U.c. No. 29. Tariff No. 101 oriqinat sheet No. 7&1 ooot"J:f.8, 20t5 Per Q.N. 33197 Jean D. Jewell Secretary SCHEDULE 73 COGENERATION AND SMALL POWER PRODUGTION SCHEDULE - IDAHO AVAILABILITY ln all electric territory served by the Company in the State of ldaho. APPLICABILITY To Qualifying Facilities that intend to sell their output to the Company by either (i) interconnecting to the Company's electrical system at an interconnection point within the State of ldaho, or (ii) delivering the output to the Company at a point of delivery ('POD') on the Company's electrical system within the State of ldaho. A Gustomer selling the output of any Qualifying Facility (including both Qualifying Facilities with a maximum generating capability equal to or less than the Eligibility Cap and Qualifying Facilities with a maximum generating capability greater than the Eligibility Cap) will be required to enter into a written Energy Sales Agreement ("ESA") with the Company in accordance with the contracting procedures set forth in this tariff. Any such ESA is subject to the approval of the ldaho Public Utilities Commission ("Commission). DEFINITIONS Customer as used herein means any individual, partnership, corporation, association, governmental agency, political subdivision, municipality, or other entity that owns an existing or proposed Qualifying Facility. Coqeneration Facilitv means equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam) used for lndustrial, commercial, heating, or cooling purposes, through the sequential use of energy. Dailv Shape Adiustment means an adjustment to rates based on a difference between Heavy Load rates and Light Load rates of $7.28 per MWh as established in Commission Order No. 30415. Eliqibilitv Cao means for all Qualifying Facilities except wind and solar Qualifying Facilities, 10 average megawatts in any given month. For wind and solar Qualifying Facilities, "Eligibility Cap" means 100 kilowatts ('kW') nameplate capacity. Facilitv means the electric generation facility owned by the Customer that is located on the Customer's side of the POD, and all facilities ancillary and appurtenant thereto, including interconnection equipment. Heavv Load Hours means the daily hours from hour ending 0700 - 2200 Mountain Time, (16 hours) excluding allhours on Sundays, NewYears Day, Memorial Day, lndependence Day, Labor Day, Thanksgiving Day, and Christmas Day. Lisht Load Hours means the daily hours from hour ending hours) plus all hours on Sundays, New Years Day, Memorial Day, Thanksgiving Day, and Christmas Day. 2300 - 0600 Mountain Time, (8 lndependence Day, Labor Day, IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY GregoryW. Said, Vice President, o 1221 West ldaho ! It- I l.p.u.c. No. 29, Tariff No, 101 originat sheet No. 73-2 oootoJ:f.8, 2015 ldaho Power Company Seasonal Factors means a seasonal weighting May, 1 .20 lor the months of July, August, November, January, February, June, September, and October. IDAHO PUBLIC UTILITIES GOMMISSION Effectlve Jan. 1,2015 PerO.N.33197 Jean D. Jewell Secretary SCHEDULE 73 COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO (Continued) DEFI NITIONS (continued) lnteoration Charoes means the Commission-approved integration charge applicable to any intermittent generation resource, including but not limited to, wind and solar generation. Generator lnterconnection Aoreement ('GtA"). The interconnection agreement that specifies terms, conditions, and requirements of interconnecting to the Company electrical system, which will include, but not be limited to, all requirements as specified by Schedule 72. lf the Facility is not interconnecting directly to the Company electrical system, the Facility will not have a GIA with the Company but instead will have a similar agreement with the utility the Facility is directly interconnecting to. Point of Deliverv (POD) is the location specified in the GIA (or Transmission Agreement) wherethe Company's and the Seller's (or third-party transmission provider's) electrical facilities are interconnected and the energy from the Qualifying Facility is delivered to the Company electrical system. Qualifvinq Facilitv shall mean a Cogeneration Facility or a Small Power Production Facility that is a "Qualifying Facility" as that term is defined in the Federal Energy Regulatory Commission's regulations, 18 C.F.R. S 292.101(b)(1) (2010), as may be amended or superseded. of 0.735 for the months of March, April, and and December and 1,00 for the months of Small Power Production Facilitv means the equipment used to produce output including electric energy solely by the use of biomass, waste, solar power, wind, water, or any other renewable resource. Transmission Aqreement. lf the Facility is not directly interconnected to the Company electrical system, the Facility must obtain firm transmission rights from the appropriate utility(s) to deliver the Facility's maximum capacity to an agreed to POD on the Company electrical system for the full term of the ESA. This agreement(s) shall have minimum terms equal to the lesser of (a) the term of the ESA being requested by the Qualifying Facility in Section 1.a.xiv., or (b) the minimum term required by the third-party transmission entity to ensure firm roll over transmission rights, and (c) any other applicable terms and conditions to ensure the Facility shall have firm transmission rights for the full term of the ESA. RATE OPTIONS The Company is required to pay the following rates, at the election of the Qualifying Facility, for the purchase of output from Facilities for which this tariff applies and that is delivered and accepted by the Company in accordance with the ESA. These rates are adjusted periodically and are on file with the Commission. IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise, ldaho IEP EXHIBIT 401 Page 2 of 10 ldaho Power Company |.P.U,C. No. 29, Tariff No. 101 . Orioinal Sheet No, 73-3 !DAHO PUBLIC UTILITIES COMMISSION Approved Jan. 8, 2015 Effective Jan. 1,2015 Per O.N. 33197 Jean D. Jewell Secretary SCHEDULE 73 COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO (Continued) MTES OPTIONS (Continued) 1. Levelized Fueled Rates. These rates shall apply to Qualifying Facility projects at or below the Eligibility Cap when the Customer chooses to supply output including energy and capacity under Levelized Avoided Cost Rates for Fueled Facilities. The rates shall apply to Facilities fueled with fossil fuels and shall depend upon the on-line operation date and term of the agreement and shall be fixed for the term. The adjustable component rate shall be changed periodically subject to Commission orders. Both the fixed and adjustable rate components are subject to Seasonal Factors, a Daily Shape Adjustment, and lntegration Gharges. 2. Non-Levelized Fueled Rates. These rates shall apply to Qualifying Facility projects at or below the Eligibility Cap when the Customer chooses to supply output including energy and capacity under Non-Levelized Avoided Cost Rates for Fueled Facilities. The rates shall apply to Facilities fueled with fossil fuels and shall depend upon the on-line operation date and term of the agreement. The fixed component rate shall be fixed for the term of the agreement. The adjustable component rate shall be changed periodically subject to Commission orders. Both the fixed and adjustable rate components are subject to Seasonal Factors, a Daily Shape Adjustment, and lntegration Charges. 3. Levelized Non-Fueled Rates. These rates shall apply to Qualifying Facility projects at or below the Eligibility Cap when the Customer chooses to supply output including energy and capacity under Levelized Avoided Cost Rates for Non-Fueled Facilities. These rates shall apply to Facilities that do not use fossilfuels as their primary fuel. The rates shall depend upon the on-line operation date and term of the agreement and shall be fixed for the term. The rate components are subject to Seasonal Factors, a Daily Shape Adjustment, and lntegration Charges. 4. Non-Levelized Non-Fueled Rates. These rates shall apply to Qualifying Facility projects at or below the Eligibility Cap when the Customer chooses to supply output including energy and capacity under a contract based on Non-Levelized Avoided Cost Rates for Non-Fueled Facilities. These rates shall apply to Facilities that do not use fossil fuels as their primary fuel, and shall be fixed for the term. The rates are subject to a Seasonal Factor, a Daity Shape Adjustment, and lntegration Charges. 5. Rates Determined at the Time of Deliverv. Please see the Gompany's taritf Schedule 86. 6. lnteqrated Resource Plan ("lRPl Based Rate. The IRP Based Rate is required for all Quatifying Facilities that do not meet the Eligibility Cap and shall be calculated based on the lncremental Gost IRP Methodology tailored to the individual characteristics of the proposed Qualifying Facitity. CONTRACTING PROCEDURES The Company agrees to adhere to the following contract procedures for the purchase of output from Gustorners who own Qual'tffing Facilities for which this tariff applies and that is delivered to the Company's system. These contracting procedures are adjusted periodically and are on file with the Commission. IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise, ldaho IEP EXHIBIT 4OT Page 3 of l0 ldaho Power Company I.P.U.C. No. 29. Tariff No. 101 IDAHO PUBLIC UTILITIES COMMISSION OrioinalSheet No. 73-4 Approved Jan.8, 2015 Effectlve Jan. 1,2015 Per O.N.33197 Jean D. Jewell Secretary co e r rrr e nm o r.r n r.r o s rrltn r- r-?cffi PH LpEnLso u cr r o r'r s c n e p u r e - r nn n o (Continued) CONTRACTI NG PROCEDURES (Continued) 1. Procedures a. To obtain an indicative pricing proposal for a proposed Qualifying Facility, the Customer shall provide the Company a completed Qualifying Facility Energy Sales Agreernent Application utilizing the Application template included in this Schedule, The information required within the application is general information as listed below. i. Qualiflting Facility owner name, organizational structure and chart, contact information, and project name; ii. Generation and other related technology applicable to the Qualifying Facility; iii. Maximum design capacity, station seruice requirements, and the net amount of power, all in kW, to be delivered to the Company's electric system by the Qualifying Facility; iv. Schedule of estimated Qualifoing Facility electric output, in an 8,760-hour electronic spreadsheet format; v. Ability, if any, of Qualifying Facility to respond to dispatch orders from the Company; vi. Map of Qualifying Facility location, electrical interconnection point, and POD (identified by nearest landmark and GPS coordinates); vii. Anticipated commencement date for delivery of electric output; viii. List of acquired and outstanding Qualifying Facility permits, including a description of the status and timeline for acquisition of any outstanding permits; ix. Demonstration of ability to obtain Qualifying Facility status; x. Fuel type(s) and source(s); xi. Plans to obtain, or actual fuel and transportation agreements, if applicable; xii. Where Qualifying Facility is or will be interconnected to an electrical system besides the Company's, plans to obtain, or actual electricity transmission agreements with the interconnected system; xiii. lnterconnection agreement status; and IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise, ldaho IEP EXHIBIT 4OI Page 4 of 10 ldaho Power Company LP.U.C. No. 29. Tariff No. 101 Oriqinal Sheet No. 73-5 !DAHO PUBLIC UTILITIES COMMISSION Approved Jan. 8,2015 Effectlve Jan. 1,2015 Per O.N. 33197 Jean D. JewellSecretary c o c e r.r E nnr r o rrr n rrr o s un r- r-?cjriPH lEnlso u cr r o N s crr e o u r- e - r on H o (Continued) CONTRACTI NG PROCEDURES (Continued) 1. Procedures(Continued) xiv. Proposed contracting term and requested Rate Option for the sale of electric output to the Company. b. Where the Company determines that the Customer has not provided sufficient information as required by Section 1.a., the Company shall, within 10 business days, notifythe Customer in writing of any deficiencies c. Following satisfactory receipt of all information required in Section 1.a., the Company shall, within 20 business days, provide the Customer with an indicative pricing proposal containing terms and conditions tailored to the individual characteristics of the proposed Qualifying Facility; provided, however, that for Qualifying Facilities eligible for Published Rates pursuant to the Commission's eligibility requirements, the Company will provide such indicative pricing proposalwithin 10 business days. d. The indicative pricing proposal provided to the Customer pursuant to Section 1.c. will not be final or binding on either party. Prices and other terms and conditions will become final and binding on the parties under only two conditions: i. The prices and other terms contained in an ESA shall become final and binding upon full execution of such ESA by both parties and approval by the Commission, or ii. The applicable prices that would apply at the time a complaint is filed by a Qualifying Facility with the Commission shall be final and binding upon approval of such prices by the Commission and a final non-appealable determination by the Commission that: (a) a "legally enforceable obligation" has arisen and, but for the conduct of the Company, there would be a contract, and(b) the Qualifying Facility can deliver its electrical output within 365 days of such determination. e. lf the Customer desires to proceed with contracting its Qualifying Facility with the Company after reviewing the indicative pricing proposal, it shall request in writing that the Company prepare a draft ESA to serve as the basis for negotiations between the parties. ln connection with such request, the Customer shall provide the Company with any additional Qualifying Facility information that the Company reasonably determines necessary for the preparation of a draft ESA, which shall include: i. Updated information of the categories described in Section 1.a. ii. Evidence of site control for the entire contracting term IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, .Regulatory Afiairs 1221West ldaho Street, Boise, ldaho IEP EXHIBIT 401 Page 5 of 10 ldaho Power Company I P U C No 29 Tariff No 101 IDAHO PUBLIC UTILITIES COMMISSION OrioinalShee-t No 73-6 Per O.N. 33197 Jean D. Jewell Secretary SCHEDULE 73 COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - ]DAHO (Gontinued) CONTRACTING PROCEDURES (Continued) 1. Procedures(Continued) iii. Anticipated timelines for completion of key Qualiffing Facility milestones, to include: (a) Licenses, permits, and other necessary approvals;(b) Funding;(c) Qualifying Facility engineering and drawings;(d) Significantequipmentpurchases;(e) Construction agreement(s);(0 lnterconnectionagreement(s);and(g) Signing of third-party Transmission Agreements, where applicable. iv. Additional information as explained in the Company's indicative pricing proposal. f. lf the Gompany determines that the Customer has not provided sufficient information as required by Section 1.e., the Company shall, within 10 business days, notify the Customer in writing of any deficiency. g. Following satisfactory receipt of all information required in Section 1.e., the Company shall, within 15 business days, provide the Customer with a draft ESA containing a comprehensive set of proposed terms and conditions. The draft shall serve as the basis for subsequent negotiations between the parties and, unless clearly indicated, shall not be construed as a binding proposal by the Company. h. Within 90 calendar days after its receipt of the draft ESA from the Company pursuant to Section 1.9., the Customer shall review the draft ESA and shall (a) notifi7 the Company in writing that lt accepts the terms and conditions of the draft ESA and is ready to execute an ESA with same or similar terms and conditions as the draft ESA or (b) prepare an initial set of written comments and proposals based on the draft and provide them to the Company. The Company shall not be obligated to commence negotiations with a Customer or draft a final ESA unless or until the Company has timely received an initial set of written comments and proposals from the Customer, or notice from the Customer that it has no such comments or proposals, in accordance with this Section 1.h. i. After Customer has met the provisions of Section 1.h. above, Gustomer shall contact the Company to schedule ESA negotiations at such times and places as are mutually agreeable to the parties. IDAHO lssued per Order No. 33197 Effective - Janua'ry 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise, ldaho IEP EXHIBIT 401 Page 6 of 10 Approved Jan. 8, 2015 Effective Jan. 1,2015 ldaho Power Company I.P.U.C. No. 29, Tariff No. 101 Oriqinal Sheet No. 73-7 IDAHO PUBLIC UTILITIES GOMMISSION Approved Jan. 8, 2015 Effective Jan. 1, 2015 Per O.N. 33197 Jean D. JewetlSecretary SCHEDULE 73 cooErurRRttou RNo sunttffiE6ucttot'r scHeoute - toRtto (Continued) CONTRACTI NG PROCEDURES (Continued) 1. Procedures(Continued) j. ln connection with any ESA negotiations between the Company and the Customer, the Company: i. Shall not unreasonably delay negotiations and shall respond in good faith to any additions, deletions, or modifications to the draft ESA that are proposed by the Customer; ii. May request to visit the site of the proposed Qualifying Facility; iii. Shall update its pricing proposals at appropriate intervals to accommodate any changes to the Company's avoided cost calculations, the proposed Qualiffing Facility or proposed terms of the draft ESA; iv. Shall include any revised contracting terms, standards, or requirements that have occuned since the initial draft ESA was provided; v. May request any additional information from the Customer necessary to finalize the terms of the ESA and to satisfy the Company's due diligence with respect to the QualifYing FacilitY. k. When both parties are in full agreement as to all terms and conditions of the draft ESA, including the price paid for delivered energy, and the Customer provides evidence that any applicable Transmission Agreements have been executed and/or execution is imminent, the Company shall prepare and forward to the Customer, within 10 business days, a final, executable version of the ESA. l. The Customer shall, within 10 business days, execute and return the final ESA to the Company. m. Where the Customer timely executes and returns the final ESA to the Company in accordance with Section 1.1. above, the Company will, within 10 business days of its receipt of the ESA executed by the Customer, execute such ESA. The Company will then submit the executed ESA to the Commission for its review. n. Failure of the Customer to meet any timelines set forth in this section relieves the Company of any obligation under this tariff until such time as the Customer resubmits its Qualifying Facility and the procedures begin anew. lf the Customer does not execute the final ESA per Section '1.1, such final ESA shall be deemed withdrawn and the Gompany shall have no further obligation to the Customer under this tariff unless or until such time the Customer resubmits the Qualifying Facility to the Company in accordance with this Schedule. IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise, ldaho IEP EXHIBIT 401 Page 7 of 10 ldaho Power Company |.P,U.C. No.29. Tariff No. 101 OriqinalSheet No. 73-8 IDAHO PUBLIC UTILITIES GOMMISSION Approved Jan. 8,2015 Effective Jan. 1,2015 Per O.N.33197 Jean D. Jewell Secretary SCHEDULE 73 COGENERATION AND SMALL POWER PRODUCTION SCHEDULE _ IDAHO (Continued) CONTRACTI NG PROCEDURES (Continued) 2. lnterconnection, Transmission Aqreements, and Desionated Network Resource a. The Company's obligation to purchase Qualifying Facility electrical output from the Customer will be conditioned on the consummation of a GIA in accordance with the Compant's Schedule 72. Where the Qualifying Facility will not be physically located within the Company's electrical system, the Customer will need to consummate a similar GIA with the third-party electrical system. b. Where the Qualifying Facility will be interconnected to a third-party electrical system and is requesting either Published Rates, or rates based on firm delivery of its electrical output, the Company's obligation to purchase such electrical output will be conditioned on the Customer obtaining a firm Transmission Agreement or agreements to deliver all electrical output to the agreed upon POD. c. The Company's obligation to purchase Qualifying Facility electrical output from the Customer will be conditioned on the Facility being classified as a Company Designated Network Resource. 3. Qualifuinq Facilitv Enerov Sales Aqreement Application (FORM STARTS ON NEXT PAGE) IDAHO lssued per Order No. 33197 Effective - January 1, 2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise, ldaho IEP EXHIBIT 401 Page 8 of 10 ldaho Power Company |.P.U.C. No. 29, Tariff No. 101 OriqinalSheet No. 73-9 IDAHO PUBLIC UTILITIES COMMISSION Approved Jan. 8, 2015 Effective Jan. 1, 2015 SCHEDULE 73 Per O.N. 33197 Jean D. JewellSecretary COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO (Continued) QUALIFYING FACILITY ENERGY SALES AGREEMENT APPLICATION ldaho Power Qualifying Facility (QF) contact information: Mailing Address: Attn: Energy Contracts, P O Box 70 Boise, lD 83702 PhysicalAddress: 1221W.ldaho Street, Boise, lD 83703 Telephone number: 208-388-6070 E-Mail Address: rallphin@idahopower.com Preamble and lnstructions All generation facilities that qualify pursuant to ldaho Power Company Schedule 73 tor a QF Energy Sales Agreement and wish to sell energy from their facility to ldaho Power must complete the following information and submit this Application by hand delivery, mail or E-mail to ldaho Power. Upon receipt of a complete Application, ldaho Power shall process this request for a QF Energy Sales Agreement pursuant to ldaho Power Company Schedule 73. Qualifying Facllity lnformation Proposed Proiect Name of Facility: Resource Type: (1.e. wind, solar, hydro, etc): Facility Location: GPS Nearest City or landmark: County and State: Map of Facility, including proposed interconnection point. Anticipated commencement date of energy deliveries to ldaho Power: Facility Nameplate Capacity Rating (kW): Facili$ Maximum Output Capacity (kW): Station Service Requirements (kW): Facility Net Delivery to ldaho Power (kW): Facility interconnection status: Proposed Contracting Term (cannot exceed 20 years): Requested Rate Option (details provided in Schedule 73): Does the Facility have the ability to respond to dispatch orders from ldaho Power Company (Yes or No): IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise, ldaho IEP EXHIBIT 401 Page 9 of 10 ldaho Power Company LP.U.C. No.29, Tariff No. 101 OriqinalSheet No. 7&10 IDAHO PUBLIG UTILITIES COMMISSION Approved Jan.8,2015 Effectlve Jan. 1,20{5 SCHEDULE 73 Per O.N.33197 Jean D. Jewell Secretary COGENERATION AND SMALL POWER PRODUCTION SCHEDULE _ IDAHO (Continued) QUALIFYING FACILIry ENERGY SALES AGREEMENT APPLICATION (Continued) Please include the following attachments: ,/ Hourly estimated energy deliveries (kW) to ldaho Power for every hour of a one year period. ,/ List of acquired and outstanding Qualifying Facility permits, including a description of the status and timeline for acquisition of any outstanding permits.. At the minimum a FERC issued QF certificate/self-certification is required and/or evidence that Facility will be able to obtain a Qualifying Facility certificate. ,/ lf the Facility will require fuel be transported to the Facility (i.e. natural gas pipelines, railroad transportation, etc), evidence of ability to obtain sufficient transportation rights to operate the Facility at the stated Maximum Output Amount. ,/ lf the Facility will not be interconnecting directly to the ldaho Power electrical system, evidence that the Facility will be able to interconnect to another utility's electrical system and evidence that the Facility will be able to obtain firm transmission rights over all required transmission providers to deliver the Facility's energy to ldaho Power. Owner lnformation Owner / Company Name: Contact Person: Gity:State:_ Zip:_ Telephone: E-mail: Applicant Signature I hereby certify that, to the best of my knowledge, all information provided in this Qualifying Facility Energy Sales Agreement application is true and correct, Signature Print Name Date IDAHO lssued per Order No. 33197 Effective - January 1,2015 lssued by IDAHO POWER COMPANY Gregory W. Said, Vice President, Regulatory Affairs 1221 West ldaho Street, Boise,ldaho IEP EXHIBIT 401 Page 10 of 10 Article 1 2 3 4 5 6 7 8 9 l0 1l ENERGY SALES AGREEMENT BETWEEN IDAIIO POWER COMPAIVY AI{D CLARK SOLAR 1, LLC TABLEOF CONTENTS TITIT Definitions No Rcliancc on Idaho Power S/arrantics Conditions toAccqltance of Encrgy Tcrmand OperationDate Purchasc md Salc of Nct Encrgy Porchase hicc andMcthod ofPayncnt Environmcntal Atfributes Facility and Intcrconnectioar M*cring, Mctcring Communications md SCADA Tclcmctry Rcmrds Operations Indcmnificatim and Insurance ForccMajcurc Liability; Dedication Scvcral Obligations Waivcr Choiccof Laws andVcouc Dispurcs andDcfault Govcrnmeotal Authorization CommissionOrder Succcssors and Assigus Modification Taxes Notices and Authorizcd Agcnts Additional Tsms and Conditions Scvcrability Countcrpans Entire Agrec,mart Signatrrcs L2 13 t4 l5 t6 t7 l8 l9 20 2t 22 23 24 ?s 26 27 28 29 AppadixA AppardixB Appcodix C AppardixD Ap'padixE AppcndixF AppcndixG AppendixH Appcndixl Gc,ncration Schcduling aod Rcpoting Facility andPoint of Dclivery F.n gin ecr' s Ccrtifi cations Forms of Ugid Security Solar Facility Energ5r Prioes and Integration Chargcs Altcrnativc SolarFacility Energy Priccs and Integratioa Chargcs Insurmcc Rcquircmcnts Solar Energy Production Forccasting Estimatcd Hourly Energy Production IEP EXHIBIT 402 Page 1 of34 ENERGY SALES AGREEMENT (Solar PV Project with a Nameplate rating greater than 100 kW) Project Name: Clark Solar l. LI,C Project Numb er: 252449 13 This Energy Sales Agreement (*AGREEMENT), entered into on tnt /3 day of 2014 between CLARK SOLAR l,LLC, an Idaho Limited Liability Company (Seller), and IDAHO POWER COMPANY, an Idaho corporation Qdaho Power), hereinafter sometimes referred to collectivcly as '?arties" or individually as "Part5r." WITNESSETH: WHEREAS, Seller will design, consmrct, owu, maintain and operate an electric generation facility; and WHEREAS, Seller wishes to sell, and Idaho Power is required to purchase, elechic energy produced by a PURPA QualiSing Facility. THEREFORE, In consideration of the mutual covenants and agreernents hereinafter set forth, the Parties agree as follows: ARTICLEL DEFINITIONS As used in this Agreement and the appendices attached hereto, the following terrns shall have the following meanings: 1.1 "Adusted Estimated Net Eners ' - the Estimated Net Energy Amount specified in paragraph 6.2 including any adjustments that have been made in accordance with paragraphs 6.2.2 or 6.2.3 and any applicable Solar Panel Degradation adjustments. 1.2 "AuthorizerlAgent" - a person or persons specified within pardgraph 25.2 of this Agreement as being authorized and empowered, for and on behalf of the Seller, to execute instruments, agreements, certificates, and other documents (collectively'Docume,nts') aud to take actions on behalf of the Seller, and that Idaho P-owSCompany and its directors, officers, employees, and agents are entitled to consider and deal with such persons as agents ofthe Seller for all purposes, IEP EXHIBIT 402 Page 2 of34 1.3 1.4 1.5 1.6 1.7 until such time as an authorized officer of the Seller shall have delivered to Idaho Power Company a notice in urriting stating that such person is and shall no longer be an agent on behalf of the Seller. Any Documents executed by such pemons shall be deemed duly authorized by the Sellcr for all purposes. 'Eagsjnergy''- Monthly Net Energy less any Surplus Energ5r as calculated in paragraph 1.46. "eomqllsion'o - The Idaho Public Utilities Commission "Contragq-Ygd'- The period commencing cach cale.ndar year on the same calendar date as the Operation Date and ending 364 days thereafter. '2Elay_Crgg_Perioil" - 120 days immediately following the Scheduled Operation Date. '&laapamages" - ((Current month's Estimated Net Energy Amount as specified in paragraph 6.2 divided by the number of days in thc cunqrt month) multiplied by the number of days in the Delay Period in the current month) multiplicd by the curre,nt month's Delay Price.) 'DglAy_Eeriod" - All days past the Scheduled Operation Date until the Scller's Facility achieves the Opcration Date or the Agreement is terminated by Idaho Power. 1.9 'Dglay Price" - The current month's Mid-Columbia Market Energy Cost minus the surrent month's Base Energy Light Load Purchase Pricc as specified in the Solar Facility Pricrng Schedulc of this Agreement. If this calsulation results in a value less ttran 0, the result of this calculation willbe 0. 1.10 "Desienated Dispatch Facil ' - Idaho Power's Inad Serving Qlerations, or any subseque,nt group designated by Idaho Power. 1.11 "Effective-Date" - The date stated in the opening paragraph of this Encrgy Sales Agreemant reprcsenting the date upon which this Energy Sales Agreem€nt was fully executed by both Partics. L,lz "Environmental Attributes" - means any and all credits, bencfits, emissions reductions, offsetq and allowances, howsoever e,ntitled, attributablc to the g€ncration from thc Facility, and its avoided emission of pollutants. Environmcntal Attributcs includc but arc not limitcd to: (l) any avoidcd emission of pollutants to thc air, soil or water such as sulfiu oxidcs (SOx), niEogen oxidcs (NOx), carbon monoxide (CO) and other pollutants; (2) any avoidcd cmissions of carbon IEP EXHIBIT 402 Page 3 of34 1.8 dioxide (COr, methanc (CIL), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hcxafluoride and other greenhouse gasas (GHG$ that have been determined by the Unitcd Nations Intergovc,mmental Panel on Climate Change, or otherqrise by law, to contribute to the actual or potcntial tbrcat of altering the Earth's climate by trapping heat in thc amospherc;t (3) thc rcporting rights to these avoided emissions, such as REC Rcporting Rights. REC Rcporting Rights are the right of a REC purchaser to rqrort the ownership of accumulated RECs in compliance with federal or state law, if applicablg andto a fedcral orstrate agc,ncy or any other party at the REC purchaser's discretion, and inctude without limitation thosc REC Rcporting Rights accruing undcr Section 1605(b) of The Energy Policy Act of 1992 afi any prcsqrt or future federal, state, or local law, regulation or bill, and intemational or foreign emissions trading program. RECs arc accumulated on a MWh basis and oae REC represcnts the Environmcntal Atributes associated with onc (l) MWh of cnergy. Environmental Athibutes do not include (i) any cncrgy, capacity, rcliability or other power atributes from the Facility, (ii) production tax sredits or investment tax credits associated with the constuction or operation of the Facilip and other financial incentives in the form of crcdits, reductions, or allowances associated with the Facility that are applicable to a state or fcderal income toration obligation, (iii) the cash grant in lieu of the investment tax credit pursuant to Section 1603 of the American Rggovery and Rcinvcshcnt Act of 2009, or (rv) emission reduction credits encumbered or used bylthc Facility for compliance with local, state, or federal operating and/or air quality permits. 1.13 "Btimated Net Enerqv Amount AdJustrnent Percentage" - (Pricc Adjustment Adjusted Estimated Nct Encrgy Amount dividcd by thc applicable month's Montbly Estimatsd Gcneration) e4nessed as a percentagc. If this calculation results in a value greater than 100%, thc result of this calculation will bc 100%. 1.14 "Fagility" - That electric generation facility described in Appcndix B of this Agrccment. I Avoided cmissions tnay or uny not have any valuc for GHG compliancc puryoscs. Although avoided cmissio,ns are includcd in the list of Environmcntal Atfributes, this inclusion docs not crcats any right to use those avoidcd cmissions to comply with anyGHG regulatoryprogram- IEP EXHIBIT 402 Page 4 of34 1.15 "First-EggtgtDatgu - The day comme,ncing at 00:01 hours, Mountain Time, following the day that Sellcr has satisfied the requirements of Articlc IV and after thc Seller requested First Energy Date. 1.16 '@!-.1ou!4gg" - a partial or total reduction of a) the Facility's capacity to produce and/or deliver Net Energy to the Point of Delivery or b) Idaho Power's ability to accept Net Energy at the Point of Delivery for non-economic reasons, as a result of Idaho Power or Facility: l) equipment failure which was not the result of ncgligence or lack of preventative maintenance, or 2) responding to a transmission provider curtailment order, or 3) unplanned preventative maintenance to rcpair eEripment that left unrcpaired, would result in failure of equipment prior to the planncd maintenance period, or 4) planned maintcnance or constnrction of the Facility or electrical lines required to serve this Facility. 1.17 "Gencration Interconnection Aer€cment (GlA)" - Thc interconnection agreement that spccifies tcrms, conditions aud rcquircmorts of intcrconnecting to thc Idaho Power elcctrical s5xst€,m, which will includc but not be limited to all reguircmcnts as spccificd by Schedule 72. 1.18 "Generation_-IJnit" - a complete solar pv elechical generation system within thc Facility that is able to gcnerate and deliver energy to the Point of Delivery independent of other Generation Units within thc same Facility. l.l9 "@'- The daily hours from hour ending 0700 - 2200 Mountain Time, (16 hours) excluding all hours on all Sundays, New Years Dan Mcmorial Day, Independence Day, Labor Day, Thanksgiving and Chrishnas. 1.20 "@" - the hourly Gnergy estimates provided by the Seller and included in Appcndix I of this Agrcement. These hourly cncrgy cstimates are a material input used in the calculation ofthc energy prices specified in Appcodix E and F. l.2l "Intcrconncction Facilities" - All equipmcnt specified in thc GIA. 1.22 '@'- The daily hours from hour cnding 2300 - 0600 Mountain Time (8 hor:rs), plus all otlcr hours on all Sundays, Ncw Years Day, Memorial Day, Independence Day, Labor Day, Thanksgiving and Christmas. IEP EXHIBIT 402 Page 5 of34 t.2s 1.26 1.23 "Losses" - The loss of electical eoergy expressed in kilowat hours ft\Vh) occurring as a result of the transformation and traosmission of encrg5r betwcen the point wherc the Facility's c,nergy is metered and Facility's Point of Delivery. The loss calculation formula will be as specified in Appendix B of this Agrecment. 124 '@' - Eighty-five pcrceirt (857o) of thc Miil-Columbia Markct 1.2? Energy Cost. "Material .Breach" -A Default (paragaph 19.2.1) subject to paragraph 19.2.2. "Maximum Capacitv Amount" - The maximum capacity (MW) of the Facility will be as spccificd in Appcndix B ofthis Agrccment. "Mid-Columbia Markct Encrey Cosf' - is 82.4Yo of thc monthly arithmctic avcrage of each day's Intercontinental Exchange ('ICE') daily firm Mid-C Peak Avg and Mid{ Oft-Pcak Avg index priccs in the month as follows: The actual calculation bcing: It .824* (I (ICEMid-C PeakAvg. * Hlhours forday) + X-t (ICE MidC Off-Pcak Avg* * LL hours for ilay)) / (n*24) where n: number of days in the month If thc ICE Mid-C Index priccs arc not rc,portcd for a particular day or days, prices derived from the respective avoragcs of HL and LL priccs for the immediatcly prccoding and following reporting pcriods or days shall be substituted into the formula stated in this definition ard shall thcreforc bc multiplicd by the appropriatc respcctive numbers of HL anrl LL Hours for such particular day or days with thc result that cach hour in such month shall have a rclatcd pricc in such formula. If thc day for which priccs arc not rcportcd has in it only LL Hours (for cxamFle a Sunday), thc rcspective avcragcs shall use only priccs reported for LL hours in thc immediatcly prcceding and following reporting pcriods or days. If thc day for which priccs arc not rcportcd is a Satruday or Monrday or is adjacent on the calendar to a holiday, thc priccs uscd for HL Hours shall bc thosc for HL hours in thc nearest (for:ward orbachrard) rc,portingpcriods ordalrs forwhich HLpriccs arcreportcd. IEP EXHIBIT 402 Page 6 of34 1.28 1.29 "Monthly Estimated Generation" - the monthly estimated generation as specified in Appendix I identified as the Monthly estimated kWh adjusted for any applicable Solar Paael Degradation. "Monthlv Namcplate Eneret'' - Nameplate Capacity multiplied by thc hours in the applicable month. "IQ!0ffl4lgleggifi" JThe full-load clectical quantities assigned by the designer to a Gcneration Unit and its prime mover or othcr piecc of electical cquipmarf such as transformers and circuit breakers, rmder standardized conditions, expressed in amperes, kilovolt-amperes, kilowatts, volts or other appropriate trnits. This value is establishcd for the term of this Agreemcnt in Appendix B, item B-l of this Agrcement and validated in paragraph 4.1.4 of this Agree,ment. 'tlet-Eqergg" - All of the electric cnergy produced by the Facility, lcss Station Usc and Losses, exprcssed in kilowatt hours (krtr/h) dclivcred by the Facility to Idaho Power at the Point of Dclivcry. Subjcct to the tcrms of this Agreement, Sellcr commits to dcliver all Nct Encrgy to Idaho Powcr at the Point of Dclivcry forttrc full tcrm of the Agrccment. "OpcratlggDate" - The day commcncing at 00:01 hours, Mountain Time, following thc day that all requirements of paragraph 5.2 have beeo completed and after the Seller requested Opcration Date. "Pq!4-of-DElivEry" - The location specified in the GIA and referenced in Appendix B, where Idaho Powcrns and thc Seller's elcctrical facilities are interconnected and thc c,ncrgy from this Facility is dclivered to the Idaho Power clcctrical system. "Price AdJustnent Atusted Estfud '- the Estimated Net Energy Amount spccificd in paragraph 6.2 including any adjustrucnts that havc becn made in accordancc with paragraphs 6.2.2 and any applicable Solar Panel Dcgradation adjusbnents. "Pricing Adjushcnt PcrcentagC'- Estimatcd Nct Encrgy Amount Adjustmcnt Perccntagc plus 2%. If this calculation rcsults in a value greater than 100%, thc rcsult of this calculation will be 100% or if this calculation results in a valuc less than 90o/o,the rcsult of this calculation will bc 90%. IEP EXHIBIT 402 Page 7 of34 1.30 1.31 1.32 1.33 1.34 1.35 1.36 1.37 '@' - Those practices, methods and equipment that are commonly and ordinarily used in electical engineering and operations to operate electric equipment lawfirlly, safely dependably, efficicntly and economically. '@' or "BEe" means a certifiOate, credit, allowancg grcen ta& or other transferable indicia, howsoever entitled, indicating generation of renewable energy by the Facility, and includes all Environmental Attibutes arising as a result of the generation of electricity associated with the REC. One REC represents the Environmental Attributes associated with the generation of one thousand (1,000) kWh of Net Energy. 1.38 "ScheduledOpcrationDate" - The date specified in Appcndix B when Seller anticipates achieving the Operation Date. It is expectcd that the Scheduled Operation Date provided by the Seller shall be a reasonable estimate of the date that the Seller anticipates that the Seller's Facility shall achieve the OpcrationDate. 1.39 "Schedule2' - Idaho Power's Tariff No 101, Schcdule 72 or its succcssor schedules as approved by thc Com+rtsion. 1.40 "Sgilv Dgpgsit" - $45 per kW Nameplate Capacity of the entire Facility. l.4l "Solar Energy Production Forecasf'- A forecast ofenergy deliveries from this Facility provided by an Idaho Power administercd solar forecasting model. The Facility shall be responsible for an allocatcd portion of the total costs of the forecasting modcl and to providc solar irradiation and weather data specified in Appendix H. 1.42 "Solar Facility Pricing S d' - The pricing schedule to be applied to all energy purchases within this Agreement as dctcrmined by paragraph 7.1. 1.43 "Solar Inteeration Charse" - a pcr kWh charge as specified in the Solar Facility Pricing Schedule applied to all Net Encrgy to be deductcd from the monthly cnergy payme,nts in accordance with Article VII of this Agrccmcnt. 1.44 "Solar Panel Desradation" - shall be the degradation as specifically documented by the solar pv panel manufasturer for the actual solar panels installed at this Facility, stated in a perc€ntage value for each Contract Year. These values will be provided and validated as specified in paragraph 4.1.6 of this Agrecment. IEP EXHIBIT 402 Page 8 of34 1.45 1.46 "Statigr_Use" - Electic energy that is used to operat€ equipment that is auxiliary or otherwisc related to the production of electicity by the Facility. "@_Engrg' - Is (1) Net Energy produced by the Selle,f s Facility and delivered to the Idaho Power elecnical system during the month which exceeds ll10% of the monthly Adjusted Estimated Net Energy Amount for the corresponding month specified in paragraph 6.2, or Q)if the Net Energy produced by the Seller's Facility and delivered to the Idaho Power electrical system during the month is less thm 90% of the monthly Adjusted Estimated Net Encrgy Amount for the corresponding month specified in paragraph 6.2, then all Net Energy delivcrcd by the Facility to the Idaho Power elechical systcm for that given month, or (3) all Net Energy produced by the Seller's Facility and delivered bythe Facility to the Idaho Power electrical systcm priorto thc Operation Datg or (4) all monthly Net Encrgr that exceeds the Monthly Nameplate Energy. "Terminatigda!0aggs" - Financial damagcs thc non defaulting parly has incurred as a result of termination of this Agrcemcnt. ARTICLE tr: NO RELIANCE ON IDAHO POWER Seller Inde,pendent Investigation - Seller warrants and represents to Idaho Power that in entering into this Agrecrnc,nt and the undcrtaking by Seller of the obligations set forth herein, Sellcr has investigated and dctcrmincd that it is capablc of pcrforming hcreunder and has not relied upon thc advice, experience or expertise of Idaho Power in connection with the transactions contemplatcd by this Agrccment. Seller Indeoendcnt Expcrts - All profcssionals or experts including, but not limited to, engineers, attoneys or accountants, that Sellcr may have consulted or relied on in undertaking the transactions contcmplated by this Agrccmcnt havc becn solcly those of Scllcr. ARTICLE ltr: WARRA}.ITIES No Warranty by Idaho Power - Any rcview, acceptancc or failure to review Sellcr's dcsign, spccifications, equipment or facilitics shall not be an cndorscment or a confirmation by Idaho Power and Idaho Powcr makes uo warranties, exprcssed or implied, rcgarding any aspcct of IEP EXHIBIT 402 Page 9 of34 1.47 2.1 3.1 3.2 Seller's design, qpccifications, cquipment or &cilities, including, but not linited to, safety, durability, reliability, strengt\ capacity, adequacy or economic feasibility. Qualiffing Facili[v Status - Scller warrants that thc Facility, oncc constnrcted, will be a "Qualiffing Facility,'as that term is used ancl dcfincd in 18 CFR 292201et seq. After initial qualification, Seller will take such steps as maybc requircd to maintain the Facility's Qualifring Facility status during the term of this Agrccmcnt and Sellcr's failure to maintain Quali&ing Facility status will be a Matcrial Breach of this Agrceme,nt. Idaho Powcr rcscrvcs thc rigfut to rcrricw the Facility's auatrying Facility stahrs and associated support md compliance documents upon reasonable request during the term of this Agrcc,me,lrt. Solar Project Oualifications - Scllcr warrants that thc Facility is a "Solar Project " as that tcrm is uscd in Commission Order 32697. Aftcr initial qualificatio4 Scllcr will takc sueh stcps as may be rcquired to maintain thc Facility's Solar Projcct status during thc ftll tcrm of this Agrcemcnt aud Seller's failurc to maintain Solar Project status will be a Matcrial Brcach of this Agrc€, crrt. Idaho Powcr resarycs the right to review the Facility's Solar Projcct status and associated support and compliance documcnts upon reasonable rcquest furing the term of this Agrcemcnt. Hourly Energy Estimates - Scller walrants that thc Hourly Encrry Estimatcs providcd by the Scller and containcd in Appcndix I arc accuxatc cstimates of thc Facility's cxpcctcd hourly cncrgy production bascd on the characteristics of tho solm gcncration cquipmcnt bcing installed, configuration and oricntation of the cquipmcnt installation, location qpccific solar radiation and aoy othcr information available as of the Effcctivc Datc. Material dcviations from thcse Hourly Energy Estimates will be a Matcrial Breach of this Agrcement. ARTICLE IV: CONDITIONS TO ACCEPTA}.ICE OF ENERGY Prior to thc First Encrgy Datc and as a condition of Idaho Powcr's acccptance of dclivcrics of encrgy from the Selleruader this Agrccmcnt, Scllcr shall: 4.1.1 Submit proof to Idaho Powcr that all liccnscs, pcrmits, d*crminations or approvals neccssary for Scller's operations have bcen obtaincd from applicable fcderal, state or local authoritics, including but not limitcd to, cvidcncc of compliancc with Subpart B, 1 8 IEP EXHIBIT 402 Page 10 of34 3.3 3.4 4.1 ffR292.201 et seq. as a certified QualiSing Facility and evidmce of compliance with the eligibility to be classilied as a Solar Project as refere,nced in Commission Order 32697. 4.1.2 Opinion of Counsel - Submit to Idaho Power an Opinion Letter signed by an attomey admitted to practice and in good standing in the State of Idaho providing an opinion that Seller's licenses, permits, determinations and approvals as set forth in paragraph 4.1.1 above arc legally and validly issued, are held in the name of thc Seller and" based on a reasonable independent r6view, counsel is of the opinion that Seller is in substantial compliauce with said permits as of the date of the Opinion Letter. Thc Opinion I*tter will be in a form acceptable to ldaho Power and will acknowlcdge that the attorney rendering the opinion understands that Idaho Power is relying on said opinion. Idaho Power's acceptance of the fomr will not be unreasoaably withhcld. The Opinion Irtter will be governed by and shall be interpreted in accordance with the legal opinion accord of the American Bar Association Section of Business Law (1991). 4.1.3 Commission Approval - Confrm with Idaho Power that Commission approval of this Agreement in a form acceptable to Idaho Powerhas been received- 4.1.4 Nameplate CaErcity - Submit to Idaho Power manufacturer's and engineering documentation that cstablishes the Nameplate Capacity of each individual Generation Unit that is inclqded within this entire Facility md the total of these units to determine the Facility Nameplatc Capacity rating. Upon reccipt of this data, Idaho Power shall rcview the provided data and dctcrminc if the Nameplate Capacity spccifrcd is reasonable based upon the manufacturcr's specified gcneration ratings for the qpccific Generation Units. Thc Namcplate Capacrty shall bc mcasured in Alternating Cuncnt (AC). 4.1.5 Completion ccrtificatc - Submit a certificate exccuted by an authorizcd agent of thc Scllcr attcsting that all mechanical aod clcctical cquipmart of thc designatcd Gencration Uoit(s) of the Facility has been completed to enable the Generation Uni($ to bcginning testing and delivery of Test Encrgy in a safc manner. IEP EXHIBIT 402 Page 1l of34l0 4.1.6 Solar Panel Deeradation - submit Solar Panel Degradation values (e,xpressed as a pcrcentage) for cach Contract Year for the ftll term of this Agrec,mcnt and the panel manufacturer dosumentation and certification that clcarly identifies nnd validates these exact values. Only values that are within reasonable solar industry standards and specifically validated by the manufacturer documeirtation will b€ acceptable. 4.1.7 Insurance - Submit writtcn proof to Idaho Power of all insuraace required in Article )iltr. 4.1.8 Interconnection - Provide written confirmation from Idaho Powcr's business unit that administers thc GIA that Seller has satisfied all interconnection and testing reErirements that will enablc the Facility to bc safcly connected to the Idaho Power clcctrical systcm. 4.t.9 Network Rcsource Desienation - Confirm that thc Scller's Facility has becn dcsignatcd as an Idaho Power network iesource capable of delivering energy up to the amount of the Maximum Capacity at the Point of Dclivery. 4.1.9.1 As spccfficd in Appendix B item B-7 of this Agrecmart the Scller's Facility must have achieved the status of being an Idaho Power Designatcd Nctwork Resource CDI.IR') prior to Idaho Power accqrting any €ncrry from this Facility. Appcndix B item B-7 providcs information on the initial application proccss requircd to cnablc Idaho Powcr to dctcrmine if nctwork tansmission capacity is availablc for this Facility's Maximum Capacity Amount and/or if Idaho Power transmission nctwork upgradcs will bc rcquircd. The rcsults of this study proccss and any associated costs will be includcdinthe GIA for this Facility. 4.1,9.2 Only aftcr the Facility has complctcd all rcquirc,ments of thc GIA that c,nablc the Facility to comc online can Idaho Power bcgin thc final process of desipating this rcsor:rcc as an Idaho Power DNR. Thc final proccss must be initiatcd at a minimum 30 days prior to thc First Eacrgy Date. Thcrcforc, Idaho Powcr will begin this process 30 days prior to the Schcdulcd First Energy Datc specificd in Appcudix B of this Agrecmcnt aud only aftcr Idaho Powa has rcceivcd confirmation that the GIA rcquireme,nts have bceo complcted. If the Sellcr estimates that the actual First Energy is expected to be diffoent thcn thc IEP EXHIBIT 402 Page 12 of34ll 5.1 5.2 Schcduled First Energy Date specified in Appendix B of this Agreement, the Seller must notiff Idaho Power of this revised date no later than 30 days prior to Scheduled First Energy Date. Under no circumstances will thc projest b€ able to deliver any energy to Idaho Poweruntil such time as Idaho Power has designated this Facilityas anldaho PowerDNR. 4.1.10 Written Acceptance - Request and obtain written confirmation from Idaho Power that all conditions to accqrtance of energy have been fulfilled. Such written confinnation shall be provided within a coomercially reasonable time following the Sellcr's request and will not be unreasonably withheld by Idaho Power. ARTICLE V: TERM A}.ID OPERATION DATE Term - Subject to the provisions of paragraph 5.2 below, this Agreement shall become effective on the date first written and shall continue in full force and effect for a pcriod of 20 (not to exceed 20 years,) Contract Years from the Operation Date. OpcrationDate-A single Operation Date will be grantcd for thc entire Facility and may occur only after the Facility has achieved all of the following: a) At the minimum, 75% of thc Nameplatc Capacity of this Facility as idcntified in Appcndix B, item B-1 has achieved First Energy Date. b) Seller has demonshated to Idaho Powet's satisfaction that all mechanical and elechical tcsting has been complctcd satisfactorily and thc Facility is able to provide energy in a consistorl rcliable and safc manner. c) Enginecr's Certilications - Submit an cxecutcd Enginceds Ccrtificatioo of Dcsign & Constnrction Adequacy and an Enginee/s Certification of Opcrations and Maintenance (O&M) Policy as described in Commission Ordcr No.21690. These ccrtificates will bc in the form specified in Appc,ndix C but may bc modificd to the extent necessary to recogpizc the different e,ugincering disciplines providing the ccrtificates. IEP EXHIBIT 402 Page 13 of34l2 5.3 d) Seller has requested an Operation Date from Idaho Power in a witten format. e) Seller has received wrifien confirmation from Idaho Power of the Operation Date. This confirmation will not be unreasonably withheld by Idaho Power. Operation Date Delay -r Seller shall cause the Facility to achieve the Operation Datc on or before thc Scheduled Operation Date. Delays in the interconnection and transmission network upgrade study, desigu and consructiotr process (Ihis includes any delay in making the reErired dcposit payments sct forth in the Facility's GIA) that are not causcd by Idaho Power or Force Majcurc events accqlted by both Parties, shall not prcvent Delay Damages or Termination Damages from being due and owing as calculated in accordance with this Agreunent. Termination - If Seller fails to achicvc thc Operation Datc prior to expiration of the Dclay Cure Period, such failure will bc a Matcrial Brcach and Idaho Power may terminate this Agrccmcnt at any time until the Seller cures the Material Breach. Delay Damagcs billine and palm€nt - Idaho Powcr shall calculatc and submit to the Scller any Dclay Damagcs due Idaho Power within 15 days after the end of each month or within 30 days of the datethis Agreeinent is terminatedby Idaho Power. Termination Damases billing and palment - Idaho Power shall calculatc and submit to thc Scller any Tcrmination Damagcs due Idaho Power within 30 days aftcr this Agrcemart has bcen tcrminated. Sellcr Paymart - Seller shall pay Idaho Power aoy calculatcd Delay or Tcrmination Damages within 7 days of when Idaho Powcr prcsents these billings to thc Seller. Scller's faih:rc to pay thcse damagcs within the specified time will be a Material Breach of this Agreemcnt and Idaho Powcr shall draw funds from the Security Dcposit provided by thc Scllcr in an amount cqual to the calculatcd damages. Security Dcposit - Within thirty (30) days of thc date of a fmal non-appealablc Commission Ordcr approving this Agrcemart as specificd in Article )O(I, thc Scllcr shall post and Eaintaitr liquid security in a form as dcscribed in Appondix D cqual to or cxcceding thc amoult spccificd within this Agrccment as thc Sccurity Dcposit rmtil snrch timc as thc Sccruity Deposit is rclcased by Idaho Power as specified in paragraph 5.8.1. Failure to post this Security Deposit in the time IEP EXHIBIT 402 Page 14 of34 5.5 5.6 5.7 5.8 13 6.1 6.2 specified above will be a Material Brcach of this Agreement and Idaho Power may tcmrinate this Agreement. 5.8.1 Idaho Power shall release any remaining Security Deposit provided by Seller promptly after either the Facility has achieved its Operation Date or this Agreemeut has been tcrminated and only after all Delay and Tcrmination Damages have been paid in full to Idaho Powcr. ARTICLE VI: PURCHASE A}.{D SALE OF NETENERGY NctBnergy Purchase and Delivery -Except wheir either Party's performance is cxcused as provided herein, Idaho Powcr will purchasc and Seller will sell all of the Net Energy to Idaho Powcr at thc Poiut of Dclivcry. Estimatcd Nct Encrcy Amounts - shall be equal to Monthly estimated kWhs as qpecificd in Appendix I and as listed below: Month January Fcbruary March April May Junc July August Scptcmber October Novcmber Dcccmber k\r/h 8,179,485 10,815,971 14,675,623 16,440,251 19,993,120 20,468,567 23,001,655 21,410,640 17,565,099 15,303,268 9,032,003 8.037.740 Total 184,922,421 Thcse Estimated Net Encrgy Amounts will be adjustcd to rcflcct thc applicablc Solar Pancl Degradationthroughout thc tcrm of this Agreemcnt. 6,2.2 Seller's Adjustment of Estimatcd Nst Enerey Amounts - Aftcr thc Operation Datg the Scller may revisc any future monthly Estimatcd Nct Encrgy Amounts by providing writtcn notice no later than 5 PM Mountain Standard timc on thc last busincss day of thc Notification Month spccificd in thc following schedulc: IEP EXHIBIT 402 Page 15 of34t4 Notification Month Future monthly Estimated Net Enerry Amounts cligiblc to be rcviscd November DecembEr January February March April May June July August September January and any future months February aad any future months March and any frrturc months April and any ftture montbs May and any futtre months June and any future months Julyand any future months August aod any future months September and any futurcmonths October and any future months November and aay firture months October Dccember and any future months This written notice must be provided to IdahoPowcr in accordancc with paragraph 25.1 or by clectronic notice provided and vcrificd via rctum clcctronic vcrification of reccipt to the clcctronic notices addrcss spccified in paragraph 25.1. Faihre to providc timely written notice of changed Estimated Net Encrgy Amounts will bs dee,med to be an election of no changc from the most recently provided Estimated Net Energy Amounh. c.) Any Seller provided Adjustmcnt of Estimated Net Energy Amounts will include any Solar Pancl Degradation. Thc Solar Pancl Dcgradation adjushcnt will only bc applied to Estimated Net Energy Amounts ttrat have not becn adjustcd by the Scller since the inception of thc current Conkact Ycax. 6.2.3 Idaho Power Adjustment of Estimatcd Nct Enerqy Amount - If Idaho Power is cxcused from accepting the Scllcr's Nct Encrgy as spccified in paragraph 12.2.1 or if the Scller declares a Suspension of Energy Dclivcrics as spccified in paragraph 12.3.1 and thc Seller's declarcd Suspension of Encrgy Dclivcrics is acccpted by Idatro Power, the Estimatcd Nct Energy Anrount as specified in paragraph 6.2 for thc spccific month in which the rcduction or strspcasion undcr paragraph 12.2.1 or 12.3.1 occurs will be temporarily reduccd in accordaoce with thc following and only for thc astual month itr which the cvcnt occurred: IEP EXHIBIT 402 Page 16 of34 a.) b.) l5 Where: NEA = Current Month's Estimated Net Energy Amormt (Paragraph 6.2) SGU :a.) If Idaho Power is excused from acccpting the Selleds Net Energ;r as specified in paragraph 12.2.1 this value will bc equal to the pcrcentage ofcurtailmenf as qpccified by Idaho Power multiplied by the TGU as dcfincd bclow. b.) If the Seller declares a Suspension of Energy Deliveries as specificd in paragraph 12.3.1 this value will be tle sum of the individual Generation Units sizc ratings as spccificd in Appcndix B that arc impactcd bythc circumstances causing thc Seller to declare 3 $uspension of Energy Dcliverics. TGU : Sum of all of the individual generatorratings ofthc Generation Units at this Facility as specificd in Appcndix B of this agreement. Dsrr Actual hours the Facility's Net Energy delivcries were eitherr\urr rcduced or suspended under paragraph 12.2.1 or 12.3.1 TH - Acfual total hours inthe current month Rcsultine fornula being: Adiusted ssiimatea : NEA Net Encrgy Amount x NEA ) . (H(r *ry")) This Adjustcd Estimated Net Encrgy Amount will be used in applicablc Surplus Energy calculations for only the specific month in which Idaho Power was cxcused from accepting the Seller's Nct Energy or the Seller declared a Suspcnsion of Energy. Failure to Deliver Minimum Estimatcd Net Energv Amounts - Unless excuscd by an event of Forcc Majcure, Seller's failure to dcliver Nct Encrgy in any Coutract Ycar in an amount equal to at least ten percent (107o) of the sum of the Monthly Estimatcd Gcncration shall constitutc an event ofdcfault. ARTICLB VII: PI]RC}IASE PRICE A},ID METHOD OF PAYMENT The Solar Facility Pricing Schcdulc to bc includcd in this Agrecmcnt is diqputcd by thc Partics. Idaho Power belicves Appendix E is thc appropriate Solar Facility Pricing Schedule as it includes IEP EXHIBIT 402 Page 17 of34 7.1 16 an Idaho Power capacity deficit psriod beginnine m2021. The Scllcr belieyes Appendix F is the appropriate Solar Facility Pricing Schcdule and it includes an Idaho Powcr capacity deficit pdod bcginning in 2016. Both of thcse pricing schedules were calculated using the Commission approved Incremental Cost IRP Avoided Cost Methodology, with thc only ditroence leing the starting datc of the Idaho Powsr capacity deficit period. Thc Parties may submit to the Commission written argument or Comments in zupport of their respective positions, in accordance with a procedrual schedule mutually agreeable to the Partics and the Commission. The Parties have agreed to all othcr tcrms and conditions of this Agrccment and hereby agree to submit this Solar Facility Pricing Schedule disputc to thc Commission for resolution. Thc Partics agrec to abide and bc bound by the Commission's decision on this issuc. The final Ordcr of thc Commission resolving this disputc will bc includcd and becomc an intcgral part of this Agrecmeirt, which thc Parties agrec to support and uphold. Basc Encrg!'Ilcary Load Purchase Price - For all Base Encrgy reccived during Hcavy Ioad Hours, Idaho Powcr will pay the monthly Base Encrgy Hcayy Load Purchaso Pricc as spccified in thc Solar Facility Pricing Schcdule including any applicable Pricc Adjusment, less the Solar Intcgration Charge. Basc Encrgy Light Load Purchasc Price - For all Base Energy reccivcd during Light Inad Hours, Idaho Power will pay the monthly Basc Encrgy Light Load Purchase Pricc as specified in thc Solar Facility Pricing Schedule including an applicable Pricc Adjushcnt, lcss the Solar lntegration Chargc. Sumlus Encrgy Pricc - For all Surplus Encrgy, Idaho Powcr shall pay to thc Scllcr thc current month's Markct Encrgy Refercnce Pricc or thc Basc Encrgy Light load Purchase Price including any applicable Pricc Adjushent, lcss thc Solar Integration Chargc for that month, whichevcr is lowcr. Pricc Adjustmcnt - Upou acccptancc of a Seller Adjustment of Estimatcd Net Encrry Amounts as spccificd in paragraph 6.2.2, Idaho Power will calculate the Pricing Adjustnent Pcrccntagc for thc applicable month(s). All pncing contained within thc Solar Facility Pricing Schedulc for thc IEP EXHIBIT 402 Page 18 of34 7.2 7.3 7.4 7.5 t7 7.6 7.7 curent applicable month(s) and all future applicable montbs will be multiplied by the Pricing Adjustment and the resulting revised prices will rqrlace the prices contained withitr the Solar Facility Pricing Schedule until such time as the Seller submits a ncw Seller Adjushent of Estimated Net Energy Amounts at which time a new Pricing Adjustment Percentage will be calculated and applied in accordance with this paragraph. For Example - a Pricc Adjustment applicable to Jaouary 2018 y'rill also be applied to all months of January for the remaining term of the Agree,ment. This reviscd January pricing will thcn rcmain in effect until zuch time as the Scllcr requcsts an additional Adjushent og 6stimated Net Energy Amounts that would be applicable to future months of January. Delivering Nct Energy that exceeds the Monthly Narneplate Energy to Idaho Power for 2 consecutive months and/or in any 3 months during a Contract Year will be a Material Breach of this Agreemcnt and Idaho Powcr may terminatc this Agree,mcnt within sixty (60) days aftcr thc Material Brcach has occurred. Payments - Undisputed Base Energy and Surplus Energy palments inclusive of Price Adjustmcnts, lcss Solar Integration Costs, less Solar Enerry Production Forecasting Costs, and less any palments due to Idaho Power will be disbursed to the Seller within thirty (30) days of the date which Idaho Power receives and accepts (acting in its reasonable discretion and in a reasonably timely manner) the documentation of the monthly Base Energy and Surplus Encrgy actually delivered to Idaho Power as specified in Appendix A. Continuing Jurisdiction of thc Commission -This Agrccment is a special contract and as such, the rates, terms and conditions contained in this Agrecment will bc construed in accordance with Idaho Powa Company v. Idaho Public Utilities Comnrission and Afton Encr$v. Inc., l0T Idaho 781, 693 P.Zd 427 (1984), Idaho Powo Companv v. Idaho Public Utilitics Commission, 107 Idaho 1122, 695 P.2d I 261 (1985), Afton Encrey. Inc. v. Idaho Power Compan),. l l l Idaho 925, 729 P.2d 400 (1986), Scction 210 of thc Public Utility Rcgulatory Policies Act of 1978 and 18 cFR $292.303-308. IEP EXHIBIT 402 Page 19 of34 7.8 18 8.1 ARTICLE VItr: ENVIRONMENTAL ATTRIBUTES Idaho Power will be granted ownemhip of 50Yo of all of the Environmcntal Athibutes associated with the Facility and Seller will likewise retain 50% ownership of all of thc Environmcnal Attributes associated with the Facility. Title to 50% of the Environmcntal Attributcs shall pass to Idaho Power at the same time that hansfer of title ofthe associatcd Surplus Energy or Nct Encrgy to Idaho Power occurs. Idaho Power's titlc to 507o of lhe Environmcntal AtEibutcs shall cxpire at the cnd of the term of this Agrecment, unless the partics agree to extend in future agreements. If after the Effective Date and during thc tam sf this any additional Environmental Attributes or similar environmeirtal value is "r"ut"d by l"gislatio4 rcgulatioq or any other action, including but not limited to, carbon crcdits and carbon offsets, Idaho Powcr shall be grantcd ownership of 50% of thcsc additional Environmcntal Attibutcs or cnvironmental valucs that arc associatcd with thc Net Energy dclivercd by thc Scller to Idaho Powcr. Sellcr shall usc pmdent and commercially reasonable cfforts to ensurc that aay operations of the Facility do not jeopardizc thc curcllt or futurc Enviroomental Attributc status of this solar gcneration Facility. The Parties shall ssspsrafe to ensure that all Environmcntal Attribute ccrtifications, rights and reporting requirements are completed by the responsible Partics. 8.2.1 At lcast sixty (60) days prior to the First Energy Date, the Partics shall mutually cooperatc to enablc Idaho Powsr's Environmcntal Attributcs from this Facility to bc placed into Idaho Powcr's Wcstcm Rcncwable Energy Ge,:reration Information Systcm C'WREGIS') account or arry othcr Environment Attributc accounting and tracking system selected by the Idaho Power. Thc Sellcr at the Seller's sole expcnse will be rcsponsiblc to cstablish and maintain the Scllcr's WREGIS or othcr Environmqrtal Attribute account and/or systcm t&at cnablcs the creation of thc Environmcntal Attributc certificatcs associatcd with this Facility and the tansfer of 50% of the Environmcntal Attributcs to Idaho Powcr for the Tcrm of this Agrccment. If thc Environmcntal Athibutc accounting and tracking system initially selectcd by Idaho Power is matcrially altcred or discontinucd during the Term of this Agrcemcnt, thc Partics shall coopcrate to IEP EXHIBIT 402 Page 20 of34 8.2 19 identi$ an appropriate altemative Environmental Attribute accounting and hacking proc€ss and e,nable the Environnrcntal AtEibutes be processed throug$. this altcrnative method. 8.2.2 Each Party shall only report under Section 1605(b) of the Energy Policy Act of 1992 or under any applicable progam the 50% of the Environme,ntal Athibutes that such parly owns and shall refrain from reporting the Environmental Attributes owned by the other Party. 82.3 If Idaho Power requests additional Environmartal Attribute certifications beyond what is provided by the WREGIS proccss the Scller shall use its best cfforts to obtain any Environmental Athibute certifications required by Idaho Power for those Environmental Attributes delivered to Idaho Powcr from the Seller. If the Seller incurs cost, as a rcsult of Idatro Power's request and if the additional certification providcs benefits to both parties, the parties shall sharc the costs in proportion to the additional bcnefits obtained. If Idaho Power elects to obtain its own certifications, then Seller shall fully cooperatc with Idaho Power in obtainiag such certification. ARTICLE D(: FACILITY A}TD INTERCONNECTION 9.1 Dasien qf Facilitv - Sellcr will design, constuct, install, own, operate antl maintain the Facility and any Seller-owned Interconnection Facilitics so as to allow safe and reliablc generation and delivery of Net Energy to the Idaho Power Point of Dclivcry for thc full term of the Agrcement in accordancc with thc GIA. ARTICLE X: METERTNG. MEIERD{G COMMT]NICATIONS A}iID SCADA TELEMETRY 10.1 Mctcring - Idaho Powcr shall, providc, install, and maintain mctering equipmcnt needcd for metering the clectical cncrgy production from the Facility. Thc mctcring cquipmcnt will bc capablc of measuring, recording rctricving and rcporting thc Facility's hourly gross clectrical cnclgy production, Station Use, maximum encrgy delivcries (klfrD and any otho energy mcasurcments at thc Point of Delivcry that Idaho Power nccds to administcr this Agrccmcnt and IEP EXHIBIT 402 Page2l of3420 integrate this Facility's energy production into the Idaho Power elcctical system. Specific equipment, installation details and requireineirts for this metering equipmcnt will be cstablishcd in the GIA p(rcess and documented in thc GIA Seller *hall be responsible for all initial and ongoing costs of this as specified in Schedule 72 and the GIA. 10.2 Metcrine Commrmications - Scller shall, at thc Sclle,fs solc initial and ongoing e4pcnse, arrange for, provide, install, and maintain dedicated metering communications equipment capable of transmitting thc metering data spccified in paragraph 10.1 to Idaho Powcr in a frcquency, rnaDncr and form acccptable to Idaho Powcr. Scller shall grant Idaho Power sole control and use of this dedicated mctering communications equipment. Spccific details aoil rcquireinarts for this mctcring communications equipment will bc cstablished in the GIA process and documentcd in thcGIA. 10.3 Supcrvisory Control and Data Acquisition (SCADA) Tclemetry-If thc Facilitfs Namcplatc Capacity cxcceds 3 MW, in addition to thc requireme,nts of paragraph 10.1 and 10.2, Idaho Power may rcquire telemctry equipnnent and telecommunications which will be capable of p,roviding Idaho Powcr with continuous instantaneous SCADA tclcmctry of the Scllc,fs Net Encrry and Inadvcrtent Encrgy production in a form acccptablc to Idaho Powcr. Scllcr shall grant Idaho Power sole control and use of this dedicatcd SCADA and telccommunications cquipmcnt. Specific dctails and rcquire,mcnts forthis SCADA Tclcmetry and tclccommunications cquipmcnt will bc established in the GIA process and documcnted in the GIA. Sellcr shall be responsible for all initial and ongoing costs of this equipmcnt as spccificd in Schcdulo 72 and thc GIA. ARTICLE XI . RECORDS l1.l MaintsnanccofRccords - Scllcr shall maintain monthly rccords at thc Facility or such other location mutually acceptablc to thc Partics. Thcsc rccords shall iacluilc total gc,ncratio& Nct Energy, Station Usc, Surplus Energy, Inadvcrtont Encrgy aad maximum hourly gcncration in (kW) and be records in a form aod conte,nt acccptablc to Idaho Powcr. Monthly records shall bc retaincd for a pcriod ofnot lcss than fivc ycars. ll.2 Inspcction - Either Party, after reasonablc noticc to the other Party, shall havc thc rigbt, durhg IEP EXHIBIT 402 Page22 of342l normal business hours, to inqpect and audit any or all records pertaining to the Seller's Facility generation, Net Ene,1gy, Station Use, Surplus h*gy, Inadvertcnt Encrgy and maximum hourly gencration in kW. ARTICLE)fi: OPERATIONS l2.l Communications - Idaho Power and the Sellcr shall maintafu appropriate operating communications through Idaho Power's Dcsignated Dispatch Facility in accordance with the GIA. 12.2 AcceptanceofEnergy- 12.2.1 Idaho Power shall be excused from accepting and paying for Net Energy which would have otherwise becn producod by the Facility and delivered by thc Seller to the Point of Delivcry: a.)If energy deliveries are intemrpted due an cvqrt of Forcc Majeure or Forced Outage. If intemrption of energy deliveries is allowed by Section 210 of &e Public Utility Regulatory Policies Act of 1978 and 18 CFR $292.304r. If temporary disconnection and/or intemrption of energy deliveries is in accordance with Schedule 72 or otler provisions as specifred within the GIA. If Idaho Power determines that curt4ilment, intemrption or reduction of Net Energy delivcrics is necessarybccause of linc construction, clectrical system maintenance rcquircments, cmergcncics, electrical system opcrating conditions, elcctrical systcm rcliability cmergencies on its systcm, or as otherwisc requircd by Prudcnt Elcctical Practiccs. 12.2.2 lf, in the reasonable opinion of Idaho Power, Ssllet's operation of the Facility or Intcrconnection Facilitics is unsafc or may othcrwise advcrscly affcct Idaho Power's I Any clcctric utility which gives notice . .. will uot bc rcquircd to purchase eleptric cnergy or cepacity during any pcriod during which, due to operational circumstances, purchases &om qualifying facilitics will result iu costs grcatcr than &osc which thc utiliry would incur if it did not make such purohases, but instcad gcncratcd an cquivalent amount of energy itsclf. IEP EXHIBIT 402 Page 23 of34 b.) c.) d.) 22 equipmerf, persormel or service to its customers, Idaho Power may tc,mporarily disconnect the Facitty from Idaho Powcr's ftansmission/dishibution systcm as spccified within the GIA or Schedule 72 or take such other reasonablc stq)s as Idaho Powcr decms appropriate. 12,2.3 Under no circumstances will the Seller deliver enerry from the Facility to the Point of Delivcry in an amount ttrat exceeds the Ma:rimum Capacity Amount at any moment in time. Seller's failure to limit deliveries to the Maximum Capacity Amount will bc a Material Breach of this Agree,ment and must be cured immcdiatcly. 12.2.4 \f ldaho Power is unable to acccpt the energy from this Facility and is not cxcuscd from acccpting thc Facility's Gncrgy, Idaho Power's damages shall bc limitcd to only thc value of the estimated cnergy that Idaho Power was unable to accept valued at the applicablc energy prices specified in the Solar Facility Pricing Schcdulc. Idaho Power will have no rcqponsibility to pay for any other costs, lost revcnue or consequeotial damagcs the Facility may incur. Sellcr Declared Suspension of Energy Deliveries - 12,3.1 If thc Sellcr's Facility experiences a Forced Outagc, and Scllcr initiatcs a Declarcd Suspension of Energy Deliveries, Seller shall, after giving notice as provided in paragraph 12.3.2 below, te,mporarily reduce deliveries of Net Energy (kW) to Idaho Power from thc Facility to not cxcecd thc reduccd crrcrgy dclivcrics (kW) statcd by thc Seller in the initial declaration for a period of not lcss than 48 hours ('Declared Suspcnsion of Energy Deliverics'). Thc Scllcr's Dcclared Suspension of Encrgy Dcliverics will bcgin at the start of thc next fuIl hour following the Sellerns tclcphonc notification as spccificd in paragaph 12.3.2 aad will continue for thc timc as spccified (not lcss than 48 hours) in thc written notification provided by thc Scllcr. In thc month(s) in which thc Declared Suspension of Energy occurred, thc Estimatcd Net Encrgy Amount will bc adjustcd as spccificd in paragraph 6.2.3. 12.3.2 If thc Scllcr dcsircs to initiatc a Dcclarcd Suspc,nsion of EncrgyDclivcrics as provided in paragraph 12.3,1, the Seller will noti$ the Designatcd Dispatch Facility by tclcphonc. IEP EXHIBIT 402 Page24 of3423 t2.4 The beginning hour of the Declared Suspension of Energy Deliveries will be at the earlicst the next full hour after making tclcphone contact with Idaho Power. The Scller will, within 24 hours after the telephone contacf, provide Idaho Power a unittcn notice in accordaoce with Article )Q(V that will contain the beginning hour and duration of the Declared Suspcnsion of Energy Deliveries, a description of the conditions that caused the Sellcr to initiate a Declarcd Suspcnsion of EnergyDeliveries, and the reduced levcl (kW) of energy deliveries the Facility is requesting that will be set as the maximum c,rrcrgy deliveries to Idaho Powerforthe duration of&eDeclared Suspension of EnergyDclivery event (not less than 48 hours). Idaho Powcr will rcview the documentation provided by the Scllcr to determine Idaho Power's acceptancc of the dcscribed Forccd Outagc as qualiffing for a Declarcd Suqpension of Energy Deliveries as specified in paragraph 12.3.1. Idaho Pourer's accq)tance of thc Seller's Forced Outage as an acceptable Forced Outage will be bascd upon thc clcar documentation provided by the Seller that thc Forced Outago is not due to an event of Force Majeure or by neglect, disrepair or lack of adequate prcvcntative maint€nance of the Seller's Facility. Schcdulcd Maintc,nance - On or before January 31't of each calendar year, Seller shall submit a written proposed maintenance schcdulc of significant Facility maintenance for that calendar year and Idaho Power and Scllcr shall mutually agr€e as to the acceptability of the proposcd schedule. If the Seller intends to perform planncd maintenance at approximately the same time cvery year, the Seller may submit a maintenance schcdule for the first calcndar year and includc a statement that this maintc,nance schedule shall be consistc,nt for all futtre years, until such time as the Seller notifies Idaho Powcr of a changc to this schcdulc. The Parties dctermination as to thc acceptability of thc Seller's timetable for scheduled maintenance will take into consideration Prudcnt Elcctrical Practiccs, Idaho Powcr s)4stem rcEriremc,nts and the Sellcr's prcfcrrcd schcdule. Ncither Party shall unrcasonably withhold acc€ptancc of thc proposed maintcnancc schcdulc. Idaho Powcr Maintcnancc Information - Upon recciving a writtcn rcqucst from thc Sellcr, ldaho Power shall providc publically availablc information in regards to Idaho Powcr planncd IEP EXHIBIT 402 Page 25 of34 12.5 24 13.1 maintenance information that may impact the Facility. 12.6 Contact Prior to Chrtailmcnrt - Idalro Power will makc a reasonable attempt to oontact the Scller prior to exercising its rights to intemrpt interconnection or surtail deliveries from thc Seller's Facility. Scller undcrstands that in the case of emergenoy circumstances, real time operations of the electical system, and/or unplarned cv€ots, Idaho Powcr may not be ablc to provide noticc to the Seller prior to intemrption, curtailment, or reduction of elecnical energy deliveries to IdahoPower. ARTICLE XIII INDEMNEICATION A}.ID INSI.JRA}TCE Indemnification - Each Party shall agrce to hold harmless and to ind€mnit, the other Party, its ofEcers, age[ts, affiliatcs, subsidiaries, paront company and employccs against all loss, damage, expense and liability to third persons for injury to or death of pcrson or injury to property, proximately caused by the indemnifiog Party's, (a) constnrctio4 oumership, opcration or maintenance o{, or by failurc of, any of such Par[fs works or facilitics used in connection with tlis Agreement, or (b) negligent or intentional acts, errors or omissions. The indemnifuing Party shall, on the other Party's request, dcfcnd any suit asserting a claim covqred by this indemnity. Thc indemniffing Party shall pay all documcnted costs, including reasonablc attorney fecs that may be incunedby the othcr Party in cnforcing this indcmnity. Insurance - During the term of this Agreement Scller shall securc and continuously carry instrance as specified in Appendix G. ARTICLE XIV: FORCE MAJETJRE 14.1 As used in this Agrecmcnt, "Forcc Majcure" or "an event of Force Majeurc" mcals arry causc bcyond ttrc control of thc Scllcr or of Idaho Power which, dcspitc the cxcrcisc of duc diligcncc, such Party is unablc to prcvent or overcomc. Force Majcure includes, but is not limitcd tq acts of God, firc, flood, storms, warsr hostilitics, civil stifc, strikcs and othcr labor disturbanccs, earthquakes, fires, lightning, cpidemics, sabotagq which, by the exercise of reasonable forcsigbt such party could not reasonably have becn expcctcd to avoid and by the cxercisc ofduc diligcnce, IEP EXHIBIT 402 Page 26 of34 13.2 25 it shall be unable to overcome. Fluctuations and/or changes of the motive force and/or the fuel supply are not eve,rts of Force Majeure. If cither Party is re,ndered wholly or in part unable to perform its obligations rmder this Agreement because of an event of Force Majeurg both Partics shall be excuscd from whatever performancc is affected by the eveirt of Forcc Majerue, provided that: (l) The non-performing Party shall, as soon as is reasonably possible after the occulTence of the Force Majcure, give thc other Party written notice describing the particulars ofthe occurrence. @ The suspension of performance shall be of no grcater scope and of no longer duration than is required by thc evcnt of Force Majeure. (3) No obligations of cither Party which arose beforc thc occurre,ncc of thc Force Majeure evcnt and which could and should have becn fully performcd bcforc such occurrence shall be excused as a result ofsuch occurrence. ARTICLE XV: LIABILITY: DEDICATTON Limitation of Liability-Nothing in this Agrecment shall be construed to creato any duty to, any standard ofcare with reference to, or any liability to any person not a Party to this Neithcr party shall be liable to the other for any indirect, special, consequential, nor punitive damages, cxcept as exprcssly authorized by this Agrecme,nt. Dedisation - No undertaking by one Party to the other under any provision of this Agrcemcnt shall constitute tle dedication of that Party's systcm or any portion thereof to thc Parly or the public or affcct tle stahrs of Idaho Power as an indqrcndcnt public utility corporation or Seller as an indcpendent individual or c'!$lty. ARTICLE XVT SBVERAL OBLIGATIONS 16.1 Exccpt whcre specifically statcd in this Agreemcnt to bc othcrwise, the duties, obligations and liabilitics of thc Parties are intcnded to be scvcral and not joiat or collcctive. Nothing containcd in this Agrccmcnt shall ever bc constnred to create an association, tust, partncrship orjoint vcnturc IEP EXHIBIT 402 Page27 of34 15.1 15.2 26 or impose a trust or partnership duty, obligation or liability on or with regard to cither Party. Eaeh Party shall be individually and severally liable for its own obligations rmdcrthis Agreemeirl ARTICLE XVII: WAIVER 17 .l Any waiver at any time by cither Party of its rigfuts with respect to a default undcr this Agrecment or with rcspect to any other matters arising in conncction with this Agreemcnt shall not bc deemed a waiver with ralpeot to any subsequent default or other matter. ARTICLEXVItr: CHOICEOF LAWS A},ID VENUE 18.1 This Agreement shall be construed and interpreted in accordancc with thc laws of the State of Idaho without rcference to its choicc oflaw provisions. 18.2 Venue for any litigation arising out of or rclated to this Agreement will lie in the Distict Court of the FourlhJudicial District ofldaho in and forthe County ofAda. ARTICLE XD(: DISPUTES AND DEFAULT Diqputes - All disputcs related to or arising undcr this Agreement, including but not limited tq thc intcrprctation of the terms and conditions of this Agrecment, will be zubmitted to the Commission for resolution. Notice of Dcfault 19.2.1 Dcfaults - If cither Party fails to perform any of the terms or conditions of this 19.1 t9.2 Agreement (an "evcnt of default'), the non-defaulting Party shall causc notice in writing to be given to thc defaulting Party, specifring thc manncr in which such clefault occurred. If the defaulting Party shall fail to cure such default within thc sixty (60) days aftcr scrrrice of such noticc, or if thc dcfaulting Party rcasonably dcmonstrates to the other Party tbat the default can be cured within a commercially rcasonablc timc but not within such sixty (60) alay pcriod aud thcn fails to diligcntly pursuc suoh curc, thsn thc non-dcfaulting Party may, at its option, terminate this Agreeme,nt and/or pursuc its lcgal or eguitablc rcmcdics. Matcrial Breachcs - Thc notice and cure provisions in paragraph 19.2.1 do not apply IEP EXHIBIT 402 Page 28 of34 t9.2.2 27 to defaults identified in this Agreement as Material Breaches. Material Breaches must be cured as expeditiously as possible following occurrmce of the breach or if a specific sure and/or inability to cure is ide,ntified by this Agrecment for the specific ' Material Breach then that cure shall apply. 19.3 Prior to the Operation Date and thereafter for the ftll term of this Agreement, Seller will provide Idaho Power with the following: 19.3.1 Insurance - Evideirce of compliancc with the provisions of Appendix G. If Scller t9.3.2 fails to comply, such failure will be a Material Breach. Ensineer's Certifications - Every thrce (3) years after the Operation Date, Seller will supply Idaho Power with a Certification of Ongoing Operations and Maintenance (O&M) from a Registered Professional Engineer licensed in the Statc of Idaho, which Certification of Ongoing O&M shall be in the form specified in Appendix C. Seller's failure to supply the required certificate will be an event of default. Such a default may only be cured by Scller providing the required certificatc; and 19.3.3 Liccnscs / Permits / Determinations - During the fuIl term of this Agrccment, Seller shall maintain compliance with all pe,r:nits, licenses and determinations described in paragraph 4.1.1 of this Agreement. In additioq Seller will supply ldaho Power with copies of any new or additional pennits, licenses or determinations. At least every fifth Conkact Year, Sellcr will update the documentation described in Paragraph 4.1.1. If at any time Seller fails to maintain compliancc with the permits, licenses and determinations describcd in paragraph 4.1.1 or to providc the documentation required by this paragraph, such failure will be an cvent of dcfault and may only bc cured by Seller submitting to Idaho Power cvidence of compliancc from thc pcnnitting agcncy. ARTICLE }O(: GOVERNMENTAL AUTTIORTZATION 20.1 This Agrccme,lrt is subjcct to the jurisdiction of those governmcntal agcncics having contol ovcr eithcr Party of this Agrccmcnt. IEP EXHIBIT 402 PageZ9 of3428 ARTICLE XXI: COMMISSION ORDER 2l.l Idaho Power shall file this Agreement for its acceptance or rejection by thc Coomissioa and resolution of the diqputed SolarFacilityPricing Schedule as described inparagraph 7.1. This Agreeme,nt shall only become finally effectirae upon the Commission's appronal of all terms and provisions hcreof without changc or condition and declaration that all palmcnts to be made to Seller hereunder shall be allowed as prudently incuned sxpenses for ratanaking purposcs. ARTICLE )OfiI: SUCCESSORS A}.ID ASSIGNS 22.1 This Agreement and all of the terms and provisions hereof shall bc binding upon and inure to the benefit of the respcotivc successors and assigns of the Parties hercto. Neither this Agreemcnt nor auy rights or obligations of cithcr Party herermder may be assigncd in wholc or in part, by opcration of law or otherwise, wittrout the prior writtcn conse,nt of both Partics, which conscot shall not be unreasoru$ly withhcld. Notwithstanding thc foregoing atry party with which Idaho Powcr may consolidate, or into which it may merg€, or to which it may cotrvey or transfer substantially all of its clechic utility asssts, shall automaticalln without firther act, and without need of consent or approval by thc Seller, zuccccd to all of Idaho Power's rights, obligations and inte,rcsts undcr this Agreement. Any purported assignment in derogation of thc foregoing shall bc void. This article shall not prevent a fmancing entity with rccorded or sectrcd rights from cxcrcising all rights and rcmedics availablc to it undcr law or contract. Idaho Powcr shall have thc right to be notificd by the financing entity that it is cxcroising such rights or remedies. ARTICLE )Oilft MODIFICATION 23.1 No modification to this Agreement shall be valid unless it is in writing and signcd by both Partics and subscquartly approved by the Commission. ARTICLE X)$V: TA}(ES 24.1 Each ParU shall pay bcfore delinquency all taxes and other governmental chargcs which, if failed to bc paid when duc, could result in a lien upon thc Facility or thc Intcrconnection Facilitics. IEP EXIIIBIT 402 Page 30 of3429 ARfiCI,E )Ofl/: NOTICES AND AUTIIORIZED AGENTS 25.1 Notices -All written aoticcs under this Agreemom shall be directed as follows and shall be considcred dclivercd whcn faxe4 c-mailed and confimed with deposit in the U.S. Mail, first- class, postageprepai4 as follows: To Seller: Name: Tclephonc: Tclephonc: E-mail: Bmail: Name: Telcphonc: E-mail: To IdahoPower: Original documcntto: ClarkSolar l, LLC Attr: MarkranGulik POBox7354 Boiss Idaho 83707 (208)3424836 (800) 405-797s mvangulik@suncrE\rworld.com mark@intcrmountainenergtrpartners.com Cqpy ofDocumcnt to: McDcvitt& MillcrLLP Atta: DcanJMillcr 420We,*Bannock Boise, Idaho 83702 (208) 343-7s00 j oc@cdcvitt-millcr.com Orieinal documcntto: Vice Prcsident Power Supply Idaho PowcrCompany POBoxT0 Boisc,Idaho 83707 Email: lqrow@idahopowcr.com Copyof documcntto: Cogcneration and Small Power Production Idaho PowcrCompany POBoxT0 Boisc, Idaho 83707 E-mail : rallphin(O dahopower. com IEP EXHIBIT 402 Page 31 of3430 Either Party may change the contact person aod/or address information listed abovg by providing written notice from an authorized person represcnting the Party. 25.2 AuthorizcdAgqrtG) Name Authorized Agcnts as listed above may be modified by the Seller by requesting and completing an Authorized Agcnt modification documcnt provided by Idaho Powcr. This doeumcat at minimum will includc the requested changes and rcquirc signahuc(s) from an authorizcd party of thc Sellcr. Title 26.1 ARTICLE )O(VI: ADDITIONAL TERMS A}.ID CONDITIONS Equal Employrnent - During performance pursuant to this Agreement, Scller agrees to comply with all applicable cqual cmploymcnt opportunity, small business, and affirmativc action laws and regulations. All Equal Emplolme,nt Opportunity and affirmative action laws and regulations arc hcrcby incorporatcd by this refercnce, including provisions of 38 U.S.C. g 4212, Executive Order 11246, as a-endcd, and any subsequent cxecutivc ordcrs or other laws or regulations relating to cqual opportunity for cmploymcnt on govcroment contracts. To thc cxtcnt this Agrecmcnt is covcrcd by E;rccutivc Ordcr 11246, thc Equal Opporhrnity Clauses containcd in 4l C-F.R. 60-1.4, 4l C.F.R. 60-250.5, aad 41 CFR 60-741.5 are incorporated herein by rcfercnce. Prior to thc Scllcr cxccutiug this Agrcc,mcnt, thc Scllo shall have: a) Submitted an interconnection application for this Facility and is in compliance with all palmqlts and rcquircments of thc intcrconnection process. IEP EXHIBIT 402 Page 32 of34 26.2 31 b) Acknowledged rasponsibility for all interconnection costs and any costs associatcd with acquiring adequate firm transmission capaciqr to enable the project to be classffied as an Idaho Power Designated Network Resource. If final intcrconnection or hansmission studie$ are not complcte at the timc the Seller executes this Agreement, the Seller understands that the Seller's obligations to pay Delay aad Termination Damages associated with the project's failure to achieve thc Operation Date by the Scheduled Operation Date as spccificd in this Agrecment is not relieved by final interconnection or transmission costs, processes or schcdules. 26.3 This Agreement includes the following appendices, which are attached hereto and included by refcrence: Appendix A - Generation Schcduling andRcporting Appendix B - FacilityandPoint ofDclivcry Appcndix C - Enginecr's Ccrtifi.cations Appcndix D - Forms of Liquid Security Appendix E - SolarFacilityEnergyPrices Appcndix E - Alternativc SolarFacility EnergyPrices Appendix G - Insurancc Requircments Appcndix H - SolarEnergyProduction Forecasting Appendix I - Estimated Hourly Encrgy Production ARTICLE XXVII: SEVERABILITY 27.1 The invalidity or unenforceability of any term orprovision of this Agreement shall not affect the validity or enforceability of any other terms or provisions and this Agree,ment shall be consfiued in all other raspects as if the invalid or uncnforccablc term or provision werc omittcd. ARTICLE }O(VItr: COIJNTERPARTS 28.1 This Agreement may bc cxecuted in two or morc counterparts, each of which shall bc dccmed an original but all of which togcthcr shall constitutc onc and the same instrument. ARTICLE XXD(: ENTIRE AGREEMENT 29.1 This Agrccment constitutcs thc c,ntirc Agrccmcnt of thc Parties conceming thc subjcct matter hercof and supcrscdes all prior or contenrporaneous oral or writtcn agreements betwecn the Parties conceming thc subject matter hcreof. 32 IEP EXHIBIT 402 Page 33 of34 IN WTINESS WIIEREOF, The Parties hereto have caused this Agreement to bc orecutcd in their respective names on the dates set forth below: Idaho PowcrCompany Clark Solar 1, LLC -AJ24AD*Da- f#* @ €x€ad,lo lict Presibrl ,^l ' hl oP;;tg O#'ar Dated rul rg[\ "IdahoPowct'' MarkvanG\Ik Managcr IEP EXHIBIT 402 Page 34 of34 33 @pE-f-:tli?,:H by Val Stori Project Director Clean Energy States Alliance April 2013 About This Report This report and the State-Federal RPS Collaborative are generously supported by the U.S. Department of Energy and the Energy Foundation. However, the views and opinions stated in this document are the autho/s alone. The following individuals reviewed a draft of the report and provided useful comments that significantly improved the end product: Lori Bird and Jenny Heeter of the National Renewable Energy Laboratory and Warren Leon of the Clean Energy States Alliance. Any remaining weaknesses are not their responsibility. Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately-owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of the authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. (CSffiiii':lg Hydropower Environmental Rules in Renewable portfolio standards lntroduction Hydropower is an eligible technology in most of the states' renewable portfolio standards (RPS), but there are generally restrictions on which hydro projects can be included, because of the technology's maturity, established financial footing, and environmental concerns. Several states, including Connecticut, Maine, Oregon, and Washington, are currently considering revisions to their RPS that would change the way hydropower is treated in meeting renewable energy targets. ln addition, a few states are considering strengthening or better defining their environ menta I q ua lifications for hyd ropower. The most common environmental criterion in state RPSs is a capacity limit; most RPSs allow hydropower facilities under 30 MW to count towards RPS targets. Other states, such as California, have more restrictive definitions of renewable energy and limit hydropower's inclusion in the RPS with additional environmental criteria. This paper looks at the various approaches states have taken in their RPS policies to safeguard the environment when hydropower is developed. lt describes the rules for hydropower qualification, especially those having to do with environmental standards. Hydropower and Renewable Portfolio Standards Renewable Portfolio Standards, also sometimes called renewable electricity standards or clean electricity standards, are used to mandate the generation of electricity from renewable or other clean energy resources. These policies generally require that a certain percentage of the electricity sold within the state comes from designated energy resources. ln almost all of the RPSs1, hydropower is an eligible resource. The hydropower rules related to RPSs differ from state to state, but generally restrict hydro- power by capacity/size, vintage, or technology. The predominant limiting factor to hydropower RPS inclusion is age. RPSs generally give the highest priority to new or recent renewable energy development, thereby excluding most hydroelectric facilities given that most were installed decades ago. ln addition, because of concern over the ecological impacts of large dams, large hydropower (most frequently defined as greater than 30 megawatts (MW)'), is limited in t There are mandatory RPSs in 29 states, plus the District of Columbia and Puerto Rico, as well as voluntary renewable targets in 8 states. ' Different states have different definitions of small hydropower. There is no standard definition of "small," but 30 MW is the general upper limit. (0)sr'#ll:ii':fJ Hydropower Environmental Rules in Renewabte portfotio standards S Pn-r rX sL\ inclusion in state RPSs. ln contrast, 25 states allow small hydro, generally defined between 3 and 60 MW, depending upon the state.3 It is common for state RPSs to divide their energy target requirements into two or more resource tiers or classes; these tiers promote particular technologies (notably solar PV) and require that a certain percentage of the RPS be met through the tier. As it relates to hydro- power, RPS tiers differentiate by capacity, vintage, or hydro technology. For example, Maine's Tier 1 is for new renewable facilities, whereas Tier 2 is for existing renewable facilities. Both tiers include hydropower. New Jersey's Tier 1 allows hydropower facilities less than 3 MW, whereas its Tier 2 allows facilities up to 30 MW. Nineteen states and the District of Columbia have multiple tiers.a Leaving aside the tiers restricted to solar, six of these states (including DC) exclude hydropower from one or more tier, but include other renewable technologies such as wind, biomass, and landfillgas.s Recently, several states-particularly in New England and the Pacific Northwest-have been reassessing hydropower's role in their renewable energy portfolios and have been considering either expanding eligibility for existing hydropower or including large hydro facilities. As states increase their renewable energy targets, several have questioned what types of hydropower should count towards RPS targets. The U.S. Department of Energy estimates that existing non- powered dams have the potential to add up to 12 GW of renewable power.t And the National Hydropower Association advocates modernizing turbines at existing electricity-generating facilities to increase efficiencies and add new capacity, as well as adding generation capacity to existing non-powered dams.7 Regulation When it comes to environmental regulation of hydropower, the Federal Energy Regulatory Commission's (FERC) hydropower licensing process serves as a baseline. FERC works to mini- mize environmental damage through its regulatory authority to oversee a series of federal environmental laws (e.g., the National Environmental Policy Act) and by requiring that all project applicants communicate with relevant federal and state stakeholders. After a lengthy review process, a qualifying hydropower facility receives a FERC license that typically lasts 30 to 50 years. 3 Wisconsin defines "small hydropowe/'as less than 50 MW.a See the RPS DSIRE spreadsheet here: http://dsireusa.orglrosdata/index.cfm s The six states excluding hydropower from one or more tiers are: Arizona, Connecticut, District of Columbia, Massachusetts, Missouri, and New Hampshire. 6 An April 2012 U.S. DOE report assessed the energy potential at non-powered dams: http://nhaao.ornl.eov/svstem/files/NHAAP NPD FY11 Final Report.pdf 7 National Hydropower Association's policy priorities call for improving efficiencies and modernizing equipment: http://www, hvdro.oreltech-and-policv/policv-priorities/clean-renewable-electricitv-standards/ (O)8[?liiffilg Hydropower Environmentat Rutes in Renewabte portfotio standards RPS hydropower eligibility varies significantly from state to state. There are many factors that affect how projects are regulated, licensed, and relicensed. These include size and capacity, ownership, age, technology type (e.g., reservoir or run-of-river), and environmental considerations. States, local agencies, and other federal agencies may also have regulations that impact hyd ropower facilities.s New Construction Of the 30 states (including the District of Columbia) in which hydropower is eligible for the RPS, 23 allow new hydropower development and 5 others explicitly prohibit new dams.s Two of the states prohibiting new dams allow new run-of-river facilities to qualify for the RPS.10 A handful of others prohibit new development, but will make exceptions for dams under a certain capacity or allow capacity increases as a result of efficiency upgrades or incremental production. Fifteen states restrict new hydropower development to 50 MWs or less in at least one tier. Size Restrictions Eight states do not place any capacity limits on new impoundments,ll Michigan and New Hampshire (Tier 2) do not place capacity restrictions for new run-of-river projects or for incremental increases or efficiency gains. However, the majority of states allowing existing hydropower facilities to qualify for the RPS restrict eligibility to "small" hydro facilities.12 Twelve states allow existing facilities under 30 MW in at least one tier13, though five other states do not specify a capacity limit.la The capacity cap is intended to reduce the environmental impacts associated with larger hydropower facilities, though the operation (not the size) of a facility often has an equal, if not greater, impact on the environment. Consequently, some states have placed additional restrictions on small facilities. Connecticut has some of the most stringent criteria for new small hydropower in 8 Examples of federal, state, and local agencies that can regulate hydropower facilities include the U.S. Forest Service, the U.S. Fish and Wildlife Service, state Fish and Wildlife agencies, and local water authorities.s Five states prohibit new dams: lL, MD, Ml, NH, and WA. CT and MA prohibit new dams in Tier 2. 10 Connecticut is considering replacing its Class I "run-of-river" criterion with Low lmpact Hydropower lnstitute certification. Ml and MATier 2 allow new run-of-river. " HA, NC, NM, OH, and PA do not have capacity limits for new developments. NY and DC do not place capacity limits in one of their tiers. Wl does not have a limit for large hydropower (<60 MW) completed after 2011. " Again, small hydropower is usually defined as 30 MW, but this upper limit is somewhat arbitrary.t' Eleven of these tiers limit "small" development to 10 MW or less. The Massachusetts Department of Energy Resources has proposed revisions to the RPS, expanding eligibility for existing hydroelectric facilities from 25 MW to 30 MW as a Class I resource. http://www.mass.sov/eea/docs/doer/renewables/225-cmr-14-00-draft-res-doer- 02 14L3-tracked-cha nges.pdf 'o AZ,D.C., HA, lL, and KS do not specify a capacity limit for existing facilities. r! {l \ /,.--, \GleonEnergy\ '- '' / Sloles Allio,ice Hydropower Environmental Rules in Renewable Portfolio Standards its Class l. To qualify, a hydropower project must be less than 5 MW, be run-of-river, and have been built after 2003. Washington places one of the strictest RPS restrictions on hydropower, allowing only the efficiency gains on existing projects to qualify for the RPS. Maine, on the other hand, is considering a new bill that would allow new or existing hydropower facilities up to 400 MW to qualify for the RPS.15 A proposal in Connecticut would allow large-scale hydropower to qualify as a Class I resource in a separate "contracted tier." The state's Department of Energy and Environmental Protection has presented to the legislature a plan to use large hydropower to fulfill2% of the Class ltarget in2OL4 with an annualincrease of L%up to a maximumof 7.5% in 2020.16 Environmental Requirements As mentioned above, states divide hydropower into two size categories-large and small-and tend to use installed generating capacity as an environmental criterion for RPS eligibility. The majority only count small hydro towards RPS targets. Capacity limits alone, however, do not safeguard the environment from ecological and land-use impacts, To minimize environmental impacts, some states prohibit new impoundments or diversions, allow only incremental produc- tion increases, or allow only efficiency gains. Twelve state RPSs place additional environmental restrictions on hydropower eligibility.lT Among the states with hydropower environmental regulations in RPSs, the following environ- mental values are the most commonly protected by states: o Adequate water flow to protect aquatic life and wildlife o Fish passage o Water quality o Watershed protection The Ohio Alternative Energy Portfolio Standard, for example, does not place a capacity limit on new or vintage hydropower facilities (including those in adjoining states), but it does require that all facilities meet its strict environmental standards. These include: (1) providing for river " ln March 2013, state lawmakers contemplated a bill that would remove the 1OO MW limit on all renewable energy technologies: http://bansordailvnews.com/2013/03/13/politics/state-house/lepase-measure-would- remove-100-m egawatt-ca p-for-a I l-ren ewa bles/ " CT DEEP released a draft study in March 2013 recommending a revised RPS with a flexible "contracted tier'' structure: http://www.dpuc.state.ct.us/DEEPEnerev.nsf/c6c6d525flcdd1168525797d0047c5bf/67d62db9c92d7f6885257b32 0066e509/SFl LElDEEP%20RPS%20STUDY.odf 17 The following states apply some kind of specific environmental restriction on hydropower in RPS: M, CA, CT, DE, ME, MA, NH, NJ, NY, OH, OR, ANd PA. (O)S,HII:ffiI?: Hydropower Environmentat Rules in Renewable portfotio standards flows that are not detrimental for fish, wildlife, and water quality, including seasonal flow fluctuations as defined by the applicable licensing agency for the facility; (2) demonstrating compliance with the water quality standards of the state; (3) complying with the recommendations of the Ohio Environmental Protection Agency; and ( ) in cases where the facility is not regulated by FERC, complying with similar requirements as recommended by agencies with jurisdiction over the facility. Four states require project certification by the Low lmpact Hydropower lnstitute (LlHl) for RPS inclusion.ls LlHl is a non-profit organization that seeks to reduce the environmental impacts of hydropower projects. lt offers a voluntary certification program to identify and recognize hydropower facilities that have minimal environmental impacts. lts Certification Program has established eight criteria by which to evaluate the environmental impacts of hydropower facilities. These criteria include: river flows, water quality, fish passage and protection, water- shed protection, threatened and endangered species protection, cultural resource protection, recreation, and facilities recommended for removal. The criteria can be applied to existing and new facilities. ln addition, LlHl checks state and federal compliance documents and the applicant must ensure that it is meeting all required federal, state, and local standards. LlHl does not certify pumped storage facilities or new impoundments. ln general, these environmental criteria afford greater environmental protection than current legal requirements.le ln 2009, LlHl reported 45 certified projects in 24 states. As of April 2013, there are over 100 certified projects.20 New York, the largest hydropower producer east of the Rocky Mountains, generates more than L7% of the state's electricity demand from hydropower. The state has determined that hydro- power can play a significant role in grid resiliency and expects hydropower to grow increment- tally as a mainstay of renewable power generation in the state.2l The state's policies support hydropower, both new and old, including through its RPS. While the state does not require LlHl certification, it has set its own rigorous environmental review requirements. The state limits RPS eligibility to new facilities with up to 30 MW of capacity and does not allow any new impoundments. Qualifying new facilities must meet the following environmental standards: (1) enforcement of all mitigation measures required as conditions of various state, local, and federal ordinances, regulations and licenses that govern the construction and operation of a project; (2) within practical limits, coordination of plant operations with any other water- t'DE, MA, OR, and PA require LlHl certification in at least one tier. Utah requires LlHl certification for its voluntary Renewable Portfolio Goal. 1e LlHl Certification Handbook tD://www.lowlm0afihVOrO.OrfllaSSeIS/IlleS/LlHlToZUHanObOOl(LreCemberTo2OZ( Low lmpact Hydropower lnstitute, Certified Facilities. Accessed April 15, 2013. http://www.lowim pacthvd ro.orglcertified-facil ities/ 21 http://www.dec.nv.eov/enerev/43242. html (O)S,t#II:ffiHI Hydropower Environmental Rules in Renewabte portfotio standards Sg* €r (et control facilities that influence water levels or flows to mitigate impacts and protect indigenous species and habitat; (3) compensation for loss of significant habitat by the creation of similar habitats, supporting the same stock, at or near the development site within the same ecological uniU (4) installation of fish passages to maintain pre-existing migration patterns both up and downstream; and (5) installation of measures necessary to minimize fish mortality. Pumped Hydroelectric Storage Pumped hydroelectric storage projects vary in their environmental impacts, with some using relatively low-impact pumped storage technologies, such as off-channel or closed-loop pumped storage.22 States vary in how they treat pumped storage within their RPSs. Nine states explicitly ban pumped storage projects from the RPS.23 Those states that allow pumped storage generally require that the pumping be powered by renewable energy. California allows pumped storage facilities to qualify for the RPS if the facility meets the state requirements for small hydro- electric facilities and if the electricity used to pump the water into the storage reservoir qualifies as RPS eligible. Similarly, pumped storage facilities in the Northern Maine lndependent System Administrator area are eligible if the pumping needs are met using an eligible renewable resource. New York's main tier allows pumped storage powered by tidal energy. Conclusion The majority of states with an RPS include hydropower; of these, 23 count some new hydro- power development towards RPS targets. Each state treats hydropower inclusion differently, some with explicit environmental restrictions; others embrace new development without any capacity limits or additional environmental restrictions beyond their FERC license (if FERC- applicable). States have a variety of criteria they can apply when considering whether and how hydropower resources should qualify for RPSs. As states consider the eligibility of existing or large hydropower, they can look to the environmental restrictions other states have already adopted to minimize environmental impacts. These restrictions include safeguarding water flows, fish passage, watershed protection, and endangered species, and in some cases, requiring LIH I certification. The table below lists the states' rules for RPS hydropower qualification and shows the states' varied approaches to regulating hydropower. 22 Closed-loop or off-channel pumped storage systems present minimal to no impact on existing river systems because the reservoirs are located in areas geographically separated from existing river systems. " The following states prohibit pumped storage: CO, D.C., MD, Ml, MO, OR, PA, DE, and MA. (O)8rHliiffi:?I Hydropower Environmentat Rules in Renewable Portfolio standards q)o)(E(L o)E(EF T'o! o 6 .9otoo-go6;o ouoo ut .g o 'ooI! I o -gfE 6coEEI UJ > (.) 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E9:z(u0 (D -lNO EaE(6()(ubP=5E.e 3cg e EE .P 8,8--<Ega =EE6q>9;]+Joo.9 >,269e EP6.ooE5]e =.E f -ll'6o-i9 E gE HOc-^d).-oY E E 3KEt=>>9E=J-E (U- oi: ==ts E '6 .Eo auo E'.9=ooo.th oE =Eoc E'o'o ooooCoc o .E U' co o).cEo(u = 'o Coo.o = o.ototso5(L Case No. PAC-E-I5-03 Exhibit No.,l @o f Witness: Paul H. Clements BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION ROCKY MOI.JNTAIN POWER Exhibit Accompanying Direct Testimony of Paul H. Clements February 2015 il4t?t Rocky Mountain Power Exhibit No. 1 Page 'l of 3 Case No. PAC-E-15-03 Vvitness: Paul H. Clements location Type Size (MW)Proposed Online Date Idaho Gas 4.5 08/0 t20 5 Idaho Solar 40.0 08/0 t20 6 Idaho Solar 20.0 08/0 t20 6 Idaho Solar 20.0 08/0 t20 6 Idaho Solar 50.0 08/0 t20 6 Idaho Solar 20.0 0t3 t20 6 Idaho Solar 20.0 0t3 120 6 Idaho Solar 21.0 213 120 6 Idaho Solar 20.0 2t3 t20 6 Idaho Solar 20.0 2t3 120 6 Idaho Solar 20.0 2t3 120 6 Idaho Solar 20.0 2t3 /20 6 Oregon Geothermal 3.5 0s/0 t20 4 Oregon Solar 10.0 213 120 5 Oregon Solar 0.8 2t3 120 5 Oregon Solar 10.0 2t3 /20 6 Oregon Solar r 0.0 2t3 /20 6 Oregon Solar 7.5 2/3 /20 6 Oregon Solar 0.0 2t3 120 6 Oregon Solar 0.0 2t3 t20 6 Oregon Solar 0.0 zt5 /20 6 Oregon Solar 0.0 2t3 /20 6 Oregon Solar 0.0 213 120 6 Oregon Solar 8.0 213 120 6 Oregon Solar 9.9 2t3 120 6 Oregon Solar 9.9 2t3 t20 6 Oregon Solar 9.9 2t3 120 6 Oregon Solar 10.0 2t3 t20 6 Oregon Solar 10.0 2t3 120 6 Oregon Solar 9.9 2/3 /20 6 Oregon Solar 7.5 2t3 t20 6 Oregon Solar r0.0 2t3 t20 6 Oregon Solar 10.0 2t3 t20 6 Rocky Mountain Power Exhibit No. 1 Page 2 of 3 Case No. PAC-E-15-03 Witness: Paul H. Clements Location Type Size (MW)Proposed Online Date Oregon Solar 9.9 2t3 t20 6 Oregon Solar 9.9 2t3 t20 6 Oregon Solar 45.0 2/3 t20 6 Oregon Solar 20.0 2t3 t20 6 Oregon Solar 44.2 0 l/0 120 7 Utah Solar 50.0 08/3 t20 5 Utah Wind 80.0 0to 120 5 Utah Wind 45.0 l0 120 5 Utah Solar 50.4 210 t20 5 Utah Solar 65.6 2t i/20 5 Utah Solar s0.4 2lt5/20 5 Utah Solar 10.0 213 t20 5 Utah Solar 80.0 2t3 120 5 Utah Solar 80.0 zl3 t20 5 Utah Solar 80.0 2t3 t20 5 Utah Solar 5.0 213 120 5 Utah Solar 21.0 0r/0 120 6 Utah Solar 80.0 0l/0 t20 6 Utah Solar 1.0 04t03/20 6 Utah Solar 80.0 06t0 t20 6 Utah Solar 80.0 0610 120 6 Utah Solar 80.0 06t0 t20 6 Utah Solar 80.0 06t0 t20 6 Utah Solar 80.0 0610 120 6 Utah Solar 80.0 06t0 /20 6 Utah Solar 80.0 0/0 /20 6 Utah Solar 20.0 l0/0 t20 6 Utah Solar 80.0 lo 120 6 Utah Solar 80.0 l0 t20 6 Utah Solar 80.0 t0 120 6 Utah Solar 80.0 l0 t20 6 Utah Solar t.0 2t3 t20 6 Utah Solar 20.0 2t3 t20 6 Utah Solar 40.0 213 120 6 Utah Solar 50.0 2/3 120 6 Utah Solar 15.0 213 120 6 Utah Solar 14.5 213 120 6 Rocky Mountain Power Exhibit No. 1 Page 3 of 3 Case No. PAC-E-15-03 \ /itness: Paul H. Clements Location Type Size (MW)Proposed Online Date Utah Solar 7.5 213 /20 6 Utah Solar 50.0 2t3 t20 6 Utah Solar 80.0 213 120 6 Utah Solar 80.0 2t3 t20 6 Utah Solar 6.0 2t3 t20 6 Utah Wind 69.0 2/3 120 6 Utah Solar 78.2 2/3 120 6 Utah Solar 80.0 0l/0 t20 8 Utah Solar 80.0 0l/0 120 8 Utah Wind 80.0 0t/0U20 8 Utah Wind 80.0 0t/0U20 8 Wyoming Wind 80.0 07t3U20 5 Wyoming Wind 80.0 t2l0U20 5 Wyoming Wind 80.0 01/01t20 6 Wyoming Wind 60.0 0U0U20 6 Wyoming Wind 80.0 2131/20 7 Wyoming Wind 80.0 2t3t/20 7 Wyoming Wind 80.0 2131120 7 Wyoming Wind 80.0 2l3t/20 7 t0 129 FERC fl 61,148 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners: Jon Wellinghoff, Chainnan; Suedeen G. Kelly, Marc Spitzer, and Philip D. Moeller. JD Wind 1, LLC JD Wind 2,LLC JD Wind 3,LLC JD Wind 4,LLC JD Wind 5 LLC JD Wind 6,LLC Docket No. EL09-77-000 NOTICE OF INTENT NOT TO ACT AND DECLARATORY ORDER (Issued November 19, 2009) l. In this order, we give notice that we decline to initiate an enforcement action pursuant to the section 210(h) of the Public Utility Regulatory Policies Act of 1978 (PURPA).t However, as discussed below, we conclude that the May l,2OOg decision of the Public Utility Commission of Texas (Texas Commission),2 which determined that the wind-powered generation of JD Wind I,LLC, JD Wind 2,LLC, JD Wind 3, LLC, JD Wind 4,LLC, JD Wind S,LLC and JD Wind 6,LLC (JD Wind) is not entitled to a legally enforceable obligation and an avoided cost rate calculated at the time that obligation is incurred, is inconsistent with the requirements of PURPA and our regulations implementing PURPA.3 Backqround 2. JD Wind I,LLC, JD Wind 2,LLC, JD Wind 3,LLC, JD Wind 4,LLC, JD Wind 5, LLC and JD Wind 6,LLC are each a wholly-owned subsidiary of John Deere Renewables, LLC; each of the companies that comprise JD Wind owns and operates small power production facilities that have been self-certified as qualiffing facilities t l6 u.s.c. g 824a-3(h) (2006). ' JD Wird I, LLC, et al. v. Southwestern Public Service Company,Texas Commission Docket No. 3442 (May l, 2009) (Texas Commission Order). *v,tlo ' 16 u.s.c. $ 824a-3 (2006); 18 C.F.R. Part292(2009). Docket No. EL09-77-000 -2- (QF).4 JD Wind sought to enter into contracts with Southwestern Public Service Company (SPS) to sell the electric energy output from its QFs pursuant to long-term contracts at avoided cost rates. When negotiations failed, JD Wind sought to establish legally enforceable obligations pursuant to the procedures of the Texas Cornmission. On June27,2007, JD Wind filed a complaint with the Texas Commission seeking a legally enforceable obligation from SPS and seeking rates based on the avoided costs calculated at the tirne that obligation was incurred. JD Wind pointed to section 292.304(d)s of the Commissior's regulations, which gives QFs the option of selling energy "as available"6 or selling "energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term."7 If a QF chooses the second option, i.e., to sell energy or capacity over a specified term pursuant to a legally enforceable obligation, it has the option to sell at rates either based on avoided costs calculated at the time of delivery, 8 or based on avoided costs calculated at the tirne the obligation is incurred.e In the cornplaint before the Texas Commission, JD Wind sought both a legally enforceable obligation, and rates based on avoided costs calculated at the tirne the obligation was incurred. a On May 18,2005, J.D.Wind I,LLC filed a notice of self-certification in Docket No. QF05-114-000; on September 12,2007, JD Wind l, LLC filed a notice of self- recertification. On May 18,2005, J.D.Wind Z,LLC filed a notice of self-certification in Docket No. QF05-l 16-000; on September 14,2007, JD Wind 2,LLC filed a notice of sellrecertification. On April 29,2005,J.D.Wind 3,LLC filed a notice of self- certification in Docket No. QF05-l 15-000; on September 14, 2007 JD Wind 3, LLC filed a notice of self-recertification. On November 18,2002, J.D.Wind 4,LLC filed a notice of self-certification in Docket No. QF03-13-000; JD Wind 4,LLC filed notices of self- recertification on May 30, 2006, and on September 21,2007. On June 30,2006, .J.D.Wind 5, LLC filed a notice of self-certification in Docket No. QF06-289-000; JD Wind 5,LLC filed a notice of self-recertification on September 18, 2007. On June 30, 2006, J.D.Wind 6,LLC filed a notice of self-certification in Docket No. QF06-290-000; JD Wind 6,LLC filed a notice of self-recertification on September 18, 2007 . All of the J.D.Wind QFs are l0 MW, except for J.D.Wind 4, LLC which is 79.8 MW. t l8 c.F.R.92s2.304(d) (2009). u u. g 2ez.3o4(d)(r). ' td. Sze2.3o4(d)(2). t rd $ 2s2.304(dx2)(i). n rd. S 2s2.304(dx2)(ii). Docket No. EL09-77-000 -3- 3. A Texas Cornmission Administrative Law Judge issued a Proposal for Decision on March 25,2009. The Administrative Law Judge found that, while JD Wind had satisfied the procedural requirements for establishing a legally enforceable obligation, i.e., that it had given the proper notice under Texas law of its intent to establish a legally enforceable obligation, it had not established a legally enforceable obligation.I0 The Administrative Law Judge also found that, under Texas law, a legally enforceable obligation requires a showing that the QF is capable of providing "firm power," and that, in the absence of that showing, "the JD Wind Companies cannot create a legally enforceable obligation."ll The Administrative Law Judge's decision was largely based on a finding of fact that "Wind- Generated Power is not readily available."" The Texas Commission affinned the Administrative Law Judge's decision with the exception of the laffer finding that "Wind- Generated Power is not readily available." The Texas Commission concluded that the Administrative Law Judge's decision otherwise supported a finding that JD Wind did not offer "frrm power," and the Texas Commission affirmed and adopted the Administrative Law Judge's decision.13 4. JD Wind asks the Commission to enforce PURPA. JD Wind states that the Texas Cornmission has acted inconsistently with the requirements of section 292.304(d) of our regulations in failing to award JD Wind a legally enforceable obligation at rates calculated based on SPS's avoided costs determined at the tirne of creation of a legally enforceable obligation. JD Wind argues that section2l}(h)(2) of PURPAIa authorizes the Commission to enforce the requirements of PURPA against a state regulatory authority, such as the Texas Cornmission. JD Wind also argues, quoting frorn the Commission's Policy Statement Regarding the Commission's Enforcement Role Under Section 2 10 of the Public Utilities Regulatory Policies Act of t 97& rs that the Commission's enforcement authority extends to situations where state regulatory authority irnplementation actions under PURPA "are inconsistent with or contrary to the Commission's regulations." JD Wind concludes that the Commission should exercise its 'o JD Wind I, LLC, et al. v. Southwestern Public Service Company,Texas Cornmission Docket No. 3442 at32-38 (March 25,2009). rr Id. t2 Id. at 40. 13 Te*as Cornrnission Order at l. 'o l6 u.s.c. g 824a-3(hx2) (2006). tt 23 FERC fl 6l ,204 at61,644 (1983) (1983 Policy Staternent). Docket No. EL09-77-000 -4- authority under section 210(h)(2) of PURPA because the Texas Cornrnission's order implements PURPA in a manner inconsistent with section 292.304(d) of the Commission's regulations. 5. JD Wind also asserts that its petition has general applicability to the development of intermittent resources, particularly wind-powered and solar-powered generation. JD Wind argues that the requirement for the establishment of legally enforceable obligations, at rates based on avoided costs detennined at the time of the establishment of the obligation, was intended to encourage the development of QFs, including QFs making use of intermittent resources, by providing greater certainty and predictability as to the return of investment which will allow such QFs to obtain the funding necessary to assure that such facilities are built. JD Wind further argues that, in the absence of state regulatory authority implementation of the requirements of section 292.304(d) of the Commission's regulations, i.e., allowing a legally enforceable obligation and the payrnent of a rate based on avoided costs established at the time of the establishment of the obligation, developers and financiers would not have a way to accurately predict the revenue stream that a QF would receive; the resultant uncertainty undermines the willingness of investors to fund the construction of QFs making use of intennittent resources. 6. Notice of JD Wind's filing was published in the Federal Register, T4 Fed. Reg. 51147 (2009), with interventions and protests due on or before October 22,2009. 7. The Texas Cornmission filed a timely notice of intervention and protest. The Texas Commission argues that an enforcement proceeding pursuant to section 210(h) of PURPA does not lie; instead the Texas Commission suggests JD Wind should pursue a challenge to the Texas Comrnissionos decision pursuant to section 210(g) of PURPA in state court. The Texas Commission also suggests that the Cornrnission has no role in the Texas implementation of PURPA once the Texas Commission has adopted rules to implernent PURPA. The Texas Cornmission also argues that its decision regarding JD Wind is lirnited to the facts of JD Wind, and thus does not warrant a declaratory order of general applicability. Finally, the Texas Cornrnission argues that its decision is consistent with PURPA and the Cornmission's regulations irnplementing PURPA. 8. Xcel Energy Services, Inc. (Xcel), on behalf of itself and its public utility operating company affiliate, SPS, filed a tirnely motion to intervene and protest. Xcel argues that JD Wind properly belongs in state court, pursuant to section 210(g) of PURPA, instead of seeking enforcement pursuant to section 210(h) of PURPA. Xcel states that this is particularly true where, as here, JD Wind is pursuing an appeal of the Texas Cornrnission order in state court. Xcel also argues that JD Wind has mischaracterized the Texas Cornrnission order. Xcel states that, while Texas law contemplates that legally enforceable obligations can only be created by QFs delivering "firm power," the Texas Cornmission expressly disagreed with the notion that all wind- powered generation is non-firm. Xcel also argues that the Texas Commission's Docket No. EL09-77-000 -5- limitation of the right to a legally enforceable obligation to those QFs that deliver "firm power" is consistent with section 292.304(d) of the Commission's regulations. Finally, Xcel states that its own development of wind power, as well as its other purchases of wind-powered generation, demonstrates that it is not trying to inhibit the development of wind power. Xcel concludes that this case is merely a dispute between JD Wind and SPS about rates; accordingly, there are no generic issues which require a Commission decision. 9. Occidental Permian Ltd. (Occidental) filed a timely motion to intervene and protest. Occidental explains that it is SPS's largest retail customer and purchases substantial quantities of electric energy from SPS in connection with Occidental's oil and gas operations in Texas and New Mexico. Occidental states that a Commission decision in this case will affect the retail rates it pays SPS. Occidental argues that the dispute is not ripe for Commission decision because JD Wind has filed an appeal of the Texas Commission order in state court. Occidental also argues that the determination of whether and under what circumstances a legally enforceable obligation has been created is solely a state function in which the Commission plays no role. Occidental argues that the Texas Commission's finding that JD Wind Companies did not satisff the requirement that a QF must have the capability to provide firm power to the utility before the QF can establish a legally enforceable obligation, involves a fact-specific application of Texas law which is not subject to Commission enforcement jurisdiction. Occidental further argues that the Texas Cornmission decision is not inconsistent with PURPA or with the Comrnission's regulations implementing PURPA. Occidental argues that JD Wind's arguments that the Texas Cornmission will have a devastating impact on the development of wind-powered and solar-powered generation across the United States are "hyperbolic claims" and "absurd on their face."l6 10. The Arnerican Wind Energy Association (AWEA) and the Solar Energy Industries Association (SEIA) filed a motion to interveneo and joined by the Project for Sustainable FERC Energy Policy, also submitted comments in support of JD Wind's request for a declaratory order, stating that wind, solar and other intennittent resource QFs are not prohibited from selling their output pursuant to legally enforceable obligations based on forecast avoided costs. AWEA states that it is a national trade association representing a broad range of entities with a colnmon interest in encouraging the expansion and facilitation of wind energy resources in the United States. SEIA states that it is a national trade association for the solar industry. They argue that the Texas Commission decision is inconsistent with the Cornrnission's regulations and that the Texas Cornrnission does not have the authority, under PURPA, to act inconsistently with the Cornmission's regulations. They argue that the Texas Cornmission's decision that states that a legally 16 Occidental Motion to Intervene at25. Docket No. EL09-77-000 -6- enforceable obligation does not apply to wind generation because it is intermiffent, or "non-firm" in the language of the Texas Commission, prohibits all intermittent resources frorn establishing legally enforceable obligations for the delivery of energy or capacity over specified terms. They argue that, by eliminating the option for intermittent resource QFs to create legally enforceable obligations, such QFs are denied the ability to have rates based on avoided costs calculated at the time the obligations are incurred. They argue that rates based on avoided costs calculated at the time the obligations are incurred encourages development of intermittent resources by making financing more available. They ask the Commission to grant the relief requested by JD Wind. I l. Distributed Wind Systems, LLC (Distributed Wind Systems) filed a timely motion to intervene and comments in support of JD Wind's petition for declaratory order and enforcement of PURPA. Distributed Wind Systems is a QF developer that provides management and consulting services to JD Wind. Distributed Wind Systems argues that the application of the Texas Commission policy throughout the United States would undermine all QF renewable resource generation that is intermittent in nature and urges the Commission to grant JD Wind's petition. 12. Golden Spread Electric Cooperative (Golden Spread) filed a timely motion to intervene. Golden Spread suggests that the Commission hold a hearing to determine the potential impact on SPS customers of the relief that JD Wind requests. 13. Montana Srnall Independent Renewable Generators (Montana Renewables) filed a timely motion to intervene. Montana Renewables states that its members are hydropower and wind developers owning both proposed facilities, and facilities in operation, throughout Montana and the Pacific Northwest. Montana Renewables states that the Texas Cornmission's interpretation of when legally enforceable obligations can be established will negatively affect all intermittent resource QFs in the United States. 14. The Texas Renewable Energy Industries Association (Texas Renewables) filed comments in support of JD Wind's petition. Texas Renewables states that the Texas Comrnission decision will adversely affect the development of renewable resource electric generation in Texas. Reversal of the Texas Cornrnission decision is necessary, Texas Renewables argues, for potential facilities to obtain project financing, which is critical to developing new renewable resource generation. 15. NRG Energy, Inc. filed a timely motion to intervene. 16. The Wind Coalition filed an untimely motion to intervene and comments in support of JD Wind's petition. The Wind Coalition states that it is concerned about the harm the Texas Cornrnission's decision will cause to the development of renewable resources. The Wind Coalition argues that the Texas Cornrnission order is inconsistent with the plain language of both PURPA and the Comrnission's regulations irnplernenting PURPA. Docket No. EL09-77-000 -7 - 17. JD Wind filed an answer to the protests filed by Xcel, Occidental, the Texas Cornmission and Golden Spread. Xcel and Occidental filed answers to JD Wind's answer. Discussion Procedural Matters 18. Pursuant to Rule 214 of the Commission's Rules of Practice and Procedure, l8 C.F.R. $ 385.214 (2009), the notice of intervention and the timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding. Furthermore, we find that good cause exists to grant the untimely intervention of the Wind Coalition, given the constituency which it represents, the early stage of this proceeding, and the apparent absence of any undue prejudice or delay. Rule 213(a)(2) of the Commission's Rules of Practice and Procedure, 18 C.F.R. $ 385.213(aX2) (2009), prohibits an answer to a protest or answer unless otherwise ordered by the decisional authority. We are not persuaded to accept the answers of JD Wind, Xcel and Occidental and will, therefore, reject thern. Commission Determination 19. JD Wind asks the Commission to declare that a Texas Commission order is in conflict with PURPA and the Commission's regulations implementing PURPA. Specifically, JD Wind asks the Comrnission to declare that the Texas Commission finding limiting the creation of a legally enforceable obligation only to QFs that provide "firm power," as defined by the Texas Comrnission, is in conflict with section 292.304.(d)(l) of our regulations." That section, JD Wind argues, gives all QFs the option of selling pursuant to a legally enforceable obligation and, in turn, the option of selling either at avoided costs calculated at the tirne of delivery, or at avoided costs calculated at the time the legally enforceable obligation was incurred. 20. PURPA directs the Commission to prescribe "such rules as it determines necessary to encourage cogeneration and srnall power production." l8 PURPA, in turn, directs the states to "implement" the rules adopted by the Cornmission.le A "state " l8 c.F.R.52s2.304(d)(l) (2ooe). " 16 u.s.c. $$ B24a-3(a)-(b) (2006). t' l6 U.S.C. $ 824a-3(f) (2006); accord FERC v. Mississippi,456tJ.S.742,75l (1982); Independent Energt Producers Association v. Califurnia Public Utilities Commission,36 F.3d 848, 856 (9th Cir. 1994); Cogeneration Coalition of America, Inc., 6l FERC n 61,252, at61,925-26 (1992); Small Power Production and Cogeneration (continued...) DocketNo. EL09-77-000 -8- commission may comply with the statutory requirements by issuing regulations, by resolving disputes on a case-by-case basis, or by taking other actions reasonably designed to give effect to [the Commission's] rules.o'20 As a result, a state may take action under PURPA only to the extent that that action is in accordance with the Commission's rules. 21. The Commission has enforcement authority under section 210(h)(2) of PURPA when a state commission's (or a nonregulated electric utility's) implementation of PURPA is "inconsistent or contrary to the Cornmission's regulations."2l Section 210(hX2XB) of PURPA22 permits any qualiffing small power producer, among others, to petition the Commission to act under section 210(h)(2XA) of PURPA23 to enforce the requirement that a state commission implement the Commission's regulations. The Commission's enforcement authority under section 210(hX2)(A) of PURPA is discretionary. As the Commission pointed out in its 1983 Policy Statement, "the Commission is not required to undertake enforcement action."24 If the Commission does not undertake an enforcement action within 60 days of the filing of a petition, under section 210(hX2XA) of PURPA, the petitioner then may bring its own enforcement action directly against the state regulatory authority or nonregulated electric utility in the appropriate United States district court.2s 22. Here, we give notice that we do not intend to go to court to enforce PURPA on behalf of JD Wind; JD Wind thus may bring its own enforcement action against the Texas Commission in the appropriate United States district court. Facilities; Regulations Implementing Section 210 of the Public Util@ Regulatory Policies Act of 1978, Order No. 69, FERC Stats. & Regs. u 30,128, at 30,864 (1980), order on reh'g, Order No. 69-4, FERC Stats. & Regs. tl 30,160 (1980), affd in part and vacated in part, American Electric Power Service Corporation v. FERC,675F.2d 1226 (D.C. Cir. 1982), rev'd in part, American Paper Institute, Inc. v. American Electric Power Service Corporation,46l U.S. 402 (1983). 20 FERC v. Mississippi, 456 ll .5. 7 42, 7 5l (1982); see also 1983 Policy Staternent, 23 FERC fl 61,304, at 61,643 (1983). 21 1983 Policy Statement, 23 FERC fl 61,304 at 61,644. 2' 16 u.s.c. g 824a-3(h)(2)(B) (2006). 23 16 u.s.c. g 82aa-3(h)(2xA) (2006). 24 lg83 Policy Statement, 23 FERC fl 61,304 at 61,645. 2s l6 U.S.C. g 82aa-3(hX2XB) (2006). The Cornrnission may intervene in such a district court proceeding as a rnatter of right. Id. DocketNo. EL09-77-000 -9 - 23. Notwithstanding our decision not to go to court to enforce PURPA on behalf of JD Wind, we find that the Texas Comrnission's decision denying JD Wind a legally enforceable obligation, and the requirement in Texas law that legally enforceable obligations are only available to sellers of "firm power," as defined by Texas law, are inconsistent with PURPA and our regulations implementing PURPA, particularly section 292.304(d) of our regulations.26 24. When Congress enacted PURPA in 1978, there was very little non-utility generation; virtually all new generating capacity was provided by traditional electric utilities. In fact, one of the principal reasons Congress adopted section 210 of PURPA was because electric utilities had refused to purchuse powei from non-utility producers.2T Congress thus required the Commission to prescribe rules that the Commission "determines necessary to encourage cogeneration and small power production."2s In section 210(a)of PURPA," Congress also required electric utilities to purchase electric energy from QFs, which the Commission, in section 292.303 of its regulations interpreted as imposing on electric utilities an obligation to purchase all electric energy and capacity made available from QFs.3o 25. The Commissionos regulations under PURPA also include a requirement that QFs have the option to sell not only as available but pursuar?t to legally enforceable obligationi oue. specified terms.3t Section 292.304(d)32 provides: (d) Purchases "as available" or pursuant to a legally enforceable obligation Each qualiffing facility shall have the option either: (l) To provide energy as the qualifying facility deterrnines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the purchasing utility's avoided costs calculated at the tirne of delivery; or 'u l8 c.F.R.5292.304(d) (2009). 2' FERC v. Mississippi, 456 tJ.S. 742,750 (1982). '8 l6 u.s.c. g 824a-3(a) (2006). " Id. " r8 c.F.R. g 292.303 (2009). " 1d $ 292.304(d)(2). "Id. S 292.304(d). Docket No. EL09-77-000 - 10- (2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the qualiffing facility exercised prior to the beginning of the specified term, be based on either: (i) The avoided costs calculated at the time of delivery; or (ii) The avoided costs calculated at the time the obligation is incurred. Section 292.304(d) and the requirement that a QF can sell and a utility must purchase pursuant to a legally enforceable obligation were specifically adopted to prevent utilities from circumventing the requirement of PURPA that utilities purchase energy and capacity from QFs. The Commission explained: Paragraph (dX2) permits a qualiffing facility to enter into a contract or other legally enforceable obligation to provide energy or capacity over a specified term. Use of the term "legally enforceable obligation" is intended to prevent a utility from circumventing the requirement that provides capacity credit for an eligible facility merely by refusing to enter into a contract with a qualifuing facility.[33] Thus, under our regulations, a QF has the option to commit itself to sell all or part of its electric output to an electric utility. While this may be done through a contract, if the electric utility refuses to sign a contract, the QF may seek state regulatory authority assistance to enforce the PURPA-imposed obligation on the electric utility to purchase frorn the QF, and a non-contractual, but still legally enforceable, obligation will be created pursuant to the state's implementation of PURPA.3a Accordingly, a QF, by 33 Order No. 69, FERC Stats. & Regs. fl 30,128 at 30,880 (1980); accord id. (noting "the need for qualiffing facilities to be able to enter into contractual commitments" and agreeing to "the need for certainty with regard to return on investment in new technologies"). 3a Nrw P|IRPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, Order No. 688, FERC Stats. & Regs. n31,233, atP 212 (2006), order on reh g, Order No. 688-4, FERC Stats. & Regs. n31,250, atP 136-37 (2007), aff'd sub nom. American Forest and Paper Association v. FERC,550 F.3d I179 (D.C. Cir. 2008); see also Midwest Renewable Energy Projects, LLC,I l6 FERC fl 61,017 (2006). Docket No. EL09-77-000 - 1l - committing itself to sell to an electric utility, also commits the electric utility to buy frorn the QF; these commitments result either in contracts or in non-contractual, but binding, legally enforceable obli gations. 26. JD Wind sought a legally enforceable obligation, pursuant to the procedures set forth in Texas law. JD Wind notified SPS that it sought a legally enforceable obligation to sell the entire output of its wind facilities to SPS, selected the rate option of avoided costs calculated at the time the obligation was incurred, and began delivering 100 percent of the net output of its wind-powered facilities to SPS. SPS refused to acknowledge a legally enforceable obligation, and instead paid JD Wind for the output of the facilities pursuant to a Texas rate schedule implementing the Commission's "as available" option;3s SPS took JD Wind's output, but paid JD Wind an "as available" rate. SPS took the position that intermittent resources were "non-firm" and that legally enforceable obligations were limited to sales of "firm" resources. JD Wind Companies filed a complaint with the Texas Commission, which, as discussed above, agreed with SPS, and found that only firm resources were entitled to a legally enforceable obligation and that JD Wind's resources were not firm resources. 27. The Texas Commission and other protesters argue that the Texas Commission decision is consistent with our regulations. They believe that the option contained in section 292.304(d)(2)tu is availabl e gnly to QFs that can deliver eegrr-r' power, and that the option in section 292.304(d)(l)" must be chosen by those QFs that tannot deliver "firm" power. We do not agree. As a starting point, we note that section292.304(d) does not draw such a distinction; it does not contain the words "firm" or o'non-firm." Protesters, however, point to the use of the words o'as available" in the title, and to the language of section 292.304(d)(l), as suggesting that section292.304(d)(l) is intended to be applied to all "non-f,irm" sales. This is contrary to the language of the regulation which provides that"felacft qualiffing facility shall have the option either:"38 to choose the section 292.304(d)(l) method of sale, or the section 292.304(dX2) rnethod of sale; i.e., the QF rnay choose either: (l) to sell as-available energy whenever it determines such energy is available, or (2) sell capacity or energy for a fixed term, pursuant to a mutually agreed-to contract, or pursuant to a contract or other legally enforceable obligation irnposed on the utility by the state regulatory authority. No lirnitation based on firmness is mentioned. Indeed, in Order No. 69, the Cornmission explained that an "as " S"r l8 C.F.R. 5292.304(dXl) (2OOs). 'ord. S 292.304(d)(2). " rd. g 292.304(d)(r). " 1d $ 292.304(d) (ernphasis added). Docket No. EL09-77-000 -t2- available" basis merely means "without legal obligation."3e Thus, section 292.304(d) gives each QF, even those using an intermittent resource, the option of choosing to sell: (1) energy, on an "as available" basis, i.e., not pursuant to a legal obligation, when the QF determines such energy to be available for purchases, or (2) energy or capacity, pursuant to a legally enforceable obligation over a specified term. If the QF chooses the laffer option, as JD Wind seeks to do, it then has the option to choose arate based on avoided costs calculated at the time the obligation is incurred. 28. Both the Texas Administrative Law Judge and the protesters in this proceeding have pointed to language in Order No. 69,40 which they believe justifies their reading into section 292.304(d) of our regulations a requirement that legally enforceable obligations may be awarded only to those QFs that deliver "firm" power. The discussion they point to, however, has been taken out of context. It does not involve the section of our regulations at issue here, section292.304(d), which gives QFs the option to choose to sell pursuant to a legally enforceable obligation, but is discussing a different section of our regulations, titled "'Factors affecting rates for purchases. "4l There, the Commission stated that the calculation of avoided costs, which are used to determine an avoided cost rate, can include a recognition of the capacity value provided by QFs. The Commission explained that QF sales to utilities did not fit neatly into traditional utility concepts of "firm" and oonon-firm" power and so discussed how to calculate the capacity component of rates for energy from various types of QFs, including those utilizing what are called "intermittent" resources, such as wind, solar, and hydro.a2 Th" discussion of "firm" power in Order No. 69 thus provides no basis for concluding that the Commission intended legally enforceable obligations to be available only to QFs that provide "firm" resources. 29. In conclusion, we find that the Texas Cornmission's order, limiting the award of a legally enforceable obligation to only those QFs that provide "firm" power, is inconsistent with our regulations implementing PURPA. Under our regulations, JD Wind has the right to choose to sell pursuant to a legally enforceable obligation, and, in turn, has the right to choose to have rates calculated at avoided costs calculated at the tirne that obligation is incumed. " Ord"r No. 69, FERC Stats. & Regs.1130,128 at 30,880. ao Id. at3o,88l-83. o' Sr" 18 C.F.R. S 292.304(e) (2009). n' O.d". No. 69, FERC Stats. & Regs. fl 30,128, at 30,881-82 (1980). In fact, the Cornmission also expressly found that wind generators can provide "firm capacity." Id. at 30,882. DocketNo. EL09-77-000 - 13 - The Commission orders: (A) Notice is hereby given that the Commission declines to initiate an enforcement action under section 210(hX2XA) of PLIRPA. (B) JD Wind's petition for a declaratory order is hereby granted, as discussed in the body of this order. By the Commission. (sEAL) Kimberly D. Bose, Secretary. \(o)'9 130 FERC n6t,t27 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners : Jon Wellinghoff, Chairman; Marc Spitzer, Philip D. Moeller, and John R. Norris. JD Wind l, LLC JD Wind 2,LLC JD Wind 3,LLC JD Wind 4,LLC JD Wind 5 LLC JD Wind 6,LLC Docket No. EL09-77-001 ORDER DENYING "REQUESTS FOR REHEARING, RECONSIDERATION OR CLARIFICATION" (Issued February 19, 2010) l. On November 19, 2009, the Commission issued an order responding to a petition for enforcement under section 210(h) of the Public Utilities Regulatory Policies Act of 1978 (PURPA) filed by JD Wind I,LLC, JD Wind 2,LLC, JD Wind 3,LLC, JD Wind 4, LLC,JD Wind S,LLC, and JD Wind 6,LLC (collectively, JD Wind).l In the November 19 Order, the Commission gave notice that it declined to initiate an enforcement action pursuant to the section 210(h) of the Public Utility Regulatory Policies Act of 1978 (PURPA).2 In the November 19 Order, in response to JD Wind's petition for declaratory order, the Commission also declared that the May 1,2009 decision of the Public Utility Commission of Texas (Texas Commission)3 -- which determined that JD Wind's wind- powered generation is not entitled to a legally enforceable obligation and an avoided cost ' JD Wind t, LLC,l29 FERC fl 61,148 (2009) (November 19 order). ' 16 u.s.c. g 824a,3(h) (2006). 3 JD Wtrd I, LLC v. Southwestern Public Service Co., Texas Commission Docket No.3442 (May 1,2009) (Texas Commission Order). Docket No. EL09-77-001 -2- rate calculated at the time that obligation is incurred -- is inconsistent with the requirements of PURPA and our regulations implementing PURPA.4 2. Occidental Permian Ltd. (Occidental) and Xcel Energy Services, Inc. (Xcel) each filed pleadings styled as requests for rehearing, reconsideration, or clarification of the November 19 Order. Occidental and Xcel claim that the November 19 Order erred by declaring that the Texas Commission Order was inconsistent with PURPA and the Commission's regulations implementing PURPA. As discussed below, Occidental and Xcel have raised nothing in their requests that warrants changing our decision in the November l9 Order; we accordingly deny the requests. Background 3. As discussed more fully in the November 19 Order, JD Wind I,LLC, JD Wind 2, LLC, JD Wind 3,LLC, JD Wind 4,LLC, JD Wind S,LLC, and JD Wind 6,LLC are each a wholly-owned subsidiary of John Deere Renewables, LLC; each of the companies that comprise JD Wind owns and operates small power production facilities that have been self-certified as qualiffing facilities (QF). JD Wind sought to enter into contracts with Southwestern Public Service Company (SPS) to sell the electric energy output from its QFs pursuant to long-term contracts at avoided cost rates. When negotiations failed, JD Wind sought to establish legally enforceable obligations pursuant to the procedures of the Texas Commission. On June 27 ,2007, JD Wind filed a complaint with the Texas Commission seeking a legally enforceable obligation from SPS and seeking rates based on the avoided costs calculated at the time that obligation was incurred. JD Wind pointed to section 292.304(d) of the Commission's regulations,s which gives QFs the option of selling energy "as available"6 or selling 'oenergy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term."7 If a QF chooses the second option, i.e., to sell energy or capacity over a specified term pursuant to a legally enforceable obligation, it has the option to sell at rates either based on avoided costs calculated at the time of delivery,8 or based on avoided costs calculated at the time the obligation is incurred.e In the complaint before the Texas Commission, n l6 u.s.c. $ 824a-3 (2006); 18 C.F.R. Part292 (2009). t l8 c.F.R. S 2e2.304(d) (2ooe). u td. $2e2.304(d)(r). ' u. S 2e2.304(d)(z). t lA. $ 2e2.304(dx2)(i). n td. S 2s2.304(dx2xii). Docket No. EL09-77-001 -3- JD Wind sought both a legally enforceable obligation, and rates based on avoided costs calculated at the time the obligation was incurred. 4. A Texas Commission Administrative Law Judge issued a Proposal for Decision on March 25,2009. As relevant here, the Administrative Law Judge found that, under Texas law, a legally enforceable obligation requires a showing that the QF is capable of providing o'firm power," and that, in the absence of that showing, "the JD Wind Companies cannot create a legally enforceable obligation."l0 The Administrative Law Judge's decision was largely based on a finding of fact that "Wind-Generated Power is not readily available."rr The Texas Commission affirmed the Administrative Law Judge's decision with the exception of the laffer finding that "Wind-Generated Power is not readily available." The Texas Commission concluded that the Administrative Law Judge's decision otherwise supported a finding that JD Wind did not offer "firm power," and the Texas Commission affirmed and adopted the Administrative Law Judge's decision.l2 5. JD Wind then came to this Commission, petitioning the Commission to enforce the requirements of our regulations, and to issue a declaratory order as to the meaning of the Commission's regulations. The November 19 Order resulted. November L9 Order 6. The Commission exercised its discretion and declined to go to court to enforce PURPA on JD Wind's behalf. The Commission, however, declared that JD Wind has the right to a legally enforceable obligation. The Commission pointed out that its regulations implementing PURPA include an express requirement that each QF has the option to sell not only on an "as available" basis, but also has the option to sell pursuant to legally enforceable obligations over specified terms.r3 The Commission specifically pointed to section 292.304(d),ra which provides : (d) Purchases "as available" or pursuant to a legally enforceable obligation Each qualiffing facility shall have the option either: to JD Wind I, LLC, et al. v. Southwestern Public Service Co., Texas Commission Docket No. 3442 at32-38 (March 25,2009). " Id. at 40. " Texas Commission Order at l. 13 November 19 Order, 129 FERC !T61,148 atP 25-29. 'ord.; 18 c.F.R. g 2s2.304(d) (2009). Docket No. EL09-77-001 -4- (1) To provide energy as the qualiffing facility determines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the purchasing utility's avoided costs calculated at the time of delivery; or (2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the qualiffing facility exercised prior to the beginning of the specified term, be based on either: The avoided costs calculated at the time of delivery; or The avoided costs calculated at the time the obligation is incurred. 7. Noting that section292.304(d) and its requirement that a QF can sell and a utility must purchase pursuant to a legally enforceable obligation were specifically adopted to prevent utilities from circumventing the requirement of PURPA that utilities purchase energy and capacity from QFs, the Commission concluded that, under the language of its regulations, a QF has the option to commit itself to sell all or part of its electric output to an electric utility through a contract or a non-contractual, but still legally enforceable, obligation.ls The Commission concluded that a QF, by committing itself to sell to an electric utility, also commits the electric utility to buy from the QF. The Commission explained that these commitments result either in contracts or in non-contractual, but binding, legally enforceable obligationr.'u 8. The Commission concluded that the Texas Commission Order, denying JD Wind's request to establish a legally enforceable obligation and finding that the award of a legally enforceable obligation is limited to only those QFs that provide oofirm" power, is inconsistent with the Commission's regulations implementing PURPA.TT Under these regulations, each QF, including each QF owned by JD Wind, has the right to choose to ts November 19 Order, 129 FERC fl 61,148 atP 25,29; New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, Order No. 688, FERC Stats. & Regs. n31,233, atP 212 (2006), order on reh'g, Order No. 688-4, FERC Stats. & Regs. n31,250, at P 136-37 (2007), aff'd sub nom. American Forest and Paper Association v. FERC, 550 F.3d I 179 (D.C. Cir. 2008); see also Midwest Renewable Energy Projects, LLC,l16 FERC fl 61,017 (2006). 16 November 19 Order, 129 FERC tT61,148 atP 25,29. (i) (ii) " Id. P 26-29. Docket No. EL09-77-001 -5- sell pursuant to a legally enforceable obligation, and, in turn, has the right to choose to have rates calculated at avoided costs calculated at the time that obligation is incurred.rs Reouests for Rehearins. Reconsideration or Clarification 9. In its request, Xcel argues that the Commission has reinterpreted section 292.304 of the Commission's regulations in a manner that is inconsistent with PURPA and Congressional intent. Xcel also argues that this allegedly new interpretation of the regulations will result in rates that exceed avoided costs, in violation of PURPA.Te Finally Xcel argues that the Commission should have instituted a rulemaking before re-interpreting its regulations. Xcel also asks the Commission to clariff that its November l9 Order is "of no legal moment." Xcel further asks the Commission to clari$ that its order is not binding on the Texas Commission. 10. In its request, Occidental argues that the Commission's November 19 Order relies on what Occidental characterizes as a newly-announced interpretation of section 292.304(d) of its regulations that, Occidental argues, misconstrues the language of that provision and is contrary to PURPA. Occidental also argues that the decision of whether a legally enforceable obligation has been established is the responsibility of the state regulatory authority, and not the Commission. Occidental also argues that the November 19 Order is inconsistent with PURPA's requirement that payments to QFs may not exceed a utility's avoided costs; Occidental argues that the November 19 Order assumes that utilities must treat "as available" resources as though they are firm for purposes of calculating avoided costs. Finally, Occidental argues that the Commission can not extend legally enforceable pricing options to intermittent, non-firm QF power, in the context of a declaratory order; Occidental argues that, to extend the right of establishing legally enforceable obligations to intermittent resources, the Commission should have acted in the context of a rulemaking. Occidental also asks the Commission to clariff that the Commission: (l) made no findings about whether JD Wind satisfied Texas procedural requirements for establishing a legally enforceable obligation; and (2) did not address the appropriate avoided cost rate that JD Wind should be paid. I l. JD Wind filed a response to the requests of Occidental and Xcel asking the Commission to summarily dismiss the requests on the ground that rehearing does not lie. T Id. le Xcel also argues that the Commission has engaged in a rulemaking in this proceeding, rather than in a declaration of the meaning of an existing rule, and that rehearing of the November 19 Order lies under the Federal Power Act. Docket No. EL09-77-001 -6- Discussion Procedural Matters 12. Because this proceeding arises under section 210(h) of PURPA, formal rehearing does not lie, either on a mandatory or a discretionary basis.2o We will, however, address the requests, as provided below. 13. The Commission's Rules of Practice and Procedure, although silent with respect to requests for reconsideration and answers to requests for reconsideration, do not normally permit answers to requests for rehearing." We have previously indicated that the concerns that militate against answers to requests for rehearing similarly should apply to answers to requests for reconsideration.22 Accordingly, we will reject JD Wind's answer. Commission Determination 14. We deny Occidental and Xcel's requests. Nothing raised in the requests warrants a change to our November 19 Order. 15. Both Occidental and Xcel argue that the Commission's November l9 Order represents a change to its interpretation of section292.304(d) of its regulations.23 Both also argue, relying primarily on a portion of the legislative history of PURPA,2a thatthe alleged change to the interpretation contained in the November 19 Order is inconsistent with PURPA. We disagree. 16. As an initial matter, we do not believe that our interpretation of section 292.304(d) of our regulations represents a change. As pointed out in the November 19 Order, our decision was based primarily on the express language of section 292.304(d) of our regulations, which gives "each" QF the option to choose to sell on what is known as an "as available" basis (section 292.304(d)(1)), or to sell pursuant to a legally enforceable 'o Src Southern Califurnia Edison Co.,7l FERC fl 61,090, at 61,305 (1995); New York Stote Electric & Gas Corp.,72 FERC n 61,067 , at 61,340 (1995). " r8 c.F.R. $ 38s.7r3(d) (2009). " Sr" CGE Fulton, L.L.C.,71 FERC 1161,232, at 61,880-81 (1995); Connecticur Light & Power Co.,7l FERC fl 61,035, at6l,15l (1995). " l8 c.F.R. $ 2s2.304(d) (2009). 'a H.R. Rep. No. 95-1750, at99 (1978). Docket No. EL09-77-001 -7 - obligation (section 292.304(d)(2))." If the QF chooses to sell pursuant to a legally enforceable obligation, it has the express right to choose a rate based on either the avoided costs calculated at the time of delivery,26 or the avoided costs calculated at the time the obligation is incurred.2' Because the Commission relied on the express language of the regulation, the November 19 Order in no way represents a breaking of new ground, or in any sense a change of policy. Occidental and Xcel, moreover, do not point to Commission precedent that interpreted section 292.304(d) differently.2s 17. Any suggestion that the preamble to the Commission's order adopting its original regulations could be read to prohibit the award of a legally enforceable obligation to a nonfirm resource must equally fail. The Commission, in its November l9 Order, pointed out that doing so reads the language concerning firmness out of context; that language, in fact, provides no reasonable basis for an understanding that legally enforceable obligations are limited to firm resources." Th" preamble to its adoption of the regulation at issue here expressly contemplated that QFs could receive a capacity payment.30 And, in fact, the Commission recognized the possibility that intermittent QF resources, including solar and wind resources, which would not be considered '6firm" using traditional utility concepts, could still enable a utility to avoid capacity, and that "the aggregate capacity value of such facilities must be considered in the calculation of rates " l8 C.F.R . 5 292.304(d) (2009) (emphasis added). The difference between these options is: when a QF chooses to sell pursuant to a legally enforceable obligation, it commits ahead of time to sell all or some part (e.g., during certain hours) of its output to an electric utility; when a QF chooses instead to sell on an "as available" basis, it makes no such advance commitment to the electric utility and may choose to make sales to the electric utility essentially at its discretion. 'u r 8 c.F.R . 5 2s2.304(d)(2xi) (200e). 27 l8 c.F.R. S 2e2.304(dx2)(ii) (200e). 28 The fact that Texas may have implemented section 292.304(d) of our regulations inconsistently with the express language of the regulation is not evidence as to the proper interpretation of the regulation. Nor is the fact that the inconsistent implementation may have been long standing. We do not routinely review the states' implementation of PURPA for consistency with our regulations; review typically occurs, as here, when we are presented with a petition for enforcement. 2e Novemb er 19 Order, 129 FERC fl 61,148 atP 28. 'o Id. Docket No. EL09-77-001 -8- for purchases."3r As capacity payments are available under section 292.304(d) only to those facilities that have chosen the legally enforceable obligation, even aside from the express language of the regulation, the preamble to the order adopting the regulation supports a finding that the Commission always intended that nonfirm, intermittent QF resources are included in the phrase "each qualiffing facility" that has the option to choose to sell pursuant to a legally enforceable obligation. 18. In sum, our interpretation of section 292.302(d) is based on the express language of the regulation, and is also consistent with the preamble to the regulation issued at the time the regulation was enacted. We, accordingly, conclude that our interpretation of section 292.302(d) of our regulations is in no way a new interpretation of the regulation. 19. Occidental and Xcel's remaining arguments largely depend on the argument that the Commission in the November 19 Order has reinterpreted section 292.304(d) of its regulations. In this regard, Occidental and Xcel claim that the Commission should have announced this interpretation of section 292.304(d) in the context of a rulemaking because the interpretation constitutes a change to the regulation which, they claim, can be accomplished only by a rulemaking. Because our interpretation of section 292.304(d) does not represent a change, however, Occidental and Xcel's argument that the Commission should have instituted a rulemaking must fail. 20. Similarly, Xcel's argument that the Commission should look to PURPA's legislative history to limit section 292.304(d) is misplaced. Section292.304(d) constitutes part of the Commission's original implementation of PURPA in 1980, which was appealed to the Supreme Court, and was affirmed.32 Xcel's arguments about the legislative history are, in effect, a very belated collateral attack on the original rulemaking; to the extent that a party wished to raise the issue of the consistency of our regulations with PURPA, including the issue of the consistency of our regulation granting a QF the option of selling pursuant to a legally enforceable obligation with PURPA, the issue should have been raised in the context of that rulemaking and the appeal of that rulemaking. " Id. P 28 & n.42. (citing Order No. 69, FERC Stats. & Regs. tT 30,128 at 30,882.) 32 Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order No. 69, FERC Stats. & Regs. tT 30,128 (1980), order on reh'g, Order No. 69-4, FERC Stats. & Regs. fl 30,160 (1980), affd in part and vacated in part, American Electric Power Service Corp. v. FERC,675 F.2d 1226 (D.C. Cir. 1982), rev'd in part, Americon Paper Institute, Inc. v. American Electric Power Service Corp.,46l U.S. 402 (1983). Docket No. EL09-77-001 -9- 21. Nonetheless, we will address the argument here and we find that the legislative history cited by Xcel does not support a finding that section 292.304(d) is inconsistent with PURPA. Xcel points to the following language to support its argument that Congress intended that nonfirm power cannot qualif, for a legally enforceable obligation: The conferees expect that the Commission, in judging whether the electric power supplied by the [qualiffing facility] will replace future power which the utility would otherwise have to generate itself either through existing capacity or additions to capacity or purchase from other sources, will take into account the reliability of the power supplied by the [qualiffing facility] by reason of any legally enforcible [sic] obligation of such [qualiffing facilityl to supply firm power to the utility.[33] This language, however, does not address the issue of whether a QF has the option of selling nonfirm power pursuant to legally enforceable obligation. Rather this language reflects the Congressional conferees' concern that the firmness of power be considered in determining the rate for that power - particularly the capacity component of the rate.3a The Commission's regulations, discussed above, addressing both the right to a legally enforceable obligation as well as, separately, consideration of the f,rrmness of the power in developing the rate for that power, are consistent with this concern. 22. We next turn to Occidental and Xcel's arguments that our interpretation of section 292.304(d) will result in rates for intermittent QF resources that exceed the utility's avoided costs. As an initial matter, we note that Occidental is correct that the Texas Commission, because it ruled that the JD Wind facilities were not entitled to a legally enforceable obligation, never calculated arate based on the utility's avoided cost calculated at the time the obligation was incurred. Nor did JD Wind's petition ask us to address the issue of how to calculate avoided costs, other than asking the Commission to declare that JD Wind was entitled to rates based on avoided costs calculated at the time the legally enforceable obligation was incurred. Consequently, this Commission has not in this proceeding addressed the calculation of an avoided cost rate for the JD Wind facilities. The Commission, in the November l9 Order, ruled only that the JD Wind facilities are entitled to a legally enforceable obligation, and thus, under section 292.304(d)(2),to an avoided cost rate calculated at the time the obligation is incurred; the Commission did not address any proposed calculation of avoided costs. Occidental and " H.R. Rep. No. 95-1750, at99 (1978). 'n Norrember l9 Order, 129 FERC fl 61,148 atP 28; see Order No. 69, FERC Stats. & Regs. fl 30,128 at 30,881-83. The Commission has, in fact, indicated that firm capacity can be provided by dispersed wind systems. Id- at 30,882. Docket No. EL09-77-001 - 10- Xcel nonetheless suggest that an avoided cost rate cannot be accurately calculated for intermittent resources at the time the obligation is incurred. 23. The Commission's regulations, from the beginning, have given QFs the option of choosing to have rates calculated at the time the obligation is incurred. The intention of the Commission was to enable a QF "to establish a fixed contract price for its energy and capacity at the outset of its obligation."3s The Commission recognizedthat: [I]n order to be able to evaluate the financial feasibility of a cogeneration or small power production facility, an investor needs to be able to estimate, with reasonable certainty, the expected return on a potential investment before construction of a facility.[36] The Commission recognized that avoided costs could change over time, and that the avoided costs and rates determined at the time a legally enforceable obligation was incurred could differ from the avoided costs at the time of delivery.37 The Commission has, since then, consistently affirmed the right of QFs to long-term avoided cost contracts or other legally enforceable obligations with rates determined at the time the obligation is incurred, even if the avoided costs at the time of delivery ultimately differ from those calculated at the time the obligation is originally incurred." Rater based on avoided costs at the time the obligation is originally incurred are consistent with the requirements of PURPA, and we see no impediment to accurately determining such rates for QFs powered by intermittent resources. 24. Occidental argues that the Commission should not have commented on this case on the ground that the Commission's longtime practice has been to leave to state commissions the issue of when a legally enforceable obligation is created. Occidental is correct that the Commission generally does leave to state commissions the issue of when and how a legally enforceable obligation is created.3e However, that the Commission 3s Id. at3o,B8o. 'u Id. ut30,868. 3' Id. at3o,88o. 38^u" See, e.g., New York State Electric & Gas Corp., 71 FERC n 6I,027, at 6l,l l5- 16 (1995), order denying reconsideration, T2 FERC nil,067 (1995), appeal dismissed sub nom. New York State Electric & Gas Corp. v. FERC, 117 F.3d 1473 (D.C. Cir.1997). 3e Occidental is also correct that the Commission has twice refused to prematurely address certain issues between Xcel and JD Wind. See Xcel Energt Services, Inc., 122 FERC fl 61,048, at P 45 (2008) (the Commission, because it was denying Xcel's PURPA (continued...) Docket No. EL09-77-001 - ll - generally leaves this issue to the states (and to nonregulated utilities when applicable), does not mean that a state commission is free to ignore the requirements of PURPA or the Commission's regulations. Under PURPA, the Commission has prescribed "such rules as it determines necessary to encourage cogeneration and small power production." a0 PURPA, in turn, directs the states to "implement" the rules adopted by the Commission.al When a state commission ignores the requirements of PURPA, as implemented in our regulations, the QF has the right under PURPA to seek enforcement of its PURPA rights.42 The first step in the enforcement process is the QF's filing of a petition pursuant to section 210(h)(2)(B) of PURPA."' Section 210(h)(2)(B) of PURPA permits any qualiffing small power producer, among others, to petition the Commission to act under section 210(hX2XA) of PURP Aaa to enforce the requirement that a state commission implement the Commission's regulations. JD Wind filed such a petition, and, in response, in the November l9 Order, the Commission declined to go to court on JD Wind's behalf. When the Commission declines to go to court, it can do so with or without making a statement as to its position on the issues. Here, the Commission chose section 210(m) petition to terminate the mandatory purchase obligation, declined to address whether a legally enforceable obligation had been established); Xcel Energt Services, Inc. v. Southwest Power Pool, Inc., 118 FERC n 61,232, atP 27 (2007) (the dispute between Xcel and JD Wind concerning the particular rate for, and the terms and conditions governing, a sale were a matter to be resolved pursuant to Texas' implementation of PURPA). In each of these cases, the Commission left certain PURPA implementation issues to the Texas Commission. Our decisions in those two cases, however, did not authorize the Texas Commission to resolve issues in a manner inconsistent with our regulations. The Texas Commission having done so, however, it is now appropriate for the Commission to give guidance on the meaning of our regulations. o' 16 u.s.c. $$ B24a-3(a)-(b) (2006). o' 16 U.S.C. $ 824a-3(f) (2006); accord FERC v. Mississippi,456 U.S. 742,751 (1982); Independent Energlt Producers Associationv. Califurnia Public Utilities Commission,36 F.3d 848, 856 (9th Cir.1994); Cogeneration Coalition of America, Inc., 6l FERC n 61,252, at 61,925-26 (1992). a2 November l9 Order, 129 FERC fl 61,148 atP 21. n3 l6 u.s.c. g 824a-3(h)(2XB) (2006). nn r6 u.s.c. g 824a-3(hX2XA) (2006). Docket No. EL09-77-001 -t2- to provide a statement of its position on the issues. We have done so before, and there was nothing unusual or inappropriate in our doing so here.as 25. Where, as here, the Commission does not undertake an enforcement action within 60 days of the filing of a petition, under section 210(hX2)(A) of PURPA the petitioner then may bring its own enforcement action directly against the state regulatory authority or nonregulated electric utility in the appropriate United States district court.a6 Our November 19 Order, as well as the instant order, serye as a statement of our position regarding the right under PURPA of each QF to enter into a legally enforceable obligation.aT The Commission orders: Occidental's and Xcel's requests are hereby denied. By the Commission. (sEAL) Kimberly D. Bose, Secretary. 43n-' See, e.g., MidAmerican Energt Co.,85 FERC n61,470 (1998) (Notice of Intent Not to Act, stating that the Commission would issue a later declaratory order), and, 94 FERC 1[61,340 (2001) (later declaratory order where the Commission found that Iowa's net metering law does not conflict with PURP A); Connecticut Light & Power Co., 70 FERC n 61,012 ( 1995), reconsideration denied,7l FERC n il,012 (state adder to avoided cost rate conflicts with PURPA). nu 16 U.S.C. g 824a-3(h)(2XB) (2006). The Commission may intervene in such a district court proceeding as a matter of right. Id. n' Cf. 18 C.F.R. $ 385.207 (a)(2) (2009) (providing for petitions for declaratory orders or rulings to terminate controversy or remove uncertainty). To the extent that Xcel has argued that a declaratory order has no legal effect and is of no legal moment, we note that Xcel itself has on at least one recent occasion sought a declaratory order from the Commission. See, e.g., Tri-County Electric Cooperative, Inc., Xcel Energt Seryices, Inc., and Southwestern Public Service Co., 117 FERC fl 61,280, at P I (2006). Exelon Wind'1, L.L.C. v. Nelson,766 F.3d 380 (2014) Utit. t-. Rep. P t+,gte 266 F.gd g8o United States Court of Appeals, Fifth Circuit. EXELON \ IIND t, L.L.C., formerly known as JD Wind r, L.L.C.; Exelon Wind z, L.L.C., formerly known as JD Wind z,L.L.C.; Exelon Wind 3, L.L.C., formerly known as JD Wind 3, L.L.C.; Exelon Wind 4, L.L.C., formerly known as JD Wind 4, L.L.C.; Exelon Wind 5, L.L.C., formerly known as JD Wind 5, L.L.C.; Exelon Wind 6, L.L.C., formerly known as JD Wind 6,L.L.C., Plaintiffs-Appellees, Donna L. NELSON, ir'h", official capacity as Chairman of the Public Utility Commission of Texas; Kenneth W. Anderson, Jr., in his official capacity as Commissioner of the Public Utility Commission of Texas; Rolando Pablos, in his official capacity as Commissioner of the Public Utility Commission of Texas, Defendants-Appellants, Southwestern Public Service Company; Occidental Permian, Limited, Intervenors-Appellants. No. rz-5rzz8. I Sept.8,zot4. Synopsis Background: Qualifoing wind generation facilities under the Public Utilities Regulatory Policies Act (PURPA) brought action against the Texas Public Utilities Commission (PUC), challenging the PUC's requirement that only qualiffing facilities that generate "firm power" were eligible to sell power through a legally enforceable obligation. The United States District Court for the Western District of Texas, granted summary judgment for the generation facilities. The PUC appealed. Holdings: The Court of Appeals, Jennifer Walker Elrod, Circuit Judge, held that: ['1 Texas Courts had exclusive jurisdiction over the facilities' challenges to the Texas PUC's order; t21 federal courts had exclusive jurisdiction over the facilities' challenges to the Texas PUC's rule; and t'l PURPA and Federal Energy Regulatory Commission (FERC) regulations did not mandate that all qualiffing facilities must be able to form legally enforceable obligations. Reversed and remanded. Edward C. Prado, Circuit Judge, filed an opinion concurring in part and dissenting in part. West Headnotes (23) lrl Electricity *;-Regulation in general; statutes and ordinances State regulatory agencies are directed to adopt rules which comply with Federal Energy Regulatory Commission's (FERC) regulations and implement the Public Utilities Regulatory Policies Act, which differs fiom many other statutory regimes, where the states are given the option to either implement the federal law themselves or else have the federal government directly enforce the law. 16 U.S.C.A. $ 82aa4$). Cases that cite this headnote t2t Electricity **Regulation in general; statutes and ordinances The Federal Energy Regulatory Commission (FERC) provides state regulatory authorities great latitude in determining the manner of implementation of the Commission's rules, provided that the manner chosen is reasonably designed to implement the requirements of FERC regulations. Cases that cite this headnote A n,staNert Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 Federal Courts *-Jurisdiction l7l The Court of Appeals reviews de novo a district court's determination of subject matter jurisdiction. Cases that cite this headnote Federal Courts @Presumptions and burden of proof A plaintiffhas the burden ofestablishing subject matter jurisdiction. Cases that cite this headnote Federal Courts e=Dismissal or other disposition If a court concludes that there is no subject matter jurisdiction, the case must be dismissed. Cases that cite this headnote Courts t*Exclusive or Concurrent Jurisdiction Federal courts have exclusive jurisdiction over implementation challenges to the Public Utilities Regulatory Policies Act (PURPA), which involves a contention that the state agency has failed to implement a lawful implementation plan, while state courts have exclusive jurisdiction over as-applied challenges to PURPA, which involves a contention that the state agency's implementation plan is unlawful, as it applies to or affects an individual petitioner. l6 U.S.C.A. $$ 82aa-3(0,824a1(g). Cases that cite this headnote Courts FExclusive or Concurrent Jurisdiction The Public Utilities Regulatory Policies Act's (PURPA) multi-layered enforcement provisions give federal courts exclusive jurisdiction over challenges to a state's implementation of PURPA if two conditions are met: (l) the patty bringing the claim must first petition the Federal Energy Regulatory Commission (FERC) to bring an enforcement action, and (2) after FERC declines to bring such an action, the party may file a complaint which challenges the state regulations as an illegal implementation of PURPA and the FERC regulations. l6 U.S.C.A. S 82aa-3(hX2XAHB). Cases that cite this headnote Courts {pExclusive or Concurrent Jurisdiction Wind generation facilities' challenges to an order of the Texas Public Utilities Commission (PUC), which found the facilities could not create legally enforceable obligations under the Public Utilities Regulatory Policies Act (PURPA), involved an as-applied challenge under PURPA, and thus Texas courts had exclusive jurisdiction over the claims, even though the Federal Energy Regulatory Commission (FERC), in an informal guidance letter, characterized the facilities' claims as implementation challenges, where the PUC expressly declined in the order to create a categorical rule preventing wind generators from forming legally enforceable obligations. l6 U.S.C.A. $ 82aa-3(g). Cases that cite this headnote Administrative Law and Procedure **=Plain, literal, or clear meaning; ambiguity Under the first step of Chevron analysis, a court ,',' -ll.i..r,'Ngxt '0'l 5 Jircrrrrsori ReLrtt:rs No clarnr to orri.lrri.,tl ll S Goverirtttettt Ulork:; Exelon Wind 1, L.L.G. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 asks whether Congress has directly spoken to the precise question at issue or whether the statute is ambiguous; if Congress has resolved the question, then the clear intent of Congress binds bottr the agency and the court. lr3l Cases that cite this headnote Administrative Law and Procedure hPermissible or reasonable construction Under the second step of Chevron analysis, if the statute is silent or ambiguous with respect to the specific issue, the question for the court is whether the agency's answer is based on a permissible construction of the statute, and a iourt defers to the agency's interpretation if it is l14l a reasonable interpretation ofthe statute. Cases that cite this headnote Federal Courts **Necessity of Objection; Power and Duty of Court The courts have to make their own determination on whether the district court has jurisdiction, rather than deferring to a federal agency in the first instance. Cases that cite this headnote ll2l Federal Courts c-Necessity of Objection; Power and Duty of Court Requiring that a court defer to an agency's interpretation of the court's own subject-matter jurisdiction would interfere with the courts' independent obligation to determine their own subj ect-matter j urisdiction. Cases that cite this headnote Administrative Law and Procedure s-Deference to agency in general An agency's interpretation of a statute such as those in opinion letters, like interpretations contained in policy statements, agency manuals, and enforcement guidelines, all of which lack the force of law, do not warrant Chevron-style deference. Cases that cite this headnote Courts tsExclusive or Concurrent Jurisdiction Wind generation facilities' challenges to a Texas Public Utilities Commission (PUC) rule, which limited the qualified facilities that could form legally enforceable obligations under the Public Utilities Regulatory Policies Act (PURPA) to those that produced firm power, involved an implementation challenge under PURPA, and thus federal courts had exclusive subject matter jurisdiction over the claims, where the facilities' request for a declaration that all quali$ing facilities could form legally enforceable obligations would require the Texas PUC to alter its current rules. 16 U.S.C.A. $ 82aa-3(f). Cases that cite this headnote Judgment *=lnferences from judgment Questions of subject matter jurisdiction have been passed on in prior decisions silentio are not entitled to preclusive effect. Cases that cite this headnote Iill that sub ilestIa','v'Next O20l5ThonrsonReirters Noc',larlr tooric;rnal US GoverrrrrerriWorks Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 116l Courts &Particular questions or subject matter Prior Court of Appeals' decision, upholding Texas Public Utilities Commission (PUC) rule against challenge under Public Utilities Regulatory Policies Act (PURPA), did not pass on jurisdictional question sub silentio but, rather, devoted substantial time to jurisdictional question, and thus decision had precedential effect on that question. Public Utility Regulatory Policies Act of 1978, $ 210(0, 16 U.S.C.A. $ 824a-3(f). Cases that cite this headnote ItTl Electricity *Regulation in general; statutes and ordinances A federal court reviews a state public utilities commission's implementation of the Public Utilities Regulatory Policies Act (PURPA) and the Federal Energy Regulatory Commission (FERC) regulations with deference, because a state has broad authority to implement PURPA with respect to the approval of purchase contracts between utilities and qualifring facilities. l6 U.S.C.A. $ 82aa-3(0(l). Cases that cite this headnote lrEl Electricity t:Regulation in general; statutes and ordinances States may implement the Public Utilities Regulatory Policies Act (PURPA) by issuing regulations, by resolving disputes on a case-by-case basis, or by taking any other action reasonably designed to give effect to Federal Energy Regulatory Commission's (FERC) rules. 16 U.S.C.A. $ 82aa-3(0(l). Cases that cite this headnote Ilel Electricity &Regulation of supply and use The Public Utilities Regulatory Policies Act (PURPA) and Federal Energy Regulatory Commission (FERC) regulations did not mandate that all qualifing facilities must be able to form legally enforceable obligations, and thus the Texas Public Utilities Commission (PUC) could additionally require that qualiffing facilities produce firm power before permitting the facilities to enter legally enforceable obligations. l6 U.S.C.A. $ 824a-3(f)(l); l8 c.F.R. $ 2e2.304(d). Cases that cite this headnote Administrative Law and Procedure *-Plain, literal, or clear meaning; ambiguity A court's prior construction of a stafute trumps an agency construction otherwise entitled to Chevron deference when the prior court decision held that its construction follows from the unambiguous terms of the statute and thus leaves no room for agency discretion. Cases that cite this headnote I2rl Administrative Law and Procedure qi-Plain, literal, or clear meaning; ambiguity Administrative Law and Procedure ,iir*Erroneous construction; confl ict with statute An agency's interpretation of a statute is not entitled to deference when it offers up an interpretation that a court has already said to be unambiguously foreclosed by the regulatory text. Cases that cite this headnote riji,:,11.,i'.'*'Next O 201fi'f horrsor.r [leirlcr,c N0 Clarril to c:rrr]rnail l-l S C,Overrrmr;rrt Works Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 l22l Statutes *-Superfluousness A statute should be construed so that effect is given to all its provisions, so that no part will be inoperative or superfluous, void or insignificant. Cases that cite this headnote Administrative Law and Procedure &-Construction When presented with two plausible readings of a regulatory text a court should prefer the reading that does not render portions of that text superfluous. Cases that cite this headnote Attorneys and Law Firms *383 Thomas K. Anson, Esq., Jonathan Derek Quick, Esq., Strasburger & Price, L.L.P., Austin, TX, Judith R. Blakeway, Strasburger Price Oppenheimer Blend, San Antonio, TX, for Plaintiffs-Appellees. Andrew S. Oldham, Deputy Solicitor General Office of the Attorney General, Office of the Solicitor General, John Richard Hulme, Esq., Assistant Attorney General, Office of the Attorney General, Austin, TX, for Defendants-Appel lants. Ron H. Moss, Esq., Attorney, Winstead, P.C., Stephen E. Fogel, Xcel Energy Service, Incorporated, F. Michael Stenglein, King & Spalding, L.L.P., Austin, TX, Ashley Charles Parrish, Erq., King & Spalding, L.L.P., Washington, DC, for Intervenors-Appellants. Appeals from the United States District Court for the Western District of Texas. Before SMITH, PRADO, and ELROD, Circuit Judges. Opinion JENNIFER WALKER ELROD, Circuit Judge: This appeal addresses the Texas Public Utilities Commission's (PUC) interpretation *384 and implementation of a federal statutory and regulatory scheme governing the purchase of energy between public utilities and certain energy production facilities known as Qualifuing Facilities. Appellees are qualifuing wind generation facilities collectively known as Exelon that challenged a state rule and order which prohibited Exelon from forming Legally Enforceable Obligations when selling power. The district court determined that it had jurisdiction to hear Exelon's claims and then granted summary judgment to Exelon. We disagree. We VACATE the portion of the judgment regarding Exelon's challenge to the PUC's order and direct the district court to dismiss for want of subject matter jurisdiction. As to the remaining claims challenging the PUC's rule, we REVERSE and REMAND because the PUC acted within its discretion and properly implemented the federal regulation at issue here. I. Congress enacted the Public Utilities Regulatory Policies Act of 1978 (PURPA) to reduce the dependence of electric utilities on foreign oil and natural gas and to control consumer costs. Congress sought to do so in part by encouraging development of alternative energy sources. See FERC v. Mississippr, 456 U.S. 742,745,102 S.Ct. 2126,72 L.Ed.2d 532 (1982); Power Res. Grp. v. Pub. Util. Comm'n, 422 F.3d 231, 233 (sth Cir.2005) [hereinafter Power Resource /11 ].r PURPA directs the Federal Energy Regulatory Commission (FERC) to promulgate regulations to promote energy purchases from cogeneration and small power production facilities, including renewable energy providers such as wind and solar generators. These energy providers are known as Qualifiing Facilities. See l6 U.S.C. $$ 796(17), 824a-3(a); l8 C.F.R. $$ 292.101(b)(t), 292.203. While Congress sought to promote energy generation by Qualifoing Facilities, it did not intend to do so at the expense of the American consumer. PURPA thus strikes a balance between these two interests. For example, PURPA requires utilities to purchase power generated by Qualifring Facilities, but also mandates that the rates that utilities pay for such power "shall be just and reasonable to the electric consumers of the electric utility and in the public interest." l6 U.S.C. $ 824a-3(a)(2), (bXl). I'l "State regulatory agencies, such as the PUC, are directed to adopt rules which comply with FERC's reelfatiol and imnf1m1ll-_P_URlA " Power Resource III, E,11 \'v':11ll1ll" r ":tllglf 13 81Irg1L Util. L. Rep. P 14,913 422 F.3d at 233 (citing l6 U.S.C. $ 82aa-3(f)). In other words, PURPA orders the states to implement a federal law. This unusual mandate differs from many other statutory regimes, where the states are given the option to either implement the federal law themselves or else have the federal government directly enforce the law. See Nev, York v. United States, 505 U.S. 144, 16748, I 12 S.Ct. 2408, 120 L.Ed.2d 120 (1992) (citing the Clean Water Act, Occupational Safety and Health Act, and Resource Conversation and Recovery Act and explaining that "where Congress has the authority to regulate private activity under the Commerce Clause, we have recognized Congress' power to offer States the choice of regulating that activity according to federal standards or having *385 state law pre-empted by federal regulation"). As the Supreme Court has noted, the mandatory nature of PURPA's directive to states raises "troublesome" Tenth Amendment concerns. FERC v. Mississippi,456 U.S. at 759, 102 S.Ct.2126.ln FERC v. Mississippr, the Supreme Court was able to avoid those concerns by explaining that FERC's regulations allow the states to implement PURPA simply by adjudicating disputes arising under the statute. ld. at 760, 102 S.Ct. 2126. The Supreme Court found PURPA acceptable because it does not require states to pass regulations implementing FERC's regulations; instead, states have the option of"resolving disputes on a case-by-case basis" by opening up their courts to adjudicate such claims. ld. at 751,760, 102 s.Ct.2126. Texas has opted to have the PUC implement FERC's regulations through rulemaking, rather than case-by-case adjudication.' l2l FERC provides state regulatory authorities like the PUC "great latitude in determining the manner of implementation of the Commission's rules, provided that the manner chosen is reasonably designed to implement the requirements" of FERC regulations. See Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, 45 Fed.Reg. 12214, 12230-31 (Feb. 25, 1980). At issue here is one of the rules that the PUC promulgated to implement a FERC regulation. This FERC regulation provides Qualifying Facilities with two ways to sell power to utilities. See 18 C.F.R. $ 292.304(d) (FERC's Regulation). Under subsection (d)(l) of FERC's Regulation, a Qualiffing Facility may only provide power to the utility on an "as-available" basis, and must price the power at the "time of delivery." 1d $ 292.304(d)(l). Immediately following (d)(l) is another subsection of FERC's Regulation, which allows a Qualifuing Facility to sell its power pursuant to a Legally Enforceable Obligation. Id. S 292.304(dX2). A Qualiffing Facility that chooses to sell through a Legally Enforceable Obligation has two options for how it prices its power: It may calculate the price at the moment of delivery, just as under subsection (d)(l), or it may choose to fix the price "at the time the obligation is incurred." 1d. In other words, Quali$ing Facilities that form Legally Enforceable Obligations are able to select between the current (as-available) and past (time of obligation) market prices for power. The PUC's rule implementing FERC's Regulation permits only a Qualiffing Facility that generates "firm power" to enter into a Legally Enforceable Obligation. l6 Tex. Admin. Code $ 25.2a2@) (PUC Rule 25.242). The PUC defines "firm power" as "power or power-producing capacity [from a Qualifoing Facility] that is available pursuant to a legally enforceable obligation for scheduled availability over a specified term." Id. S 25.242(c)(5). The PUC defines non-firm power from a Qualifuing Facility as "[p]ower provided under an arrangement that does not guarantee scheduled availability, but instead provides for delivery as available." Id. S 25.242(c)(9). In other words, only those Qualifuing Facilities able to forecast when they will deliver energy to the utility-and capable of delivering the specified amount ofenergy at the scheduled time-are eligible to take advantage of the pricing options in subsection (d)(2) of FERC's Regulation. *386 By contrast, Qualifuing Facilities with non-firm power that cannot guarantee such delivery may charge the utility only the current or "as-available" market price for the power. Exelon is a Qualifuing Facility, but cannot supply firm power, due in part to the nature of wind generation. Wind is a notoriously fickle energy source, as it blows intermittently and the power it generates is difficult to store.r Technological advancements have made it possible for some wind farms to provide more consistent service, but Exelon lacks such technology, and the winds in the Texas Panhandle, where Exelon's facilities are located, do not blow in a predictable pattern. Because it is subject to the whims of these winds, Exelon cannot guarantee that a particular amount of energy will be available at a particular time. Southwestern Public Service Company (Southwestern) is a utility company that is required under PURPA to buy all of Exelon's wind-generated energy. See 16 U.S.C. $ 82al-3(aX3). At various times in 2005 and 2006, Exelon sent letters to Southwestern demanding that Southwestern purchase Exelon's energy output for the next twenty years, and purported to create Legally Enforceable Obligations with Southwestern. Exelon further demanded that Southwestern pay Exelon amounts that ranged from Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) utit.-1. nep.Fl+s13 - -- approximately $0.035 per kilowatt-hour to more than $0.090 per kilowatt-hour for the first nine years of that twenty-year term. Southwestem refused to accept Exelon's terms. According to Southwestern, these rates were much higher than the as-available prices offered by other generators. Southwestern asserted that Exelon could not form a Legally Enforceable Obligation under subsection (d)(2) because it could not provide firm power. As a result, Southwestern argued that Exelon could not charge more than the as-available prices allowed under subsection (dxl). In June 2007, Exelon filed a complaint with the PUC alleging that it had formed a Legally Enforceable Obligation with Southwestern, and that Southwestern was underpaying for its power. Exelon's complaint did not challenge PUC Rule 25.242 or any other Texas rule implementing FERC's regulations under PURPA. Instead, Exelon argued in the PUC proceeding that its power was firm because Exelon promised to sell all of the power it produced to Southwestern. Exelon's case was first heard by an administrative law judge at the PUC. The administrative law judge determined that Exelon's power was *387 non-firm, that it had not created a Legally Enforceable Obligation, and that it was not entitled to additional compensation.r The PUC Commission issued an order (PUC Order) that adopted the administrative law judge's conclusions, with one notable exception. The administrative law judge had proposed including a categorical finding that wind generators could not create Legally Enforceable Obligations because "wind generated power is not readily available." The Commission rejected this proposal. Instead, the Commission concluded that while Exelon was unable to produce firm power, other wind generators may be able to do so and may therefore be capable of forming Legally Enforceable Obligations. The PUC Order noted this conclusion: The [administrative law judge] found that wind-generated power is not readily available. The Commission disagrees with this broad statement encompassing all wind-generated power. The Commission notes that disparate wind patterns in the diverse geographic regions of the state can result in significantly different characteristics for wind-generated power. Further combining wind with energy storage techniques or other energy sources, like solar ,^,'-..i[.i,.',Ne)(t .] .ji) 1r, liiOtrts(,i Iir:, 1:;i.:, iJ:r L i:]i:t i,, energy, can also result in signifi cant differences. Exelon appealed the PUC's ruling to the state district court in Travis County, Texas. While the state court appeal was pending, Exelon filed a petition for enforcement and request for declaratory order from FERC, arguing that all Qualiffing Facilities are entitled to create Legally Enforceable Obligations, regardless of whether the energy they produce is firm or non-firm. FERC declined to initiate an enforcement action against the PUC, and instead issued an informal declaratory order (FERC's Letter) stating that the PUC Order was inconsistent with FERC's Regulation. FERC's Letter stated that a Qualiffing Facility may form a Legally Enforceable Obligation even if its power is non-firm.' Exelon voluntarily non-suited its state court appeal ofthe PUC Order. In December 2009, Exelon f,rled this lawsuit in federal district court seeking declaratory and injunctive relief against the PUC Commissioners in their official capacities. In its complaint, Exelon requested that the district court declare that: (l) the PUC Order did not implement FERC's Regulation; (2) all Qualifuing Facilities may form Legally Enforceable Obligations; and (3) *388 the PUC must reopen the proceeding brought by Exelon in light of these determinations. Exelon also requested an injunction: (l) requiring the PUC to fully implement FERC's Regulation; (2) prohibiting the PUC from enforcing the PUC Order; and (3) requiring the PUC to address and consider Exelon's petition in light of those declarations. Southwestern and Southwestern's biggest consumer, Occidental Permian Limited (Occidental), intervened. The PUC, Southwestern, and Occidental moved to dismiss Exelon's claims under Federal Rule of Civil Procedure l2(b)(l) and l2(bX6), arguing that PURPA grants exclusive jurisdiction to state courts to hear the sort of claims advanced by Exelon. The district court disagreed, and concluded that it hadjurisdiction to hear the case. The parties then moved for summary judgment. The district court issued an order granting Exelon's motion for summary judgment and denying all other motions for summary judgment. The district court concluded that the PUC Order failed to implement PURPA and permanently enjoined the PUC from requiring a Qualifying Facility to provide firm power as a condition of creating a Legally Enforceable Obligation. The district court subsequently amended its judgment to enjoin the PUC Commissioners, rather than the PUC itself. The PUC, Southwestern, and Occidental (collectively, Appellants) appealed. ,,,',,,,,r, '' 'rir., ,.'. Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) utir. r-. nef n n,sli-- - II. l3l l4l Isl We begin by addressing Appellants' argument that there is no subject matter jurisdiction to hear Exelon's claims. We review de novo a district court's determination of subject matter jurisdiction. /r re FEMA Trailer Formaldehyde Prods. Liab. Litig. (Miss.Plaintffi), 668 F.3d 281, 286 (5th Cir.20l2). Exelon, as the plaintiff, has the burden of establishing subject matter jurisdiction. Id.lf we conclude that there is no subject matter jurisdiction, the case must be dismissed. Home Builders Ass'n, Inc. v. City of Madison, 143 F.3d 1006, l0l0 (5th Cir.l998). l0l lzl pgpp4 provides for two types of review of a state utility regulatory authority's actions: implementation and as-applied challenges. See Power Resource III, 422 F.3d at 234-j5. Federal courts have exclusive jurisdiction over implementation challenges, while state courts have exclusive jurisdiction over as-applied challenges.u The type of claims brought by Exelon thus determines whether we have jurisdiction. Id. at 235. "An implementation claim involves a contention that the state agency ... has failed to implement a lawful implementation plan under $ 824a-j(f) of PURPA, whereas an 'as-applied' claim involves a contention that the state agency's implementation plan is unlawful, as it applies to or affects an individual petitioner." 1d (internal quotation marks and citations omitted); see also l6 U.S.C. $ 82aa-3(g). The parties disagree as to whether Exelon asserted as-applied or implementation *389 challenges. Appellants make several arguments for why these were as-applied challenges over which the district court had no jurisdiction. First, Appellants contend that Exelon is challenging the PUC Order, which only applies to Exelon, rather than PUC Rule 25.242. Next, Occidental asserts that, although we treated similar claims as implementation challenges in Power Resource III, that determination is not binding here. Finally, the PUC argues that we must read PURPA's jurisdictional grant to federal courts narrowly in order to avoid the "troublesome" Tenth Amendment concerns identified by the Supreme Court in FERC v. Mississippi. We address each of these points in turn. A. Appellants argue that Exelon raised as-applied challenges because Exelon only challenged the PUC's application of PUC Fiule 25.242 to Exelon. In response, Exelon contends that this was an implementation challenge because the PUC Order had broad effects, and because the PUC Order and PUC Riule 25.242 together fail to implement FERC's Regulation. The district court agreed with Exelon, and characterized Exelon's claims as implementation challenges. The district court first reasoned that Exelon was asserting that it was entitled to form a Legally Enforceable Obligation under FERC's Regulation. The district court explained that, because the PUC Order denied Exelon the right to create a Legally Enforceable Obligation, Exelon was challenging that PUC Order as a failure to implement FERC's Regulation. Second, the district court determined that the PUC Order "implicitly broadened its findings when it explained what other conditions could allow a wind energy facility to succeed in providing firm power" and thus concluded that the PUC Order did not limit its effect only to Exelon. We agree with the district court with respect to only some of Exelon's claims. t. To help elucidate the difference between implementation and as-applied challenges, we begin by reviewing our decision in Power Resource III, 422 F.3d at 23 l. There, the PUC had determined that a Qualiffing Facility called PRG could not form a Legally Enforceable Obligation because it could not guarantee power delivery within ninety days, as required by PUC Rule 23.66. Id. at 234. PRG filed suit in both state and federal court asserting both as-applied and implementation challenges to the PUC's determination. The Texas state courts adjudicated PRG's as-applied claims, including whether the PUC properly interpreted its own rule, and whether that interpretation was preempted by FERC's regulations. See Power Res. Grp., Inc. v. Pub. Util. Comm'n, 73 S.W.3d 354, 356-57 (Tex.App.-Austin 2002, pet. denied) [hereinafter Power Resource I f. PRG then brought suit in federal district court, where it requested several additional forms of relief, including: (l) a declaration that the PUC had failed to implement the requirements of PURPA; (2) a declaration that the PUC's actions with respect to PRG violated PURPA; and (3) injunctive relief requiring the PUC to implement new Legally Enforceable Obligation regulations, and then requiring the PUC to consider PRG's petition under that new regulatory framework. See Power Res. Grp. v. Pub. Util. Comm a No. |:03-{Y-762-HLH, Dkt. No. l, atxl2 (W.D.Tex. Oct. 10, 2003) [hereinafter Power Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) urii. L R;tP M,e13 Resource 1/ l. The district court dismissed all but one of PRG's claims for lack of jurisdiction after determining that they were as-applied challenges: *390 PRG again asks this Court to grant relief in the form of an order directing [PUC] to consider PRG's claims under a revised system of regulation.... These allegations state an "as applied" claim, which this Court has no jurisdiction to heqr.... [T]he one ultimate and limited issue before the Court at this timeis whether [PUC] failed to implement the [Legally Enforceable Obligationl option provided by FERC's regulations. /d. (emphasis in the original). The district court then granted summary judgment to the PUC and other defendants on PRG's implementation claim. We affirmed, without reaching the issue of whether the district court could have also heard PRG's other claims. Power Resource III, 422F.3d at239. ii. ltl We now turn to Exelon's claims, which fall into two main categories. The majority of Exelon's requests for relief focus on the specific PUC Order, rather than PUC Frule 25-242. For example, Exelon asked the district court for a declaration that the PUC Order did not implement FERC's Regulation and is preempted. These claims challenging the PUC Order are identical to the as-applied claims that the state court of appeals adjudicated in Power Resource 1, 73 S.W.3d at 36142. Exelon also asked the district court to declare that the PUC must reopen Exelon's proceedings for further consideration, and to issue an injunction prohibiting the PUC from enforcing the PUC Order. In a thoughtful, well-reasoned opinion, the federal district court in Power Resource 11 dismissed these types of claims for lack of jurisdiction because they were as-applied challenges. Power Resource 11, No. |:03-{Y-762-HLH, Dkt. No. 44, at 17-18. We agree with the conclusions reached by both the state and federal dishict courts in Power Resource I & II regarding their exclusive jurisdiction under PURPA. Exelon's challenges to the PUC Order are "contention[s] that the state agency's ... implementation plan is unlawful, as it applies to or affects an individual petitioner" and are thus as-applied challenges over which we have no jurisdiction. Power Resource IIl, 422 F.3d at 235 (internal quotation marks and citations omitted).' The district court in this case reasoned that Exelon's claims challenging the PUC Order were implementation challenges based on what it considered to be a broad ruling in the PUC Order that prevented all wind generators from forming Legally Enforceable Obligations. We disagree. The PUC explicitly declined to create a categorical rule preventing wind generators from forming Legally Enforceable Obligations and instead issued an order limited to only Exelon's capacity to produce firm power: The [administrative law judge] found that wind-generated power isnot readily available. The Commission disagrees with this broad statement encompassing all wind-generated power. The Commission notes that disparate wind patterns in the diverse geographic regions of the state can result in significantly different characteristics for wind-generated power. Further combining wind with energy storage techniques or other *391 energy sources, like solar energy, can also result in signifi cant differences.' The PUC thus left open the possibility that other wind generators might be able to comply with the firm power requirement, either through technological advances or based on their locations in regions with more predictable wind patterns than those found around the Exelon facilities. As both the PUC and Occidental aptly note, the fact that as-applied challenges may establish precedent relevant to future cases does not transform them into facial or implementation challenges. Courts routinely adjudicate as-applied constitutional challenges to statutes; these decisions do not become facial challenges simply because of their stare decisis effect in future cases presenting similar facts or legal theories. Cf, In re Cao, 619 F.3d 410,430 (5th Cir.20l0) (en banc); see also id. at 443 (Jones, C.J., concurring in part and dissenting in part). The PUC Order is best viewed as an application of PUC Rule 25.242-which the PUC promulgated more than thirty years ago-to an individual petitioner.' As a result, Exelon's challenges to the PUC Order are as-applied challenges. Itt. tttlr Ili.',,rillii!: i.r-'.,tt,t.;Ngxt i,ir{ll:, Iirr)trr',r;il iilti;ir:r:; f'.ri, i:li, i{i 1. ()i i.i;rili l-J: Exelon Wind 1, L.L.G. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 Exelon offers one additional argument for why these claims are implementation challenges. Exelon points to FERC's Letter, which Exelon requested from FERC after receiving an unfavorable ruling from the PUC. While this FERC-issued document is rather impressively called a Declaratory Order, it is actually akin to an informal guidance letter. See Indus. Cogenerators v. FERC, 47 F.3d 1231, 1235 (D.C.Cir.l995) ("The Commission nowhere purported to make the Declaratory Order binding upon the FPSC, nor can we imagine how it could do so. Unlike the declaratory order of a court, which does fix the rights of the parties, this Declaratory Order merely advised the parties of the Commission's position."). In this Letter, FERC states that Exelon's claims are implementation challenges. Exelon cites City of Arlington v. FCC, _U.S. _,133 S.Ct. 1863, 1872,_L.Ed.2d - (2013), and maintains that we should give deference to FERC's characterization, in its Letter, of these claims as an implementation challenge. Exelon argues that, based on this deference, we should conclude that the federal courts have jurisdiction to hear Exelon's claims. The district court here adopted Exelon's position without providing any reasoning or case law in support: "That Exelon is in fact challenging PUC[ ]'s implementation of PURPA, rather [than] a particular application, is *392 confirmed by the reasoning in the FERC Declaratory Order, and the positions taken by various intervenors before FERC." lel lr0l We disagree. ln City of Arlington, the Supreme Court afforded Chevron deference to an agency's interpretation of its own jurisdiction. 1d'0 Indeed, the Supreme Court explicitly noted that it granted certiorqri "limited to the first question presented: Whether ... a court should apply Chevron to ... an agency's determination of its own jurisdiction." Id. at 1867-68 (internal quotation marks omitted). In contrast, the question here is not whether FERC has jurisdiction to address Exelon's claims, but rather whether these claims belong in a state or a federal cowt. City of Arlinglon does not address this entirely different proposition advocated by Exelon, and does not support the argument that we should defer to FERC's interpretation of our own jurisdiction under the statutory scheme. lrtl lrzl t;yL11" the Supreme Court has not addressed this novel argument, our own precedent forecloses it. As Judge Wisdom noted long ago, "[t]he courts, howeyer, have to make their own determination whether the district court has jurisdiction, rather than defer to the [federal agency] in the first instance." Reeb v. Econ. Opportunity Atlanta, Inc., 516 F .2d 924, 926 (sth Cir. 1975); see also Lopez-Elias v. Reno, 209 F.3d 788,791 (5th Cir.2000) (explaining that "the determination of our jurisdiction is exclusively for the court to decide"). More recently, our sister circuit explained that, "the Supreme Court has repeatedly affirmed that federal courts have an independent obligation to determine their own subject-matter jurisdiction." Shweika v. Dep't of Homeland Sec., 723 F.3d 710, 719 (6th Cir.20l3) (citing Henderson ex rel. Henderson v. Shinsek' - U.S. -,13l S.Ct. 1197,1202,179 L.Ed.zd 159 (2011); Arbaugh v. Y & H Corp.,546 U.S. 500, 514, 126 S.Ct. 1235, 163 L.Ed.2d 1097 (2006); Steel Co. v. Citizens for a Better Env't, 523 U.S. 83, 95, l18 S.Ct. 1003, 140 L.Ed.2d210 (1998). "Requiring that a court defer to an agency's interpretation of the court's own subject-matter jurisdiction would interfere with this independent obligation." /d. Ir3l Even assuming arguendo that an agency's interpretation of a court's jurisdiction could warrant deference, FERC's Letter would still not be entitled to Chevron deference because it is an informal guidance document. As the Supreme Court has explained, "[i]nterpretations such as those in opinion letters-like interpretations contained in policy statements, agency manuals, and enforcement guidelines, all of which lack the force of law-{o not warrant Chevron-style deference." Christensen v. Harris Cnty., 529 U.S. 576, 587, 120 S.Ct. 1655, 146 L.Ed.2d 621 (2000). Exelon conceded as much at oral argument, and acknowledged that FERC's Letter is "entitled to respect," but only to*393 the extent that it is persuasive. /d. (citing Skidmore v. swift & Co., 323 U.S. 134,65 S.Ct. 16l, 89 L.Ed. 124 (1944)). Because we find the reasoning in Power Resource I & II more persuasive than FERC's Letter, we conclude that Exelon's challenges to the PUC Order are as-applied challenges, over which the district court lacked jurisdiction. i. Iral Exelon's second category of claims challenges PUC Fiule 25.242. Exelon argues that the Rule does not fully implement FERC's Regulation because PUC Rule 25.242 limits the category of Quali$ing Facilities that may form Legally Enforceable Obligations. In response, Occidental contends that Exelon did not plead a proper implementation challenge because it did not explicitly ask the district court to require the PUC to engage in new rulemaking or to invalidate PUC R.:ule 25.242. Exelon did, B. ','.';,.,iIr.'vNext r.,.r,r1;i5l Thr-rn.tslrn [ir-rule rs f.]1-r (;l;,jrrlr ir; orr.lrnali U S Governilerrt !'Vcr-k:-:1l) Exelon Wind 1, L.L.C. v. Nelson, 765 F.3d 380 (2014) however, raise a more general challenge to PUC Rule 25.242 by asking for a declaration that all Qualifoing Facilities may form Legally Enforceable Obligations, and requesting that the court issue an injunction requiring the PUC to fully implement FERC's regulations. Either form of relief would necessarily require the PUC to alter its current rules. We see little difference between these requests for relief and those that we addressed as implementation challenges in Power Resource III, 422 F.3d at 23719. Exelon's claims challenging PUC Rule 25.242 are thus implementation challenges. Itsl ltel 6.r14.ntal asserts that our "drive-by" jurisdictional ruling in Power Resource III is not entitled to precedential effect. We disagree. While "questions of jurisdiction [that] have been passed on in prior decisions sub silentio" are not entitled to preclusive effect, Power Resource III is not such a case. See Hagans v. Lavine,4l5 U.S. 528,533 n. 5,94 S.Ct. 1372, 39 L.Ed.2d 577 (1974). The district court opinion in Power Resource 11 devoted substantial time to the jurisdictional question. We, in turn, devoted a large portion of our opinion to recounting the dishict court's jurisdictional determination before reaching the merits of the case. See Power Resource III, 422 F.3d at 234-37. The appellantin Power Resource III also briefed the issue of whether the district court erred in determining that it lacked jurisdiction to grant relief on PRG's as-applied claims. Id. at239. While our decision in Power Resource III certainly could have given more guidance on its jurisdictional determination, the issue was clearly before the court. Power Resource III is thus distinguishable from cases where we have held that the jurisdictional determination had no precedential effect because the prior court did not appear to consider the issue. See, e.g., USPPS, Ltd. v. Avery Dennison Corp., 647 F.3d274,283 (5th Cir.20l l) ("No one contends that the propriety of jurisdiction in this Circuit was actually argued to the prior panel or that the prior panel's decision actually addresses that question."); Kershaw v. Shalalq, 9 F.3d ll, 13 n. 3 (5th Cir.l993) ( "[T]he jurisdictional issue was neither raised by the parties nor addressed by the Court."). Even assuming arguendo that we were not bound by the jurisdictional determination in Power Resource III, we would conclude that the delineation drawn by the district court in Power Resource 1/ between implementation and as-applied challenges is a persuasive reading of PURPA's text, and would follow the same approach here. The PUC insists r.,'-.,..r1,r,,..|-lei.t'; lt. that we should read PURPA's : ii,,,r,l:-,,t'i,',ill.,r'. I'j,, I ) jurisdictional grant more naffowly, *394 based on the Supreme Court's decision in FERC v. Mississippi, 456 U.S. at 759, 102 S.Ct. 2126. Under the PUC's view, federal courts only have jurisdiction to hear claims asserting that the PUC has failed to open its doors to adjudicate disputes under PURPA when it is simultaneously hearing similar state lawsuits. While this reading of PURPA's jurisdictional provisions may be possible, it is not compelled by the Supreme Court's decision in FERC v. Mississippl, and would conflict with our own prior interpretation of the scope of PURPA's jurisdictional grant. See Power Resource lll, 422 F.3d at 23517. Absent a clear contrary statement from the Supreme Court or en bqnc reconsideration, we are bound by our own precedent. See United States v. Stone, 306 F .3d 241, 243 (sth Cir.2002). Moreover, we do not think that the PUC's approach is necessary to avoid constitutional problems in this case. As the Supreme Court noted in FERC v. Mississippr, states have the option of implementing FERC's regulations through state regulations, but may decline to do so if they would prefer to open their state courts only to hear disputes over FERC's regulations. 456 U.S. at 760, 702 S.Ct. 2 126. As a result, Texas was not forced to pass laws implementing FERC's regulations. Cf. Printz v. United States, 521 U.S. 898, 933, ll7 S.Ct. 2365, 138 L.Ed.2d 914 (1997). Instead, Texas opted to have the PUC promulgate regulations implementing FERC's Regulations. See Tex. Utils. Code Ann. $ 35.061; see also 27 Tex. Reg. 5966, 5968 (2002) ("The commission chooses to continue implementation of PURPA through rulemaking. The commission agrees with Texas [Qualiffing Facilities] that implementation on a case-by-case, contested proceeding hearing approach would waste parties' resources."). We thus decline to follow Appellants' approach and adhere instead to the framework we followed in Power Resource lll, 422F.3d at236. Accordingly, we VACATE the portion of the judgment regarding Exelon's challenge to the PUC's order and direct the district court to dismiss for want of subject matter jurisdiction, and review only Exelon's claims that PUC Rule 25.242 fails to implement FERC's Regulation. III. whether the district court properly judgment in favor of Exelon on its PUC failed to implement FERC's review a district court's ruling on a We now turn to granted summary claims that the Regulation, "We ;.ri iI :-- i.i i, r,r,, i , Util. L. Rep. P 14,913 motion for summary judgment de novo and apply the same legal standards as the district court." Bellard v. Gautreaux,675 F.3d 454,460 (5th Cir.20l2). "The court shall grant summary judgment if the movant shows that there is no genuine dispute as to any material fact and the movant is entitled to judgment as a matter of law." Fed.R.Civ.P. 56(a). When ruling on a motion for summary judgment, we are required to review all inferences in the light most favorable to the nonmoving pafi. Matsushita Elec. Indus. Co. v. Zenith Radio, 475 u.s. 574,587, 106 S.Ct. 1348, 89 L.Ed.2d 538 (1986). l"l We review the PUC's implementation of PURPA and the FERC Regulation with deference because "a state has broad authority to implement PURPA with respect to the approval of purchase contracts between utilities and [Qualifuing Facilities]." Power Resource III, 422 F.3d at 236 (citations omitted). Itsl PURPA requires states to implement FERC's regulations. See *395 16 U.S.C. $ 82aa-3(f)(l)." States may implement PURPA "by issuing regulations, by resolving disputes on a case-by-case basis, or by taking any other action reasonably designed to give effect to FERC's rules." FERC v. Mississippi, 456 U.S. at 7 5l , 102 S.Ct.2126. Here, Texas chose to give effect to FERC's rules by promulgating regulations. FERC's Regulation at issue here provides that each Qualiffing Facility "shall have the option ... [t]o provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term." l8 C.F.R. S 292.304(d). We note at the outset that the plain language of PUC R.:ule 25.242 does not conflict with FERC's Regulation. Indeed, there is no FERC Regulation or PURPA provision specifically addressing whether non-firm energy providers may form Legally Enforceable Obligations. Exelon claims instead that the PUC failed to implement FERC's Regulation because PUC Rule 25.242 limits the class of Quali$ing Facilities that have the option of forming Legally Enforceable Obligations.'' Because Congress has left this determination to the PUC, rather than FERC, we disagree. In determining whether PUC Rule 25-242 fails to implement FERC's Regulation, we turn once again to our binding precedent in Power Resource III, 422 F.3d at 237-39. The dissenting opinion's view of this case apparently flows from the view that we are not bound by Power Resource III here. We disagree, and explain below why that case forecloses the position taken in the dissenting opinion. A. Ilel ln Power Resource III, we upheld the PUC's determination that PRG-which was also a Qualiffing Facility---+ould not form a Legally Enforceable Obligation because it could not guarantee power delivery within ninety days as required by the PUC's 90-day Rule. Id. at 234. PRG-like Exelon-argued that the PUC's 90-day Rule did not meaningfully implement the same FERC Regulation at issue here because the PUC's 90-day Rule "eviscerate[d]" the Legally Enforceable Obligation option for an entire category of Qualifoing Facilities that were unable to meet the rule's requirements. Id. at238. We disagreed, and upheld the PUC's 90-day Rule, explaining that, *396 PRG has failed to show that PURPA and the FERC regulations mandate that all [Qualifring Facilities], including unbuilt ones, must be able to create a [Legally Enforceable Obligation] at any time.... FERC regulations grant the states discretion in setting specific parameters for [Legally Enforceable Obligationsl. If FERC had determined it necessary to set more specific guidelines concerning [Legally Enforceable Obligationsl, it could have done so.... The plain text of the FERC regulation, however, fails to mandate that requirement. Rather, defining the parameters for creating a [Legally Enforceable ObligationJ is left to the states and their regulatory agencies. Id. at 238-39 (emphasis added). Power Resource 1// thus forecloses the dissenting opinion's first argument, that under the plain language of FERC's Regulation, all Qualified Facilities must always be allowed to enter into Legally Enforceable Obligations. Instead, Power Resource 11l held that state regulatory agencies-rather than FERC-were empowered to define the parameters of the circumstances in which Qualified Facilities could form Legally Enforceable Obligations. Id. It is this essential holding which binds us here: under the cooperative federalism scheme created by PURPA, it is the PUC, rather than FERC, that defines the parameters for when a Qualified Facility may form a Legally Enforceable Obl igation. The same holds true here. The PUC had the discretion to determine the specific parameters for when a wind farm can form a Legally Enforceable Obligation, and through regulation determined that only when a wind farm can provide firm power may it enter into a Legally Enforceable Obligation. This does not, as the dissenting Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) '1 ", Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 opinion fears, prevent all wind farms from ever forming Legally Enforceable Obligations. To the contrary: As we noted in our jurisdictional analysis, the PUC explicitly left open the possibility that other wind farms might be able to provide firm power, and thus form Legally Enforceable Obligations. Even Exelon is not, as the dissenting opinion claims, "ineligible" to form a Legally Enforceable Obligation. If Exelon is able to demonstrate that it can provide firm power, either through modification or through advances in technology, then it too may enter into Legally Enforceable Obligations.'l C/ Matthew L. Wald, Texas Is lhredfor l(ind Power, and More Farms Plug In, N.Y. Times, July 24,2014, at Bl (noting improvements in transmission infrastructure for Texas wind farms). Here, just as in Power Resource lll, the mere fact that PUC Rule 25.242 prevents some Qualifiing Facilities from entering into Legally Enforceable Obligations at certain times does not mean that the PUC failed to implement FERC's Regulation. As we said in Power Resource III, "[t]he *397 plain text of the FERC regulation fails to mandate" that all Qualifuing Facilities be allowed to form Legally Enforceable Obligations. Id. at 239. To determine otherwise here would put us in conflict with our own controlling precedent in Power Resource III. B. Exelon maintains that we should instead defer to FERC's Letter, which determined that PUC Rule 25.242 failed to implement, and was inconsistent with, FERC's Regulation. Specifically, FERC interpreted its Regulationto allow all Qualifoing Facilities---even those that produce non-firm power-to form Legally Enforceable Obligations. Exelon conceded at oral argument that FERC's Letter is not entitled to deference under either Chevron or Auer v. Robbins, 519 U.S. 452, 457, I l7 S.Ct. 905, 137 L.Ed.2d 79 (1997).A Instead, Exelon argues thatwe ought to give weight to FERC's informal determination based on its persuasive value. We disagree for several reasons. We begin by noting that FERC is not a party to this litigation, and did not take a position on this question of interpretation before our court. FERC's involvement in this case has been limited to sending Exelon a single letter that supports the position that Exelon has taken in this case. We cannot defer to Exelon's proffered interpretation of the FERC Regulation, because it is foreclosed by our own reading of the Regulation in Power Resource III.|5 l20l Even if Exelon had not conceded that FERC's Letter was entitled to no deference under Chevron and Auer, a court's prior construction of a statute trumps an agency construction otherwise entitled to Chevron deference when the prior court decision held that its construction follows from the unambiguous terms of the statute and thus leaves no room for agency discretion. Nat'l Cable & Telecomm. Ass'n v. Brand X Internet Servs., 545 U.S. 967, 982, I 25 S.Ct. 2688, I 62 L.Ed.2d 820 (2005). " Power Resource 111 makes clear that our prior reading of FERC's Regulation unambiguously forecloses the interpretation offered by Exelon here: If FERC had determined it necessary to set more specific guidelines conceming [Legally Enforceable Obligationsl, it could have done so. For example, the FERC regulations could have mandated *398 that the [Qualif,ing Facilitiesl must be able to lock in purchase rates with a [Legally Enforceable Obligationl prior to construction of a facility. The plain text of the FERC regulation, however, fails to mandate that requirement. Rather, defining the parameters for creating a [Legally Enforceable ObligationJ is left to the states and their regulatory agencies. Power Resource III, 422 F.3d at 239 (emphasis added). Our approach does not, as the dissenting opinion argues, "flip [ ] Brand X on its head." Dissent at 2 I . Rather, it is a straight-forward application of the doctrine, which is consistent with the way in which this court and our sister circuits have applied the decision. See Burks v. United States, 633 F.3d 347, 360 (5th Cir.20ll); Tran v. Mukasey,5l5 F.3d 478,484 (5th Cir.2008); Sierro Club v. Envt'l Prot. Agency, 479 F.3d 875, 880-84 (D.C.Cir.2007) (vacating an EPA rule that conflicted with circuit precedent and explaining that the EPA "must obey the Clean Air Act as written by Congress and interpreted by this court"). Our decision is also consistent with the approach used in cases where our sister circuits have previously interpreted statutes and regulations to be ambiguous, and thus deferred to the agency's interpretation following the Supreme Court's ruling in Brand X, 545 U.S. 967, 125 S.Ct. 2688. In those cases, the courts emphasize that their i. Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 prior decisions also noted ambiguity in the text at issue. See, e.g., Garfias-Rodriguez v. Holder,702F.3d 504,512 (9th Cir.20l2) ("We wrote in Acosta that '[t]he statutes involved do not clearly indicate whether the inadmissibility provision or the penalty-fee adjustment of status provision should take precedence,' and reached our conclusion by relying heavily on our earlier Perez4onzalez decision."); Hernandezlarrera v. Carlson, 547 F.3d 1237, 1245 (l0th Cir.2008) ("The Supreme Court has twice explicitly found the statute to be ambiguous."); Fernandez v. Keisler, 502 F.3d 337, 34748 (4th Cir.2007) ("We thus do not hold that a court must say in so many magic words that its holding is the only permissible interpretation of the statute in order for that holding to be binding on an agency. In many instances, courts were operating without the guidance o/ Brand X, and yet the exercise of statutory interpretation makes clear the court's view that the plain language of the statute was controlling and that there existed no room for contrary agency interpretation."); Dominion Energt Brayton Point, LLC v. Johnson, 443 F.3d 12, 17 (lst Cir.2006) ("The short of it is that the Seacoast covrt, faced with an opaque statute, settled upon what it sensibly thought was the best construction of the Clean Water Act's 'public hearing' language."); La,ry v. Sterling Holding Co., LLC, 544 F.3d 493, 503 (3d Cir.2008) (explaining that in the prior case "we struggled to divine their applicability to the instant fact pattern.... [and] repeatedly noted the lack of clear guidance in the text or elsewhere regarding whether and to what extent reclassifications fell within the Rule's scope"); see also Note, Implementing Brand X: What Counts as a Step One Holding?, I l9 Harv. L.Rev. 1532, 1538 (2006) (discussing the possible ways to implement Brand X ).ln contrast to these cases, in Power Resource III we determined that the "plain text" of FERC's Regulation allowed the PUC to limit the situations in which Qualifoing Facilities can form Legally Enforceable Obligations. Thus, under Brand.{ the interpretation put forward by Exelon would not be entitled to deference even if counsel had not conceded this point at oral argument. *399 l2rl Even assuming arguendo that this prior interpretation left room for discretion, an agency is not entitled to deference when it offers up an interpretation of the Regulation that we have already said to be unambiguously foreclosed by the regulatory text. See Christensen, 529 U.S. at 588, 120 S.Ct. 1655 ("Auer deference is warranted only when the language of the regulation is ambiguous."). This court has already determined that FERC's Regulation unambiguously "left [it] to the states and their regulatory agencies" to "defin[e] the parameters for creating a Legally Enforceable Obligation." Power Resource III, 422 F.3d at 239. We therefore accord no deference to the interpretation in FERC's Letter. Contrary to the dissenting opinion's claim, we are not substituting our own reading of the regulation for FERC's here. Nor are we deferring "based on nothing more than the state regulatory authority's say-so." Dissent at 401 . lnstead, we are deferring to the PUC's official interpretation of the Regulation lre a promulgated state regulation because our precedent requires us to defer to the PUC on this particular issue, and prevents us from deferring to Exelon's proffered interpretation. Like FERC, the PUC too has a great deal of expertise. Indeed, Texas is rather unique in that it runs its own electric grid. Even if that were not the case, Congress delegated the authority to make this call to the PUC. C. The reading advocated by Exelon would also render PURPA subsection (d)(l) superfluous.'' Subsection (d)(l) of FERC's Regulation allows a Qualiffing Facility to provide power to the utility only on an as-available basis, and requires the Qualiffing Facility to price the power at the moment of delivery. Id. S 292.304(dxl). Subsection (d)(2) gives a Qualifring Facility this exact same option to sell power to the utility on an as-available basis, and also provides a Quali$ing Facility with a second option to choose to fix the price "at the time the obligation is incurred." l22l l23l Under the reading advocated by Exelon and adopted by the district court, every Qualiffing Facility must have the option to form a Legally Enforceable Obligation, and thus to select between the two pricing options available under subsection (dX2). If every Qualifring Facility may take advantage of the choice provided by subsection (d)(2), it is hard to understand why Congress or FERC would also include a separate subsection limiting Qualiffing Facilities to one pricing option. Exelon's "reading is thus at odds with one of the most basic interpretive canons, that a statute should be construed so that effect is given to all its provisions, so that no part will be inoperative or superfluous, void or insignificant." Corley v. United States, 556 U.S. 303, 314, 129 S.Ct. 1558, 173 L.Ed.2d 443 (2009) (internal quotation marks and brackets omitted). When presented with two plausible readings of a regulatory text, this court common-sensically follows the same principle and prefers the reading that does not render portions of that text superfluous. See Nat'l Ass'n of Home Builders,55l U.S. Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 at 668, 127 S.Ct.25l8 ("But this reading would render the regulation entirely superfluous." *400 ); see also Antonin Scalia & Bryan A. Garner, Reading Law: The Interpretation of Legal Texts 174 (2012) ("lf possible, every word and every provision is to be given effect (verba cum effectu sunt accipienda ). None should be ignored. None should needlessly be given an interpretation that causes it to duplicate another provision or to have no consequence." (footnote omitted)). In contrast, the PUC's reading of the provisions gives effect to both subsections: Only if a Qualifoing Facility can guarantee a particular quantity of power at a particular time can it take advantage of the additional pricing option under subsection (d)(2). Occidental notes that this reading also supports the congressional intent that rates under PURPA "shall be just and reasonable to the electric consumers of the electric utility and in the public interest." l6 U.S.C. $ 824a-3(a)(2), (bXl). According to Occidental, a Legally Enforceable Obligation requires a utility to purchase power at rates set potentially years in advance, and as a result, the utility needs to know that the promised power actually will be produced and readily available. Otherwise, the utility would be unable to determine how much additional power it must arange to purchase to meet its requirements without paying a premium for last-minute purchases. Because only firm power Qualiffing Facilities can provide that kind of certainty, it makes sense that only they should be able to select between the rate options.'* D. In sum, Exelon has failed to show that PURPA and FERC's Regulation mandate that all Qualifoing Facilities be able to create Legally Enforceable Obligations at any time. Power Resource III, 422 F.3d at 238. PURPA allows states discretion in determining when a Legally Enforceable Obligation is created, and PUC Rule 25.242 falls within that discretion. See id. at 239. The PUC is therefore entitled to deference in defining the parameters for creating Legally Enforceable Obligations. ld. at 236. Here, the PUC has reasonably distinguished between Qualifoing Facilities that can, and cannot, provide firm power. As Occidental notes, mandatory long-term contracts between generators and utilities can burden customers by imposing prices well above the actual market prices. The PUC made a reasonable decision that only those Quali$ing Facilities capable of providing reliable and predictable power may enter into such arrangements. Thus, Exelon has not proven that the PUC failed to implement FERC's PURPA regulations. IV. We VACATE the portion of the judgment regarding Exelon's challenge to the PUC Order and direct the district court to dismiss for want of subject matter jurisdiction. As to the remaining claims, we REVERSE and REMAND for proceedings consistent with this decision. EDWARD C. PRADO, Circuit Judge, concurring in part and dissenting in part: I concur in the majority's carefully reasoned jurisdictional analysis. But I have serious reservations about the majority's arguments on the merits, and I must therefore respectfully dissent. The effect of the majority's opinion is to undermine an important federal program that promotes renewable energy. The majority rejects the considered view ofthe federal *401 agency that authored the regulation in question and that enforces the program, based on nothing more than the state regulatory authority's say-so. In doing so, the majority contravenes established principles of interpretation and administrative law and disrupts the scheme that Congress intended. This case concerns the distinct roles Congress gave to federal and state regulatory authorities in Section 210 of Title II of the Public Utility Regulatory Policies Act of 1978 ("PURPA"). Pub.L. 95417,92 Stat. 3117,3144. PURPA gave the Federal Energy Regulatory Commission ("FERC") authority to promulgate rules "to encourage cogeneration and small power production" including rules that "require electric utilities to offer to ... purchase electric energy from such facilities." 16 U.S.C. $ 824a-3(a). PURPA in turn provided that "each State regulatory authority shall implement [any] rule [prescribed by FERC under $ 824a-3(a) )." Id. $ 824a1(f). PURPA not only divided the tasks of regulation and implementation between federal agencies and states respectively; it also divided authority to challenge and review those implementation schemes. On one hand, PURPA makes state courts the avenue for judicial review of "any proceeding conducted by a State regulatoryauthority for purposes of implementing any requirement of a [FERC] rule." l6 U.S.C. $ 82aa-3(g)(/ ){2) (cross-referencing l6 U.S.C. $ 2633); l6 U.S.C. $2633 ("Any person ... may obtain review of any determination made under [certain provisions] ... in the i,.,Neilt , ,l Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 appropriate state court."). On the other hand, PURPA authorizes FERC to "enforce the requirements of [the state implementation provision]" by way of "an action against the state regulatory authority ... for failure to comply" with the implementation requirements. 1d. $ 82aaa$)Q)(A). In addition, PURPA entitles electric utilities and small power producers to petition FERC "to enforce the requirements of [the state implementation provisionl." Id. S 824a-3(hX2XB). If FERC declines to use its enforcement authority within sixty days, "the petitioner may bring an action in the appropriate United States district court to require such State regulatoryauthority to comply with [the implementation] requirements," and FERC may intervene as of right. 1d. These interlocking components of PURPA----ordering FERC to prescribe rules, giving state regulatory authorities control over implementation of those rules, and empowering FERC to enforce state compliance with the FERC rules-provide the framework for this dispute. Here, FERC mandated that "[e]ach qualifuing facilityr shall have the option ... to provide energy or capacity pursuant to a legally enforceable obligation." l8 C.F.R. $ 292.304(d)(2). The Public Utility Commission of Texas ("PUC") implemented that regulation by permifting only some quali$ing facilities to enter into a legally enforceable obligation. 16 Tex. Admin. Code $ 25.242(c) ("PUC Rule 25.242"). In response to Appellees' (collectively, "Exelon") petition for enforcement, FERC issued a declaratory order ("Declaratory OrdeC') finding that the PUC failed to implement its rule: "we find that ... the requirement in Texas law that legally enforceable obligations are only available to sellers of 'firm power,' as defined by Texas law, [is] inconsistent with PURPA and our regulations implementing PURPA, particularly section 292.304(d) of our regulations." *402 JD lYind l, LLC, 129 FERC tT6l,l48 (Nov. 19, 2009). The majority diverges from the detailed reasoning of the district court, which, like FERC, had found that the PUC had failed to implement the regulation. In doing so, the majority departs from the plain language of the regulation, which mandates that every qualiffing facility shall have the option to form legally enforceable obligations. PUC Rule 25.242 deprives qualifoing facilities of that option and therefore is inconsistent with the regulation. Even if the regulation did not plainly bar the PUC's regulation, the majority also errs by refusing to defer to the FERC's expert interpretation of its own regulation. I. DISCUSSION We review a district court's interpretation of a federal regulation de novo. The starting point for our court's analysis is to apply standard interpretive principles to determine whether FERC (in its rule) or Congress (in PURPA) have spoken directly to the precise issue in question. See Talk Am., Inc. v. Mich. Bell TeL Co., -u.s.-, t3t s.ct. 2254,2260,180 L.Ed.2d 96 (2011) (first analyzing whether a "statute or regulation squarely addresses" the issue in that case); Chase Bank USA, N.A. v. McCoy,562 U.S. 195, l3l S.Ct. 871, 878, 178 L.Ed.zd 716 (2011) (same); cf, Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837, 84243, 104 S.Ct. 2778, 81 L.Ed.2d 694 (1984) (asking at the first step "whether Congress has directly spoken to the precise question at issue" or whether the statute is ambiguous). To ascertain whether the regulation has spoken unambiguously to the question at issue, the court "avail[s itselfl of the traditional means of statutory interpretation, which include the text itselt its history, and its purpose." See Bellum v. PCE Constructors, Inc., 407 F.3d 734,739 (5th Cir.2005) (citing Gen. Dynamics Land Sys., Inc. v. Cline, 540 U.S. 581, 600, 124 S.Ct. 1236, 157 L.Ed.2d r0e4 (2004). If the regulation is silent or ambiguous-that is, it does not answer the precise question at issue-after using ordinary tools of statutory interpretation, our court then must confront a difficult issue of deference doctrine: where Congress has given important roles to both a federal agency and state regulatory authorities, and those federal and state agencies offer conflicting interpretations of the federal regulation, to which agency, if any, should we defer?' We typically defer to a federal agency's reasonable interpretation of its own regulation. But the Appellants and the majority assume that the discretion afforded state regulatory authorities in implementing the regulation suggests that they deserve the deference, not FERC. As I explain below, we ought to give FERC deference because FERC is the author ofthe regulation at issue and the structure of PURPA suggests Congress's intent to let FERC's interpretations of its own regulation trump the state's. Yet, to be sure, we do not need to reach this question of deference because the regulation's plain language bars the PUC's interpretation. II. "STEP ONE' PURPA required FERC to promulgate rules that "require electric utilities to offer *403 to ... purchase electric energy from such facilities." 16 U.S.C. $ 824a-3(a). The ',r'i'*r1ie',',,Next (', 2()1h .f ltcrirr.r--| iieLrlers X: r-:i.-ii|ir tr.r !,rrornirli lJ [i (.i0r,r.t[rrr'irerit \/d0llis 1$ Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Utit.-t-.nep.ef+,SfS- statute did not do any more to describe the regulatory scheme that would give effect to this mandatory purchase provision, leaving FERC to work out the details. FERC, pursuant to its delegated authority, issued the following regulation: Each qualiffing facility shall have the option either: (l) To provide energy as the qualifoing facility determines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the purchasing utility's avoided costs calculated at the time of delivery; or (2) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the quali$ing facility exercised prior to the beginning of the specified term, be based on either: (i) The avoided costs calculated at the time of delivery;or (ii) The avoided costs calculated at the time the obligation is incurred. r8 c.F.R. $ 292.304(d). A. AI! Qualifying Facilities Are Entitled to Create Legally Enforceable Obligations. The key phrase in dispute is "Each qualifring facility shall have the option ... [t]o provide energy ... pursuant to a legally enforceable obligation." The majority looks at that phrase and concludes that "the plain text ofthe FERC regulation fails to mandate that all Quali$ing Facilities be allowed to form legally enforceable obligations." Majority op. at 397 (citation and internal quotation marks omitted). I strongly disagree. FERC spoke "in terms of the mandatory 'shall,' which normally creates an obligation impervious to judicial discretion." Lexecon Inc. v. Milberg l(eiss Bershad Hynes & Lerqch, 523 U.S. 26,27, I l8 S.Ct. 956, 140 L.Ed.zd 62 (1998); see, e.g., Nat'l Ass'n of Home Builders v. Defenders of ll/ildlife,55l U.S. 644,66142, 127 S.Ct. 2518, 168 L.Ed.2d 467 (2007) (language in the Clean Water Act that EPA "shall approve" an application was mandatory and removed EPA's discretion not to approve the applications); Black's Law Dictionary 1375 (9th ed.2009) (noting that it is the "mandatory sense [of 'shall'] that drafters typically intend and that courts :l...,.r.trt*r, -- ,, . ,; ,, ,, , , i.r typically uphold"). The majority points to no argument that would alter this presumption of a mandate. The terms of this mandate require the state regulatory authority to preserve an option belonging to each quali$ing facility to form a legally enforceable obligation. The option belongs to each qualiSing facility, which means that it belongs to "every" qualifring facility. See Sierra Club v. EPA, 536 F.3d 673, 678 (D.C.Cir.2008) (" 'Each' means '[e]very one of a group considered individually.' " (quoting American Heritage Dictionary 269 (4th ed.200l))). Every qualiffing facility "ha[s]" the option; not the state regulatory authority. Thus, the state regulatory authority may not make the choice for each qualiffing facility. See 45 Fed.Reg. 12,214, 12,224 (1980) ("The Commission intends that rates for purchases be based, at the option of the qualifying facility, on either the avoided costs at the time of delivery or the avoided costs calculated at the time the obligation is incurred." (emphasis added)). Additionally, the option guarantees the ability to form a legally enforceable obligation. The term "legally enforceable obligation" is scarcely defined, and the majority *404 assumes that this ambiguity means that the regulation does not precisely answer the question at issue. But this ambiguity does not alter in any way the regulation's mandate. Whatever the term "legally enforceable obligation" might mean is irrelevant, so long as each qualifoing facility has the option to form one. From this fact we can also infer that any definition of "legally enforceable obligation" that undermines the mandate is not permitted. So, since Qualiffing facilities may include wind power producers, see 18 C.F.R. $ 292.204@)-(b) (covering small power producers whose primary energy source is renewable resources, including wind), and the PUC Rule defines "legally enforceable obligation" so that those producers cannot claim that entitlement, the PUC's definition of "legally enforceable obligation" violates the clear mandate. If FERC had intended categorically to limit the mandatory option, it would not have used terms such as "each" and "shall." B. The PUC Firm-Power Rule Makes Some Qualifying Facilities Ineligible to Form Legally Enforceable Obligations. As the majority states, "the PUC's rule implementing FERC's Regulation permits only a Qualifuing Facility that generates 'firm power' to enter into a Legally Enforceable Obligation." Majority op. at 385 (citing PUC Rule 25.242). That alone should be enough to conclude that the PUC rule "fail[s] to comply" with the 1--r,11 1,r ; li i'i | 1 f.i',r'i)il..i: Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 implementation requirements imposed on it by PURPA. See l6 U.S.C. $ 82aa-3(f), (hX2XA). Because the mandatory option is the linchpin of the regulation and the PUC Rule categorically bars some qualifying facilities from exercising their mandated option, I would conclude that the PUC regulation conflicts with the unambiguous terms of the regulation. The majority says that "there is no FERC Regulation or PURPA provision specifically addressing whether non-firm energy providers may form Legally Enforceable Obligations." Majority op. at 395. But this reading overlooks the term "each," which plainly means any and every qualiling facility. Since every qualifuing facility may form legally enforceable obligations, the regulation does not need to specify which qualifoing facilities, be they firm or non-firm, may form them. It would be an illogical and inconsistent result, then, to read "each" as meaning only "firm-power." Finally, our interpretation of the regulation should give effect to the purposes ofthe statute. Congress identified a problem: electric utilities were monopsonies, lone buyers of energy in a market with many potential producers of energy, and "traditional electricity utilities were reluctant to purchase power from ... nontraditional facilities." FERC v. Mississippi,456 U.S. 742,750, 102 S.Ct.2126, 72 L.Ed.zd 532 (1982). Congress sketched out a bold solution to that problem-mandatory purchases of energy by electrical utilities from qualif,ing facilities, l6 U.S.C. $ 824a-3(af-and asked FERC to promulgate rules to that effect. FERC chose a scheme that turned on making legally enforceable obligations available for each qualifuing facility. In fact, FERC recognized that to encourage that sort of energy production, the regulations had to provide the certainty that comes with having a long-term obligation. Thus, FERC invoked "the need for quali$ing facilities to be able to enter into contractual commitments" and "the need for certainty with regard to return on investment in new technologies" that only those long-term legally enforceable obligations could provide. 45 Fed.Reg. at 12,224. Giving only some of the qualified facilities the leverage to *405 overcome the uncompetitive monopsonies would undermine this basic purpose. It will provide no investment certaingl, and, inevitably, many developers will be unable to produce energy using the new technologies that PURPA sought to encourage. The majority appears to endorse the view that a contrary purpose of the statute should prevail: "the congressional intent that rates under PURPA 'shall be just and reasonable to the electric consumers of the electric utility and in the public interest.' " Majority op. at 400 (quoting 16 U.S.C. $ 824a-3(a)(2), (bxl)). But none of the Appellants brings a challenge to FERC's regulation implementing PURPA, and if there were any ambiguity about FERC's consideration of those views, FERC has made a permissible interpretation of the general statutory command. See Chevron,467 U.S. at 843, 104 S.Ct.2778. Indeed, FERC addressed the majority's concerns for just and reasonable rates through an entirely different scheme in its regulation. FERC used the concept of "avoided costs" to simultaneously provide nondiscriminatory pricing to the new market entrants, the small energy producers, but also accord with market rates for electricity. See l8 C.F.R. S 29230a@), (c) (setting guidelines for state avoided-cost rate-setting); 45 Fed.Reg. 12,222 ("The Commission has ... provided that the rate for purchases meets the statutory requirements [forjust and reasonable rates] ifit equals avoided costs."). The idea that the couft can read FERC's regulation as violating the terms of the statute-but for the saving interpretation that Occidental offers-runs contrary to the Chevron canon. It is inappropriate for the court to assert that "[b]ecause only firm power Qualifying Facilities can provide that kind of [cost] certainty, it makes sense that only they should be able to select between the rate options." Majority op. at 400. It may "make[ ] sense" to us lay judges, though I tend to think not. But it makes as much sense to do as FERC has done-namely, to provide every qualiffing facility with the option to enter into a legally enforceable obligation and trust that "in the long run, 'overestimations' and 'underestimations' of avoided costs will balance out." 45 Fed Reg. 12,224. The point is, though, that it really is not for a court to say. Congress delegated the authority to weigh these considerations to an expert agency. Only by displacing FERC's role as Congress's delegatee and going beyond the issue in dispute can the court offer its merely plausible reading of statutory language and conclude that FERC is doing it wrong. III. "STEP ZERO" Supposing that we could get past the mandatory language of the statute, I would still find that the district court properly adopted FERC's view of its own regulation. The majority would have us upset this basic doctrine of agency deference because the PUC enjoys some discretion in implementing FERC regulations. The majority's conclusion that the PUC acted within its discretion to answer the supposedly ambiguous question in this case lacks foundation. But it is worth first examining the hard issue of first impression this case !'Jp.,tl,-1,.',,Nex1 i:',rll01l' iiroir-rs:r-,irlli'irlers, i\i;ci;'lrnrti:lrrr..tiial tjll Goveinrnent Wor ks Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Ut,t L RepF 14813 actually creates and why, neveftheless, deference to FERC makes sense. A. The Court Should Defer to FERC's Interpretation of lts Own Regulation, Even Under PURPA's Cooperative Federalism Scheme. It is well-established that a federal agency's interpretation of its own regulation " 'becomes of controlling weight unless it is plainly eroneous or inconsistent with the regulation.' " Elgin Nursing & *406 Rehab. Ctr. v. U.S. Dep't of Health & Human Servs., 718 F.3d 488, 492 (5th Cir.20l3) (quoting Bowles v. Seminole Rock & Sqnd Co., 325 U.S. 410,414,65 S.Ct. 1215,89 L.Ed. 1700 (19a5)); see also Auer v. Robbins,5l9 U.S. 452,461, ll7 S.Ct. 905, 137 L.Ed.2d 79 (1997). Indeed, Seminole Rock and Auer dictate deference to the federal agency's interpretation of its own regulation even when that agency's interpretation is made informally. Elgin Nursing, 718 F.3d at 493 (*This court and others have held that opinion letters, handbooks and other published declarations of an agency's views, including amicus briefs, are authoritative sources of the agency's interpretation of its own regulations." (citations and intemal quotation marks omitted)). Therefore, if l8 C.F.R. S 292.304(d) really were ambiguous, FERC's interpretation of that regulation in its 2009 Declaratory Order would ordinarily control our court's interpretation "unless it is plainly erroneous or inconsistent with the regulation." If a statute entitles two agencies to take administrative actions based on promulgated regulations under the statute and those agencies come to conflicting interpretations of the regulation, we must ask a prior question: To which agency did the statute give "the power to render authoritative interpretations of [the] regulations"? Martin v. Occupalional Safety & Health Review Comm'n,499 U.S. 144, 152,1I I S.Ct. I l7l, 113 L.Ed.2d I l7 (1991). To answer that question, courts must "infer from the structure and history of the statute" which agency should be the primary interpreter of the regulations.' 1d. ln Mqrtin, the court examined the split-enforcement scheme Congress created under the Occupational Safety and Health Act ("OSH Act"). The OSH Act entrusted the Secretary of Labor with "responsibility for setting and enforcing workplace health and safety standards," but delegated authority the Occupational Safety and Health Review Commission to adjudicate disputes, including employer challenges to the Secretary's enforcement actions. See id. at 14748, lll S.Ct. llTl (citing 29 U.S.C. $S 651(bX3), 658-661, 665, and 666). If the Commission ruled against the Secretary, the Secretary had "the right to seek review of [the] order in the court of appeals." Id. at 148, I I I S.Ct. I l7l. Faced with an appeal in which the Commission and the Secretary offered conflicting interpretations of an OSH Act regulation, the Martin Court held that the Secretary deserved the deference. Id. at 152, lll S.Ct. ll7l. The Court placed *407 heavy emphasis on the fact that the Secretary-as the head of the agency that promulgates the standards-was "in a better position than the Commission to reconstruct the purpose of the regulations in question." Id. ln addition, the Court found that "by virtue of the Secretary's statutory role as enforcer, the Secretary comes into contact with a much greater number of regulatory problems than does the Commission," which adjudicated episodically based only on contested enforcement actions. /d. Thus, the Court concluded that the Secretary should enjoy primary interpretive authority due to the agency's "historical familiarity and policymaking expertise," id. at 152, I I I S.Ct. I l7l, and courts "should defer to the Secretary [to the extent] the Secretary's interpretation is reasonable," id. at 158, lll S.Ct. I l7l (emphasis omifted). Martin 's statute-specifrc analysis should guide our analysis of the deference dilemma here. Like the delegation to the Secretary under the OSH Act, PURPA placed FERC in charge of writing rules and enforcing them. See l6 U.S.C. $ 824a-3(a), (h)(l). In particular, 16 U.S.C. $ 82aa-3(h) ( "Commission enforcement") empowered FERC to o'enforce the requirements of [the state implementation provision]" when a state has "fail[ed] to comply" with the implementation requirements. See id. $ 824a-3(h)(2).' Congress apparently did not just want FERC to provide its views on its regulation through enforcement actions; PURPA also confers on FERC an entitlement to intervene as ofright in a petitioner's federal court action even when FERC did not use its discretionary enforcement power. 1d. State regulatory authorities have no analogous role to either the Commission or the Secretary in Martin. Whereas the Commission in Martin had the power to hear and decide cases brought against the Secretary, a state regulatory authority enjoys no equivalent adjudicative authority. Instead, state regulatory authorities have a unique mandate to implement the FERC regulations through their own chosen state mechanisms. See FERC v. Mississippi,456 U.S. at760,102 S.Ct. 2126; see also l6 U.S.C. $ 824a-3(f). In addition, state regulatory authorities may defend as-applied challenges to their implementation plans in state court actions, but, under lltor.;rsort lillrlcr,, lir,,,.:illrrn to olglti.ri tl li (;r)v( ri't ri(,rli i'!/i)ii l!) Exelon Wind 1, L.L.G. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 federal law, they enjoy neither a special adjudicative or enforcement power. See 16 U.S.C. $ 82aa-3(g). This scheme strongly indicates that "the power to render authoritative interpretations of [PURPA] regulations is a 'necessary adjunct' of [FERC's] powers to promulgate and to enforce national ... standards." See Martin, 499 U.S. at 152, lll S.Ct. ll7l. FERC is the author of the regulations it is asked to interpret and enforce, and FERC is thus in a "better position than" the PUC to say what those regulations mean. Id. We have said before that this authorship rationale is "[t]he most important reason for extending {'408 greater deference" to an agency's informal interpretation of its own regulation under the Auer doctrine. Belt v. EmCare, Inc., 444 F.3d 403, 416 n. 35 (5th Cir.2006). Nothing about PURPA's cooperative federalism scheme detracts from this crucial reason for deference to the promulgating agency. The layered design of the enforcement provisions further points to FERC's leading interpretive role. Although PURPA specifically provided a special implementation role for state regulatory authorities, PURPA gave FERC a trump card when it permitted FERC to bring enforcement actions against state regulatory authorities that had "fail[ed] to comply" with FERC regulations. It would be odd indeed for Congress to give FERC the power to bring enforcement actions against state regulatory authorities, only to let FERC lose every action because Congress had supposedly intended states, not FERC, to have interpretive authority. Such an outcome would nulliff FERC's enforcement power and upset the "multi-layered enforcement" scheme PURPA devised. Congress appears to have intended for FERC's interpretation, not the PUC's, to have the upper hand. Here, that means we should give controlling weight to FERC's reasonable interpretation of its own regulation. What mitigates the effect of this FERC trump for the PUC is the latitude that FERC has granted state agencies "in determining the manner of implementation of [FERC's] rules, provided that the manner chosen is reasonably designed to implement the requirements of [8 C.F.R. $$ 292.301-141." 45 Fed.Reg. at 12,230-31. FERC did so with a sense that states could use discretion to implement better policies. FERC noted the context of "economic and regulatory circumstances [that] vary from State to State and utility to utility" and 'orecogni[zed] the work already begun and ... the variety of local conditions." 1d. at 12,231 . The Supreme Court ratified that "latitude" language in FERC v. Mississippi 456 U.S. at 751, 102 S.Ct. 2126. Congress also expected meaningful interaction between state regulatory authorities and FERC, since PURPA instructed FERC to consult with state regulatory authorities before issuing regulations. See 16 U.S.C. $ 824a-3(a) ("Such rules shall be prescribed, after consultation with representatives of Federal and State regulatory agencies having ratemaking authority for electric utilities, and after public notice and a reasonable opportunity for interested persons (including State and Federal agencies) to submit oral as well as written data, views, and arguments."). In light of FERC's stated position, our court has previously said that "[w]e review the PUC's implementation with deference because '[a] state has broad authority to implement PURPA with respect to the approval of purchase contracts between utilities and QFs.' " Power Resource IIl, 422 F.3d at 236 (quoting N. Am. Natural Res., Inc. v. Mich. Pub. Serv. Comm'n, 73 F.Supp.2d 804, 807 (D.Mich.l999)). Or, as we summarized it elsewhere, the state regulatory authorities exercise their discretion in "setting the specific parameters" on when and how legally enforceable obligations may be formed. Id. at 238 (citing FERC declaratory orders that permitted state discretion in defining parameters of legally enforceable obligations); id. at 239 (referring to the discretion that "FERC has given" state regulatory authorities). This discretion is limited, though, and, in any case, it tells us little about which agency Congress wanted to speak with the force of law. Generally, implementation discretion is limited by the requirement that the chosen means of implementation *409 are "reasonably designed to give effect to FERC's rules." FERC v. Mississippi, 456 U.S. at 751, 102 S.Ct.2126.In addition, in some cases, PURPA gave exclusive control to FERC to implement some rules. ln Power Resource III, for example, the court acknowledged that PURPA gave an exclusive grant of authority to FERC over rules on the certification of qualiffing facilities. 422 F.3d at 236 n. 2.; see also Indep. Energt Prods. Ass'n, Inc. v. Cal. Pub. Utils. Comm'n,36 F.3d 848, 853-54 (9th Cir.l994) ("The structure of PURPA and [FERC]'s regulations[ ] reflect Congress's express intent that [FERC] exercise exclusive authority over QF status determinations."). B. The Majority's Reasons Do Not Support Deferring to the PUC. I am unconvinced by the majority's reasons for deferring to the PUC's interpretation of the FERC regulations. )i) Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 l.NoFERClnterpretation parties to consult. JD l(ind 1, LLC, 129 FERC 61,148 rhe majoriry opines that there is no FERC interpretation $fJ;'J;,i31?].'}iiHrTHr::f:""Hffr because that to interpret in this case. Not so. First, while the majority opinion correctly notes that FERC is not a party and did not take a position before our court, the fact that FERC is not a party makes no difference. In fact, courts regularly grant deference to nonparty amici. See, e.9., Decker v. 2. Power Resource III Nw. Erutl. Def. Ctr., - U.S. -, 133 S.Ct. 1326, 1336-37,185 L.Ed.2d 447 (2013)(giving Auerdeference Power Resource III does not support the majority's to the EPA's interpretation offered in an amicus brief). In holding. Two important limitations make that case any case, the FERC interpretation is "before our court" inapplicable here. First, Power Resource 111 's statement not only because its Declaratory Order is in the record and of deference was highly context-specific. This case is has been briefed by the partiei, but also because FERC's different. Second, that case tells us nothing about which Declaratory Order was the jurisdictional prerequisite for agency deserves deference where FERC has spoken and the case even coming to our court. See Power Resource disagrees with a state agency's interpretation of FERC's Itl, 422 F.3d at 245 (lt FERC does not bring an regulations' enforcement action within 60 days following the date on which a petition is filed, the utility or qualifuing facility FERC's grant of discretion to the PUC was necessarily may bring an enforcement action in federal distriit court.i' tied to the particular issue in the case-conditions on the (quoting 16 U.S.C. 82aa-3(h)(2)(B)). formation of legally enforceable obligations. Every indication shows that the Power Resource .1// court was Also note that if the court required that the interpretation careful not to overstate the scope of the PUC's discretion. be argued by a party "before our court," we would lts .crucial statement of deference, which the majority actually lack a PU-C interpretation, too. Before our court, recites, accords deference only "with respect to the the PUC has notably abandoned the interpretation of the approval of purchase contracts between utilities and FERC regulation that it made in the district court, instead QFs."o The district court thoroughly discredited reliance relying entirely on the now-repudiated argument that our on Power Resource 111 in its opinion below: court lacks jurisdiction. It would seem a double standard for the majority to rely on this argument to negate FERC's interpretation *hil" pr"r..ringlhe pUC's. " In Power Resource fill J' the Fifth Circuit considered whether [the PUC]'s ninety-day rule was a valid Second, the majority acknowledges that FERC offered its implementation of PURPA. The ninety-day rule simply interpretation in its Declaratory brder, but minimizes the limits when in time a LEo can be created; no LEo can effeci of that interpretation by characterizing it as a be established more than ninety days before the QF has ,,single letter,'s sent to Exelon. This misunderltands the power available, or will have power available. After siturtion. FERC made its Declaratory Order pursuant to careful analysis, and noting the discretion afforded the its regulatory authority. See supra n. 4. FERC published States in determine when a LEO is formed, the Fifth noticJ of Exelon,s piedecerror,s filing in thi Federal circuit upheld the rule. 1422 F.3d) at 240.... Unlike the Register, inviting interventions and protJsts. See JD Wind firm-power rule, any wind QF can comply with the l, LLC, et al.; Notice for petition for Declaratory Order, ninety-day rule; it is simply a matter of timing. 74 Fed.Reg. 5114742 (oct. 5, 2009). FERC ,eceiued Although there are no doubt considerable practical briefing frJm the Appellants in that proceeding, and also expenses and difficulties involved, in theory any QF from a-variety of other industry groupr, r.n.*u-bl" energy can comply with the ninety-day rule through careful developers, and utilities. see JD wind l, LLC, l2g FE{t planning in advance, such as in what sequence to seek ,,1l 6l , l4g, at !f 6l ,630-32. Many of these intervenors were financing, obtain permitting, and begin different phases under the impression that FEIic's interpretation was not of construction, in relation to when to send LEo just a one-ofi missive intended for a single party, but a paperwork to a utility'... By contrast, the firm-power wide-rangingpolicy interpretation. *410 see,'e.s.:'id. atn rule is simply insurmountable for an entire class of 61,631. (..Montana Reniwables states that t"ne fer,as QFs. No sequence of permitting, financing, and Commission's interpretation of when legally enforceable construction will magically transform the vagaries of obligations can be established will negitively affect all the wind into the constant, predictable stream of energy intermittent resource eFs in the United States.,'). Then, demanded by the firm-power rule. As such, this case FERC published its interpretation in a public ieporter, falls outside the scope of guidance offered by Power ry?i!*lf!f gll_lBte qeg{31ory_19!,Loti!iil g9 .ge{Igq _ Resource fitt J' ,','','-,11r'.,Nglt i..'.rtl 1|'.,,'r.,',1 l(i.;t,: ltt. r.l.r,:trli,)l ,(lrl.t 1;1',,'.t;,:.,,,',.., ,.;,.'. -,i Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 Put another way, Power Resource [III] reviewed [a] rule I J governing when and how a LEO is formed, whereas the firm-power rule ... determin [es] w hether some types of QF can ever obtain a LEO. Exelon Wind l, LLC v. Smitherman, 2012 WL 4465607, at *12 (W.D.Tex.20l2) (emphasis added). The difference between that case and this one is one of kind, not degree.*4ll The next difference between this case and Power Resource 111 is just as remarkable and legally significant. In Power Resource III, FERC did not offer its interpretation of its own regulation in response to the petitioner's request. Power Resource III, 422 F.3d at234 (describing that "[a]fter FERC had not acted on [Power Resource Group]'s petition for 60 days, [Power Resource Group] filed a complaint"). Still, Power Resource III looked to (and was persuaded by) FERC declaratory orders in determining whether it was appropriate to grant discretion to the PUC: see id. at236 n.2, and FERC's own position that defining the parameters of LEO formation was within the state's discretion, id. at 238. Based on those considerations, the court necessarily concluded that the state had been assigned the role of chief implementer and chief interpreter of those particular rules. Adopting the "Step Zero"-like Martin framework merely makes explicit our underlying considerations of Power Resource III, and it explains why this case is different. 3. Brand X In rejecting Auer deference for FERC's Declaratory Order, the majority invokes the Brand X doctrine even though it is inapposite. See Nat'l Cable & Telecomms. Ass'n v. Brand X Internet Servs., 545 U.S. 967,980-86, 125 S.Ct. 2688, 162 L.Ed.2d 820 (2005). That case held that "[a] court's prior construction of a statute trumps an agency construction otherwise entitled to Chevron deference only if the prior court decision held that its construction follows from the unambiguous terms of the statute and thus leaves no room for agency discretion." 1d. at 982, 125 S.Ct. 2688. The majority then asserts that Power Resource lll's "prior reading of FERC's Regulation unambiguously forecloses the interpretation offered by FERC." Majority op. at 397. I disagree. As discussed above, Power Resource 1/1 answered a different question, so even if that case did offer an unambiguous interpretation of the regulation, that interpretation would not bind us. In addition, as Power Resource /// states in a portion quoted in the majority opinion, "[t]he plain text of the1'412 FERC regulation fails to mandate [the] requirement [that Power Resource Group sought]." 422 F.3d at 239. In other words, Power Resource III determined that the plain text of the FERC regulation is silent or at least ambiguous on the issue in question. That means quite plainly that Power Resource III 's interpretation of the regulation cannot bar FERC's later interpretation. In fact, the majority flips Brand X on its head in concluding that a prior judicial construction, which held that the regulation is ambiguous, can be used as a bar against deferring to a later agency construction. Brand X establishes the opposite holding: it ensures that a later agency construction of an ambiguous statute or regulation is entitled to deference in spite of a prior judicial opinion that interpreted the ambiguous provision a different way. Here, the majority in effect punishes FERC for failing to defend its (purportedly identical) position in a prior case, West Penn [Power Co., 7l F.E.R.C. tT 61153, 61,495 (May 8, 1995),1 and its progeny Jersey Central Power & Light Co., 73 F.E.R.C. n 61,092,61,297 (Oct. 17, 1995), and Metopolitan Edison Co., 72 F.E.R.C. fl 61,015, 61,050(July 6, 1995), support the proposition that the FERC regulations grant the states discretion in setting specific parameters for LEOs. Id. at238.ln other words, *FERC has given each state the authority to decide when a LEO arises in that state." /d. at 239 (emphasis added). Therefore, Power Resource III does not stand for unalloyed deference to the state regulatory authority in interpreting FERC's regulations. At best, it stands for deference to the state regulatory authority when FERC has taken no action and has previously announced that it will leave an ambiguous provision to the state agencies to interpret. FERC has offered a contrary interpretation to the PUC here, and so Power Resource III cannot control. Still, Power Resource /// is entirely consonant with the Martin analysis laid out above. The Power Resource III court made its deference determination contingent on whether Congress and FERC intended for the state to make an authoritative interpretation and whether the state acted within the scope of that delegation. In particular, p_5,9t !9:9yyJ!r q.Il qgJg_q th" {ru$Iry_o_lllp '_!glgtq,'r'i'r'.tt,r',',iNext ar-r;?()1i, lhtrrrr:,i-rrr [it:rrlr;r1 No r,]l;rrtrlo orri..trrritl [,j S (]overrtrrret.;t Worhs 2:) Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Util-L.Rep. P-14,913 butas BrandXsaid, "[a]gency inconsistency is not a basis for declining to analyze the agency's interpretation." BrandX,545 U.S. at 981, 125 S.Ct.2688. Ultimately, the majority's point boils down to simply saying that a prior opinion of this court deferred to the PUC in implementing an ambiguous regulation. 4. Superfluity Engendered by FERC's Interpretation The next reason the majority gives for its refusal to defer to FERC is that "the reading advocated by [FERC and] Exelon would render PURPA subsection (dXl) superfluous." Majority op. at 399. The superfluity argument goes as follows: if (dX2) does give an advantage by permitting a qualifying facility to get as-available prices but also an ability to lock in a buyer for a period of time, then no qualifuing facility would choose the (d)(l) route. The majority says this reading makes (d)(l) superfluous because it is "hard to understand why" FERC chose this bifurcated scheme for electricity sales. /d. at 399. But the difficulty of understanding dynamic, complex, and technical fields is not a reason to presume superfluity. Fundamentally, the opinion conflates the desirability of the (d)(2) option with its necessity. That is, although forming a legally enforceable obligation is desirable, that option is not always practically available, in which case (d)(l) provides a complementary or second-best scheme for qualifuing facilities. Thanks in part to rules like the one our court affirmed in Power Resource III, a legally enforceable obligation can be harder to form. Consequently, selling power without a legally enforceable obligation can saye those formation costs. In the event that a quali[ing facility begins producing energy but is barred for ninety days from forming a legally enforceable obligation, (d)(l) would allow the qualifying facility to begin selling its energy without waiting for the formation of the legally enforceable obligation. So, even admitting my ignorance of the intricacies of electricity markets, I still can confidently say that (d)(l) would not be superfluous merely because (dX2) is also an available option for qualiffing facilities.' 5. Concession by Counsel Finally, the majority concludes that it should not apply Auer deference to the Declaratory Order because Exelon's counsel conceded the point at oral argument. Simply put, it is our job, not counsel's, to interpret the regulation correctly and to determine whether deference to an agency is appropriate, so counsel's concession is of no legal moment. *413 The majority points to no case in which such a concession has mattered, and based on my research, the concessions of parties---+ither challenging or acceding to Auer deference-have never had the weight that the majority places on Exelon's concession. ln Elgin Nursing & Rehabilitation Center, this court noted that the party challenging a Department of Labor interpretation of its own informal regulatory document had conceded that the DOL would enjoy Auer deference over a reasonable interpretation. TlS F.3d at492n.5. But instead of relying on that concession, the Elgin court concluded that the DOL interpretation was not entitled to Auer deference because the interpretation was of an informal regulatory document. Id. at 4931, see also Castellanos-Contreras v. Decatur Hotels, LLC, 622 F.3d 393, 401 n. 8 (5th Cir.20l0) (en banc) (noting a concession by the agency as to deference but relying on other grounds for rejecting Auer deference). In sum, the majority does not provide a good reason to refuse to give controlling weight to FERC's interpretation of its own regulation. The majority's deference analysis rests on five grounds: (l) the absence of a FERC interpretation; (2) an application of Power Resource III; (3) an extension of Brand X analysis; (4) a superfluity argument; and (5) the concession of Exelon's counsel.'As I explain above, these grounds do not give good reason to offset the strong basis our court has for deferring to FERC. Therefore, assuming the regulation is ambiguous on the question at issue here, I believe the better approach would be to defer to FERC's reasonable interpretation of its own regulation, as stated in its Declaratory Order. IV. CONCLUSION The majority's opinion does not persuade me that the regulation is ambiguous or that we should not defer to FERC. Using standard tools of interpretation to uncover the FERC regulation's plain meaning, I conclude that the PUC rule conflicts on its face with the FERC regulation. Even if the regulation were ambiguous, I would conclude that our court should defer to FERC's reasonable interpretation of that regulation according to well-established principles of administrative deference. I fear that the majority's approach will not only prevent the realization of the goals that Congress identified when it passed PURPA; it also sets a far-reaching precedent, with '-..11 ,.,,,rp*r., Exelon Wind 1, L.L.C. v. Nelson,766 F.3d 380 (2014) Util. L. Rep. P 14,913 the potential to impact how we review the numerous federal programs that seek to obtain the benefits of both state and federal participation. See, e.g., AT & T Corp. v. Iowa Util. Bd., 525 U.S. 366, I l9 S.Ct. 721,142 L.Ed.2d 835 (1999) (holding that the Federal Communications Commission, not a state agency, had authority to interpret a provision of the Telecommunications Act of 1996); Alaska Dep't of Envtl. Conservation v. E.P.A.. 540 U.S. 461,502,124 S.Ct. 983, 157 L.8d.2d967 (2004) (holding that the EPA could ovemrle the state agency's construction of the term "best available control technology" in the Clean Air Act"). For these reasons, I concur in part and respectfully dissent in part to the majority's opinion. Parallel Citations Util. L. Rep. P 14,913 Footnotes 1 Power Resource Group filed one action under PURPA in Texas state court, and one in federal district court. Power Resource Group subsequently appealed the federal district court decision. Each of these actions is relevant to our discussion in this case. ln order to avoid confusion, we refer to the state court decision as Power Resource l, the district court decision as Power Resource 11 and the subsequent decision by this court on appeal as Power Resoutae ilt. 2 The PUC was created in 1975 when the Texas Legislature enacted the Public Utility Regulatory Act (PURA). The PUC regulates the state's electric and telecommunication utilities, implements respective legislation, and offers customer assistance in resolving consumer complaints. A number of commentators have noted that the intermittent nature of wind supply remains one of the major obstacles to producing wind-generated power. As one report explained: Wind generation has technical characteristics which inherently differ from those of conventional generation facilities. Conventional generation can be controlled, or'dispatched' to a precise output level. The primary energy source for wind generation, however, is inherently variable and incompletely predictable. Thus, electrical output of wind generation plants cannot be dispatched. Drew Thornley, Texas Wnd Energy: Past, Prcsent, and Futurc, 4 Envt'|. & Energy L. & Pol'y J. 69, 76-77 (2009) (quoting Gen. Elect. Energy, Analysis of Wind Generation lmpact on ERCOT Ancillary Requirements 7 (2008)); see a/so John Shelton, Who, What, How, & Wind: The Texas Energy Mafuefs Future Relationship with Wind Energy and Whether lt Will Be Enough to Meet fhe Stafe's Needs, 1 1 Tex. Tech Admin. L.J. 401 , 408-Og (2010) (explaining that 'the wind blows intermittently, and therefore the wind delivers energy intermittently as well"); Governor's Competitiveness Council, 2008 Texas State Energy Plan 16, 28 (2008) (same); Thornley, supra al76 ('Largely because of its intermittent nature, wind is not a baseload resource; thus, it cannot meet a large portion of energy demand."). The PUC has three commissioners who make final determinations on the PUC's rules and orders. Before the commissioners hear a dispute, it may first be heard by an administrative law judge. The commission retains the power to alter the administrative law judge's findings of fact or conclusions of law before issuing an order. See Tex. Gov't Code Ann. $ 2003.049(9). FERC's Letter states that FERC's Regulation does not contain the words 'firm" or "non-firm".... This is contrary to the language of the regulation which provides that "[e]ach qualifying facility shall have the option either: to choose the seclion 292.304(dxl) method of sale, or the section 292304(dX2) method of sale;' in'conctusion, we find that the Texas Commission's order, limiting the award of a legally enforceable obligation to only those Qualifying Facilities that provide "firm" power, is inconsistent with our regulations implementing PURPA. Under our regulations, [Exelon] Wind has the right to choose to sell pursuant to a legally enforceable obligation, and, in turn, has the right to choose to have rates calculated at avoided costs calculated at the time that obligation is incurred. JD Wind 1 , LLC, 129 FERC 61 ,148 (Nov. 19, 2009). PURPA's " 'multiJayered' enforcement provisions" give federal courts exclusive jurisdiction over challenges to a state's implementation of PURPA if two conditions are met: (1) the party bringing the claim must first petition FERC to bring an enforcement action, and (2) after FERC declines to bring such an action, the party may file a complaint which ',nr;.,t1a,,'rrNext i!).-l01ir llrlr.rrsorr lltrrtcr:, No r,li,.rrn 1o olorrrai l.l Ii (-lovt,r'rrrli.,i'r1 Works;') ti Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 challenges the state regulations as an illegal implementation of PURPA and the FERC regulations. Power Resource lll, 422 F .3d at 234-.35; see also 16 U.S.C. S 824a-3(h)(2XA)-(B). There is no dispute that the first condition is met here. Exelon petitioned FERC and FERC declined to initiate an enforcement action, although FERC did issue a declaratory order. 7 This result is supported by other courts that have had occasion to interpret PURPA's jurisdictional grant. See Occidental Chem. Corp. v. La. Pub. Seru. Comm'n,494 F.Supp.2d4O1,411 (M.D.La.2007) (applying the reasoning fromthefederal districtcourtin PowerResourcel/); Mass. lnst.of Tech.v.Mass.Dep'tof Pub.Utils.,941F.Supp. 233,238 (D.Mass.1996); Greensboro Lumber Co. v. Ga. Power Co., il3 F.Supp. 1345, 1374 (N.D.Ga.1986), affd, 844F.2d 1538 (11th Cir.1988). 8 Discussion between the PUC Commissioners on the record of the hearing confirms that the PUC Order had a limited scope: CHAIRMAN SMITHERMAN: Well, I think the problem here is that there's no definition of "not readily available power." So that sort of leads us into a confusing state. COMM. NELSON: I think we just want to clarifo it so that in the future, if somebody came in and could meet that standard that we're not being preclusive. iibuU. ANDERSON: Because I could envision in the future wind, for a variety of reasons, could be readily available whether through storage or geographical diversity or mixed with solar. COMM. NELSON: Right. And it really depends on the area of the state- COMM. ANDERSON: lt really does. COMM. NELSON:-because, you know, along the coast the pattern is totally different and it blows at peak times. 9 The PUC promulgated a predecessor to PUC Rule 25.242 in 1981. There have been several intermediate iterations of the Rule since then, none of which impact the outcome of this case. See Act of Apr. 10, 1981, 67th Leg., R.S., ch. 31, S 2, 1981 Tex. Gen. Laws 70, 71 (codified at Tex. Utils. Code Ann. $ 35.061). 10 The Supreme Court's decision in Chevron U.S.A., lnc. v. Natura/ Resources Defense Council, lnc., requires courts to conduct a two-step inquiry when determining whether to defer to an agency's interpretation of a statute that it administers. 467 U.S. 837, 104 S.Ct. 2778,81 L.Ed.2d 694 (1984). Under the first step, we ask "whether Congress has directly spoken to the precise question at issue" or whether the statute is ambiguous. ld. a|84243, 104 S.Ct. 2778. ll Congress has resolved the question, then the clear intent of Congress binds both the agency and the court. /d. Under the second step, if "the statute is silent or ambiguous with respect to the specific issue, the question for the court is whether the agency's answer is based on a permissible construclion of the statute." /d. at 843, 104 S.Ct. 2778. Under this second step, we defer to the agency's interpretation if it is a reasonable interpretation of the statute." Entergy Corp. v. Rivetueeper,lnc.,556 U.S. 208, 218,129 S.Ct. 1498, 173L.Ed.2d 369 (2009). 11 Appellants argue that we should read FERC's Regulation narrowly to avoid Tenth Amendment issues that might arise from forcing Texas to implement certain regulations. As noted in Section ll.C.ii, supra, this narrow interpretation is not necessary to avoid Tenth Amendment issues here. Texas opted to have the PUC issue rules to enforce PURPA, rather than simply opening its courts to hear PURPA disputes. Having done so, Texas (and the PUC) may not pass regulations that are inconsistent with FERC's regulations. See Frd. Fed. Sav. & Loan Assh y. de la Cuesta. 458 U.S. 141, 153, 102 S.Ct. 3014,73 L.Ed.2d 664 (1982) ("Even where Congress has not completely displaced state regulation in a specific area, state law is nullified to the extent that it actually conflicts with federal law."). Cf. New York,505 U.S. at 166-€7, 1 12 S.Ct. 2408; Nat'l Collegiate Athletic Assh v. Govemor of N.J., 730 F.3d 208, 228 (3d Cir.201 3), cerf. denied,2014 U.S. LEXIS 4343, and ceft. denied,2014 U.S. LEXIS 4345, and cert. denied,2014 U.S. LEXIS 4346 (June 23, 2014). 12 The PUC's regulations provide the following definitions: (5) Firm power-From a qualifying facility, power or power-producing capacity that is available pursuant to a legally enforceable obligation for scheduled availability over a specified term. (9) Non-firm power from a qualiffing facility-Power provided under an arrangement that does not guarantee scheduled availability, but instead provides for delivery as available. 16 Tex. Admin. Code $ 25.2a2G)$), (9). 13 Nor did our holding in Power Resource l// depend, as the dissenting opinion suggests, on the fact that a state regulatory agency is entitled to deference only when FERC is silent on the issue. Rather, it was based on a recognition of the careful balance of authority between the federal and state authority that Congress drew when it implemented Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 over decisions delegated to state regulatory agencies. Such a shift in power might raise the sort of "troublesome" Tenth Amendment concems expressed by the Supreme Court in FERC v. Mississtppr, 456 U.S. at 759, 102 S.Ct. 2126.The dissenting opinion does not address the serious constitutional concerns that could flow from its approach, and we are hesitant to wade unnecessarily into such murky waters. We therefore reject the dissenting opinion's interpretation of Power Resource lll. 14 ln Auer the Supreme Court applied the same two-step analysis lrom Chevron and explained that agency interpretations of their own regulations are entitled to even greater deference. 519 U.S. a|457,117 S.Ct. 905. 15 The dissenting opinion argues that even though Exelon conceded that FERC's Letter advocating this interpretation was not entitled to deference under Chevron and Auer, we should still defer. ln support of this conclusion, the dissenting opinion relies on a dissent from an en banc opinion of this court, Casfe//anos-Contreras v. Decatur Hotels, LLC, 622 F.3d 393, 397 (sth Cir.20't0) (en banc), and our decision in Elgin Nurcing & Rehabilitation Center v. U.S. DepT ol Health & Human Serys., 718 F.3d 488, 492 (Sth Cir.2013). A dissenting opinion is, of course, not binding. E/grn did not address the issue of whether a party may concede that an interpretation is not entitled to deference. lnstead, the court in Elgin gave an interpretation the proper level of deference when the two parties disagreed on the appropriate level of deference. 718 F.3d a|492. We therefore see no reason why we should not accept Exelon's concession here. 16 While the Supreme Court's decision in Brand X specifically addressed Chevrcn deference, our sister circuits have applied this same framework when interpreting regulations. See, e.9., Levy v. Steding Holding Co., LLC,544 F.3d 493, 502 (3d Cir.2008) ("We see no reason why these principles should not apply equally to the interpretation of a regulation."). 17 Here, Exelon has not given an adequate explanation for what independent role (d)(1) could play under its interpretation of the Regulation. Only the dissenting opinion offers some explanation of what role (d)(1) might serve under Exelon's interpretation. We cannot determine that a provision is nof rendered superfluous by a party's reading simply because there may be some theoretical situation, not identified or even articulated by either party, that would give it effect. 18 lndeed, as Occidental notes, the PUC is far from alone in requiring a Qualifying Facility to deliver firm power in order to form a Legally Enforceable Obligation. According to Occidental, seven other states place similar requirements on Qualifying Facilities. That is, each cogenerator and small power producer that FERC finds meets certain operating and efficiency standards under 18 C.F.R. $S 292.203{7. As one scholar recently observed, "State implementation of federal law is commonplace, but has been largely ignored by the interpretive doctrines of legislation and administrative law." See Abbe R. Gluck, /nfrastatutory Federalism and Statutory lnterpretation; Sfafe lmplementation of Federal Law in Health Reform and Beyond, 121 Yale L.J. 534, 534 (2O11). The Martin test parallels the Supreme Court's Chevrcn "Step Zero" analysis, which asks whether Congress delegated authoritytomakeinterpretationscarryingtheforceof law.See United Sfatesv. Mead,533 U.S.218,226-27,121 S.Ct. 2164, 150 L.Ed.2d 292 (2001); see a/so Gluck, supra, at 599 ("An extension of Mead, or something like it, to include state implementers-that is, to take into account the specific ways that Congress utilizes state implementers to determine the level of deference the various concurrent implementers should receive-rnay not be a radically different approach than the one currently in use."); Jacob E. Gersen, Ovedapping and Undedapping Jurisdiction in Administrative Law, 2006 Sup.Ct. Rev. 201 ,219,223-24 (stating that deference questions in a statute administered by multiple agencies is "best treated as a Step Zero inquiry" and discussing Maftin as an illustration of that inquiry). Under that analysis, courts determine where to place a single agency's interpretation of a statute along a spectrum of deference. See Mead, 533 U.S. a|236-37, 121 S.Ct. 2164. Courts look for that "[d]elegation of [interpretive] authority ... in a variety of ways, as by an agency's power to engage in adjudication or notice-and-comment rulemaking, or by some other indication of a comparable congressional intent." ld. a|227,121 S.Ct. 2164.Ihe analysis, then, is attentive to the structure and text of each specific statute. ln addition, although Maftin did not require it, we might expect to only give deference to an agency interpretation when it colors inside the boundaries Congress gave it-i.e., when it is within the scope of its delegation. Mead, 533 U.S. at 227,121 S.Ct. 2164. With regard to its enforcement powers, FERC has reasonably interpreted its enforcement power to include the ability "to terminate a controversy or remove uncertainty" through the use of declaratory orders. 18 C.F.R. S 385.207(a) (interpreting enforcement authority under the Federal Power Act); see 16 U.S.C. S 824a-3(h)(2)(A) (directing FERC to enforce state implementation of its rules as a 'rule enforceable under the Federal Power Act"). Therefore, FERC's Declaratory Order is a valid exercise of FERC's enforcement powers under the theory ?5 Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014) Util. L. Rep. P 14,913 that the greater enforcement power neoessarily includes the lesser authority to issue declaratory orders. 5 The "lette/'that FERC sent Exelon is also known as a "Declaratory Ordef-the preferred nomenclature. See, e.g., lndus. Cogenemtorc v. FERC, 47 F.3d 1231 (D.C.Cir.1995). 6 Even this statement of limited deference is somewhat confusing. The deference applies to conditions on the formation of both contracts and legally enforceable obligations, which are emphatically not contracts. 7 The majority acknowledges that this is a satisfactory explanation for (dX1). See Majority op. at 399 n. 17. 8 The majority also rejects Auerdeference to FERC on the ground that it occasions a "shift in power [that] might raise ... 'troublesome'Tenth Amendment concerns.' Majority op. at 396 n. 13. The majority does not elaborate on what those constitutional concerns might be, so it is impossible for me to respond to the majority's statement. ln any case, the majority does not rely on this constitutional avoidance argument for its deference holding. End of Document O 2015 Thomson Reuters. No claim to original U.S. Government Works V/estlawNexf O 2015 Thomson Reuters No claim to origrnal U S $overnmenl Works 27 rcffi* Inteorated Resdurce Plan 2015 SAFE HARBOR STATEMENT This document may contain forward-looking statements, and it is important to note that the future esults could differ materially from those discussed. A full discussion of the factors that could cause future results to differ materially can be found in ldaho Poweri lilings with the Securities and Exchange Commission. SEffi*" An IDAC0RP Company June 2015 lnteqrated Resdurce ACKNOWLEDGMENT Resource planning is an ongoing process at ldaho Power. ldaho Power prepares, files, and publishes an lntegrated Resource Plan every two years. ldaho Power expects that the experience gained over the next few years will tit<ely rp-{ifrify=..the 20-year resource plan presented in this document. an 2015 - -:.::. ,iii::!s' ,i.ttpu[ commeh li{iid discussion provided by the lntegrated Resource 4fEndviso4{$$uncil and other concerned citizens and customers.,fl :ran.Advrsor,i{f l,' 4* ai |J1tlr' ffikes approxffiely one year for a dedicated team of individuals at ldaho ::1r:rlllr ,rt]luf.airt*r\*,-- r-t^--^1^i h^-^..--^ hI-.^ TL^ rl-L^ n--,-^-t^^-:-lll!,1.?^ ,,ffil "mmru.Wne lntegrated Resource Plan. The ldaho Powerteam is'q , compikdb-tffiilividuals that represent many different departments within it:nll:-: ',.::::::.::::::::,.:1 . ii i: il ldaho Poli,iiv innitd.outsidq partitiiidtion to help develop the 2015 l n teg rateiL:fi*o u rsi Pla i. ldiho power va l ues the knowledgeable ;:::gut, comm6hglffid discussion provided by the lntegrated Resour q" .Ol;r-.t*L,.,ii::":f; LUlllyllJsu vl"'IllulvluuqlJ LllqL lsPlEJSIlL lllolly ulltglstlL Usyol LIllEtlL) vvltllltl b" _:rl_or preparing forecasts, working with the advisory council and the public,'ru "W o:tt*,:,:,,:n" anafvses necessary:o prepare the resource plan. i+ ldaho Power looks forward to continuing the resource planning process with-ii customers, public interest groups, regulatory agencies, and other interested' parties. You can learn more about the ldaho Power resource planning process at www.idahopower.com. SAFE HARBOR STATEMENT This document may contain forward-looking statements, and it is important to note that the future results could differ materially from those discussed. A full discussion of the Iactors that could cause future results to differ materially can be found in ldaho Power's filings with the Securities and Exchange Commission. @ Printed on recycled paper ldaho Power Company Table of Contents .lli.W Greenhouse Gas Emissions............. ........:':.............4 2. Political, Regulatory, and Operational Issues. ..................13 Idaho Energy P|an........ .............13 Idaho Strategic Energy Alliance ..................14 FERC Relicensing .....................14 Idaho Water Issues...... ..............16 *M Proposed P i lot Proj ects .......................,ffiF":u:r.. 't";1' ''" ''.bt ' Solar PV to Address Distribution pti€iler V6ifi-^: ...........6 ...............6 ...............6 2015 tRP Page i Table of Contents ldaho Power Company Public Utility Wholesale C Market Purchases 1t:.ll DSM Program Performance........... ..............43 Energy Efficiency Performance................ ................43 Demand Response Perfonnance................ ...............44 Committed Energy Efficiency Forecast..... .....................45 Committed Demand Response Resources ......................48 Page ii 2015 tRP ldaho Power Company Table of Contents Non-Cost-Effective DSM Resource Options ..................48 Additional Demand Response... ...................49 Energy Efficiency Working Group........ ......49 Conservation Voltage Reduction .................50 5. Supply-Side Generation and Storage Resources.. .............53 Renewable Resources @ ........53 So1ar.......... ...,i,]j4...... .......s3 ....................56 | : ::....:.:::.:.::::.Conventional Resources................. ..............';..-- ............57 ''4.::a:;:a: Coal Resources.............. Battery Stora 6.Tra .l'. Past'"ffilPresent Transm,i$ion...... ...............65 '"8;tiii/i.?* $ri'TransmisiiiffirPlanningllEftocess............ ........66 {.'j.:-, *-*"' Local Trantmis;ffi Planning Process ......................66_.itlr Regional Transmission Planning ...........67 Interconnection-Wide Transmission Planning. .........67 Existing Transmission System .....................68 Idaho-Northwest Path........... .................68 Brownlee East Path .............69 2015 tRP Page iii Table of Contents ldaho Power Company 7. Planning Period Forecasts... ................:',...,...'79 Generation Forecast fui &LMWeather Effects....... ...Wr*- ffi' ....................80 EconomicEff-ects.....W.'.,..**%........'!..::.1:a= ..taj.a:ti,rifui;;:i74$ atu..., -d.ffi *suw.l Peak-H ou r Load Foreca.s$ .,,...................r ..{}ffii,rllliita A v e ra ge- E, n..gy L oad lF6*r.. ir{ Page iv 2015 tRP Load and Resource Balance..... ....................99 8. Portfolio Selection ....................104 Pofifolio Design ......................104 Portfolio Design and Selection ................ .....................105 Status Quo Portfo1io............... ..............106 North Valmy Retirement Year-End 2019 Portfo1ios...................... . .....107 North Valmy Retirement Year-End 2025 Portfolios ............ ...,,r:.a;!l:;:-..... .....1 l0 , .'11,lr.r:1::::,, North Valmy Staggered Retirement Year-End 2019 (Unit,,$i'i;na; ,?#,.5iEnd2025 (Unit 2) Portfolios.. ..- .':'i'.............:#:#i"--.................1 12 Jim Bridger Staggered Retirement Year-End 2023 (Unit l) and Year-Endi20p*2 (Unit 2) Portfolios... .......................:.........................,.:?.............1l3 -*.C,*.:-Jim Bridger Staggered Retirement Year-End ZWful\lryi.p,1i1fffluend Year-End 2028 (Unit 2) Portfolio.... ...........i,;;.................. .............114 qlI,I Jim Bridger Staggered Retirement,r$,9afiEqd 2023 (UhW and Year-End 2032 (Unit 2), North Valmy Retirement Y,/:L EidiAgZJ eortffill$ip. ...................115 AlternativetoBoardmantoHeming$ffie"nffi*-................... .......116 North Valmy Staggerg[ffi m"n v 02l ru;; l) and Year-8nd2025 (Unit 2) Portfolio--...ff).....)lii'............. jI.,,....... ......................1 l8;:;;. ,i;#i ',i!:"aiL Portfolio Desig&.$-um^ary,ij:,,1,_rr**u.rrr,.,,...i"i .... ....119y ";:affiduffffiK"..l t 9. Modeling Analysis and Risulti:.'............"'.I.:'::!: . .............121 ldaho Power Company Table of Contents CAA Seoti'on:: -,' |, Systeft$l-V.ide Wt.q;;ffised Compliance ..................123 Emissions iAiegiiiy compliance utilizing the EPA's compliance building blocks ..........123 Baseline CAA Section I I l(d)..... ..........124 CAA Section I I I (d) sensitivity analysis - results .....................126 Stochastic Risk Ana1ysis.............. .,............129 Portfolio cost - assessment of year-to-year variability.............. ...................131 Tipping-Point Analysis ...........132 2015lRP Page v Table of Contents ldaho Power Company Table 1.1 Table 1.2 Table 2.1 {:." :,' . 4ti7",V' st oF,#lBLEs Historicalffiitf, Ioad, and customer data........... ........26 :aJxisting reso$fces ......................30 , ou,o ..,,n,u,!ffi, rabteWW* Table3.2wtfffi;.;=:.::j.;:!i.i.l:a Ztlitil Table 3.3 ":&ffi.gteteri]lS,Service customer count and generation capacity as of May l,201!iffi.r,....................... ................36 ::::::::::::u':i4. Tabfe 4.1 Current portfolio of demand response programs .............44 Table 4-2 Total energy efficiency current portfolio forecasted effects (2015-2034)(aMw)...... ...............47 Table 4.3 Total energy efficiency portfolio cost-effectiveness summary..............................48 Table 5.1 Solar capacity credit values .......55 Table 6.1 Available transmission irnport capacity. .......70 Page vi 2015 tRP ldaho Power Company Table of Contents Table 6.2 Table 6.3 Table 7.1 Table 7.2 Table 7.3 Table 7 .4 Table 7.5 Boardman to Hemingway capacity and permitting cost allocation ..-...................71 Transmission assumptions.............. ..............77 Load forecast-peak hour (MW) ..................83 Load forecast-average monthly energy (aMW) ............86 July monthly average energy deficits (average MW) by coal future with existing and committed.supply- and demand-side resources 170t1' percentile water and 70t" percentile load) ....... ................................. 102 I ,!. December monthly average energy deficits (average M, UV coal future with existing and committed supply- and demand-qjde ibsources (70th percentilewaterand70thpercentileload)...'.'......'i... July monthly peak-hour capacity deficits (MSD by coal future with existing and committed supply- and dem-a,{1ffi1'iide resources (90th " percenti le water and 95th percenti Ie load) r 1..............!...... Table 7 .6 Decernber rnonthly peak-hour capacity deficits (MW) by coal future with Table 8.1 Table 8.2 Table 8.3 Table 8.4 Table 8.5 Table 8.6 Table 8.7 Table 8-8" Table 8.9 Table 8.10 Table 8.1 I Table 8.12 Table 8.l3 Table 8.l4 Table 8.15 2015 tRP Page vii Table of Contents ldaho Power Company Table 8.16 Table 8.17 Table 8.1 8 Table 8.19 Table 8.20 Table 8.21 Table 8.22 Table 8.23 Table 8.24 Table 8.25 Table 9.1 Table 9.2 Table 9.3 Table 9.4 Table 9.5 Table 9.6 Table 10.1 Figure 1.4 COzemissions of the largest 100 utilities ..........................5 Figure 2.1 Brownlee historical and 201 5-2034 forecasted April - July inflow .....................1 8 Figure 3.1 Historical capacity, load, and customer data ........... ........26 Figure 3.2 2014 Idaho Power system nameplate by fuel type (MW) (owned resources plus purchased power) ...............28 Page viii 2015 tRP ldaho Power Company Table of Contents Figure 3.3 Figure 3.4 Figure 3.5 Figure 4.1 Figure 4.2 Figure 6.1 Figure 6.2 Figure 6.3 Figure 6.4 Figure 7.1 Figure 7.2 Figure 7.3 Figure 7.4 ' '-:' Figure 7.5 3O-year leveliz-edffifl-fi-i1y (fix od,*ts .................95 Figure 7.6 3O-year ley,gI*ZCd cost d-fllproductiddlrct stated capacity factors). .......96 ! --i'Figure7.7 CaOaciBlifu! of n"Y lv==s,,,,i,..4geS5urces, online 2020.......... ........97 .&"j -:Figure 7.8 Energy costr&.frNtd supply-side iesources .......................98 a1gur"ffi. Exceedancgr,$faph of standard deviations.. ....................132 Figure 9.3all ipping point analysis results .....................133 Figure 9.4 -l6iUitity neeO (SOO MW solar, existing wind, I % likelihood) .............. ...........143 tit ,::=Figure 9.5 Syst6il*gulation......... ............144 Figure 9.6 Regulation violations, spring 2012.......... ......................145 Figure 9.7 Regulation violations, summer 2012.......... ...................145 Figure 9.8 Regulation violations, fall2}l I ............... ......................146 Figure 9.9 Regulation violations, winter 201I12012 ................ .......146 Figure 9.10 LOLE (hours per year).... .........148 2015 tRP Page ix Table of Contents ldaho Power Company LIsT oF APPENDIcES Appendix A-Sales and Load Forecast Append ix B-Demand-S ide M anagemen t 2012 Annual Report Append ix C-Techn ical Appendix GlosseRY oF Acn AC-Alternating Current A/C-Air Conditioning ACOE-United States Army Corps of Engineers AFUDC-Allowance for Funds Used Dur akW-Average Kilowatt t\ :t = 'l:r:11:=:i,oo-WAirAct of leY E. CAES-CUfite rAdvance€€nergyStudies CAMP-Comprffinsi ve $$'ui fer Management Plan ::CAP-Commun ity Adtisory Process C BM-Capacity Benefi t Margin CCCT-Combined-Cycle Combustion Turbine CCR-Coal Combustion Residuals cfs-Cubic Feet per Second Page x 2015lRP ldaho Power Company Table of Contents CHP-Combined Heat and Power Clatskanie PUD-Clatskanie People's Utility District CO2-Carbon Dioxide CREP-Conservation Reserve Enhancement Program DC-Direct Current DOE-Department of Energy DSM-Demand-Side Management EEAG-Energy Efficiency Advisory Group i'i EIA-Energy Information Administration ,,,;ffio .rnil.ll.#r 1fri16'' ..::::11''+ EPA-Environmental Protection Agency '%, EPRI-Electric Power Research Institute q# ,iT,r ESA-Endangered Species Act of I973 Wd)ti::rr::====-- =',/ntli.. ""::= ':':j.:l;!r.:1. .a;;j.ll" ::::::.:::!::i:.' ESPA-Eastern Snake River Plain Aquifer ;::4 t:=:-":::'-:: rri"rqrrr r ryurrvr ::1,= ..;.:;;;;;, rr:l:.i: .",,, . 'lif"z;;:;'; F-Fahrenheit FCA-Fixed-Cost Adj FCRPS-Federal Columb S FEIS-Final tement MISSION Hg-Mercury HRSG-Heat Recovery Steam Generator IDWR-ldaho Department of Water Resources IGCC-lntegrated Gasification Combined Cycle INL-ldaho National Laboratory 2015 tRP Page xi Table of Contents ldaho Power Company IOER-ldaho Office of Energy Resources IPUC-ldaho Public Utilities Commission IRP-lntegrated Resource Plan IRPAC-IRP Advisory Counci I kV-Kilovolt kW-Kilowatt kWh-Kilowatt-hour lbs-Pounds LOLE-Loss of Load Expectation LTP-Local Transm ission Plan m2-squa." meters mm-Millimeter MMBtu-Million British Thermal Units MW-Megawatt MWh-Megawatt Hour NO*-Nitrogen Oxide NPV-Net Present Value NWPP-Northwest Power Pool NREL-National Renewable Energy Laboratory Page xii 2015 tRP ldaho Power Company Table of Contents O&M-Operation and Maintenance OATT-Open Access Transmission Tariff ODEQ-Oregon Department of Environmental Quality ODOE-Oregon Department of Energy OPUC-Public Utility Commission of Oregon PCA-Power Cost Adj ustment PM&E-Protection, Mitigation, and Enhancement PGE-Portland General Electric PPA-Power Purchase Agreement PURPA-Pzblic Utility Regulatory Policies Act of I PV-Photovoltaic QF-Qual ifying Facility RCRA-Res ource C onservation ond Re cove REC-Renewable Energy RES-Renewable MP-Request for RH BART le Retrofit Technology RPS_ SCCT_Si SCR-Selective SOz-Sulfur Dioxide SRBA-Snake River Basin Adjudication TEPPC-Tran sm ission Expansion Plann in g Policy Comm ittee UAMPS-Utah Associated Mun icipal Power Systems USFS-United States Forest Service le Portfoli 2015lRP Page xiii Table of Contents ldaho Power Company WECC-Western Electricity Coordinating Council W-Watt Page xiv 2015lRP ldaho Power Company 1. Summary 1. SuwuuARY lntroduction The 2015 Integrated Resource P/rrr (lRP) is ldaho Power's l2tl'resource plan prepared to fulfill the regulatory requirements and guidelines established by the Idaho Public Utilities Commission (IPUC) and the Public Utility Conrmission of Oregon (OPUC). The Idaho Power resource planning process has fbur prirnary goals: l. Identify sufflcient resources to reliably serve the growing dernand for energy within the Idaho Power service area throughout the 2}-year planning period=;,,,- 2. Ensure the selected resource porttblio balances cost, tiSa, and env I concerns. 3. Give equal and balanced treatment to supply-side resources, demand-side itbasures. and transmission resources. 4. Involve the public in the planning process in a meanin!fuI way. ,] The 2015 IRP evaluates the 20-year planningperiod frorn 20ts,'thrgugh2034. During this period load is forecasted to grow by 1 .2% per year fur aVbrage energy dEinand and I .5%o per year for peak-hour demand. Total customers are expected to increase to 7l 1.000 by 2034 from 515,000 in 2014. Additional cornpany-owned resources will be needed tdileet the increased demands. Idaho Power owns and ope s l7 hydroelectric'projects. three natural gas-fired plants, one diesel-powered plant, and$ares owneiship in th -coal-fired facilities. Hydroelectric generation is the crown je.ryel of Idaho Power's generation fleet. The hydroelectric plants are subject to variable water'41rCIweather conditions. Public and regulatory input encouraged Idaho Power to adopt more conservative planning criteria beginning with the 2002 IRP. Idaho Power continues to dev.Elop more conservative streamflow projections and planning criteria for use in resource ade@acy planning. Idaho Power has an obligation to serve customer loads regardless of water 411$;weather conditions. Further discr-rssion of Idaho Power's IRP planning criteria can be lound in Chapter 7. Other resources used in the planning include dernand-side managernent (DSM) and transmission lines. The goal forDSM programs is to achieve prudent, cost-effective energy efficiency savings and provide an optimalarnount ot'peak reduction frorn demand response programs. Idaho Power also strives to provide customers with tools and inforrnation to help them manage their own energy usage. The company achieves these objectives through the implementation and careful management of incentive programs, and through outreach and education. The Idaho Power resoLlrce planning process also evaluates additional transmission capacity as a resource alternative to serve retail custorlers. Transrnission projects are often regional resources and their planning is conducted by regional industry groups, such as the Western Electricity Coordinating Council (WECC) and the Northern Tier'fransmission Group (ltlTTG). Idaho Power coordinates local transmission planning with the regional forums as wellas the 2015 tRP Page 1 1. Summary ldaho Power Company Federal Energy Regulatory Commission (FERC). Idaho Power is obligated under FERC regulations to plan and expand its local transmission system to provide requested firm transmission service to third parties and to construct and place in service sufficient transmission capacity to reliably deliver energy and capacity to network customersl and Idaho Power retail customers.2 Timing of new transmission projects are subject to complex permitting, siting, regu latory and partner coordination. Public AdvisorY Process ",,"'r'Idaho Power has involved representatives of the public in the resource plarming process since the early 1990s. The public forum is known as the IRP Advisory CouffilThe IRP Advisory Council generally meets monthly during the development of the resoulcq,g[an, and the meetiCouncil generally meets monthly during the development of the rffit$Y€qffin, and the meetings are open to the public. Members of the council include political,:€fifiironrffS#tal and customer repreientatives, as well as representatives of other public-inte.1=st groups. Muriy,rn.rbers of the public pafticipate even though they are not members ' IRP Advisory Cffin1911. planrl in g process fortfl4hferSome individuals have participated in Idaho Power's rgffice planry,ing process fofr$9er 20 years. A list of the 2015 IRP Advisory Council ffiffers can b-e"ffoun d in Appendix C- Technical Appendix. W* ...u*l '' Idaho Power conducted l2 IRP Advisory Council meetings, including a resource portfol io design workshop. Public working group meetings to address the specific topics of ene,lgyaddress the spectllc toprcs oI energJ effi ciency,solarresources,an$,iffe=-..:111 study of coal resources *gp,f,l'd-lio h;f$|E In addition, ldaho Power ted a trip to the Swan Falls hl project for participffigof p ro c e ss. I d aho.:; d{,ttf:'p the field ttjEshared inftI lon variety;f pics,includi vol The IRP Advisory Council visits Swan Falls Dam. tran sm i'fti64 recreation, aviffi; b iolo gy, archaeologflrandSnakeRiv.----------------fl f water supply. f ield $iP'p-prticipai s were also led on a tour of the Swan Falls hydroelectric power plant, and the Swaii-'f 4lls,museum. Idaho Power has a regulatory obligation to construct and provide transmission service to network or wholesale customers pursuant to a FERC tariff. Idaho Power has a regulatory obligation to construct and operate its system to reliably meet the needs of native load or retail customers. Page 2 2015 tRP ldaho Power Company 1. Summary Idaho Power believes working with rnembers of the IRP Advisory Council and the public improves the lRP. Idaho Power and the members of the IRP Advisory Council recognize that flnal decisions on the resource plan are made by ldaho Power. I-lowever, Idaho Power encourages IRP Advisory Council members and members of the public to submit comments expressing their views regarding the20l5 IRP and the resource planning process in general. Following the filing of the final resource plan, Idaho Power presents the resource plan at public meetings in various communities around the company's service area. In addition, Idaho Power staff present the plan and discuss the planning process with various civic glaups and at IRP Methodology ,,-',, -',,,,. " '.=.. Preparation of the Idaho Power 2015 IRP began with the forecast of future c6.StO er demand. Existing generation resources, demand-side resources. and transrnission import capacity are combined with customer demand to create a load and resource balance for energy zind'capacity. Idaho Power then evaluated new energy efficiency prdfims, ur+, f|i.& expansion of existing programs to revise any energy and capacity deficits. FiH61Jy, Idaho Power designed and analyzed supply-side and transmission resource portfolios to addre,ss"the remaining energy and capacity deflcits. ;- ,ri Idaho Power evaluates resources and resour0e p6ff6=I using a financial analysis. Idaho Power evaluates the costs and benefits of each resource type. The financial costs include construction, fuel, operation and maintenance (OtM), necesiiry.= smission upgrades, and anticipated environmental controls and e=m.i.!,31,6'@sts. The financial benefits include economic resource operations, projected mark es, a@he rnarket value olrenewable energy certificates (REC). - ,! "n Idaho Power is part of,tffiHarger norShwg;tfigendwestern regional energy markets, and market prices are an important e6ffi.99n9,,$filUfeV6{ttatift€hergy purchases and sales. Idaho Power faces transmission imp,o-.,,ff,gonstrdiffid at times of peak customer load must rely on its own generation rg;p[#tl$ir6.Uq.fdles'3-.,6. e regional market prices. Likewise, there are times when the generation cciiihected t ,Idaho wer system exceeds customer demand and the transmission export@1city, and the company must cunail generation on its system. An additioialir,transmission connection to the Pacific Nofthwest has been pan of the Idaho Power preferred redoiiiceportfolio since the 2006 IRP. By the 2009 IRP, ldaho Power determined the approximate con-figura"tibn-nd capacity of the transmission line, and since 2009 the addition has been called the Boardman to Herningway Transmission Line Project (B2H). Idaho Power again evaluated the Boardman to Hemingway transrnission line in the 2015 resource plan to ensure the transmission addition remains a prudent resource acquisition. Similar to the 2013 IRP, Idaho Power analyzed various resource portfblios over the entire 20- year planning period in the 2015 IRP. The analyzed portfblios in the 2015 IRP add resources in 2020 at the earliest underceftain scenarios, and consequently Idaho Powerdetermined it is practical to once again consider the 2l-year planning period in total. 2015 tRP Page 3 1. Summary ldaho Power Company Greenhouse Gas Emissions Idaho Power owns and operates l7 hydroelectric projects, three natural gas-fired plants, one diesel powered plant, and shares ownership in three coal-fired facilities. Idaho Power's carbon dioxide (COz) emission levels have historically been well below the national average for the 100 largest electric utilities in the United States (US), both in terms of total COz emissions (tons) and COz emissions intensity (pounds per MWh generation). In 2012, Idaho Power and Ida-West Energy (a non-regulated subsidiary of IDACORP, Inc.) together ranked as the 38th lowest emitter of CO2 per MWh produced and the 36th lowest emitter of CO2 by tons of erni;sions among the nation's 100 largestelectricityproducers,accordingtoaMay20l4collaboiativereportusing publicly reported 2Ol2 generation and emissions data.3 Figures L3 and 1"4 show ldaho Power's relative position to other utilities in terms of COz emissions intensffirdhd;fu overall quantity of CO2 emissions. According to the report,. out of the 100 companieg named;=T'ddo Power and Ida- West Energy together ranked as the 52'0 largest power producg,r based on foSSiillfu,pl, nuclear, and renewable energy facility total electricity generation,Tffifl# li.. Figure 1.3 COz emissions intensity of the Iargest 100 utilities ' M. J. Bradley & Associates. (2014). Benchmarking Air Ernissions of the 100 Largest Electric Power Producers in the United States. ! r,soo oq Noo o !5 r,ooooc Utility Page 4 2015 tRP ldaho Power Company 1. Summary 160,000,000 140,000,000 120,000,000 't00,000,000 No(,b ao,ooo,ooo coF 60,000,000 40,000,000 20,000,000 Figure 1.4 In September 2009,ldaho Power's Board of Ni;fi-+i#'!u id e I in es to red u ce *s-ions intensity from 2010 through 2013 to Ofle.,Y"nissions intensity of 1,194 pounds per MWh. ty ffituates with streamflows and production souffi, the company has adopted an average years. Currently, gerl.e,f.*l d emiCs[,94s from company-owned resources are included in the COz intensity caldition. The company_'s progress toward achieving this intensity reduction goal and additionafi formation on ldaho Powei's COz emissions are reported on the company's website: CO2 EmisSions Intensify R€duction Goal. Information'?.1-i d to ldaho P-ower's COz emissions is also available through the Carbon:,Disclosure Proftd.tr:.A wWV.Cdproject.net and on the Idaho Power website: Emissions. In November 201Z, the goard of Directors approved the extension of the company's 201 0 to 2013 goal for reducing COz emission intensity. The goal as restated in2012 is to achieve COz emission intensity l0 to 15 percent belowthe 2005 CO2 emission intensity from 2010 to 2015. A second extension of the goal approved by the Board of Directors in May 2015 sets a target CO2 emission intensity of I 5 to 20 percent below the 2005 COz emission intensity for 201 6 to 2017 . For the first time in several cycles, the 2015 IRP does not use a carbon adder to estimate the future cost of carbon emissions. The 201 5 IRP incorporates the cost and long term effects of carbon regulation by modeling several scenarios based on the Environmental Protection Utility 2015 tRP Page 5 'l . Summary ldaho Power Company Agency's(EPA)proposed CleanAirAct (CAA)Section lll(d)regulationsandtheirnpactthe new rules would have on the company's operations. A more complete discussion of climate change and the regulation of greenhor-rse gas emissions is available starling on page 64 of the IDACORP, Inc.,20l4 Form l0-K. Proposed Pilot Projects Solar PV to Address Distribution Feeder Voltage Loss A small scale proof of concept photovoltaic and battery system pitot projeCii being considered for feeders with low voltage nearthe end of the feeder. The purpose of the pilot project is to evaluate its operational performance and its cost eff-ectiveness.'Ihe system will be designed to maintain the feeder voltage within +l- 5oh of nominal voltage (ANSI C84.1) and be cost competitive with otheroptions. During 2015 and 2016 the physical and economic- feasibility will be examined. If feasible, a pilot system will be constructed ard rnonitored. The iesults of the work will be reporled in the 2017 Integrated Resource,P:,'14n. lce-Based Thermal Energy Storage =' Identify and work with a commercial customer.to install thermal ice storage. The initial phase would involve identifying a customer, designin$:t5e system, and putting together a detailed cost estimate. The second phase would be to purchase and install the equipment followed by data collection for a period of time to determine the ef lectiveness of the concept. Community Solar In the 2009 IRP, Idaho [6;ffi. p.oporid'u Solar PV pilot project. At the time, a downward trend in the cost of solar PV w*,j,,$entifipd and ftat trend has continued over the past few years. In addition, the energy shaperof;solar'generation haS been seen as a rnuch better fit with ldaho Power's customors? ngeds whgacompared to other variable and interrnittent renewable resources. Forihbse reasons the company was interested in gaining experience and data related to solar gen€ration and a small pilot:project was proposed. : In Augui ]0, the IPUC commented in Order No.32042 (Case No. IPC-E-09-33) on the proposed sol4r pilot projec stating: Solar power has b€en identified as a resoLrrce that should be pursued by the Company. The recently announced Boise City solar project. we find. r.vill provide Idaho Power that opportunity to assess the merits of such a resource. Since the issuance of Order No. 32042, a number of unique circumstances have arisen that caused Idaho Power to pause and reassess the appropriate tirning and nature of its involvement in solarresearch and related projects. First, the solarproject ref'erenced in the IPUC orderdid not ultirnately provide the assessment opportunity envisioned by the Comrnission, as the developers chose not to pursue completion of the pro.iect. Fufiher, just three rnonths after Order 32042 was issued, in Novernber 2010ldaho Power had 80 MW of PURPA wind contracts pending approval at the IPUC and the company had received another 570 MW olrequests lor new contracts. It was Page 6 2015 tRP ldaho Power Company 1. Summary at that tirne the company filed a joint petition to address PURPA policy and pricing issues at the state level and Case No. GNR-E-10-04 was opened. Finally, just a shorl time later, Idaho Power frled an application to rnodify its net rretering service offering and the IPUC opened Case No. IPC E 1221.ln that case the Commission considered policy issues related to net metering, specifically in the areas of pricing and equitable cost assignment. Because of the broad scope of policy issues involving renewable generation under consideration by the IPUC in each of these cases, Idaho Power felt it was appropriate to postpone the development of any solar research projectorcuStot-trer-fbcusedprogrampendingtheoutcomeofthosecaSeS. Customer interest in central station and distributed solar generation was.ffifl,*lliiiect of a number of discussions within the context of the 2015 IRP preparations, among,r6 the IRPAC members and Idaho Power leadership. Late in the 2015 IRP public process, l-d-ffi-6.?.e,.wer was approached by several interested parties and asked to consider sponsoring a qQ-mmuniftBp,lar project. The U.S. Department of Energy (DOE) in their document A Guide,lo CommuniSi'S red Solar: IJtility, Private, and Nonprolit Projec't Dcvelopment (http://www.nrel.gov/docs/ly l2osti/54570.pdf) defines "community shared solar" as a solar- electric system that provides power and/or financial penent to mulpj'file community members. The DOE document further states the primary goal of cbfmpunity:*6lar is to increase access to solar energy and to reduce up-fiont costs for participantsYr$fufrfidary goals include: I ) improved economies of scale, 2) optimal project siting,.3) increased pE .ltg, understanding of solar energy, and 4) localjob generation.f.i.ti)'l:i | , , Several models have been used to facilitate community shared solar projects including utility sponsored, special plrrpose entity and nonprofit. T.a.b l.l beloW from the DOE guide compares Table 1.1 Community solar modef comparisoii Utility .:$p.eciat Purpose Entity (SPE) Nonprofit Owned By Financed By .,, '' t t':' Hostedffi,." Subscribei Profile Subscriber Motive, Long-term Strategy ofSponsor Examples Utility or thiffiarty Utilig, g ra nts,.'cu.slomer subscriplions Utility o party Electric c0s&mers of the utility Offset pe al electricity use Offer solar options; add solar generation (possibly for Renewable Portfolio Standard) . Sacramento Municipal Utility District - SolarShares Program . Tucson Electric Power - Bright Tucson Program SPE members Member investments, grants, incentives Third party Community investors Return on investment; offset personal electricity use Sell system to host; retain for electricity production . University Park Community Solar, LLC . Clean Energy Collective, LLC . lsland Community Solar, LLC Nonprofit Memberships, donor contributions, grants Nonprofit Donors, members Return on investment; philanthropy Retain for electricity production for life of system . Winthrop Community Solar Project . Solar for Sakai 2015 tRP Page 7 1. Summary ldaho Power Company Several possibilities exist for the structure of a solar pilot project. One option Idaho Power is interested in pursLring would be to develop a photovoltaic (PV) project at a substation near existing load. This concept would not require the addition of new transmission resources and would have economy-of-scale advantages over distributed rooftop installations. The cost of the project could be sLrbsidized by allowing participating custorners to buy the output on a voluntary basis fioln the project as a means of investing in renewable energy. The interested parties have asked Idaho Power to sponsor a community based solar project to satisfy the solar pilot project proposed by the company in the 2009 IRP. Foran example of this concept, there are a number of utility-sponsored projects whereby utility customers participate on a voluntary basis by contributing either an up-front or ongoing payment to support a solar project. In exchange, customers receive a payment or credit on their eleCtfjc bills that is proportional to I) their contribution and 2) how much electricity the solai froject produces. Usually. the utility or some identified third-party owns the solar systern itself- The participating customer has no ownership stake in the solar system. Rather, the customer buySrjghts to the benefits of the energy produced by the system. -' t: It is important to note that Idaho Power's load and reSQ}.f p bafgprob indicates an investment in any new generation, including solar generation, is neith€ti,iie.g,$ld nor economic to pursue at this time or during the foLrr-year action plan horizon. However, as,f-ggulations governing carbon emissions mature, additional renewable gqii$$ll,,,JI.may be wd'iihhted and community shared solar could be a viable option to help satisf,i iom6,ftffi1lon intensity targets. ..1' Given the quickly changing regulatory, techno-lbgic-al$d eConomic landscape, the company will actively explore the risks and opportunities of, an-d potential designs for, a community-based solar project by continuing-fs;*orkWith interested parties. Because there is no identified resource need in the nearrtEft, a projH$t of this n " would be pursued outside of the traditional needs-based'regulatory ftflffig..worf1 and would rather focus on meeting changing customer prefbrences wift-i.e,,,g $$i#lierb and how the energy they use is produced. Portfol io Analysis Um mary A fundamental goal of the'IRP procesS'is the identification of a selected, or preferred, resource portfoli6. The preferred poftfolio identifies resource options and timing to allow Idaho Power to continue to reliably serve customer demand balancing cost, risk, and environmental factors over the 2015-2034p,lanning period. Several key factors create uncertainty regarding the selection of a preferred portfolio in the 2015 lRP. These factors include consideration of North Valmy and JimBridgercoal unitearlyretirernent.theEPA'sproposedCAASection lll(d)regulation, large contracted amounts of unbuilt PURPA solar projects, and the timing of the Boardman to Hemingway Transnrission Line Project (B2H). Valmy and Jim Bridger Coal Unit Early Retirement and CAA Secfion 111(d) Regulation The20l5lRPexarninestheEPA'sproposedCAASection lll(d)regulationandthefutureof Idaho Power's ownership share of the Jim Bridger and North Valmy coal-fired power plants. With the exception of the Status Quo poftfblio, all other portfolios analyzed evaluate alternatives Page B 2015 tRP ldaho Power Company 1. Summary to continued investrnent in the coal units and/orthe irnpact of reducing generation from fossil- fueled power plants to comply with uncer-tain environmental regulations. The optimization of coal unit shutdown alternatives using computer modeling tools will not be possible until the proposed CAA Section I I l(d) regulation is finalized sometime in the second half of 20l5.lt is possible to identify trends in the modeling results that indicate a porlfolio with an earlier North Valmy unit shutdown coupled with the completion of the Boardrnan to Hemingway project performs well on a2l-year NPV basis. It is important to remember that an early retirement of an asset requires accelerating the recovery of the remaining investment in that asset. This increases the cost in the early. years for a longer term savings. This is conceptually similar to repaying a home mofigage early. Over the shorlened life of a loan the totalpayments will be less, but in the near term themdXthly payment will be higher. The same is true when contemplating early retirernent of:North Valpy..pr Jim Bridger units. For example, a North Valmy 2019 early shutdown will.e st approximatb,,,V,r$95 million dollars more between2015 and20l9, but save approximatelf,,$l8l million in fiiedO&M, capital investment. and finance costs compared to a 203 I and 2034 retirement (in nominal dollars). Unlike the home moftgage example, a coal unit'will have lifile value at the decommissioning date and it is likely another resource investment will be required. : t:::::::::t ut: IJncertainty Retated to PURPA Sotar 1r;,lt'i 'Power supply planning is complicated by the inab'ilierof,a utility tci control the timing, type and quantity of PURPA resources being added to the Idaho Power.generation portfolio. Under PURPA a utility is obligated to sign energy safes agq*ments with all Qualifying Facilities (QF) that request to sell energy to ldah,g:P er. Change-in PURPA regulations, resource incentives and technology can and do-g,. ontintially change.tk quantity and MWs of projects being proposed or contracted foi'dnder the PURPA program. In addition, even after a PURPA QF agreement is executed'$1,n . propo pqgject the_ie is still uncertainty if the project will actually be built. This uncertaintf,'6.&p;qposed ptoj-ctslfud construction of projects under contract results in increased plVpp!.ryeyncert6] to the timing and type of company-owned resources needed. Current PU iif6gu.ld,tt.?,, r ut$d: not have any consideration for ldaho Power energy needs or impacts onrySiem reliabil which cre?tes challenging integration issues as well as runs contrarffi'lhe company'sffiire to d-Velop a reliable system as efficiently and cost effectively as possible. The IRP load resource balance includes 461 MW of solar photovoltaic (PV) from PURPA projects schedul lo,,be'online by year-end 2016. The energy and peak-hour capacity of these projects was includdd in the PURPA forecast at the tirne the forecast was prepared. The risk of relying on these signed contracts is exemplified by the fact that l4l MW of the 461 MW were recently terminated due to inaction by the PURPA developers. The removal of the l4l MW of solar capacity has the effect of increasing peak-hour capacity deficits by approxirnately 75 MW. Because the schedule for completing the IRP would not allow the PURPA generation forecast to be updated, the removal of the l4l MW of solar PV generation is addressed in a qualitative rranner in the risk analysis section of Chapter 9. 2015 rRP Page 9 1. Summary ldaho Power Company Boardman to Hemingway Transmission Porrfolio analysis for the 2015 IRP indicates portfolios with the Boardman to Hemingway project (B2H) consistently outperform those in which the transmission line is excluded. This result is consistent with analyses of past IRPs that have shown the 82H project is a valuable supply-side resoLrrce that will allow Idaho Power to meet future system needs. Regional growth in renewable energy resources such as wind and solar makes B2H increasingly valuable as it provides increased system flexibility critical to the reliability of interconnected systems with high penetration levels ol'variable and interrnittent resources. Se/ecfion of the Preferred Portfolio , , ,-' ,,;,:.::;' :'',,., As previously noted, portfolios with early North Valmy unit retirernents performed well in the 2015 IRP analysis. In fact, analysis shows favorable economjds.for portfolios having retirement of North Valrny Unit I as early as 2019. However. these poftfolios carry considerable risk associated with the following factors: .,,,, ,,, ",l'. - :o Uncertainty related to the proposed CAA Seciio-'ii{ l(d) regulation. particularly the effect of the final rule on operations at existing Cot['and natural gas-fired power plants in t h e p ro p o s e d i n t e r i m c o m p I i an c e ryrg,,?A,P ? gin n i n g i i 2m0 Uncerlainty related to retirementVlhfffiffiiL!'fq ajointly owned power plant, specifically the challenges associated with arrivingrat u reJ,1$gg=! e that is I'easible to both owners of the plant ,,,.ii, j :' Uncertainty related to P|RPA,lplar, and,th6 effect of further project cancellations on capacity additions in the early 2020s Uncertainty relatod io the cornpietign date of tt',. B2H project due to permitting issues and the needs of project panri'e?3 ' - Uncertainty of regulhtory acceptance of early coal unit retirement and rate impacts associated with accelerated cost recovery Given thCse risks, the prefeced portfolio selected is portfolio P6(b), which includes retirement of the Nofthlalmy plant at year-end 2025 and the completion ofthe B2H projectin2025.The close linkiilgi*f th"r. resource actions suggests an earliercompletion date of the B2H project could acceleratelhe decornmissioning of the North Valmy plant. Portfolio P6(b) also includes the addition of 6'0UW of dernand response and 20 MW of ice-based thermal energy storage in 2030. In 2031, portfu,,.lio P6(b) also adds a 300 MW combined-cycle combustion turbine. These resource additions late in the planning period address projected needs for resources providing peaking capability and system flexibility. With expected Iong-term expansion of variable energy resources, the need for dispatchable resources that provide system flexibility will also increase. Page 10 2015 IRP ldaho Power Company 1. Summary Action Plan Action plan (201 5-2018) Table I .2 provides the schedule of action items Idaho Power anticipates over the next fbur years. Actions related to the Shoshone Falls project are described in chapters 5 and 9 of the lRP. Table 1.2 Action plan (2015-2018) Resource Action 2015-2018 2015-2018 201s-2018 2015 2015 2015-2016 2016 2016 2017 2417 2019 Boardman to Hemingway Gateway West Energy Efficiency Shoshone Falls Jim Bridger Unit 3 Shoshone Falls Jim Bridger Unit 4 North Valmy Units 1 and 2 Shoshone Falls Jim Bridger Units 'l and Shoshone Falls #= ,..,...!..|9.. uPsrade of SCRlechnology for Units 1 and 2 al Jim Bridger in Ongoi n g perm itting, plan n in g studies, anilrf"€gulatory fil in gs Ongoing permitting, planning studffidhd=irJ{i1 ory fiIings Co n ti n ue p u rs u it of cost-efectty-p Edbrgy "m"Eid File to amend FERC licenqgffirding 50 frrfW "rfuion,,!.f!i;i? Com plete insta llation q.f ltie ctive cata lytic red uction emission-controltechnorogv ",t!,UJti!.f ,r,J] JNi:Y Study options tor snialJ!fupgrade ra'iiging in size up to approxlmately 4 MW Complete instal lation of=S{ffiffie catalytic red uction em ission-control th NV Qp aller upgrade during first quarter depreciation dates and :d: to cease coal-fired operations 2015 tRP Page 11 1. Summary ldaho Power Company Page 12 2015 tRP ldaho Power Company 2. Political, Regulatory, and Operational lssues 2. PouncAL, ReculRroRy, AND OpenaroNAL lssues ldaho Energy PIan !n2007, the Idaho Legislature's Interim Committee on Energy, Environrnent and Technology prepared, and the Idaho LegislatLrre approved, a new Idaho Energy Plan for the first tirne in 25 years. With rapid changes in energy resources and policies, the committee recomrrended the legislature revisit the ldaho Energy Plan every five years to properly reflect the interests of Idaho citizens and businesses. In keeping with this recommendation. the plan was reviewed and updated by the Interim Committee and approved by the legislature inZAl2. The Idaho Offlce of Energy Resources (IOER) and the Idaho Strategic Energy Alliance pr.o'rrid€d assistance to the InterimCornmitteedLrringtheupdateoftheenergyplan. The 2012 Lrpdate finds that ldaho citizens and businesses continlre to U"n"ni*i*,stable and secure access to aflordable energy. despite the potential economic and political vuluerability caused by Idaho's reliance on energy imports. Idahocurrently lacks significant commercial natural gas and oil wells and only generates about hal*the electricity it uses. Yet the state has abundant hydropower, wind. biomass, and other renewabl,s,irrB..'?fgY rorr..r. Ongoing changes in energy generation and censumption pro"vi'de an opportunity for economic groMh within the state. While the Idaho Energy Planacknowledges the risks attributed to advances in energy generation. transmission, and end:i- .:t9,,,9 nold$ies, it also recognizes the prospective beneflts. With this recognition, the 70- ahoEnergy Plan emphasizes five core ob-f ectives: a. ,','- :::: I . Ensure a secure, reliab-le, and stable energy system for the citizens and businesses 2. Maintain Idaho's low.cost energy supply and ensure access to affordable energy for all Idahoans. 3. Protect Idaho's public health, safety, and natural environment and conserve Idaho's nafural resources. 4. Promote sustainable economic growth, job creation, and rural economic development. 5. Provide the means for ldaho's energy policies and actions to adapt to chan gin g circumstances. Because the IOER was charged with coordinating and cooperating with federal and State agencies on issues concerningthe State's energy requirement, GovernorC. L. "Butch" Otter asked the IOER to coordinate the State of ldaho's response to the Environmental Protection Agency's (EPA) Clean Power Plan on behalf of all relevant State agencies. 2015 rRP Page 13 2. Political, Regulatory, and Operational lssues ldaho Power Company ldaho Strategic Energy AIIiance Under the urnbrella of the IOER, the Idaho Strategic Energy Alliance allows a wide variety of stakeholders to have representation and play a role in developing energy plans and strategies for ldaho's energy future. The Alliance is Idaho's primary mechanism to engage in seeking options fbr and enabling advanced energy production, energy efficiency, and energy business in the State of, ldaho. The purpose of the Alliance is to enable the development of a sound energ)/, portfolio for Idaho that includes diverse energy resources and production methods, that provi f the highest value to the citizens of Idaho, that ensures quality stewardship of environmen-tal,:t'esources, and that functions as an effective, secure, and stable energy system. Idaho Power representatives serve on both the Alliance board*f directors anc' number of the volunteer task forces which work in the following areas: =,,', E ,,,, '.r't\iii_i,i"'@ . Bio-gas= . E,nergy efficiency and conservation . Wind . Geothermal . Hydropower . Carbon issues iiilill1= . Baseloa d r"rour""ffi =; 'i".t)o Econom icl ftnanUffi.,$;v e!o.$i#{rt| ..r::\..- =::,-,, illttf,W.,;;;i;i;,i:,, ruA .'-s% i :r:lh ',lLLlR Transmission Communication and outreach FERC RelicenSiiflg u'tt -,. ",t . Like oftr utilities that ope{i!e non-6deral hydroelectric projects on qualified waterways, Idaho Paiworobtains licens#,,,,;$om FERC for its hydroelectric projects. The licenses last for 30 to 50 years, deRehding on ,L.,,,, , complexity, and cost of the project. Idaho Power flled I finfficense application (FLA) for the Swan Falls Hydroelectric Project (Srvan Falls Project):with FERC in June 2008, and the new license for the Swan Falls Project was issued by FERC on September 8, 2012, for a 30-year tenn expiring September 1,2042. Idaho Power's remaining and most significant ongoing relicensing effort is the Hells Canyon Complex (HCC). The HCC provides approximately two-thirds of Idaho Power's hydroelectric generating capacity and 34 percent of the company's total generating capacity. The current license fbr the HCC expired at the end of July 2005. Until the new, multi-year license is issued, ldaho Power continues to operate the pro-iect under an annual license issued by FERC. Page 14 2015 IRP ldaho Power Company 2. Political, Regulatory, and Operational lssues The HCC license application was filed in July 2003 and accepted by FERC fbr filing in December 2003. FERC is now processing the application consistent with the requirements of the Federol Power Act oJ 1920, as amended (FPA); the Ntrtional Environmental Policy Act of 1969, as amended (NEPA); the Endangered Species Act of 1978 (ESA); and other applicable federal laws. Administrative work on relicensing the HCC is expected to continue until a new license is issued. After a new license is issued, further costs will be incLrrred to cornply with the terms of the new license. Because the new license for the HCC has not been issued,and discussions on the protection, mitigation, and enhancement (PM&E) packages are still be g conducted, it is not possible to estimate the final total cost. Relicensing activities include the followin"' l Coordinating the relicensing process ..::..r,:,.:::.tt::=::: :- :.,:-::.4!aa/. !j1,' .'iiiiiift 2. Consulting with regulatory agencies, tribes, andriinterested parties "? 3. Preparing studies and gathering environmental dzita'o{1lfish, wildlife, recreation, and archaeological sites ....r.:::::::::= =.,,1_ . .4. Preparing studies and gathering engia@iBdata on historical flow patterns, reservoir operation and Ioad shaping, brebay*d river sedimentation, and reservoir contours and volumes ': tyrirtdfi-iru '';',,*'' ,rliiil,l" = i',,,6. Preparing all nec€iiChry repo$sj:-xhibits, ahdlJllings responding to requests for additional information rrd*n=F C ",;$iiiiiiriir# l Consultins on lesal matters4,a: "+r "#.,t'' :''" i8ense any of the existing hydroelectric projects at a reasonable cost will create also ha#tftffi:potential to dec?ease available capacity and increase the cost of a project's generation th?,o.,Ugh additional'bperating constraints and requirements for environmenta 7. Failure to up re on the current electri rates of Idaho Power customers. The relicensing process gh additional'bperating constraints and requirements for environmental PM&E measures rmppdiied as a co4dition of relicensing. Idaho Power's goal throughout the relicensing process is to maintaln,th.Fft* cost of generation at the hydroelectric facilities while irnplementing non-p r measures designed to protect and enhance the river environment. No reduction of the available capacity or operational flexibility of the hydroelectric plants to be relicensed has been assumed in the 2015 IRP. If capacity reductions or reductions in operational flexibility do occur as a result of the relicensing process, Idaho Power will adjust future resource plans to reflect the need for additional generation resources. 2015 tRP Page 15 2. Political, Regulatory, and Operational lssues ldaho Power Company ldaho Water lssues Power generation at Idaho Power's hydroelectric projects on the Snake River and its tributaries is dependent on the state water rights held by the company for these projects. The long-term sustainability of the Snake River Basin streamflows, including tributary spring flows and the regional aquifer system, is crucial for ldaho Power to maintain generation from these projects, and the company is dedicated to the vigorous defense of its water rights. None of the pending water-management issues is expected to affect Idaho Power's hydroelectric generation in the near term, but the company cannot predict the ultimate outcome of the legglfgnO administrative to guarantee that sufficient water is available for use at the company,$,S tric projects on the Snake River. Idaho Power along with other Snake River Basin water right holders was engaged in the Snake River Basin Adjudication (SRBA), a general streamfl ow adj ud ication process started in 1987 to define the nature and extent of water rights in the Snake River Basin. The initiation of the SRBA resulted from the Swan Falls Agreement entered into by ldaho Power below Bliss. ce dffitial water right decrees. The Final Unified n August 25,2014. ved a struggle between the State of ldaho and. n: . ,l_.. , I1"1, -RE$p;.over the:o.rpgl'r.water rights ul tl:.l*T Falls Project. lhe agreement Y1:d'.::::::#;nY,"- "l:.s.i+..trIIdaho P6€@! water rights 6-i ts hydroelectric facilities between Milner Dam and Swan Falls entitled the/d$jlpany to a mffinum flow at Swan Falls of 3,900 cubic feet per second (cfs) during the irri$6ti season and 5,600 cfs during the non-irrigation season. -:1. !" " The Swan Falls Agie€dent placed the portion of the company's water rights beyond the minimum flows in a trust established by the Idaho Legislature for the benefit of Idaho Power and the citizens of the state. Legislation establishing the trust granted the state authority to allocate trust water to future beneficial uses in accordance with state law. Idaho Power retained the right to use water in excess of the minimum flows at its facilities for hydroelectric generation until it was reallocated to other uses. Idaho Power filed suit in the SRBA in 2007, as a result of disputes about the meaning and application of the Swan Falls Agreement. The company asked the couft to resolve issues associated with Idaho Power's water rights and the application and effect of the trust provisions Page 16 2015 tRP ldaho Power Company 2. Political, Regulatory, and Operational lssues of the Swan Falls Agreernent. In addition, Idaho Power asked the court to deterrnine rvhether the agreement subordinated the company's hydroelectric water rights to aquifer recharge. A settlement signed in2009 reaffirmed the Swan Falls Agreernent and resolved the litigation by clarifying that the water rights held in trust by the state are subject to subordination to future upstream beneficial uses, including aquifer recharge. The settlernent also comrnitted the state and Idaho Power to further discussions on important water-management issues concerning the Swan Falls Agreement and the management of water in the Snake River Basin. Idaho Power and the State of Idaho are actively involved in those discussions. The settlement also recognizes water-management measures that enhance aquifer levels, springs, and river flows-such as aquifer-recharge projects-that benefit both agricultural developrnent and hydroelectric generation. Both parlies are working with water user's and other stakeholders in the development of water-management measures through the implementation of the Eastein Snake River Plain Aquifer, Cornprehensive Aquifer Management Plan (ESPA CAMP) as approved by the ldaho Water Resource Board (IWRB), and the 2009 Swan Falls Reaffirmation Agreeme Given the high degree of interconnection between theESPA and Snake River, tOut',o po*., recognizes the importance of aquifer-management planning in prortroting the long-term sustainability of the Snake River. The company continues to emphasis implernentation of the ESPA CAMP to improve aquifer levels andtributary spring florvs to the Snake River. While some of the Phase I recommendations out{fl$$,,,fable 2.1 wer0 slow to develop due to limited initial funding, House Bill 547 signed into law by Governor Otter in 2014, provides $5 million annually to the ldaho Water Resource Board$r aquifer stabilization projects, with the ESPA having first priority. While there have been two- ceS charge weather modification-that have received funding and have met ol eiCeeded targes, declin' =$.aquifer levels and spring discharge persist. During the winter of 201Q,ffip)5,,,;.t!e*ff1€idftdl${.ll'al maintenance conditions allowed for an extended winter tilme rechd(.8._lSEason from October 27 ,2014 to March 24,201 5, resulting in a volume rechaffiff:t2,325 acie-f..t. This volume significantly exceeded the combined recharge qf*lielwo previous seasoitS, and exceeded the average annual recharge of the previous t ,. '.fl,qu!il$ by +,s00 ".e +"::':' Idaho PoWerr,lnitiated and pffiued a successful weather modification program in the Snake River Basin. The Cdffiany partn-e.?d with an existing program in the Lrpper Snake River Basin and, through the cociii'eralive effort, has greatly expanded the existing weather modification operational program,rbl6ig with forecasting and meteorological data supporl. The company has an established long-term plan to continue the expansion of this program. ln 2014, Idaho Power expanded its cloud seeding program to the Boise and Wood River basins, in collaboration with basin water users and the ldaho Water Resource Board. Wood River cloud seeding, along with the upper Snake activities, will benefit the ESPA CAMP implementation through additional water supply. 2015 tRP Page 17 2. Political, Regulatory, and Operational lssues ldaho Power Company Table 2.1 Phase ! measures included in the ESPA CAMP Measure Target (acre-feet) Estimated to Date (acre-feet) Groundwater to surface-water conversions..........................,.... Managed aquifer recharge Demand reduction....... S u rface-wate r co nse rvation Crop mix modification... Rotating fallowing, dry-year lease, conservation reserve enhancement program (CREP).... .. . Weather modification 100,000 100,000 50,000 5,000 40,000 so,oo0 30,300 78,000. 26,000 0 34,000 250,000 "Average annuaf recharge Irom 2009 - 2014 :ii;.l? !tu:,, For the 2015 lRP. ldaho Power forecasted flows similar to those in the 20 t: Inp::with declines in reach gains extending through the end of the IRP planiiing period. Based on modeling under the 90-percent exceedance forecast, declining flows at Swgn FallC'diop to 4,030 cfs, which is slightly higher than the Swan Falls minimum of 3,900 ifs-r'F,igure 2. I provides the yearly April through July inflow to Brownlee Reservoir as forecasted fua*e 2015 IRP. ir- I li T lr* N ii -Historicat - -. tRP 50% +.., :.:..,tRPToo/o e s *tRP90o/o Figure 2.1 Page '18 Brownlee historical and 2015-2034 forecasted April - July inflow 2015 tRP ldaho Power Company 2. Political, Regulatory, and Operational lssues Water Lease Agreements ldaho Power views the rental of water fbr delivery through its hydroelectric system as a potentially cost-elflective power-supply alternative. Water leases that allow the company to request delivery when the water is needed are especially beneficial. Acquiring waterthrough the water bank also helps the company to irnprove water-quality and temperature conditions in the Snake River as part of ongoing relicensing efforts associated with the HCC. The company signed a rental agreement in 2014 with Water District 63 in the Boise River basin to rent 8,000 acre-feet of storage water released in January 2015. ,,,,,,i ,i,i , ln ALrgust 2009. ldaho Power also entered into a five-y ear (2009-2013)water-rental agreement with the Shoshone-Bannock Tribal Water Supply Bank for 45,716,,.4,pie'feet of American Falls storage water. Under the terms of this agreement, the company c#Schedule the release of the water to maxirnize the value of the generation from the entire;,system of main siem Snake River hydroelectric projects. ln 201 l, the cornpany extended the Shoshone-Bannock rental October of each year during the term of the agreement.lSishone-Bannock agreement was executed in part to offset the effbct of drought and changi -use patterns in southern Idaho and to provide additional generation in summer moqlhs when demand is high. The company is reviewing the potential to renegotiate the Shoshone-Binnock agreement fbr futureyears. ;.);1,,,. = ..,',.,ili;" Idaho Power intends to continue to pursue waterffil opportunities as parl of its regu lirr operations. Re n ewa b I e I nteg rati on'S.tg'dy.,,*.=.-.= ldaho Power has cogrpleted two wind integration studies and one solar integration study since the mid-2000s. ThEii studies increase<l the company's understanding of the impacts and costs associated with integrating variable and intermittent resources without compromising reliability. The variable and uncertain production fiom wind and solar resources requires Idaho Power to provirJe ihOtitiorot balancing reserves from existing dispatchable generating resources, which results in lost'opporlunity costs and corresponding increases in power supply expense. Idaho Power cornpleted the most recent wind integration study in 2013 which was the basis fbr a tarilf sclredLrle of wind integration costs proposed to the IPUC by Idaho Power. The Idaho commission approved the proposal as Schedule 87 in OrderNo.33l50 in October20l4. The frrst ldaho Power solar integration study was completed in2014 and the subsequent revision to Schedr-rle 87 was approved by the IPUC in Order No.33227 in February 2015 as part of a settlernent stipLrlation between ldaho Power and intervening parties. The solar integration settlernent stipulation includes provisions requiring Idaho Power to initiate a second solar integration study by January 2015 and to complete the second study within l2 rnonths. Idaho Power has lorrned a Technical Review Committee (TRC) of renewable energy experts for the 2015 tRP Page 19 2. Political, Regulatory, and Operational lssues ldaho Power Company second solar integration study which is in progress, but will not be finished prior to the completion of the 2015 IRP. The results of the integration studies show periods of low customer demand to be the most difficult to cost effectively integrate variable resources. During low demand periods, other existing resources are often already running at minimunr levels or may already be shut off. Under these conditions, curtailment of the variable resources may be necessary to keep generation balanced with customer load. The integration studies also demonstrate the frequency of curtailment events are expected to increase as additional variable resources are added to the system. For the IRP, integration costs for existing wind and solar resources are furon to all the portfolios analyzed and are not included in the portfolio cost accounting. However, portfolios with new wind or solar resources do include costs consistent ;yith Schedule 87,for the new resources. A copy of Schedule 87 is providedin Appendix C Technicul Appeidix, .Northwest Power Pool Energy lmba[ance M;arket Since 2012, the Northwest Power Pool (NWPP) has beeil::e=+...Q ating energy markets, sometimes referred to as a Security Constrained Econoglic Dispatch (SW,.D A second phase ofthe effort was focused on refining the design eleme4!,fl1trff.i,9;firc-,,,_PD to suit'{H$ pnique issues present in the NWPP. A third phase just completed, devel$$Bil'"1#d${lbsr_of opeiationaltools to facilitate a more robust and reliable system operation. ThfiNwPPislnbW..,-moving into a fourth phase to continue to refine design elementsof a SCEDffi,de.t/ p additional low cost/high value tools to enhance system operation. M.ajlffi.Utional issues remain before a SCED can be implemented in the Pacific Northwest.^€ \= ,. :-7 F o r I d ah o Po wer, th ere are .se ve ra l. pilncip.-le=..,!9 n e fif3;' to an EI M : l The market would fH.,d,.. H8'greater access to balancing energy to accommodate intermi-ttihi''$g;egrtion'Varigtions within Idaho Power's balancing area. $..rL[,ii;:i,.- .,, ,:::=2. There would Ae a.'@improvement in real-time dispatch costs. 3. The'market would pii$ide better real-time pricing for power imbalances that occur in real-tim t *l:",l= power customers' ldaho Power suppd& jind will continue to participate in the NWPP discussions; however, parlicipation by a majoiity of the NWPP members will be required to realize the benefits of an EIM. Renewable Energy Certificates RECs. also known as renewable energy certificates or green tags, represent the green or renewable attributes of energy produced by certified renewable resources. A REC represents the renew'able attributes associated with the production of one megawatt-hour of electricity Page 20 2015 tRP ldaho Power Company 2. Political, Regulatory, and Operational lssues generated by a qualified renewable energy resource, such as a wind turbine, geothennal plant, or solar facility. The purchase of a REC buys the "greenness" of that energy. A renewable or green energy provider (e.g.. a wind farrn) is credited with one REC for every 1,000 kilowatt-hours (kwh), or I MWh, of electricity produced. RECs and the electricity produced by a cenified renewable resource can either be sold together (bundled), sold separately (unbundled), or be retired to comply with a state- or federal-level renewable portfolio standard (RPS). A certifying tracking system gives each REC a unique identification number to facilitate tracking purchases, sales and retirements. The electricity produced by the renedle resource is fed into the electrical grid, and the associated REC can then be used (retired);'h& (banked), or traded -1i,'' "t i, i. ,, REC prices depend on many factors, including the following: r,::=:,:.: ,+i- .ThelocationofthefacilityproducingtheRECslf::. . Whether there is a tight supply/demand situation := . Whether the REC is cerlified fo. .?'#=fi, ,,1,,,ir,,.' portfolio ards (RPS) compliance . The generation type (e.g. wind, solar;g.eothErmaf) ,.,= . :.. "':,.;.'',;",:'. Whether the RECs are bundled with en-?gg r unbundled When Idaho Power sells , the @eeds are returned to ldaho Power customers through the power cost adjustment (P0A) as dire-Eft by the IPUC in Order No. 32002 and by the OPUC in Order No. I I -086. Bec$a the RE€S== sold;=Id*iho Power cannot claim the renewable attributes associated with't$d.p ffie s were delivtired to retail customers. The new REC owner has purchased.th-e1ffito claiin [he renewable attributes, or'ogreenness," of that energy. Idaho Powefuustomers that choose to purchase renewable energy can do so under Idaho Power's volunt#$reen Power Program. Under this program, every dollar contributed by a customer brings abffthe delivery of 118 kWh of renewable energy to the region's power grid, providing the contributiili|.customer a ciated claims fbr the renewable energy. The entire amount designated is ri@to purch€Se green power fiom renewable projects in the Northwest and to support Solar 4R1chools. On behalf of program participants, Idaho Power obtains and retires RECs. For the 2014'Gieen Power Prograrn, Idaho Power purchased and subsequently retired 19,318 RECs on behalf of Green Power pa(icipants. Renewable Portfolio Standard Some states have an RPS, a state policy requiring that a minimum amount (usually a percentage) of the electricity each utility delivers to customers comes from renewable energy. In the future, there may be similar federal standards. Idaho Power anticipates that existing hydroelectric 2015 tRP Page 21 2. Political, Regulatory, and Operational lssues ldaho Power Company facilities will not be included in RPS calculations. However, hydroelectric upgrades on existing lacilities, such as the Shoshone Falls upgrade, will likely be inclLrded in RPS calculations. Underthe Oregon RPS, Idaho Power is classified as a'osrnaller utility" because the cornpany's Oregon cllstomers represent less than 3 percent of Oregon's total retail electric sales. As a srnaller utility, Idaho Power will have to meet a 5- or l0-percent RPS requirement beginning in 202s. While the State of Idaho does not have an RPS, a f-ederal Renewable Energy Standard (RES) is a possibility. Idaho Power believes it is prudent to continue acquiring RECs associated with renewable resources to position the company's resource and REC portfblio to minimize the potential effect on cLrstomers if a federal RES is implemented. :REC Management Plan In Decembe r 2O}9,ldaho Power filed a REC managemenil$ian with the IPUC that detailed the company's plans to continue acquiring long-term rights to RECs in,anticipation of a federal RES but to sell RECs in the near term and return to custofiers their 95:percent share of the proceeds as defined under the PCA mechanism. Public comments"iegarding the plan mirrored the positions expressed by IRP Advisory Council members, many.of whorn flled comments with the IPUC. ln June 2010, the IPUC accepted ldaho Power's REC management plan. Federal Energy Legislation CAa Settion rir(O) Idaho Power is subject to a broad range of fedffiiiit", regional, and local environmental laws and regulations. Current and'p-nding'environmental legislation relates to climate change, greenhouse gas emissions:.and air qualjty, mercury (Hg) and other emissions, hazardous wastes, polychlorinated biphenyls, and endan$ered and threatened species. The legislation includes the Clean Air Act of 1970 (C/@f fi!.e;g6ai'Waidi Act of 1972 (CWA); the Resource Conservation and Recovery Ac1,.qf l9i6 (Rq );the Toxic Substances Control Act of 1976 (TSCA); the Comprehewif,e Ek@onmehlal Response, Compensation and Liability Act oJ' l9ti0 (cERCL&'ahd the uE.,.,, ,. ,, The util@industry will coffiue to respond to changes in environmental legislation associated with utilityoperations, including emissions regulations associated with the operation of coal- and natural gas-fi rbd generatin$ faci I ities. r:::=On June 2,2014, the!.S. Environmental Protection Agency (EPA), under President Obama's Climate Action Plan,'ieleased its long-anticipated proposal to regulate carbon dioxide (CO:) emissions frorn existing power plants under CAA Section I I l(d) of the Clean Air Act (CAA). EPA's proposed Clean Power Plan includes arnbitious, mandatory COz reduction targets fbr each state, designed to achieve nationwide 30 percent COz emission reductions over 2005 levels by 2030. The EPA has proposed a novel approach, extending regulations beyond the stationary source itself, which is where the EPA has traditionally confined its authority. Each state's rate- based goal, namely pounds CO2 per megawatt hour (lbs/MWh) was calcLrlated using fbLrr building blocks: Page 22 2015 tRP ldaho Power Company 2. Political, Regulatory, and Operational lssues l. Building Block I - improve efficiency in existing coal-fired power plants. 2. Building Block 2 - re-dispatch generation from existing coal-fired power plants to natural gas combined cycle plants. 3. Building Block 3 - increase generation from non COz emitting resources. 4. Building Block 4 - increase end use energy efficiency programs. A combination of the 4 building blocks were used to calculate an interirn goal laverage of years 2020-2029) and a final 2030 goal. Each state would then implement the.fioals through a state plan, which will need to be approved by the federal EPA. Each rate-based goal would be legally binding on each state. ,l,l With new comprehensive federal energy legislation, a utility'sresource portfolio will continue to evolve in response to its obligation to serve, market conditidft, perceived risks, an'd*gulatory policy changes. Because the EPA's proposed rule will,:11ptbe finaliz.pd until sometiit€ after the completion of tn.20l5 IRP, the IRP analysis.*u*iffip.eralcompliance sensititivities that represent possible outcomes of the final rule. Additionilliffi.rmation on those sensitivities is presented later in Chapter 9. ' 1+r' .::a:,' .':::a'.:''.=a:a-: 2015 tRP Page 23 2. Political, Regulatory, and Operational lssues ldaho Power Company intentionally. Page 24 2015 rRP ldaho Power Company 3. ldaho PowerToday Customer Load and Growth In 1990. Idaho Power served approximately 290,000 general business customers. Today, Idaho Power serves more than 515,000 general business customers in ldaho and Oregorr. Firrn peak-hour load has increased from 2,052 MW in 1990 to over 3,400 MW. On July 2,2013, the peak-hour load reached 3,407 MW-the systern peak-hour record. 3. loaHo PowEn Tooav ConstructioA::,in d owntown Edise Average finn load increased from 1,200 =fli1,, ,,,il -:' -" - -'t the load frorn the formeraMW in 1990 to 1,739 aMW in 2014 (load calculations €*e.,y#$) special-contract customer Astaris, or FMC)I,Additional detrii'ffif Idaho Power's historical load and customer data are shown in Figure 3 I'an'd !fri,,r,L -i" ' I Since 1990, Idaho Power's total narneplate ged-eratio4-E6u=ii.e.t,..qsed from 2,635 MW to 3,594 MW. The 959-MW increase in capacity'ite.p{,?.$ehts enou$h generation to serve nearly 175,000 customers at peak times. Table 3.1 showi tdaho Power's changes in repofted narneplate capacity since 1990. -:::::::::::::: ldaho Power's newest resource additioa-is the 313-MW Langley Gulch CCCT. The highly efficient, natural gas-fired po,werplant is located.:in the western Treasure Valley in Payette County, ldaho. Construction of the plant began in August 2010, and the plant became commercially available in June 2012. The datain'Table 3.1 suggests each new customer adds approximately 5.5 kW to the peak-hour load and out 2.5 average kilbwatts to the average load. In actuality, residential, commercial, and irrigation customers generally contribute more to the peak-hour load, whereas industrial custorrers contribute more to tlre average load; industrial customers generally have a more consistent load shape, whereas residential, commercial, and irrigation customers have a load shape with greater daily and seasonal variation. Since 1990, ldaho Power has added about225.000 new customers. The simple peak-hour and average-energy calcLrlations mentioned earlier suggest the additional225,000 customers require approximately 1.237 MW of additional peak-lrour capacity and about 560 aMW of energy. 2015 tRP Page 25 3. ldaho PowerToday ldaho Power Company 5,500 5,000 4,500 4,000 3,500 3,000 2,500 2,000 550,000 500,000 450,000 400,000 350,000 300,000 250,000 200,000 1,500 - 15O,OO0 'l ,000 500 0 100,000 50,000 01990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 -Total Nameplate Generation (MW1 *p"ak Firm Load (MW) -Average Firm Load (aMW) Figure 3.1 Historicalcapacity, Ioad, and customer. data ,,fi$S.ii"r Table 3.1 Historical capacity, load, and customer d' -_.= 2014 Customers Year Total Nameplate Generation (MW)Firm Load ln[Wi::'..",Average Firm Load (aMW) Customersl I 990 1 991 1992 1 993 1 994 1 995 1 996 1 997 1 998 1 999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 201 1 2012 2013 2014 2,635 2,635 2,694 ,;,;,..:;1 :'?:_A52 1,205 1,206 1,281 1,274 1,375 1,324 1,438 1,457 1,491 1,552 1,653 1,576 1,622 1,657 1 ,671 1,660 1,745 1,808 1,815 1,742 '1,679 1,711 1,745 1,801 1,739 290,492 296,584 306,292 316,564 329,094 339,450 351,261 361,838 372,464 383,354 393,095 403,061 414,062 425,599 438,912 456,104 470,950 480,523 486,048 488,813 491,368 495J22 500,731 508,051 515,262 2,644 2,661 i= l',AiA _=.2J6!. E,99.s'J;2as 2,7 4,t?,fr,i ,lt,fl,E l[1irp7asz :ii:.1.tl;,- ili 2,912 1111$ 2'e1fi1;7r:;t' 3-,g85lr :3;OB5 3,093 3,276 3,276 3,276 3,276 3,594 3,594 3,594 2,535 2,675 2,765 2,500 2,963 2,944 2,843 2,961 3,084 3,1 93 3,214 3,031 2,930 2,973 3,245 3,407 3,184 1 Year-end residential, commercial, and industrial count plus the maximum number of active irrigation customers Page 26 2015 tRP ldaho Power Company 3. ldaho Power Today Idaho Power anticipates adding approxirnately 9,800 customers each year throughout the 2O-year planning period. The expected-case load fbrecast predicts that summer peak-hour load requirements are expected to grow at about 62 MW per year, and the average-energy requirement is forecast to grow at 24 aMW per year. More detailed customer and load forecast infonnation is presented in Chapter 7 and in Appendix A-Sules and Load Forecast. The simple peak-hour load-growth calculation indicates Idaho Power would need to add peaking capacity equivalent to the 318-MW Langley Gulch CCCT plant every five years throLrghout the entire planning period. The peak calculation does not include the expected etfects of demand response programs, and ldaho Power intends to continue working with customers and applying demand response programs during times of peak energy consumption. The plan to meet the requirements of Idaho Power's load growth is discussed in Chapter 10. : =.:il',The generation costs per kW included in Chapter 7 help put forecast custoniellgrowh in perspective. Load research data indicates the average resid.edftl customer requires about 1.5 kW of baseload generation and 5 to 5.5 kW of peak-hour generation. Baseload generation,capital costs are about $1.145 per kW fbra natural gas-fired CCCT. such as ldaho Power's Langley Gulch Power Plant, and peak-hour generation capital"'6b',$,,. are abollt $800 per kW for a natural gas-fired SCCT, such as the Danskin and Bennett Mouritajh,ptojects. These capital cost estimates are in 2015 dollars and do not inglule fuel or any offig; operation and maintenanceexpenses' 14il* il |iti?,=,,,,-.. ,u!'f ,t^ reii,.,,t'ieside rc'Us1omgi. quires over $1,700 of capital investment for 1.5 kW of baseload generation#us- dditional $4,400 for 5 to 6 kW of peak- hour capacity, leading to a total generation capi. t-6dst of over $6,1 00. Other capital expenditures for transmissiol; distribution. customer systems. and other administrative costs are not included in the $6,100'_Capital genEmtion requi$ment. A residential customer groMh rate of 9,800 new customers p€iyear transl?tg; into.afpoSf $60 million of new generation plant capital each year to serve the ba"Sdloal,a-nd Feat energy rdquirements of the new residential customers. 2014 enm# - 6U*r,, Idaho PrCIi#ei's system recei* energy from a variety of fueltypes and integrates energy from more thd[=.]] PURPA projOels and three PPAs in addition to company-owned generation. Figure 3.2"belw shows the nameplate capacity of resources delivering to Idaho Power's system from company';,o-, ed resources. PURPA contracts, and long-terrn PPAs. 2015 tRP Page 27 3. ldaho Power Today ldaho Power Company 9MW Figure 3.2 201.4 purchased power) Idaho Power's electricity sources for 201 generated 77 percent ofthe total energy Idaho Power's low-cost hydroelectric plants electricity. Purchased power pr.o.v"id-,..9$ the rem includes power purchased frgnirPURPA proje through IPUC-approved PPA hgreemdfits, the ldaho Power Generation Hydro 6,169,847 M\ /h 36Yo ldaho Power Generation Gas 1,174,857 MlMr 7o/o Figure 3.3 2014 energy by source {{W;4Wq- a v ef,fi'fue wa te r ye a rs, typigdly the company's largest source ol [pg 23 percent of the energy requirement and F i gurd'ii;,if$elow. I dah o Power rket purchases and power purchased which has been identified in past lRPs. Page 28 2015 rRP ldaho Power Company 3. ldaho Power Today ln20l4,ldaho Power purchased 4,148,611 MWh of electricity through PURPA contracts, market purchases, and long{erm PPAs, Figure 3.4 provides a percentage break down by type of fuel for the PPA and PURPA purchases. Market purchases are shown in total, but not identified by fuel type since the original resource is not known. Idaho Power receives RECs from the Elkhorn Valley Wind Project, the Raft River Geothermal Project, and the Neal Hot Springs Geothermal Project. However, as noted in Chapter 2 "Renewable Energy Ceftificates," ldaho Power is required to sell these RECs and none of the renewable generation is represented as being delivered to Idaho Power retail customers in 2014. Gas 76,713 MWh ?% Market Purchases 1,301,030 MWh 31% Landfill Gases 28,975 M\ /h lYo Waste 74,878 M\ /h. 2o/o Figure 3.4 Exis 4/1_t;:::;!:,:/.1./::,:,.,,_ l.V.i! by fuel type "a'ff.,i.];, id6*.Resources fh, ='\tlitlljibk 1':'' :d and tl{ffi,g of future resources, Idaho Power prepares a load and resource nts for foffist load growth and generation from all of the company's and pla .ffi purchases. The load and resource balance worksheets showing To ideffifrffu"the need and tirffff*g of future resources, Idaho Power prepares a load and resource balance thffitl_qgounts for fofl.ld&ast load growth and generation from all of the company's existing resci presented in Appeh(.iff"ff-Technical Appendix. Table 3.2 shows all of Idaho Power' existing resources, nafiieplate capacities, and general locations. 2015lRP Page 29 3. ldaho PowerToday ldaho Power Company Table 3.2 Existing resources Resource Type Generator Nameplate Capacity (MW) Location Hydroelectric 92.3 Upper Snake Hydroelectric 75.0 Mid-Snake .... . Hydroelectric 585.4 Hells Canyon Hydroelectric 82.8 .. q.Mid-Snake ,. . Hydroelectric 12.4 ,:., North Fork Payette t tt:itii.?"Hydroelectric ,?|.,.6,!!l?,.r,,,,r- South Central ldaho !i)tlt;\it".:l;t/1,:ti.?;t........... Hydroelectric,,ltfl9tf'.5 u4fi[1{.fltr6.Hetts CanyonHydroelectric ,11..$rr91 5 ua|[ffi6-Hells Canyon Hydroelectric , tt:,. ' 13.5 '==.=$.Auth Central ldaho' 't;ilti'tk 'tttt'F"';;?o HYdroelectric .,,,r,,,,ii " 60'0 Mq,m Hydroelectric .*rf$fi$ "9.4 Uppe"FffihkeHydroetectric o lr:u ffi.nro,o.,""rrtoni.WiirL!,,.n /,iW o Hydroerectric ,,,lt,liiiiii,,,, , 12.5 Hy9rlelectric l\i:&4 27.2 Uil2ilr*l!^r-:^ '::a:t:.:.l+ o o nva'o"tectric!,ffiilir1*t,,. )rWo'o Hells canvon Hydroelectric ''\ltf:ii!i:i: tf 12.5 Upper Snake HY9rlelectric '.t'|::i:&4 27.2 Mid-Snake Hyiri'oelee$& .'.:!;;!?2..,8.8 south centralldaho Natural Gas-SCCT 172.8 Southwest ldaho Natural Gas-SCCT 270.9 Southwest ldaho Diesel 5.0 Eastern ldaho Thousand Springs......... Uyafiarec-tric tt 3 . a.a South cen l,, la.,- Twin Falls..... HydioeleCifi€:=--=-==,,,;, .,,,-_ "8529 Mid-Snake '=.:::., .::.aaaa::::a:.:-'i.i:ii, t'iitu Langley Gulch..--:i"1ffi?";.-..".,-.. . ...-....:............. Natural Gas-CCCT 318.5 Southwest ldaho "t::::;i:= , it,,,,;,:Total existingf:,fiai1r_replate capaci ir....... 3,594.4 The following re.ii$h*scribe Idaho Power's existing supply-side generation resources and long-term power purchase agreements (PPA). Hyd roel ectri c F aci I iti es Idaho Power operates l7 hydroelectric projects located on the Snake River and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and an annual generation equalto approximately 970 aMW, or 8.5 million MWh under median water cond itions. Page 30 2015 tRP ldaho Power Company 3. ldaho PowerToday Hells Canyon Gomplex The backbone of ldaho Power's hydroelectric system is the Hells Canyon Complex (tlCC) in the I-lells Canyon reach of the Snake River. The HCC consists of Brownlee, Oxbow, and Hells Canyon dams and the associated generation facilities. In a normal water year, the three plants provide approximately 70 percent of Idaho Power's annual hydroelectric generation and approximately 30 percent of the total energy generated. Water storage in Brownlee Reservoir also enables the I-ICC projects to provide the rnajor portion of ldaho Power's peaking and load- lollowing capability. Idaho Power operates the HCC to comply with the existing annual FER€&ense as well as voluntary arrangements to accommodate other interests, such as recre$llbiral use and environmental resources. Among the arrangements are the Fall Qhjpook'Prceram, voluntarily adopted by Idaho Power in I 991 to protect the spawning and incii66tion of . l{hinook below Hells Canyon Darn. The fall Chinook species is currently listed'as threatened un r the Endangered Species Act (ESA). Brownlee Reservoir is the main HCC reservoir-and=ffio Powerii only reservoir- with significant active storage. Brownlee Reservoir ha$$p-l vqtfl$?il feet of active storage capacity, which eqLrals approximately one million acre-f€€.t1$;water. Both Oxbow and Hells Canyon reservoirs have significantlyffiLler active storage capacities-approximately 0.5 percent and I percent olBrownlee Reffiffis volume, respectively. 'i.:r; . Brownlee Reservoir is a year-round, multiplffie rese-U-i-€=fo aho Power and the Pacific Norlhwest. Although the,,p.f,j ary purpgfpi*Sprovide a stable power source, Brownlee Reservoir is also u.s=€=d.= stem flo6$'b'ontrol, recreation, and the benefit of fish and wildlile resources. Brownlee Dam is on" of6r.ral Ppoffi-q!$onh*.,#irums coordinated to provide springtirne flood control on the lower Coluft$ig Ri#i. IdahU Pii#6r operates the reservoir in accordance with flood-control directions receiYed from the US Army Corps of Engineers (USACE) as outlined in Article 42 of the existing FERC li'0e1se. After flod-control requiremepts haVe'been met in late spring, Idaho Power attempts to reflll the reservoii meet peak summFf electricity demands and provide suitable habitat for spawning bass and crappie. The full reservoir also offers optimal recreational oppoftunities through the Fourth of July holiday. =The US Bureau of Reclamation (USBR) releases water from USBR storage reservoirs in the Snake River basin above Brownlee Reservoirto augment flows in the lower Snake Riverto help anadromous fish rnigrate past the Federal Columbia River Power System (FCRPS) projects. The releases are part of the flow augmentation implemented by the 2008 FCRPS biological opinion. Much of the flow augmentation water travels through Idaho Power's middle Snake (mid-Snake) pro.iects, with all of the flow augmentation eventually passing through the HCC before reaching the FCRPS projects. Brownlee Reservoir's releases are managed to maintain constant flows below Hells Canyon Dam inthefall asaresultoftheFallChinookProgramadoptedbyldahoPowerin l99l.Theconstant 2015 tRP Page 31 3. ldaho Power Today ldaho Power Company flow is set at a Ievel to protect fall Chinook spawning nests, or redds. During the fhll Chinook operations, Idaho Power attempts to refill Brownlee Reservoir by the flrst week of December to meet wintertime peak-hour loads. The fall Chinook plan spawning flows establish the minirnum flow below Hells Canyon Dam throughout the winter until the fall Chinook fry emerge in the spring. Upper Snake and Mid-Snake Projects Idaho Power's hydroelectric facilities upstream fiom the HCC include the Cascade, Swan Falls, C.J. Strike, Bliss, Lower Salmon, Upper Salmon, Upper and Lower Malad, Thousand Springs, Clear Lake, Shoshone Falls, Twin Falls, Milner, and Arnerican Falls projeCts. Although the upstream projects typically follow run-of-river (ROR) operations, a smflll amount of peaking and load-following capability exists at the Lower Salmon, Bliss, and Cr Jr.Striko,+rojects. These three projects are operated within the FERC license requirements to cdlilbide with=&ily system peak demand when load-following capacity is available ,,,.i , ,. Idaho Power completed a study to identifo the effects of load-following operationi afihe Lower Salmon and Bliss power plants on the Bliss Rapids snail. a threatened species under the ESA. The study was part of a 2004 settlernent agreerxentwith the US Fish and Wildlife Service (FWS) to relicense the Upper Salmon, Lower Salmon, Bliss, and C. J. Strike hydroelectric projects. During the study, Idaho Power ann_u-?-lty alternated'operating the Bliss and Lower Salmon facilities under ROR and load-followingoprerations. Study results indicated that while Ioad-following operations had the potential:to'harm:individual snails. the operations were not a threat to the viability or long-term persistencO, of the sp.ecies. A Bli.ss Rapids Snail ProtectioiiPlan developed in consultation with the FWS was completed in March 2010. The plan (eniifies apppriate piotection rneasures to be implemented by Idaho Power, includingffiffiiitoring sn6i'l populationsin the Snake River and associated springs. By irnplementing the pf6-Ee.tion alldl #I#Jing{easures, the cornpany has been able to operate the Lower Salmon and BliS,$pp'lffi0ts in loati:foll'dwing mode while protecting the stability and viability of the=ft.$,yffi.4pids stiEil ldaho Power has received a license amendment from FERC for both prgledt[tffiffiliorrys load;fo]lowing operations to resurne. Water,Lease Agreements Idaho Powefl.iews the rentat of water for delivery through its hydroelectric system as a potentially coskffective pO r-supply alternative. Water leases that allow the company to request delivery'W}en the:water is needed are especially beneficial. Acquiring water through the water bank also heipS.thi company to improve water-quality and temperature conditions in the Snake River as part of ongoing relicensing efforts associated with the HCC. The company signed a rental agreement in 2012 with Water District 65 in the Payette River system to rent 10,000 acre-feet of storage water released in February 2012. In August 2009, Idaho Power also entered into a five-year (2009-2013) water-rental agreement with the Shoshone-Bannock Tribal Water Supply Bank for 45,716 acre-f-eet of American Falls storage water. ln 201l, the company extended the Shoshone-Bannock rental agreement for two additional years, 201 4 and 201 5. Page 32 2015 tRP ldaho Power Company 3. ldaho PowerToday Under the terms of the Shoshone-Bannock rental agreement, the company can schedule the release of the water to maximize the value of the generation from the entire system of main stem Snake River hydroelectric projects. The company plans to schedule delivery of the water between July and October of each year during the term of the agreement. The Shoshone- Bannock agreement was executed in part to offset the effect of drought and changing water-use patterns in southern Idaho and to provide additional generation in summer months when customer demand is high. Idaho Power intends to continue to pursue water-rental opportunities as part of its regular operations. Gloud Seeding In 2003, Idaho Power implemented a cloud-seeding program to and middle forks of the Payette River watershed. In 2008, Idaho in the south expanding its program by enhancing an existing program operated by a coaliti6iil6f cou nd other stakeholders in the upper Snake River Basin above Milner : Idaho inued recentlyto work with the stakeholders in the upper Snake River nd the program a collaborated with irrigators in the Boise and Wood Ri ins to,nxpand the include those watersheds. Idaho Power seeds clouds by introducing silver iodide (AgI) into winter storms. Clo seeding increases precipitation from passi winter storm systems. If a storm has the ri combination of abundant supercooled liquid 2. /.tl::a)a:;:.::- 'at$tSn elevationr "WK/,, Mfiilified aircraff-,ti.ti.yL;.:::= UW Remote cloud-seeding generator. flares containing AgI Agl is a very efficient ice nuclei that allows it to be used in minute quantities. It has been used as a seeding agent in numerous western states for decades without any known harmful effects (http://weathermodification.org/images/AGl_toxicity.pdf). Analyses conducted by Idaho Power since 2003 indicate the annual snowpack in the Payette River Basin increased between 1 and 28 percent annually with an annual average of l4 percent. Idaho Powerestimates cloud seeding curently provides an additional 250,000 acre-feet from the upper Snake River, and 269,000 acre-feet from the Payette River. At program build-out, Idaho Power estimates that '...aa:::aa.:::a:::= iiNrlgg Benefits of eift-E-r=+ethod-.r2.?.--B by storm, and the combination of the two methods provides the most flexibility'ifficcessfully place Agl into passing storms. Minute water particles within the clouds freeze on coTf{Ffwith the Agl particles and eventually grow and fall to the ground as snow. 2015 tRP Page 33 3. ldaho Power Today ldaho Power Company additional runoff fiom the Payette, Boise, Wood, and Upper Snake projects will total approxirnately 1,000,000 acre-fbet. Studies conducted by the Deserl Research Institute fiorn 2003 to 2005 suppoft the effectiveness of Idaho Power's program. For tlre 2014 to 2015 winter season, the program included 23 remote-controlled, ground-based generators and2 aircraft for operations in the west central mountains (Payette, Boise and Wood River Basins. The Upper Snake River Basin program included 2l remote-controlled, ground- based generators operated by Idaho Power and 25 manual, ground-based generators operated by the coalition of stakeholders in the Upper Snake. Idaho Power provides meteorological data and weather fbrecasting to guide the coalition's operations. Coal Facilities '.- . j: Jim Bridger .,=.,,,,, ',,'r'= ldaho Power owns one-third, or 771 MW (generator nameplat'e rating), of the JirnBridger coal-fired power plant located near Rock Springs, Wyoming. The Jirn Bridger plant consists of fbur generating units. PacifiCorp has two-thirds owndilflleip and is,ftE'operator of the Jirn Bridger lacility. North Valmy .:i;;,ij:;,,,,,:,,= Ei ,,,.: -:): -, Idaho Power owns 50 percent, or 284 MW (fuEii ffir,t4meplateligtingl. of the North Valmy coal-fired power plant located near Winnemu'Cca, Nevad"ai=+h"erNorth Valmy plant consists of two generating units. NV Energy has 50 p6'f nt ouiribrilii ',, d is the operator of the North Valmy facility. Boardman Idaho Power owns t O p.i".nt, * 9.7.,,,,,4,ttt=y.,;a$enffi. nameplate rating), of the Boardman coal-fired power plant lodffi,,nCIdf;tsbaidfilri, Oiegon. The plant consists of a single generating Lrnit. Portland G.=.en=,.9,;3!.Electfi$riffi,SE) has 90 percent ownership and is the operator of the Boardman facility. The 2015' P assumes Id$E,.Power'31hare of the Boardman plant will not be available after Decembsr'31,2020.The242,U;date is the result of an agreement reached between the Oregon Dep ent of Environrnental Quality (ODEQ), PGE, and the Environmental Protection Agency (EPA) lared to compliance with Regional Haze Best Available Retrofit Technology (RH BART) rulEs particulate matter, sulfur dioxide (SOz), and nitrogen oxide OO,) emissions. At the end of 2014, the net-book value of ldaho Power's share olthe Boardman flacility was approximately $20.9 million. Natural Gas Facilities Langley Gulch Idaho Power owns and operates the Langley Culch plant, a nominal 318-MW natural gas-fired CCCT. The plant consists of one 187-MW Siemens STG-5000F4 combustion turbine and one 131.5-MW Siemens SST-700/SST-900 reheat steam turbine. The Langley Culch plant. Page 34 2015lRP ldaho Power Company 3. ldaho Power Today located soLrth of New Plyrnouth in Payette County, Idaho, becanre cornmercially available in June 2012. Danskin Idaho Power owns and operateslhe2Tl-MW Danskin natural gas-fired, SCCT facility. The facility consists of one 179-MW Siemens 501F and two 46-MW Siernens-Westinghouse W25lBl2,{ combustion turbines. The Danskin facility is located noflhwest of Mountain Home, Idaho. The two smaller turbines were installed in 2001, and the larger turbine was installed in 2008. The Danskin units are dispatched when needed to support systern load. Bennett Mountain =- Idaho Power owns and operates the Bennett Mountain plant, which consists qf a 173-MW Siemens-Westinghouse 50lF natural gas-fired SCCT located east of the Dans-kin plant in Mountain Home, Idaho. The Bennett Mountain plant is also dispatched as n..ded to suppoft system load. Salmon Diesel 1,,, , Idaho Power owns and operates two diesel generation unitsilodated in Salmon, Idaho. The Salmon units have a combined generator narneplate rating of 5 MW and are operated duringemergency conditions, primarily foi:V.d] 4nd.Ioad support. Solar Facilities i,, ,= ln 1994, a 25-kW solar photovoltiic (PV) array with 90 panels was installed on the rooftop of Idaho Power's corporate h,,g,,,,,,,,,,,,,fldguarters (CHQ) inB9se, Idaho. The 25-kW solar array is still operational, and Idaho,ld . uses th0 hourly genii#ion data fiorn the solar array for ,";.:::::::: : : Idaho Power also uses s^ufft inels in its daily operations to supply power to equipment used for monitoring#aterQ ity, rileasuring streamflows, and operating cloud-seeding equipment. In additionffi,these so P.!, installations, ldaho Power participates in the Solar 4R Schools Prograry;;afuns a mobile so+-41trailei that can be used to supply power fbr concerts, radio rd'.lti6irlr,-O other evd s. Net Metering S,ewic a,... ,ti)":'' Idaho Power's net'mgtering service allows custon-lers to generate power on their properly and connect to Idaho Power's system. For net metering customers. the energy generated is first consumed on the property itself, while excess energy flows out to the cornpany's grid. The majority of net metering customers use solar PV systems. As of May I ,2015, there were 479 solar PV systems interconnected through the company's net rnetering service with a total capacity of 3.316 MW. At that time, the company had received cornpleted applications for an additional 48 net metered solar PV systems representing an incremerrtal capacity of 0.498 MW. For further details regarding customer-owned generation resources interconnected through the company's net metering service, see Table 3.3. 2015 tRP Page 35 3. ldaho PowerToday ldaho Power Company Table 3.3 Net metering service customer count and generation capacity as of May 1,2015 Number of Customers Generation Capacity (MW) Resource Type Active Pending Total Active Pending Total 479 70 10 559 48 2 527 72 10 609 3.316 0.557 0.147 0.498 0.010 0.000 0.508 3.814 0.567 0.0147 4.528 ln2009,the Oregon Legislature passed Oregon Revised Stutu.,3, lOnS) 75;.i&as amended by House Bill 3690, which mandated the development of pilo+ffigrams for electiiiGdities operating in Oregon to demonstrate the use and effectivenpst of volumetric incentiqgrates for electricity produced by solar PV systems .," :.,-)::::::-,.,;i::::::;.a? As required by the OPUC in Order Nos. l0-200 and I I -08-,9;r#6fio Power established the Oregon Solar Photovoltaic Pilot Program in 2010, offering'f,$lrmetric incentive rates to customers in Oregon. Under the pilot progt, *,,.?,. * Power a$fi$t:d 400 kWac of installed capacity from solar PV systems with a nafiUfilatf;6-ffffigni[y of lesffin or equal to l0 kW. In July 2010, approximately 200 kW were allocated,,arl6 thei*maix..*,,,9?00 kW were offered during an enrollment period in October 201 l. However;:fficallf iome"Pfif1ystems were not completed from the 2Ol I enrollment, a subsequent offerin[ rtd{ n"lO on April l,2Ol3, for approximately 80 kw. ln 2013, required capacity the Oregon t-efi-iature oppfd House -eiliTSOr, which increased Idaho Power's capacity amouritll$s kW, Arl eniollment period was held in April 2014, and all was 1ll.ocat1d., bringi aho Power's total capacity in the program to 455 kW. "if" , Under the--9"igg6; Soiai'p.vLapacily,standard as stated in ORS 757.37O,ldaho Power is required,tEeither own or pEdase lllH,rgsneration from a 500-kW utility-scale solar PV facility bV 202$4lililnder the rules, if utility scale facility is operational by 2016,the RECs from the project wodld:be doubled foEurposes of complying with the State of Oregon RPS. Page 36 2015lRP ldaho Power Company 3. ldaho Power Today Power Pu rch ase Agreemenfs Elkhorn Valley Wind Project In February 2007 . the IPUC approved a PPA with Telocaset Wind Power Partners, LLC a subsid iary of Horizon Wind Energy, for I 0l MW of narneplate wind generation from the Elkhorn Valley Wind Project located in northeastern Oregon. The Elkhorn Valley Wind Project was constructed during 2007 and began commercial operations in December 2007. Under the PPA, Idaho Power receives all the RECs from the project. Raft River Geothermal Project In January 2008, the IPUC approved a PPA for -'i'::':';;:';:': "''i#ilrnt in october 2007 under asouthern ldaho. The Raft River project began commerciffi,p€i of the RECs from the project for generati 0 aMW.t; nthly. The Raft River geothermal project has rarely exceeded the "generation since 2009, and thAftHIt River geothermal project. For PURPA contract with Idaho Power that was.canceled when the,,pew PPA was approved by the IPUC. For the first 10 years (2008_2017)ffiffi1*ffigment, Ifiilo Power is enti;led to 75 percent Idaho Power is current|y receivingrregligible the second l0 years of the a5reffii|#=!?Ott:.-;1A;.1/ -'':.aa::al:aa.= RECs generated by the pro)ffi{( ':-daho Power is entitled to 5l percent of all Neal Hot Springs In May 2010, the IPUC imately 22MW of nameplate generation from the Neal Hct.S-plings Project located in eastern Oregon. The Neal Hot Springs in November 2012. Under the PPA, Idaho Power receives In SepternberZA09,ldaho Power and the Clatskanie People's Utility District (Clatskanie PUD) in Oregon entercd'into an energy exchange agreement. Under the agreement, Idaho Power receives the energy'4$'is generated from the lS-MW power plant at Arrowrock Dam on the Boise River; in exchahge, Idaho Power provides the Clatskanie PUD energy of an equivalent value delivered seasonally-primarily during months when Idaho Power expects to have surplus energy. An energy bank account is maintained to ensure a balanced exchange between the pafiies where the energy value will be determined using the Mid-Columbia market price index. The Arrowrock project began generating in January 2010, and the agreement term extends through 201 5. Idaho Power also retains the right to renew the agreement through 2025 . The Arrowrock project is expected to produce approximately 81,000 MWh annually. 2015 tRP Page 37 3. ldaho Power Today ldaho Power Company Public Utility Regulatory Policies Acf In 1978, the US Congress passed PURPA, requiring investor-owned electric utilities to purchase energy from any qualifying facility (QF) that delivers energy to the utility. A QF is defined by FERC as a small renewable-generation project or srnall cogeneration project. The acronym CSPP (cogeneration and small power producers) is often used in association with PURPA. Individual states were tasked with establishing PPA terms and conditions, including the price, each state's utilities are required to pay as paft of the PURPA agreements. Because Idaho Power operates in Idaho and Oregon, the company must adhere to both the IPIJC rules and4gulations for all PURPA facilities located in the state of Idaho and the OPUC rules and regulations for all PURPA facilities located in the state of Oregon. The rules and regulatio6 are similar but not identical for the two states. Because Idaho Power cannot accurately;i$fedi0t,the level of future PURPA development, only signed contracts are accounted for in Idaho Power's resource planning process. .i ='. ,,,',111,_ Generation from PURPA contracts has to be forecasted -dliiin the IRP planning process to update the load and resource balance. The PURPA fsrccast used in the ZOt 5 IRP was completed in October 2014. As of March3l,2015, Idaho Power had 133 PURPA contiacts.:,with independent developers for approximately 1,302 MW of nameplate "atr#,!,lfiy,,,t}hese PURPA contracts are for low-head hydroelectric projects on various irrigationthpalslffigen-eration piojects at industrial facilities, wind projects, solar projects, anaerobic dige's$rs, landfilffaB ood-burning facilities, and various other small, renewable-pQ=wrr generaftn faelities. oAthe 133 contracts, 105 were on- line as of March 31,2015, with,'a,,.b@ulative nameplate rating of approximately 781 MW. Figure 3.5 shows the percentage o-f,,rh€ total'P€RPA capacity of each resource type under contract. Biomass 2% Hydro 12% Figure 3.5 PURPA contracts by resource type Published Avoided Cost Rates A key component of PURPA contracts is the energy price contained within the agreements. The federal PURPA regulations specily that a utility must pay energy prices based on the Solar 35% Wind 4B% Page 38 2015 tRP ldaho Power Company 3. ldaho PowerToday utility's avoided cost. Subsequently, the IPUC and OPUC have established specific rules and regulations to calculate the published avoided cost rate Idaho Power is required to include in PURPA contracts. Some of the general guidelines being: Published avoided cost eligibility . Idaho-Windandsolarprojectswithanameplateratingoflessthan l00kWandallother projects less than l0 average MW calculated on a monthly basis . Oregon - All projects with a nameplate rating of less than l0 MW;,, For all projects that are not eligible for the published avoided cost ratefiique negotiated avoided cost is calculated for each project. The basis forthis negotiat€d' ided cost rate is the commission approved incremental cost IRP avoided cost methoddlbgy. IrflQtilh Idaho and Oregon the published avoided cost is different based upon the resource type'(i#i wind, solar, hydro. base load). REC ownership ,rW:' #,",$, ';' . Idaho - Projects that contract with Idaho Powdill!{$ing1.h-=€-i::ftblished avoided cost rate will retain all renewable energy certificates (REC) asSociEfu with the project. If the PURPA contract contains negotiated rates, IBU.C,Order No. 3?.@l issued December 18,2012, stipulates that the RECs will be e$1,fl,"[.ff11, $,,y:d between ldaho Power and the project owner ::::: .' ""'.:::::a:::1,.: ). oregon - The project -o,I.,t.r..ruins ati ito the nECr associated with the project . :... ",' On January 30,2015 ldahoP wer fi at the Iddfib PUC a petition requesting the required contract term within newldaho PURP# contractS",Ee.revised from 20 years to 2years. The IPUC opened case IPC-E-15-01 to addrqps.,}*,il$lim?ltot and'a hearing is scheduled for June29,2015. IPUC OrderNo.33222, isslred F$.,pfuary"6:2'0tNffitemporarily revised the contract term from 20 years to 5 years-.du1ing the pioceSsing of the case. :t: In April !}li;in" OpUC iTued OiderNo. l2-146, which opened OPUC Docket UM 1610. Oockefi6Qfl 1610 addresse5*any ofthe same PURPA issues identified in the recent Idaho PURPATdi&s as well as uni#e PURPA issues associated with Oregon. Parties have been filing testimony ahd mrnents iffie case. The initial hearing was held in Salem, Oregon, on May 23, 2013. This caS€'j,smoving into its second and third phases continuing to review and address numerous PURPA iefalgd issues. On December l8,2012,the IPUC issued OrderNo.32697. OrderNo.32697 included new rules and regulations in regard to the numerous PURPA issues presented in the various cases that began in November 2010. Some highlights are as follows: . The published avoided cost rate is available only forwind and solarprojects with a nameplate rating of less than 100 kW. . For all other resource types, the eligibility cap remains at l0 aMW. 2015 tRP Page 39 3. ldaho Power Today ldaho Power Company . Idaho Power's proposed incremental cost IRP methodology was approved to calculate the avoided cost pricing for projects ineligible for published avoided costs. o A unique published avoided cost was established for wind, solar, hydroelectric, canal drop hydroelectric, and other projects. . The QF project owner retains the RECs associated with the project for QF contracts containing published avoided cost rates. . Idaho Power shall be entitled to 50 percent of the RECs for QF contracts that contain negotiated rates. ,= :,:.=::: On May 6,2013, the IPUC issued Order No. 32802 concerning the,recois--fution of Case No. GNR-E-l l-03. Order No. 32802 affirms many of thg commission itilings in Order No. 32697. PURPA contracting continues to be an isiiie'in ldaho, and appi$imately 200 MW of various QF projects currently have some form of a filed dispute in regards to PURPA contracts with Idaho Power. Wholesale Contracts Idaho Power presently has no long-term (no long-term wholesale plkhorn, Raft Riversales contracts and no long-term who Geothermal, Neal Hot Springs, and Clatskan ts were described previously ln the Power Purchase Agreements section of Idaho Power relies on ffi.ffi=nuf rrra1k' ppty gnificant portion of energy and capacity ,/iffil M a rket P u rc h a s es a.r+trS;fffi .==-E=E)'.,lS:a...;a:ai: . , ,:!.:,1..aaai needs during certain lirffd{;jgneeds during certain tirneq of thq.,!${f."fdffit|m"i[Far is especially dependent on the regional markets during peak-load pefiq_dj, and the existing transmission system is used to imporl the_ .-...:.._:.+:1:i/.@&"r. .il:-i-+liiB,,r energy purch.g4p,E .=: ce oiffigonal markets has benefited ldaho Power customers during times of l.gffiFftt"t ttrffiugh tlre iffirt o^f low-cost energy. Custom.ers. also benefit from sales iated with s en from economically dispatched resources. Page 40 2015 rRP ldaho Power Company 4. Demand-Side Resources 4. DemaND-SrDE ResouncEs !ntrod uction Demand-side resources have been the first resource choice in every IRP since 2004. No supply-side generation resource is considered as part of ldaho Power's plan until all future achievable potential energy efficiency and demand response is accounted for and credited against future loads. In the 2015 IRP demand response will provide 390 MW of peak summer reduction while energy efficiency will reduce average annual loads by 301 aMW and 473 MW of peak reduction by the year 2034. DSM Program Overview of programs consists of demand response, e$ffiy effigiddC!.;=.,. market transformation during periods of extreme,nliiE *h;ii;ftil other resqurces, including market purchases, are at their maximum capacity. E and are the demand-si targets energy savings Cost-effectivene,i*.ffiffiei, which indicate whether the benefits of these programs exceed the costs to administer'ffi$.;$rograms along with the costs incured by participants, are published annually. The most recent analysis can be found inthe Dentand-Side Management 2014 Annual Report Supplement l: Cost Effectiveness. Each program and its component measures in the existing portfolio of demand-side resources are reviewed for their load impact over the 2}-year IRP planning horizon as part of the IRP process. Additionally, in 2014 ldaho Power contracted with Applied Energy Group (AEG) to conduct an energy efficiency potential study which resulted in a forecast of energy savings over the 2U-year IRP planning period. The resulting AEG forecast and program history were analyzed against the load forecast to ensure that the energy efficiency forecasted by AEG was credited with offsetting future loads. Details on the integration CSQHA's.14 'offices req-E-i the City of Boise Building E xce I I e n cd18#a r,! s f o r.-EB-Sf€ u sta i n a b I e C o m m e rc i a I P roj e ct organizationsffige=mo,le energy efficiency. Idaho Power has collaborated with other regional utilities and,.ffi$ffi'Y--fio$q,and furded Northwest Energy Efficiency Alliance (NEEA) market transforrni!€i5h activitieilrbirige 199?,,'Eaergy efficiency, demand response, and market transfoffin qrgglams. lffij*r.g t'd all four major customer classes:residential, irrigation, 2015 rRP Page 41 4. Demand-Side Resources ldaho Power Company of the energy efficiency fbrecast are fbund in Appendix A-Sales and Load Forecast and also in Appendix C'-Technicul Apperulix in the Demand-Side Management section. DSM Planning Changes from the 2013 IRP Demand response and market transfbrrnation were considered differently in the 2015 IRP than the previous 2013 plan. Since rnarket transfbrmation was included in the 2014 AEG study, market transformation savings are considered as a demand-side resource in the 2015 IRP whereas in the past market transfbrnration savings have been excluded from resource planning. In the 2015 IRP, demand response was treated as both a committed resoulte based on cost- effectiveness and as a potential new future resource addition beyondth ommitted resource level in select portfolios. ;, . :l -'/!.l.gr ".t:::=t, The 2013 IRP load and resource balance analysis demonstral*tno capacitydefiejts in the near term. As a consequence, Idaho Power temporarily suspende.{f{tuo of its three demiind response programs for summer 2013 under IPUC Case No. IPC-E}I9:Z9 and Tariff Advice No. l3-04 with the OPUC. The suspension of the irrigation and.qi$iitlential demand response programs would only last the one year because through IPUC Case No _IPC-E-l 3-14 (Order No. 32923) and OPUC CaseNo. UM 1653 (OrderNo. l3-482). IdahoPo*erand interested partiesreached a settlement agreement to continue the comffiy-'s demand re$-*.ase programs for 2014 and beyond. l' " :/ :5 1 ln the 2015 IRP 390 MW of Demanrl Response capacity is uded in every portfolio and up to an additional 60 MW in some portfolios as needed-1n2014,'ihieSe programs cost $10.6 rnillion; had the programs been used for the. m'aximum niiffiUer of hours, the cost would have been approximately $13.8 million.:'Ihese cti$ts represd,fl pproximately $6 million dollars in savings compared to 201 2 (S?l.2fiillion) and are significaruly less than the annual value of $16.7 million agreed on in the settlernent agfEemenl,i,rAnffier result of the settlement was guidance on how to operate the programs in y--,,,eari wheie'tHd#tinay not be short term peak capacity deficits. To maintain cust-omer engagement as pafticipants in demand response programs, ldaho Power would condueti=*iAimul If thr". .r.nts even when the extreme loads, low water, and extreme temperature aisumptions that demand response programs were designed to meet did not occur. In additign to custorner retention, the three events would allow for annual operational evaluation and incieased experience in dispatching the programs to maximize peak reduction. Since demand response is considered a cornmitted resource to the company and the potential load reduction of 390 MW from.'d€-mand response was applied to future peak summer loads prior to the selection of additional resources to'meet firture peak deficits. Market transformation achieves energy efficiency savings through engaging and influencing large national and regional companies and organizations. These organizations influence the design of energy efficiency into products, services, and practices that improve their energy efficiency. Idaho Power achieves market transformation savings primarily through its participation in the Northwest Energy Efficiency Alliance OEEA). Idaho Power has been a funding rnenrber of NEEA since its inception in 1997. Historically, Idaho Power has treated the savings reported by NEEA separate fiom savings fiom company run and adrninistered ef frciency prograrns. While the cornpany has been supporting Page 42 2015lRP ldaho Power Company 4. Demand-Side Resources rnarket transfbrrnation since the regional collaborative started, the value in the programs for Idaho Power was to promote new savings potential technologies and to look for new opportunities to be adopted into Idaho Power's program offerings. Exanrples of this would inclLrde residential energy efficient lighting that started out as a NEEA initiative to promote cornpact f'luorescent technologies and transitioned to utility prograrns across the Nofthwest inclLrding Idaho Power. Another reason affecting how nrarket transformation savings were used in resource planning was related to how savings were attribr.rted to utilities. Until 201 0 NEEA prirnarily apportioned savings by how much each regional funder Lrtility contributed to their various initiatives and there was very little effort pr-rt in to geographically pinpoint where the savings occurred. 'fhis made it difficult to count on NEEA savings that rnay or may not be actually reducing ldaho Power loads while reducing regional system,loads- : :,1 ,;':' ':,:: . Since 2010, NEEA has been working on and continuously improving its ability through evaluation and increased data collection to verify savings atflre service area level of its funders. This allows Idaho Power to include market transforrnation savings as part of thE'Company's ellorts to rneet IRP energy-savings targets. Anotherconsideiation to lully integrate market transformation into the IRP is that the AEG potential.;,Sfidy that detennines the energy efficiency forecast is agnostic to where the savings for any potefi'tilmeasure or technology come from or who provides them. The forecasted future savings can come from market transfonnation efforts done on a regional basis or from a traditiona)rffirry admini$tered program. Program Screening '"iitr11{ot:"it:lt'' " :'' ' ,,ti, .- ',-',,.' All DSM programs and measuresincluded in'Idaic?5wer's current porlfblio of programs and the forecast have been screened-'f6*@-effecti'Vdfitss. Cost-effectiveness analyses of DSM forecasts for the 2015 IRP are presented in more derail in Appcndix C-Technical Appendix- Appentlix B-Demand-$@'''Monrge*i'*t 2014 Aii,.friol Report contains a detailed description of Idaho Power's 20la cn#"€-lt nergy.#ei o:y..p=r@m porlfolio along with historical program performance (appendicei'Wila,p,$1ff-nie filed'as: efi of this IRP). A complete review of Idaho Power's DSMprograii\lll,Wvaluations, and cost-effectiveness can be can be found in the 2014 annrralfepdft filing;.Dem:"11h4,5;4u Management 2014 Annttal Repnrt, Supplement l: Cost- E/f'ective ness, Supplement 2: Evaluaiion, which is available on the ldaho Power website at http ://www. i d ahopower.coffi nergyEffi ciency/reports.cfm. DSM Program Performance While the IRP planningprocess primarily looks forward, it is also important to review historical DSM perfbnnance to understand the effects on systern load. Accurnulated annual savings frorn energy efficiency investments grow over time based on measure lives of the efflcient equipment and measures adopted and installed by customers each year. Additionally. past performance of denrand response programs has changed over time as the design and use of the programs have evolved. Energy Efficiency Performance Energy efficierrcy investrnents since 2002 have resulted in a cumnlative average annual load reduction of 167 aMW or over 1.4 million MWh of reduced supply-side energy production to 2015 tRP Page 43 4. Demand-Side Resources ldaho Power Company customers through 2014. Figure 4.1 shows the cumulative annual growth in energy efficiency effects over the l3-year period from2002 through 2014 along with the associated IRP targets that were developed as part of the IRP process since 2004. Figure 4.1 Cu Demand Res current demand response have,p,,$. 6mand-side portfoIio since the 2004 IRP. The Waf.fi9* made-iii"€,frihree distinct Drosrams that work tosether as*,W madeif ree distinct programs that work together as Demand response one resource.a different customer class. Table 4.1 lists the three programs that make u se portfolio along with the different program Peakteyrards program represents the largest percent of potential uction. During 2014 summer season participating irrigation program customers contribu Power's percent ofth tal potential demand reduction or 295 MW. More details on Idaho 2014 Annual :-l Table 4.1 rtfolio of demand response programs 180 160 FAuoIq,P 't20 GF E'E 100 oE" =80Goo.: 60s3c540o 20 response can be found in appendix B, Demand-Side Management 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Program Customer Class Reduction Technology 2014 Peak Percent olTolal2014Performance Peak Performance A/C Cool Credit lrrigation Peak Rewards FlexPeak Management residential irrigation commercial, industrial central A/C pumps various 44 12% 295 78% 40 11% Page 44 Total 378 2015 tRP ldaho Power Company 4. Demand-Side Resources Figure 4.2 shows the historical annual demand response program capacity between 2004 and 2014 along with associated IRP targets between 2004 and 2012. There were no targets for the years 201 3-2014 in the 2013 IRP. The large jump in demand response capacity from 6l MW in 2008 to 218 MW in 2009 was a result of transitioning the majority of the lrrigation Peak Rewards program to a dispatchable program. The demand response capacity in201l and2012 included 320 and 340 MW of capacity from the lrrigation Peak Rewards program, respectively, which was not used based on the lack of need and the variable cost to dispatch the program. The reported capacity value was lower in 2013 because of the one year suspension of the irrigation and residential programs' .,,1',"is.: Fisure o, ^rr,rtL'u-**W*ffiffiiif,,;^reduction capacitv and tRp tarsets, 2004-2014 ruwl Coqt-ted E ne f Effi'€ibn cy Forecast For the 201' il&P, Applied E].gy Group (AEG) was retained to update the previous study from 2012 and pro9,id'p:an updale O-year comprehensive view of Idaho Power's energy efficiency potential. fhe o6jlecti.v.g.,,q1! he2014 potential study were as follows: ::::::r Incorporate th'b rapid changes in residential lighting potential based on the impacts from LED lighting. . Provide credible and transparent estimation of the technical, economic, and achievable energy efficiency potential by year over 20 years (2015-2034) within the ldaho Power service area. . Assess potential energy savings and peak demand associated with each potential area by energy efficiency measure or bundled measure and sector. t 400 3F 3s0oGo3 aoo .93 2sot,oE:o 2OO G E6 1so IGoG 1oo 201420132011 20'l5 tRP Page 45 4. Demand-Side Resources ldaho Power Company Provide a dynamic model that will suppoft the potential assessment and allow testing of the sensitivity of all model inputs and assumptions. . Develop a final repofi, including summary data tables and graphs reporting incremental and cumulative potential by year frorn 2015 through 2034. Because the potential study's market characterization process bundles industries and building types into homogenous groupings, Idaho Power's special contract custorrers were treated oLrtside of the potential study rnodel. Forecasts fbrthese unique customers, who tend to be very active in efliciency, were based on the combined customer group's history of participation along the near-tenx pipeline of projected projects. .l In the AEG study, the energy efficiency potential estimates represg-nt gross savings developed into three types of potential:technical potential, economic potentihl, and aclr:i ble potential. Technical and economic potential are both theoretical lirnits to efficiency savings. Achievable potential embodies a set of assumptions about the decisions consumers make regarding the efficiency of the equipment they purchase, the maintenance activities they undertake, the controls they use for energy-consuming equipment, ri'iid the elements of building construction. These levels are described below. ...,,,.o Technical-Technical potential is $e.!ihgq.as the theoietical upper limit of energy efficiency potential. Technical potentiaf*sumes customers adopt all feasible measlrres regardless of cost. At the time of equipment replacement, cristomers are assumed to select the most efficient equipment available* neW construction, customers and developers are also assumed to choo.iE-t-h+.most effi'0ient'equipment available. Technical potential also assumes the adoffiidn ofi ry otherapplicable measure available. The retroflt measures are ph"p.,$.i n over.,ffimber of ygars, which is greater for higher-cost measures. Economic potehiial assum at the fime of equip*"nifut" ufi l tto adopt every other cost-effective and . Achieiible-Achievable potential takes into accolrnt market maturity. customeiplef"reniei for energy-efficient technologies, and expected program participation. Achievable potentiaI establishes a realistic target fbr the energy efficiency savings a utility can achieve through its programs. It is detennined by applying a series of annual market adoption factors to the economic potential for each energy ef ficiency measure. These factors represent the ramp rates at which technologies will penetrate the market. The potential study followed a standard approach in developing the achievable potential. First, the market was characterized by customer class. The classification phase included segmenting the market by housing type for residential and understanding tlre various industries and building types within the commercial and industrial custorrer classes. Saturations of end-use Page 46 2015 tRP ldaho Power Company 4. Demand-Side Resources technologies within customer segments are assessed to help determine which technologies are available for efficient upgrades. The next step was screening measures and technologies for cost-eff-ectiveness, and then assessing the adoption rates of technologies to determine the forecast of achievable potential. More detailed inforrnation aboLrt cost-effectiveness methodologies and approaches can be found in Appenclix C Technical Appendix. The annual savings potential forecast is provided to ldaho Power in GWh, where it is converted to hourly and then monthly demand reduction (aMW) to compare with supply-side resources for the IRP analysis, the savings are shaped by end Lrse load shapes that spread the forecasted savings across all hours of the year. The load shapes used to allocate savingi by end-use were provided by AEG as parl of the study deliverables. AII reported energy..fficiency and demand response forecasts are expressed at generation level and therefore include line losses of 9.6 percent for energy and 9.7 percent for peak demand to account for energy that.would have been lost as a result of transmitting energy from a supply-side genei:alicin resourcO e meter level. Table 4.2 shows the forecasted potential effect of the currenf portfolio of energy efficiency programs for20l5 to 2034 in five-year blocks. in terms of cumulative average annual energy reduction (aMW) by customer class. ln 2019. the forecast reducti_,6 for 2015-to-2019 programs is forecast to be 84.3 aMW; by the mid-point plan year 2024,ihe cumulative reduction across all customer classes increases to 169.4 aMW. By the end of the==lRP planning horizon in 2034, 300.8 aMW of reduction are forecast to come frqmthqenergy efficiency portfolio, with 55 percent of forecasted reduction coming from programs serving commercial alid'industrial customers. Detailed year-by-year forecast values can be foun d in Appendix C-Technical Appendix. Table 4.2 Totalenergy efficiency,,current portfolio forecasted effects 12015-20341(aMW) 20't5 2019 2024 2029 2034 I nd u stri a l/Co mm e rci a l/S pecia 1& ntra cts .. ..,. t:;., Residentiar :'1=. ......:,::.11 . 6 3. 1 't2 46 z6 11 84 93 55 22 169 138 85 23 246 167 111 23 301 lrrigation.... Total*........ .trr,. -T,i,lrlT:add exactry due torffi:ns :':l Table 4.31$lib.ws the cost-effeCtiveness sumrrary from the potential study. The table shows the net present val'tie Q\PV) analisis of the 2}-year forecast of the total resource costs (TRC) and DSM preliminzlry. ahgmatiG costs or program benefits. TRC costs account for both the costs to administer the pr6$ams and the custorner's incremental cost to invest in efficiency technologies and measures offbred through the prograrns. -l-he beneflt of the programs is avoided energy, which is calculated by valuing energy savings against the avoided generation costs of Idaho Power's existing rnarginal resources. 2015 tRP Page 47 4. Demand-Side Resources ldaho Power Company Table 4.3 Tota I energy efficiency portfolio cost-effectiveness summary 2034 Load Reduction 2034 Peak Load(aMW) Reduction (MW) Resource Total Benefits costs ($000s) ($000s) (20-Year NPV) (20-Year NPV) TRC: TRC LevelizedBenefiU Costs Cost Ratio (cents/kWh) Residential I ndustrial/Commercial/ Special Contract lrrigation Total 't 11 167 23 301 175 226 72 473 1.6 2.4 1.6 .,.1 98 3.3 10.3 6.1 $425,360 $253,982 $1 39,1 90 $81 8,s32 $691 ,1 5 1 $618,633 $222,009 $1,s31,793 The value of avoided energy over the 2}-year investment in the eneffi almost twice the TRC when comparing benefits and costs resultil}flffiffiz ratio of 2. The levelized cost to reduce energy demand by 30l,alVtXV an 473 MW is 6.1 cents per kwh from a TRC perspective. ..:1:!|ljl codes and standards, cLrstomer adoption behavior, and coSffibtiveness that are explicitly Once the energy efficiency forecast is complete, the fo1$CIffited enelgy efficiency is ir'icluded in the IRP planning horizon and the load and resource Wii#X" analysislPlanning assumptions in the energy efficiency potential forecast include new pibg".Sdils,;ffthnology, known changes to Under the current program"d:eB-i and participation levels, demand response frorn all programs is forecast to provide 390 MW tffpeak reduction'i,llyring Ju$ throughdut the I RP planninfu riod with additibhal program poteritial available during JLrne and August. The comm itted demand responsa included in the IRP has a capacity cost of $33 per annual kW/year. Non-Cost-Effective DSM Resource Options AEG provided additional potential study analysis to rnodel additional achievable potential that would occur if the cost-eflfectiveness benefit cost ratio requirements of a Total Resource Cost (TRC) test were changed from the standard requirement of one or greater Typical irrigation pivot supplied by a pump participating in the lrrigation Peak Rewards demand response program. Page 48 2015 tRP ldaho Power Company 4. Demand-Side Resources down to a value of 0.8. The revised assumptions in the rnodel produced a non-cost-effective potential of l6 aMW and 24 MW of peak reduction over the 21-year IRP planning horizon. The 2}-year present value cost of the additional efficiency was determined to have a levelized cost of 9.1 centsperkWh,whichis3.4centshigherthanthe2}-year levelizedcostoftheachievable potential within the nonnal parameters of TRC test. The additional DSM amount was made available as a resource in three of the analyzed portfolios. Additional Demand Response An additional 60 MW of demand response was made available for peak summer reduction in some portfblios. If ldaho Power were to pay increased incentive arnounts to customers then there would be added available capacity to expand the Irrigation Peak Rewards'p19gram in future years. While the current demand response portfolio cost is $33/kVV/Yr. this additional demand response capacity would cost approximately $51/kW/Yr. This;additional derfi4il4.response capacity is included in some porlfolios beginning in the yeai 202l,and is included in the preferred portfolio in 2030. .. :: ",...r11:,.Energy Efficiency Working Group =,, ., On Novemb er 4,2014, the IPUC issued O1$e6No. 33161 (CaSe No. IPC-E- l4-04) finding that Idaho Power's 201 3 DSM expenses were prudently incurred. On November 7, 2014, the IPUC issued E,rrata to Order No. 33161, stating ,nt-I'!n rel@n to issues raised in the case: The Commission agreer==th==1,,-L=$. issueS''ra!!,q=ed'b-y Stafland other parties are significant and warrant--? €.,in-depth i-w. We direct the parties to do so in the context of the Company's next Integiat_ed Resource Plan filing. , In response to the Erra@iii,Idaho P.9;.w,€i..=o=1 nt2',;,.$r,V,,,fEnergy Efficiency Working Group inviting members of the IRPAC, p{.Hlie p,A l0ipaht-idtfr,6'lRP process, and the Energy Efficiency Advisory Group (EEAC) ffib'ffirgy Efficiency Working Group held two public meetings in Decernber 2014. .,, . The flrstEnergy EfficiencYrl$orkinf,,$1ellp meeting included a discussion of a broad range of energy-efficiency and resouiCe planning issues that can be classified into two general categories: (l) strategies"re.lated to energy-efficiency program delivery and (2) treatment of energy efficiency in theiesource planning process. The second Energy Efficiency Working Group meeting fbcused on,how energy efficiency as a resource should be treated in the IRP. Topics discussed at the second working group meeting included: o A cornparison presented by AEG of potential studies fiorn other regional utilities o A comparison presented by IPUC staff of Idaho Power's inclusion of energy efficiency in the IRP to the inclusion of energy efficiency by other regional utilities o An ldaho Power-led discussion of the inclusion of transmission and distribution investntent deferral into the benefits in DSM cost-ef-fectiveness analysis. 2015 tRP Page 49 Through correspondence with working grolrp parlicipants, Idaho Power expressed the view that its current treatment of energy efficiency in the resource planning process appropriately balances the need for responsible and ef-fective resource planning and the desire to pursue allcost- effective and achievable energy efficiency. Idaho Power also recognizes that achieving those balanced objectives on an ongoing basis requires continued review and evaluation of the planning process, as well as an awareness of related industry best practices. Idaho Power has committed to continue to investigate the extent to which transrnission and/or distribution benefits result from energy efficiency measures and programs, as well as the approximate value of such benefits. Idaho Power presented a status updateofthis investigation at the May 7,2015 IRPAC rneeting. ln the May 7,2015 IRPAC rneeting,'Idaho Power indicated that the study of transmission and distribution investment deferment is ongoing. Actions to be taken as part of the ongoing study include a review of transmissiorand distri-b.Lution investments related to groMh, an evaluation of the effectiveness of energy;;p,.,.,.,,fficiency mea$fi-tes and programs in deferring transmission and distribution investment, and,#stimate of deferibl=,Falue for those cases having potential for transmission andlor distributioiliiiivestment deferment. Idaho Power is also committed to continue to discusffirprogram delivery issues identified by working group participants, and by Staff and sorne interveneiS in comments filed in Case No. IPC-E-14-04. The Company plans to use the EEAG as the forum to provide customers, regulatory staff, and other interested stakeH$If,e.f,S,ai opportunify to provide advice and recommendations to Idaho Power in formulatin$, ifiple.m.q,,,9gting, ffiH evaluating energy efficiency and demand response programs ahd activities:==. ':l:::='' Conservation Voltage Reduction'' .*t"t ttt ' : tat, I The goal of conservation ltage redffion lCVR)riis to reduce electrical demand and energy by minimizing the distribufu,feeder..v.6l while pibViding service voltage within the standard operation range. Idaho Poil parti-iBntefiinrrliiifbtthwest CVR pilot and implemented CVR on a few distribution,"fee,ders. In the 201 3 lRP, ldaho Power proposed to validate the energy savings and reduced peal€dem-nd of CVR Using new technologies and methods of measurement. Idaho Power included the vali&tion plan (Conservation Voltage Reduction Enhancements Project) in *s2}l.*#iartGrid Report. Th. p.oje.t scope is to: . Valid:* ;r,t,he energy d demand savings associated with CVR at the customer level, . Quantiffthlrcosts and benefits associated with implementing CVR, o Determine methods for expanding the CVR program to additional feeders, . Pilot methods for making Idaho Power's CVR program more dynamic, and o Determine rnethods for ongoing measurerrent and validation of the CVR program's e [f'ectiveness. 4. Demand-Side Resources ldaho Power Company The CVR measurement and verification process has been identified. Idaho Power has installed the infrastructure to evaluate CVR energy savings and demand reduction at seven substations in Page 50 2015 rRP ldaho Power Company 4. Demand-Side Resources six different weather zones. In addition, new technology has been deployed on test feeders to evaluate its effectiveness in making CVR more dynamic. Hourly customer usage data will be collected from the Advanced Metering Infrastructure (AMI) system throughout the year of 2015. This usage data will be analyzed to determine how CVR impacts the customer classes in different weather zones across Idaho Power's service territory. Idaho Power expects to complete the CVR analysis in2016. Extending CVR measures to other Idaho Power facilities will then be evaluated. 2015 tRP Page 51 4. Demand-Side Resources ldaho Power Company 2015 tRP ldaho Power Company 5. Supply-Side Generation and Storage Resources 5. SUppLY.SIDE GeruenATIoN AND SronncE RESoURcES Supply-side resources are traditional generation resources. Early IRP utility commission orders directed Idaho Power and other utilities to give equal treatment to both supply-side and demand-side resources. As discussed in Chapter Four, demand-side programs are an essential component of Idaho Power's resource strategy. The following sections describe the supply-side resources and storage technologies considered when ldaho Power developed the resource portfolios forthe 20l5lRP. Not all supply-side resources described in this section were included in the prelirninary resource portfolios, but every resource described was cg,&dered. .r.:;:-ii The primary source of cost information for the 2015 IRP is a report titIffi'Lazard's Levelized Cost of Energy Analysis" 4. Other information sources were reli"*,:&WW4.b'asidered on a case- by-case basis depending on the credibility of the source and the ff$€of the'-iid,f,.,a.ynation. For a full list of all the resources considered, and cost information, pl.9#$,i see Figures 7W,!7.6 in Chapter 7. All cost information presented is in 2015 dollffilli{u * -?;,.;^-r;riti.' '"'{, Renewable Resources lt, Renewable resources are the foundation of Idaho Power,e company has a long history of ble resources were A's proposed CAA Section ,the following sections. So/ar The primary types of solar-;Lt hno le photovoltaic (PV) and distributed PV. In geneial, PV technology ati;.Us solgr energy colldiied from sunlight shining on panels of solar cells- and a nercentase clf the solaL€neirur! :.,fthserbtd into the semiconductor material. Thecells, and a percentage"'68)5.\..9 sola PV sy rrent (AC)'' .@$-tsan tfieF,,be used on-site or sent to the grid. Even on cloudy days, a n still provid€, percent of the system's rated output. solar potentia"ffi.{-:aa areailfypically, insolation is measured in kWh p".ln' per day (daily insolation averagdi&-.e.f.]l ear). The higher the insolation number, the better the solar power potential for an area.'':National Renewable Energy Laboratory (NREL) insolation charts show the Deserl Southwest has the highest solar potential in the United States. In designing initial portfolios that included solar resources, Idaho Power chose the utility-scale PV technology because of its compliance to EPA's proposed CAA Section I I I (d) rule, a http://www .lazard.com/PDF/LevelizedYo2\CostYo2\otr/o2}EnergyYo2}-Yo20Version7o208.0.pdf energy accumulate d insid6=# conductoi material energizes the electrons and creates an electric currejuk-i,rT-4:---3 flila1.".[#.=@,.,,.- on::r more e]ectric fields thal force electrons to flow in one direction uxffitr€ii-&hffi,g peji=*t e DC energy is passed through an inverter, converting it to 2015 tRP Page 53 5. Supply-Side Generation and Storage Resources ldaho Power Company its flexibility. and its lower overall cost. Solar PV technology has existed for a number of years bLrt has historically been cost prohibitive. Recent improvements in technology and rnanufacturing, combined with increased demand due to state renewable portfolio standards (RPS), have made PV resources more cost competitive with other renewable and conventional generating technologies. The capital cost estimate used in the 2015 IRP for utility scale PV resources is based on the 2014 Lazard repofi, which estimates a cost of $1,500 per kW for fixed panels and $1,750 per kW for PV with a single-axis tracking system. The 20-year levelized cost of production fbr fixed panels is $ll8 per MWh based on a21.5 percent annualcapacity factorand $l09 per MWh fbrPV with a single-axis tracking system and a26.8 percent annual capacity facto,tr, In'attempting to capture the decreasing cost of solar, Idaho Power used the 2017 forecast pro-,.i bd,by Lazard of $1,250 per kW for PV with a single-axis tracking system. To account for the decreasing cost trend seen in PV resourod-$jU|.. the past f"fifeurr, tn" 2015 IRP assumes solar PV costs remain fixed over 11'rs.2$!\)ear planning period. In comparison. other resource costs are escalated at2.2%o over the s4gf.,,$;2,0 years. ldaho Power will Continue to closely follow the decreasing price trend of solar PV *!]U: techpology continues to become more cost cornpctitive with more traditional resource alf6ff.iatiVe5. Solar capacity Credit ==?=, ,,,1i1i,r,, =W,il,,--..p* Idaho Power reviewed the solar capacity cr caldUl{fh.nfi$ye t61$mments received during the 2013 IRP Advisory Council meetings as wellft com$,$fittslf$$ei,ved after filing the 2013 Integrated Resource Plan. Idaho Power, intereit$d.xtilhTnbers of the IRP Advisory Council, and interested members of the public norq:9 a study gr5up separate from the IRP Advisory Council to evaluate solar peak-hourcapacity ffitors. The $toup formally met in September and October, and ldaho Power had additional infor#al meeting-€md conversations with members of the study group. Idaho Power updated the s-o=@!otovo!taic, peak-hour capacity factors based on guidance from the rnembers of the soia-u==w. !roup. ' '=." .::::::::::::::. .:]:::::::::::::: Idaho Powef:Sirnulated solar geneiation for water years 201 I through 2013 as part of the solar integration study (data flor period &tober l , 201 0 through September 30,2013). ldaho Power used the siinulated solar generation combined with actual load data from the same time period to estimate the solar peak-houf'eapacity factors. In essence, the estimation used the system load data to identifu the highest I50 load hours, used the simulated solar generation data to estimate the time-coincident sirnulated solar generation, and calculated a weighted average of the solar peak-hour capacity factorwhere the frequency of the hour was used as the weight in the weighted average calculation. The steps of the process are: l. ldentifythe l50highestloadhoursfrom20ll through20l3(allaresummerhours). 2. Determine the sirnulated solar generation during each of the 150 highest load hours (solar generation sirnulation is fiorn the Idaho Power solar integration study, solar generation sirnulated at five-minute intervals at a set of utility-scale solar generation sites across the Idaho Power service territory. the five-minute data was compiled into an average for the hour). Page 54 2015 tRP ldaho Power Company 5. Supply-Side Generation and Storage Resources 3. Group the solar generation by clock hour for the 150 highest load hours (for example, a list of all the solar generation values for the clock hour fiom 2:00 pm to 3:00 prn during the 150 highest load hours). Estimatethe 90th percentile exceedance foreach clock hoLrr represented in the 150 highest load hours (among the highest 150 load hours, during the clock hour starting at xx:00, nine times out of ten, the solar generation was simulated to be at least xx percent of the maximum possible delivered solar generation). Calculate a weighted average of the solar generation for the series of clock hours, the clock hours are weighted by the proportion that the clock hour is represented in the top 150 load hours. Idaho Power used the same process for estimating fixed-panel generation syslerns and solar tracking generation. :::::::::::::::::::: The solar capacity credit is expressed as a percentug".offitulled AC narneplate .upuiity. fne solar capacity credit is used to deterrnine the amountr6f..p.eak-hour'oapacity delivered to the Idaho Power system from a solar PV plant considered ai a new IRP resource option. The solar capacity credit values used in the2015 reso,,:r;.:..,:-plan are rep in Table 5.1. Tabte 5.1 solar capacity credit r"tr"illlilt{'ll?',-.,,,,.-- ";; i PV System Description PeaK Ho0r Capacity Credit 4. 5. South Orientation Southwest Orientation Tracking *,1. 'l:.,",- , Geothermal - .;i -frfu Potential comfuercial geothermal [pneration in the Pacific Northwest inclLrdes both flashed steam and'binary-cycle tdbhnologids'#ased on exploration to date in southern Idaho, binary-cyde geothermal development is more likely than flashed steam within Idaho Power's service aiea. The flashed steam technology requires higher water temperatlrres. Most optimal Iocations fbrpotsntial geotheimal development are believed to be in the southeastern part of the state; however, the:poterrti'al for geothermal generation in southern Idaho renrains somewhat uncertain. The time requiied to discover and prove geothermal resource sites is highly variable and can take years. or even decades. The overall cost of a geothermal resource varies with resource temperature, development size, and water availability. Flashed steam plants are applicable for geothermal resources where the flLrid ternperature is 30O"Fahrenheit (F) or greater. Binary-cycle technology is used for lower- tenrperature geothennal resources. In a binary-cycle geothermal plant, geothermal water is purrped to the surface and passed through a heat exchanger where the geothermal energy is transfbrred to a low boiling point fluid (the secondary fluid). The secondary fluid is vaporized and used to drive a turbine/generator. Afier driving the generator, the secondary fluid is ;'i't 2-8i4 Percentrr !- i,,,ir' '"',ii;l,l;i, li,,:4,9 s percent r i :5rJ';3 Percent 2015 rRP Page 55 5. Supply-Side Generation and Storage Resources ldaho Power Company condensed and recycled through a heat exchanger. The secondary fluid is in a closed system and is reused continuously in a binary-cycle plant. The primary fluid (the geothermal water) is returned to the geothennal reservoir through injection wells. Cost estimates and operating parameters used for binary-cycle geotherrnal generation in the 2015 IRP are based on data from independent geothermaldevelopers and cost inforrnation from a power purchase agreement Idaho Power has with U.S. Geothermal, Inc. for the generation from the Raft River Geothennal Project located in southern Idaho. The capital cost estimate used in the 201 5 IRP for geotherrnal resources is $4,02 I per kW, and the 25-year levelized cost of production is $ l 0 l per M Wh based on a 90 percent annual capacity fact"q.r t i : .t:i .:i,l: , 'i:-::1.. Hydroelectric power is the foundation of Idaho Power's gene,,t?lion fleet. Tfi6 xisting generation is low cost and does not emit potentially harmful pollutants#aho Power believes the development of new large hydroelectric projects is unlikcly because few appropriate sites exist and because of environmental and permitting issues as- iated wi.l!1ew, large facilities. However, small hydroelectric sites have been extensively develop'dd in southern Idaho on irigation canals and other sites, many of which have PURFrl ontracts with ldaho Power. Small Hydroelectric Because small hydroelectric such as r.r.,n-ol--riu.l" and projects requiring small or no impoundments does not have the same level'' nvironnie*t5=1 d permitting issues as large hydroelectric projects, the IRPA!,expressed ry+Wt in evaluating small hydroelectric in the 2015 IRP. The potential for ne$smtillrhydroef€C ic projects was studied by the Idaho Strategic Energy Alliance's Hydrop.q er Task F$1ce, and'fte results released in May 2009 indicate between 150 MW to 800:MW of newhydroelectriciresources could be developed in the state of Idaho. These figures ate.bap;d on potenfl upgrades to existing facilities, undeveloped existing impoundments and wateiddJ'ivery,.systems,'=afid"ih-stream flow opportunities. The capital cost estimate used l+tffiilRP for Sffiall hydroelectric resources is $3,600 per kW and the 75-year Ievelized c_s$dp"fldUtdtion is $tr69,,per MWh. Shosh Falls Expansi Project In Augusi: 6, Idaho Poweifiled a license amendment application with FERC to expand the Shoshone Fd$iflydroelectri-=Project (Shoshone Falls project) from 12.5 MW to 6l .5 MW. The project curidntly has'tfiree generator/turbine units with nameplate capacities of I L5 MW, 0.6 MW, and 0.4 MW. fne expansion project involves replacing the two smaller units with a single 50-MW unit that will result in a net expansion of 49 MW. In July 2010 the FERC issued a license amendment fbr the project allowing two years to begin construction and five years to complete the project. Idaho Power has received two extensions from the FERC since the issuance of the license amendment. The latest extension, granted by the FERC in May 2014, allows Idaho Power until July 2022to complete the project. Construction associated with renovations at the intake structure, the new scenic flow structure, and replacement of the gated spillway at Shoshone Falls commenced in20l4, and is scheduled to be Page 56 2015 tRP ldaho Power Company 5. Supply-Side Generation and Storage Resources cornpleted in Decernber 2015. Idaho Power continues to analyze costs and benefrts of the generator/turbine expansion segment of the project. Forthe 2015 IRP, Idaho Power is considering the Shoshone Falls generator/tr,rrbine expansion as a resource option. The expansion is expected to produce on average about 200 GWh annually of incremental energy above the existing power plant configuration, with nearly 75o/o of the incremental energy occurring during the January through June period. The incremental energy is assumed to be REC eligible. A cost-benefit analysis of the generator/turbine expansion is provided in Chapter 9. Wind = =A typical wind project consists of an array of wind turbines ranging in si2e frop l-3 MW each. The majority of potential wind sites in southern ldaho lie between the south central and the rnost southeastern part of the state. Areas that receive consisten! suSiained winds greaterthan l5 rniles per hour are prime locations for wind development. i ,i,,:'" si When compared to other renewable options, wind reso1"f,i-9€s are-,#$ll suited for the Pacific Northwest and Intermountain regions, evidenced by thd'number of existing projects. Wind resources present a problem for utilities due to the variable and intermittent nature of wind generation. Therefore, planning new wind ret$ip.,f,q.9r requires estimates of the expected annual energy and peak hour capacity. For the 201'5.lRP-;'I$aho ,Power iised an annual average capacity factor of 28 percent and a capacity factor of rcent r g_ea"S,,,,,.!r,,9ur planning. The capital cost estimate used in the IRP for wind resources is ,800,pbr kWad the 25-year levelized cost of energy is $135 per MWh. whigh includes a windintegration cost of $15.39 per MWh. Biomass ,,') ,;.:' ;_. Biomass resource types ffi1dered, irihe 2015 IRP include wood burning resources and anaerobic digesters- Wood''bilffiiiig resources typically rely on a steady supply of woody residue collected from fbidbd arcas.'Thbre fore, fuel supply can be an issue for these types of plants as the radius ofthe area used to collect fuel is expanded. Several anaerobic digesters have been built insouthern Idaho dueto the size of the dairy industry and the quantity of luel available. HoweV4 these digesters affimited in size and would be difficult to develop on a utility scale. The capital cost estimate u in the IRP for a 35 MW wood burning biomass project is$2,622 per kW, and $4;761 pel kW for a 3 MW anaerobic digester project. The wood bLrrning unit is expected to have an aniltral capacity factor of 85 percent while the anaerobic digester is expected to operate at 75 percent. Based on the annual capacity factors, the 30-year levelized cost ol production is $ 102 per MWh for the wood burning unit and $l I 9 per MWh fbr the 25-year Iif-e. Conventional Resou rces While much attention has been paid to renewable resollrces over the past few years. conventional generation resources continue to be needed as wellto provide dispatchable capacity which is critical in maintaining the reliability of an electrical system. These conventional generation technologies include natural gas-fired resolrrces, nuclear and coal. 2015 rRP Page 57 5. Supply-Side Generation and Storage Resources ldaho Power Company N atu ral Gas-Fi red Resources Natural gas-fired resources burn natural gas in a cornbustion turbine to generate electricity. Combined-cycle combustion turbines (CCCT) are typically used fbr baseload energy, while less- efficient single-cycle combustion turbines (SCCT) are used to generate electricity during peak load periods. Additionaldetails on the characteristics of both types of natural gas resoLrrces are presented in the following sections. CCCT and SCCT resources are typically sited near existing gas pipelines, which is the case for Idaho Power's existing gas resources. However. the capacity of the existing gas pipeline system is almost fully allocated. Therefore, the 201 5 IRP assumes new natu ral gai resou rces would require building additional pipeline capacity. This additional cost is accounted for in pofifolios containing new gas resources and not in the resource stack cost estimate fo.r -CTs or SCCTs. CCCT plants have been the prelerred choice lor new commercial power generation in the region. CCCT technology carries a low initial capital cost comfhred to other baseload resources, has high thermal efficiencies, is highly reliable, offers Si fi--c.ant operating flexibility, and emits fewer emissions when compared to coal, thu,; requiring feWer.pollution controls. A traditional CCCT plant consists of a gastUlbj$elgenerator eQuipped with a heat recovery steam generator (HRSG) to capture waste heat frci'tt he turbine=.e,4lraust. The HRSG uses waste heat from the combustion turbine to drive a steam-turbine generatorto produce additional electricity. In a CCCT plant, heat that would otherwise be wasted is used to produce additional power beyond that typically produced,b, CT. N@,CCCT plants can be built or existing SCCT plants can be converted-to bined'P;fiile units hy,:adding an HRSC. Several CCCT plants,'ffitiuding Idahonf.o.wer's Langtey Gulch project, are planned in the region due to recently declining naqll Sas prices, the need for baseload energy, and additional operating reser,Xr.B.,,.;49,.9$ed to=i- ate wind resources. While there is no current shortage of natural gas,,ffilt!{frfulfiib4 criffi component of the long-term operation of a CCCT. The capital c9$ftSiimate useffi,[fuJhe IRP for a CCCT resource is $ I , 145 per kW, and the 3O-year levelizqdtust of productio{l# a 70-giercent annual capacity factor is $79 per MWh. S lm pl e-CldeJom bustion Tu rbi nes Simple-cycle, fi*ur4l gas-turbine technology involves pressurizing air that then heats by burning gas in fuel combuSt$ibi he hot, pressurized air expands through the blades of the turbine that connects by a shaft tothe electric generator. Designs range from larger, indLrstrial machines at 80-200 MW to smaller machines derived from aircrafi technology. SCCTs have a lower thennal efficiency than CCCT resources and are not typically economical to operate other than to meet peak-hour Ioad requ irements. Several natural gas-fired SCCTs have been brought on line in the region in recent years. primarily in response to the regional energy crisis of 2000-2001. High electricity prices combined with persistent drought conditions during 2000-2001. as well as continued Page 58 2015lRP ldaho Power Company 5. Supply-Side Generation and Storage Resources summefiime peak load growth created interest in generation resoLlrces with low capital costs and relatively short construction lead tirnes. Idaho Power currently has approximately 430 MW of SCCT capacity. As peak summertime electricity demand continues to grow within ldaho Power's service area, SCCT generating resources remain a viable option to meet peak load during critical high-dernand times when the transmission system has reached full inrport capacity. The plants may also be dispatched fbr financial reasons during times when regional energy prices are at their highest. The 2015 IRP evaluated two diffbrent SCCT technologies. l) a 47-MW small. aeroderivative unit and 2) a 170-MW industrial-fiame unit. The capital cost estimate used in the IRP for the small, aeroderivative unit is S1,000 per kW, and an industrial-frame.unit.is $800 per kW. Both the aeroderivative unit and the industrial-frame unit are expected to have an annual capacity factor of l0 percent. '',;:,, | ,1.,,. Based on the annual capacity f'actor, the 35-year levelized cost of production is $250iper MWh for the small, aeroderivative unit and $219 per MWh for the industrial-frarne unit. These levelized costs are close to the same as the higher efficiency of the'Small aeroderivative unit offsets the slightly higher capital cost. If an SCCT resource is id€ntified in the IRP preferred portfolio, Idaho Power would evaluate these two technologies'in greater detail prior to issuing an RFP in order to determine which technology prqvided the greatest benefit. Reciprocating Engines '" : Reciprocating engine generation sets are typically natural gas-fired engines connected to a generator through a flywheel and coupling. Because they are mounted on a common baseframe, the entire unit can be assembled, tuned, and tested in the factory before being delivered to the power plant location, which minimizes capital costs. Operationally, reciprocating engines are typically installed in configurationswith multiple, identical units which allows each unitto run at its best efficiency point ohce it is started. As'more generation is needed, additional units are starled. This coqfiguration also allows for relatively inexpensive future expansion of the plant capacity. For the;,IRP, Idaho Power *oO.t.O a reciprocating engine sirnilar to the 34SG model manufadtui.,ed by Wartsila with a nameplate rating of 18.8 MW. The capital cost estimate used for a recipio'eating engine resource is $500 per kW. and the 4l-year levelized cost of production at a l0 percent annual capacity tactor is $ 136 per MWh. Combined Heat and Power Combined Heat and Power (CHP). or cogeneration, typically refbrs to simultaneous production of both electricity and useful heat frorn a single plant. CHP plants are typically located at, or near, commercial or industrial fbcilities capable olusingthe heat generated in the process. These facilities are sometimes referred to as a stearn host. Generation technologies frequently used in CHP projects are gas turbines or engines with a heat-recovery Lrnit. The main advantage of Cl-lP is that higher overall efflcierrcies can be obtained because the steam host is able to use a large portion of the waste heat that would otherwise be lost in a typical generation process. Because CIIP resources are typically located near load centers, building 2015 tRP Page 59 5. Supply-Side Generation and Storage Resources ldaho Power Company additional transmission capacity can also often be avoided. In addition, reduced costs fbr the steam host provide a competitive advantage that will ultimately help the local economy. In the evaluation of Cl-lP resources, it became evident that CHP could be a relatively high-cost addition to ldaho Power's resource portfolio if the steam host's need for steam fbrced the electrical porlion of the projectto run attimes when electricity rnarket prices were belowthe dispatch cost of the plant. To find ways to make CHP more econornical, Idaho Power is comnritted to workirrg with individual customers to design operating schemes that allow power to be produced when it is most valuable, while still meeting the needs of the steam host's production process. This wor-rld be difficult to model for the IRP because eqch potential CHP opportunity could be substantially different. Recognizing the actual cost of a CHP resource may vary dependl ,on thq speciflc facility being considered, the capital cost estimate used in the IRP for CHP is" $2, I 23 per kV/, .and the 40-year levelized cost of production evaluated at an annual capacity-., f?ittor of 80 percent is $81 per MWh. Nuclear Resources The nuclear power industry has been working to develop and improve reactor technology for some time and Idaho Power has continued,Xdigg.s:#?te variouSite:ifpologies in the lRP. Due to the ldaho National Laboratory (lNL) site in"CaStErnlfi$.ph,Orr,,tne IRP has typically assumed that an advanced-design or small modular reactor could be b{ilff,4"1.,t#S site. For the 2015 lRP, high capital costs coupled with a great amount of uncertaint/ in waste disposal issues prevented a nuclear resource fiom being included in the portfOli6 analysis. In addition, the recent earthquake and tsunami in Japan, and the impactoh the Fukushima nuclear plant, created a global concern over the safety of nuclear power generation. Whilij"there have been new design and safety measures implemented, it is difficult to know_the full impact this disaster will have on the future of nuclear power generatiofli;,,a;:.)' For the 2015 IRP, an1lO0 MW advanced nuclear resource and a 600 MW srnall modular plant were analyzed; howeveq'for both types of plants it was assumed that Idaho Power would only be a part owner in either type of facility by taking 250 MW of the total plant capacity. The capital cost estifi-*e used in the IRP for an advanced nuclear resource is $4,350 per kW, and the 4}-year levelized C'ostof produclionr-waluated at an annualcapacity factorof 90 percent. is Sll9 per MWh. For the,small modulhiieactor technology, the capital cost estimate is 55,000 per kW, and the 40-year levelized cost,of production, evaluated at an annual capacity factorof 95 percent, is 5343 per MWh. CoalResources Conventional coal resoLlrces have been a pafi of Idaho Power's generation portfolio since the early 1970s. Growing concerns over global wanning and clinrate change have made it impractical to consider building any new conventional coal resources; however, integrated gasification combined cycle (IGCC) and IGCC coupled with carbon sequestration are two technologies that were still evalLrated in the IRP. Page 60 2015 tRP ldaho Power Company 5. Supply-Side Generation and Storage Resources IGCC is an evolving coal-based technology designed to substantially reduce COz emissions. As the regulation of COz emissions eventually makes conventional coal resources obsolete, the commercialization of this technology may allow the continued use of the country's coal resources. IGCC technology is also dependent on the development of carbon capture and sequestration technology that would allow COz to be stored underground for long periods of time. Coal gasification is a relatively mature technology, but it has not been widely adapted as a resource to generate electricity. IGCC technology involves turning coal into+ synthetic gas or "syngas" that can be processed and cleaned to a point that it meets pipelin;b1fiality standards. To produce electricity, the syngas is burned in a conventional combustion fuibine that drives a generator. The addition of COz-capture equipment decreases the overall6rfficiency of an ICCC plant by as much as l 5 percent. In addition, once the carbon is capture.di.. must either be used .or stored for long periods of time. COz has been injected into existing oil fields to enhance oi"fffiv"rV; however, if IGCC technology were widely adopted by:ffiities for,-*{.Wyer productiorf the quantities of CO2 produced would require the developme.ll of uq$eiground sequestrationmethods. .'.' t Carbon sequestration involves taking capty{,SffVrP,,ffgand stoffi.it a*uy from the atmosphere by compressing and pumping it into undergrokrd. gdtilogtg&rmations.lf compression and pumpingcompressing and pumping it into ""a"rgriw.#,*icfu.uI6#+compression and pumping costs are charged to the plant, the overall effilency 9,flrthE;*,1u.nt ir ieduced by an additional 15 to 20 percent. Sequestration methods are curret@.rteini,.,ffi'evel pbd and tested; however, commercialization of the t..Uglpffi3l_not exp$ted to happen for some time. The capital cost estimate used in the IRP fogffiC ru"WM257 pei.kW, and the 35-year levelized cost of production, evaluated cost estimate used for ity factot S5 percent, is $1l6 per MWh. The capital rxtan is $6,390 per kW, and the 35-year t to the poffi,where there is an oversupply of energy. Recently, Mid-C :rrices fdfflffiectricity are tvpicallv one-third to one-half lower than ius levelized cost of produc MWh. -l capacity factor of75 percent, is $1 84 per Sto Ren folio standa"fdi have spured the development of renewable resources in the Pacific No wholesale years ago. Atthe retail rates for electricity continue to grow as utilities have to pass the cost of builainf:iEffiiqX resources on to customers. The oversupply issue has grown to the point where at certain times of the year, such as in the spring, low customer demand coupled with large amounts of hydro and wind generation cause real-time and day-ahead wholesale market prices to go negative. As more intermittent renewable resources like wind and solar continue to be built within the region, the need for energy storage is amplified. While there are many storage technologies at various stages of development such as hydrogen storage, compressed air, and flywheels, the 2015 IRP considered and evaluated three specific storagetechnologies: battery storage, ice-based thermal energy storage, and pumped storage. 2015 tRP Page 61 5. Supply-Side Generation and Storage Resources ldaho Power Company are not a good fit for utility scale Basic illust a now o,f,i,l!u u """":"!' applications because they cannot be easily or econom:idly scaled to rnuch larger sizes. The VRB overcomes much of this issue because the capacitJi'df fi$.d:+.ff6ttery can be increased just by increasing the size of the tanks that containfhe electrolytes,,--.1Ql h also helps to keep the cost relatively low. . '=._ VRB technology also has an advantage in maintenan6-.'-.-d4placement costs, as only certain components need replaced about every l0 years, whereas other battery technologies require a complete replacement of the battgry,. and more'fiegjl'ehtly depending on how they are used. For the IRP, the capital cost estimate foirthe VRB isffi000 per kW, and the l0-year levelized cost of production, evaluated at an annual capacity factor:of 25 percent, is $240 per MWh. Battery Storage Just as there are many types of storage technologies being researched and developed, there are nulnerolls types of battery storage technologies at various stages of development. The 2015 IRP focused on one specific type of,battery technology, the vanad ir-rm redox-f'low battery (VRB). Figure XX is a diagrarn showing how the battery functions. Advantages of the VRB technology include low cost, long life, and being easily scalable to utility/grid 5 lrttp://strategy.sauder.ubc.calantwei ler/blog.php?it em:201 4-09 -28. Page 62 2015 tRP ldaho Power Company 5. Supply-Side Generation and Storage Resources lce-based Thermal Energy Sforage Ice-based thermal energy storage is a concept developed to take advantage of the air conditioning needs for mid-sized to large commercial buildings. The general concept is to create ice during low load/low price tirnes (light load hours) and then to use the ice for air conditioning needs during the high load/higher price times (heavy load hours). While this concept does not specifically store electricity, it does shift the tirne the energy is consumed with the overall goal of reducing peak day,time dernand. Pumped Storage Purnped storage is a typei8f'' .= h yd ro e I e c t r i c p o w e r g e'iieral i o n u.s.e{.,,i!$ change the "shape" or timiH$lwhpn'' electricity is produced. The techhology stores energy in the form olwater, purnped fiom a lower eleVdtion ' . reservo.ifito a higher elevati$ , Lowei- cost, off,pUhk electricity is u5ed to pump water froln the lower reservoir to the upper reservoir. During higher-cost periods of high electrical,demand, the water stored in the upper reservoir is used to produce electricity. Hld (x(tar86k (@l OJb Conroller fMsBCol lllustration of an ice-based thermal energy storage system.6 One company currently commercializing the ice-based ihermal e$ergy storage technology is Ice Energy with their lce Bear Energt Storage System. Requirements in Califomia to develop energy storage have allowed several utilities to begin to installand testthis technology with several of the installations being 5 MW to 15 MW in *-"'F.or,.,1he IRP, the capital cost estimate used for this technology is $1,500 per kW, and the Z0;year'l lized cost ofproduction, evaluated at an annual capacity factor of 10.4 percent, is $22.4'1er M-wh. :',, Pumped-storage facility. 7 6 http://www.ice-energy.com/technology/ice-bear-energy-storage-systeln. 7 http://www.renewableenergyworld.com/rea./news/arliclel2}l0/10/worldwide-pr-rrnped-storage-activity. 20'15 tRP Page 63 5. Supply-Side Generation and Storage Resources ldaho Power Company For pumped storage to be economical, there must be a significant differential in the price of electricity between peak and off-peak times in order to overcome the costs incurred due to efficiency and other losses that make pumped storage a net consumer of energy overall. Historically, the differential between peak and off-peak energy prices in the Pacific Northwest has not been suflicient to make pumped storage an economically viable resource; however, with the recent increase in the number of wind projects, the amount of intermittent generation provided, and the ancillary services required, this may change. The capital cost estimate used in the IRP for pumped storage is $5,000 per kW, and the 50-year levelized cost of production is $346 per MWh. Page 64 2015 tRP ldaho Power Company 6. Transmission Planning 6. TnnTSMISSIoN PLANNING Past and Present Transmission High-voltage transmission lines are vital to the development of energy resollrces to serve Idaho Power custolners. Transrnission lines have facilitated the development of southern Idaho's network of hydroelectric projects that serve the electric customers of soLrthern Idaho and eastern Oregon. Regional transmission lines that stretch frorn the Pacific Northwest to the Hells Canyon Cornplex (HCC) and on to the Treasure Valley were central to the development of the HCC projects in the I 950s and I 960s. ln the I 970s and I 980s. transmission lines were instrumental in the development of parlnerships in the three coal-fired power plants located in neighboring states that supply approxirnately one+hird ofths,eiergy consiifued by Idaho Power customers. Finally, transmission Iines allow Idaho Power to economically balance the variability of its hydroelectric and intermittent resources with access tiotfiryle errergy markets. Idaho Power's regional transmiss:i-o interconnec-ilffi improve reliability by providing the flexibility to move electricity between utilities and also provide economic benefits based on the ability to share operating regves. l-liglbrically, fdt Power has been a summer peaking utility, while most other utiliti*,in the Pacific Northwest eiperience system peak loads during the winter. Because of the dlf,ference.ia'peak seasons. Idaho Power purchases energy from the Mid-Columbia energy tradiAg,.*Arket to meet peak summer load, and Idaho Power sells excess energy to Pacific,Northwest uiilities during the winter and spring. New regional transmission connections to the Pacific Northw€st will beneflt the environment and Idaho Power customers through the following: . fh6'iollstruction of idditional peaking resources to serve summer peak toad is delayed or avoidgd, ,.':"- . Revenue from offjsystern sales during the winter and spring is credited to customers through the PCA. . Revenue from others' use of the transmission system is credited to Idaho Power customers. . Increased system reliability. . Provides capacity to help integrate intermittent resources, such as wind and solar. ldah:$jPgwer's doub-l, ircuit 230-kV transmission line tra ve ib.i,il'6i H e l l s- C'aii yo n. 2015 tRP Page 65 6. Transmission Planning ldaho Power Company . The ability to rnore efficiently implement advanced market tools such as energy irnbalance r"narkets (EIM) or security constrained economic dispatch (SCED). Transmission Planning Process ln recent years. FERC has mandated several aspects of the transmission planning process. FERC Order No. 1000 requires Idaho Power to parlicipate in transrnission planning on a local, regional, and interregional basis, as described in Attachment K of the Idaho Power Open-Access TransmissionTarifT(oATT)andsummarizedinthefollowingsections. Local Transmission Planning Process :','. The expansion planning of Idaho Power's transmission network Oddfurs thr0lt'gh a local-area transmission advisory process and the biennial local transmission planning pfoCess. Local-Area Transmission Advisory Process ldaho Power develops long-term, local-area transmissibi plans with community advisory committees. 'lhe community advisory committees conSi fjuiiBdictional planners; mayors; council members; commissioners; and large industry, commercial, residential, and environmental representatives. The plans identify the transmission and subsiation infrastructure required for the full development of the area. The plans aclbuni'for land-use limits and other resources of the local area. The plans identify the approximat'O year ii pffiect will be'placed in service. Local-area plans have been created for the following five IOad ceiiterS in,southern Idaho: I . Eastern ldaho Magic Valley ,,::, -. Wood River Vallej Treas u reYal leY,,.,,,. 5. West Central Mountains 'iri :t: Recently, the Treasure Vallcj,,,,Electric Plan was divided 2. -). 4. into two plans: l. I4/estern Treasu-re".YAlley Electrical Plan-The western plan was completed in 201I and encompasses Malheur County in Oregon and Canyon, Gen'I, Owyhee, Payette and Washington counties in Idaho. 2. Eastern Treasure Valley Electric Plan-The eastern plan was completed in2012 and encornpasses all or pofiions of Ada, Elmore, and Owyhee counties in Idaho. Biennial Local Transmission Planning Process The biennial local transmission plan (LTP) identifies the transmission required to interconnect the load centers, integrate planned generation resoLlrces, and incorporate regional transrnission plans. The LI-P is a 20-year plan that incorporates the planned supply-side resources identified in Page 66 2015 IRP ldaho Power Company 6. Transmission Planning the IRP process, the transmission upgrades identified in the local-area transmission advisory process, the forecasted network customer load (e.g., Bonneville Power Administration [BPA] customers in eastern Oregon and southern Idaho), ldaho Power's retail customer load, and third-party transmission customer requirements. By identifying potential resources, potential resource locations, and load-center groMh, the required transmission system capacity expansions are identified to safely and reliably provide service to customers. The LTP is shared with the regional transmission planning process. Regional Transmission Planning Idaho Power is active in regional transmission planning through the Northern Tier Transmission Group OITTG). The NTTG was formed in early 2007 with the ovExdl t$ff.flr..pf improving the operation and expansion of the high-voltage transmission systemffi de[i+;&.,,power to consumers in seven western states. In addition to ldaho Powe,rother memb3i$t!,fuslude Deseret Power Electric Cooperative, NorthWestern Energy , Portlq{t ;frineral Electric. YaCffiorp (Rocky Mountain Power and Pacific Power), and the UffiAssociated Municipal Ptiwer Systems (UAMPS). The NTTG relies on a biennial process to;lil#dFtlop a regional transmission plan. In preparing the regional transmission plan, the NTTG uses a publ& itakeholder process to evaluate transmission needs resulting ffom members' load florecasts,l.TPs. lRPs. generation interconnection queues, other proposed resource developmenuand forecast uses of the tran smission system by wholesale transmi$#ffi)ffi.;,1_o.,ryers. z ,,,, lnterconnection-WideTransmisg19,,!Plri,pfriri#W., The Western Electricity Coo-1r{=!;r=ati.rr1{ o"r"ii+ffita; r.unrrnission Expansion Planning Policv Committee (TEPPCJWffives d$ihe interc&iflection-wide transmission olannins facilitator in the westem US. Speffi lly,theWPC has tHr,$gdistinct functions: ./tji.ai-:ttlg'EPPQffives owr,t,'n:Policy Committee (TEPPq#ffiffives d$ffi,g intercff'ffection-wide transmission planning facilitator :."" fw;i._, ,w.: ,l.Overseedatamaffi6iffibtpe$.Lw1rr*€'{trWW,trlnterconnection. 2. Prov t of the planning process. 3. /G#da the analysrJ mod'$ffie for Western Interconnection economic transmission '€'*f,a n s i on p I ann i n g.:'\, ;.#", B,In addition t&ffiio,Vidine the,6tans to model the transmission implications of various load and resource scenafib-'s]at ang,ifitd-iconnection-wide level, the TEPPC coordinates planning between transmission ownerso.trinsmission operators. and regional planning entities. The WECC Planning Coordination Committee manages additional transmission planning and reliability-related activities on behalf of electric-industry entities in the West. WECC activities include resource adequacy analyses and corresponding North American Electric Reliability Corporation (NERC) reporting, transmission security studies, and the transmission line rating process. 2015 tRP Page 67 6. Transmission Planning ldaho Power Company Existing Transmission System Idaho Power's transmission system traverses from eastern Oregon through southem Idaho to western Wyoming and is composed of I l5-, 138-, 161-,230-,345-, and 500-kV transmission facilities. The sets of lines that transmit power from one geographic area to another are known as transmission paths. There are defined transmission paths to other states and between the southern Idaho load centers mentioned previously in this chapter. Idaho Power's transmission system and paths are shown in Figure 6.1. Figure 6.1 ltlaho Powertransmission system map The transmission paths identified on tlre map are described in the following sections, along with the conditions that result in capacity limitations. ldahuNorthwest Path The ldaho-Northwest transmission path consists of the 500-kV Hemingway-Summer Lake line, the three 230-kV lines between the Hells Canyon Complex and the Pacific Nofthwest, and the I l5-kV interconnection at Harney Substation nearBurns, Oregon. The ldaho-Nofthwest path is capacity-limited during summer months due to transmission-wheeling obligations for the BPA eastem Oregon and southern ldaho load and due to energy imports from the Pacific Northwest to Page 68 2015 tRP ldaho Power Company 6. Transmission Planning serve Idaho Power retail load. If new resources. including market purchases, are located r,vest ol the path, additional transmission capacity will be required to deliver the energy to the Idaho Power service area. Brownlee East Path The Brownlee East transmission path is on the east side of the ldaho-Northwest Interconnection shown in Figure 6.1. Brownlee E,ast is comprised of the 230-kV and 138-kV lines east of the Hells Canyon Complex and Quartz Substation near Baker City, Oregon. When the Herningway- Summer Lake 500-kV line is included with the Brownlee East path, the path is typically referred to as the Brownlee East Total path. The capacity limitation on the Brownlee East transmission path occurs between Brownlee and the Treasure Valley. The Brownlee East path is capacity-limited during the summer months due to a combination of Hells Canyon Complex hydroelectric generation flowing east into the Treasure Valley concurrent with transmission-wheeling obligations for BPA southern ldaho load and ldaho Power energy imports from the Pacific Northwesl'"Capacity lirnitations on the Brownlee East path limit the amount of energy Idaho,Power can import from the Hells Canyon Cornplex as well as off-system purchases from the Pacifib;Northwest. If new resources, including market purchases, are located west of the path, additional transrnission capacity will be required to deliver the energy to the Treasu*,e |;y toaA cent . tdahuMontana Path :;riili ='.i= The Idaho-Montana transmission path consists of@Antelope-Anaconda 230-kV and Goshen- Dillon l6l -kV transmission lines. The ]daho-Montana path is also capacity-lirnited during the summer months as Idaho Power, BPA; FacifiCo$7nd others move energy south from Montana into ldaho. ,, ..::. Borah west pati=Z ,' ,' ;:i'i't;i:i The Borah w,,qrt-. urt;; dlh,js internal to the Idaho Power system. The path is comprised of 345-kV,.230'-kV, u66:1p.fl-kV ti{fismission lines west of the Borah substation located near AmericanFalls, Idaho. ldaho.Powerls one-third share of energy frorn the Jim Bridger plant flows over thispa,th, as well as eaffiide hydroelectric energy and energy imporls fiorn Montana. Wyorning,'and Utah. PacifiQorp's two-thirds share of energy from the iim Bridger plant also f'lows acrossthiS::path to load centers in the Pacific Nofthwest. The Borah West path is capacity-limitedrduring summer months due to transmission-wheeling obligations coinciding with high eastern themal and wind production. Heavy path flows are also likely to exist during the light-load hours of the fall and winter months as high eastern therrnal and wind production move east to west across the system to the Pacific Northwest. Additional transmission capacity will likely be required if new resources or market purchases are located east of the Borah West path. Midpoint West Path The Midpoint West path is an internal path comprised of the 230-kV and 138-kV transnrission lines west of Midpoint Substatiorr located near Jerome, Idaho. The Midpoint West path is 2015 tRP Page 69 6. Transmission Planning ldaho Power Company capacity-lirnited due to east-side Idaho Power resoltrces, PURPA resources, and energy imporls. Similar to the Borah West path, the heaviest path flows are likely to exist during the fall and winter when significant wind and thermal generation is preserrt east of the path. Additional transmission capacity will likely be required if new resoLrrces or market purchases are located east of the Midpoint West path. ldahuNevada Path The Idaho-Nevada transmission path is cornprised of the 345-kV Midpoint-Hurnboldt line. Idaho Power and NV Energy are co-owners of the line, which was developed at the same time the North Valmy power plant was built in northern Nevada. Idaho Power is allocated 100 percent of the northbound capacity, while NV Energy is allocated 100 percent ofthe southbound capacity. The available imporl, or norlhbound, capacity on the transmission path is fully subscribed with Idaho Power's share of the Nofih Valmy generation plant. ' ldahuWyoming Path The Idaho-Wyoming path, referred to as Bridger West, is comprised of three 345-kV transmission lines between the Jim Bridger generation'plail and southeastern Idaho. Idaho Power owns 774MW of the 2,400-MW east-to-west capacity. PacifiCorp owns the remaining capacity. The Bridger West path"effectively feedsintothe Borah West path when power is moving east to west from Jim Brid$;:'bonsequently. the import capability of the Bridger West path is limited by Borah Westgth capacity,:constraints. ldahtUtah Path Total Transmission Capacity The Idaho-Utah path, referr diito us'H th C. is cornprised of 345- ,230-, I 6l -, and 138-kV transmission lines betwe-eiijoutheasterfi Idaho and nofihern Utah. PaciflCorp is the path owner and operator of all the trq[Imi!,!..i,q.'.r] es. The path efI-ectively feeds into Idaho Power's Borah West path when pO*e.r.s oving'fom east to west; consequently, the import capability of Path C is timrt.$b;,..n9f,1 \ry th capacity lirnitations. Tabte 6.1 =,.lAvailabie transmission import capacity ,.,,,,,Iri!i:it, Transmissiorf P..ath lmport Direction Capacity (MW)ATC (MW) ldaho-Nevada ldaho-Wyoming (Bridger West) ldaho-Utah (Path C) Midpoint West ... ...... . . East to West Borah West ...... East to West West to East South to North North to South West to East East to West South to North 1,200 262 383 1,915 1,027 2,557 2,400 1,250 0 0 0 0 0 0 60 0--. *Total transmission capacity and ATC as of April 1,2015. Page 70 2015 tRP ldaho Power Company 6. Transmission Planning -"The ATC of a specific path may change based on changes in the lransmission service and generation interconnection request queue (i.e., the end of a transmission service, granling of transmission service, or cancelation of generation projects thal have granled future transmission capacity). -.-ldaho Power estimated value, actual ATC managed by PacifiCorp. Boardman to Hemingway Idaho Power's IRP process has identilled a transmission line to the Pacific Nofthwest electric rnarket dating back to 2006. At that tirne, a line interconnecting at the McNary Substation to the greater Boise area was included in IRP portfblios. Since its initial identiftation, the project has been refined and developed over the years, including different terminus locations and sizing the project to economically meet projected demand. The project identifi.edjn 2006 has evolved into what is currently the Boardman to Hemingway project. The projeCt'i f,,olves permitting, constructing, operating, and maintaining a new, single-circuit 500-kV tranSful!,qjon line approxirnately 300 miles long between nofiheast Oregon and southwest ldaho. The new line will providemanybenefits,includingthelollowing:........1i,: .:,:=i .' ii.+.-o Greater access to the Pacific Northwest electr arket to,slirve homes, farms, and businesses in Idaho Power's service area --,-__, *' .,:a:::;::::::: Improved system reliability and redt*,o-ed capacity limiffilons on the regional transmission system as demands on the system ioffintie'to 81,,..,9,1 "t i . Assurance of ldaho Power's ability to et custOfi€ii' gxisting and future energy needs in ldaho and Oregon ,"Flexibility to integrd#'iene*abii..rourid., respond to pending carbon legislation and more el-ficiently implernent advanced markef tools The Boardman to Hemingway project was identified as part of the preferred resource portfolio in Idaho Power' s-ZW, 201 I and.Z0l 3 I RP's. In Januar@l 2, idaho Power entered into a joint firnding agreement with PacifiCorp and BPA to pursueplrrnitting of the'project. The agreement designates Idaho Power as the permitting project ma-ager for the Boardman to Herningway project. Table 6.2 shows each pafty's Boardman to Herningway capacity arrd permitting cost allocation. Table 5.2 Boardman to Hemingway capacity and permitting cost allocation ldaho Power BPA PacifiCorp Capacity (MW) west to east... .. Capacity (MW) east to west ..... Permitting cost allocation ..... ... 350 200 winter/500 summer 85 21% 400 550 winter/250 summer 97 24% 300 818 55% Additionally, a Memorandum of Understanding (MOU) was executed between Idaho Power, BPA, and PacifiCorp to explore opportunities for BPA to establish eastern ldaho load service 20'l5 tRP Page 71 6. Transmission Planning ldaho Power Company from the Herningway Substation. BPA identified six solutions-including two Boardman to Hemingway options-to meet its load-service obligations in southeast ldaho. On October 2, 2012, BPA publically announced the preferred solution to be the Boardman to Hemingway project. The perrnitting phase of the B2H project is subject to review and approval by the BLM, the U.S Forest Service, and the Oregon Department of Energy. The federal perrnitting process is established by the National Environmental Policy Act (NEPA). The Bureau of Land Management (BLM) is the lead agency in administering the NEPA process for the Boardman to Herningway project. On December 19,2014, BLM published the Draft F.nvironmental Impact Statement (Draft EIS). Figure 6.2 shows the proposed transmission line routes included in the Draft EIS with the agency preferred route. Idaho Power expects the BLM to issue a Final EIS in 2016. .. ,1,),, '''ii iitt:, In late February 2013, Idaho Power submitted the preliminffi Application for S'itg{ertificate (pASC) to the Oregon Department of Energy (ODOE)g;part of the state siting p@g,St. Idaho Power intends to submit an Amended pASC in late 29ryr rO,U.'.,,.itt ln light of the permitting delays and siting i*p"ai-.nii\'E+.Ah#iibccurred and may occur, Idaho Power is unable to accurately determine an approxiffi[n-service date for the line, maritohemingway.com. Page 72 2015 tRP Idaho Power Company 6. Transmission Planning {r rdrardr h S.lcdt @ry*r6lsb6.rr{ilr d.c&a!&ralnd die & bh&dra!6.f,6otie qgiideE'.ey'dtutu..@1*nddr n 3.ddtulrdio$i 0510 20rr-1 Miles Figure 6.2 B$erOm3-rl,,t emingway routes with Agency Preferred Alternative Gateway West The Cateway West transmission line project is a joint project between Idaho Power and Rocky Mountain Power to build and operate approximately 1,000 miles of new transmission lines from the planned Windstar Substation near Glenrock, Wyoming, to the Hemingway Substation near Melba, Idaho. Rocky Mountain Power has been designated as the pennitting project manager for Gateway West, with ldaho Power providing a supporting role. Figure 6.3 shows a map of the project identifying the routes studied in the federal permitting process and depicts the BLM's prefbrred route. Idaho Power has a one-third interest in the 2015lRP Page 73 6. Transmission Planning ldaho Power Company segments between Midpoint and Herningway, Cedar Hill and Hemingway, and Cedar Hill and Midpoint. Further, ldaho Power has sole interest in the segrnent between Borah and Midpoint (segment 6), which is an existing transmission Iine operated at 345-kV, but constructed at 500-kv. t tit l :ir3.; a:.tr:.i [*,,*.;;,. l-tr"-r*ffi-rrwu'l-::-"ffMla** 3. Provide future load s-$tvice capacity to the Magic Valley from the Cedar Hill 4. Transmissiiin"c-p-Uitity is needed to meet the transmission needs of the future, including transmission'h€eds associated with intermittent resources. Phase I of Gateway West is expected to provide up to 1,500 MW of additionaltransfer capacity between Midpoint and Hemingway. The fully completed project would provide a total of 3,000 MW of additional transfer capacity. Idaho Power has a one-third interest in these capacity additions. The two transmission projects, Boardman to Hemingway and Gateway West, are complementary and will provide an upgraded transmission path from the Pacific Northwest across Idaho and into al|:#t 'i;i;#fi ''-= , rurrl: the option fficate future generation resources east of the Treasure Valley. Page 74 2015 tRP ldaho Power Company 6. Transmission Planning eastern Wyoming with an additional transmission connection to the population center along the Wasatch Front in Utah. Under the federal permitting process established by NEPA, the BLM has completed the Environmental Impact Statement (EIS) for all segments of the Gateway West project except segment 8 (Midpoint to Hemingway) and segment 9 (Cedar Hill to Hemingway). The BLM is curently conducting a supplemental environmental analysis on these two segments. A final record of decision for these two segments is expected by late 2016, subject to permitting completion. Additional infonnation about the Gateway West project can be found N ii" http://www.gatewaywestproject.com. . Gateway West Need Analysis Idaho Power has two internal transmission paths between the Magic Valley and Treasure Valley: o Boise East ,*^NIII ,,,,1r,1t,,[,$' ] . Midpoint West transmission lines This transmission path to be sited in and the capability of the Boise Easl -ft, 2. Idaho Pqwer has ffifide arrangements to acquire an ownership share of the PacifiCorp- owned Miilpointl-- Hemingway 500 kV line, pending regulatory approval. Idaho Power's;,ownership share will equate to 410 MW of the 1,500 MW line rating. This is expected to be finalized by the end of 2015. Over the past several years, Idaho Power's utilization of the Midpoint West transmission path has steadily increased. Figure 6.4 illustrates this increasing utilization. 2015 tRP Page 75 6. Transmission Planning ldaho Power Company 1 800 1 600 't400 1200 1000 800 600 400 200 2010 20't'l 2012 2013 20't4 ..t-Midpoint West Rating -,i-Midpoint West Utilization 1. Large increases to the use of Midpoint west occurred fi iB1fo*ipunpo *,nol,Wind), and 2015 (third party 0+- 2009 The Midpoint West path will"g,ft#j1trIpr,to be co$ffffied following the upgrades described above. As the Boise East and tvlidpr$ffi'WEY?ffiaths become further utilized, Idaho Power will continue to invest in new transmisffifacilitie3lb reinforcelhe transmission system. Gateway West is the cd##6ifieO following the upgrades described above. p lanned upgrad e that utF.$fficrease ility o$jlhe Midpoint West path. transmission service). Use is also projected to increase Figure 6.4 Midpoint West Historical Uti Transmiss ons 100 I\A/V of solar in eastern ldaho ;-.,.:iijF in'the !RP Portfolios The Hemingway Substation in southern ldaho is a major hub for power running through ldaho Power's transmission system. Idaho Po the IRP t proces*E Regardless o location-zs@ply-side resources incl thdTi#iSource stack typically require nsmlsslon i mprovements for in{€gration into Idaho Power's system. Additional transmission improvement requirements depend on the location and size of the resource. The transmission assumptions and transmission upgrade requ irements for incremental resources are summarized in Table 6.3. ,ffi", :^x t:, ffi kes resotirgg I ocatioJn to determineffi ql requirements ffihart of Page 76 2015 tRP ldaho Power Company 6. Transmission Planning Table 6.3 Transmission assumptions Resource Type Geographic Area Resource Levels (incremental amounts)Additional Transmission Requirements Boardman to Hemingway Line Gas turbine (sccT) Gas Turbine (cccr) Combined heat and power (CHP) Geothermal Reciprocating Engines Hemingway Substation Elmore County Elmore County Canyon County Cassia County Distributed 500 [,4W (summer)/ 200 l,,IW (winter) 170 t\A,t/ 3OO MW 45 MW 30 MW 18 MW 1O MW 300 t\a,v Photovoltaic(PV) Elmore/Owyhee CountY Pumped Storage Above BrownleeHydro Reservoir New 230-kV line from Hemingway into the Treasure Valley. New 230kV substation and new 230kV line into the Treasure Valley. r:li.:: New 230kV subp.tr$,fi$fi and new 230kV line into the Treasu,f$$f,alley. for each engine location. substation and new 138kV line to 1 38-kV system line from Oxbow to Treasure '138-kV tap from site to existing y-side resources are developed 1l:t."':':: :1 1L..a:: i1 *lri?,1iks* ":rii:i'i:i:::::',:,:=1:!t:::::li:l::= J ,$**q-\\-\\_-s .,,/#.N,*4,,.New 138lpjff/nlffi-i a_tion and new'138kV line to existing/,$$8kYSr-=lFe. ',4,Ngffi38kV line froriF-fffigrce to existing ffi substation. "es%h No new transmission. New"'ili#bution 2015 tRP Page 77 6. Transmission Planning ldaho Power Company 2015 tRP ldaho Power Company 7. Planning Period Forecasts 7. PmruNrNG PeRroo Fonecnsrs The IRP process requires Idaho Power to prepare numerous forecasts and estimates that can be grouped into four main categories: l. Load forecasts 2. Generation forecast for existing resources 3. Natural gas price forecast 4. Resource cost estimates The load and generation forecasts- Forecasting lo€;t;*, is eseential ro, roano Siwer to meet including supply-side resources, DSM, future needd]lo'f ustomers' and transmission import capability-are used to .rti.ii*fulus and deficit positions in the load and resource balance. The identified deficits:re used to defup resource portfolios evaluated using financial tools and forecasts. The fcli|l,,$,,ffA9;ections prdvide details on the forecasts :;=;., :'::;::1;;1::: ::;::=,-.Load Forgcast i , '= ,. '',"'o' -":::::'!j';:' rl..:Historically, Idaho Power haffUeen all*li'mmer peaking utility with peak loads driven by irrigation pumps and air conditioning (AlCl in the months of June. July, and August. For a number of years, the groMh rate offu summ.ertitu=e.=,, :ak.horii load has exceeded the growth of the average monthly load. However,'b--Eir eaiuiei=-i-=ifipitant in planning future resources and are part of the road "":? tfi,ff,,;;i'-%,2or5 rRP' The expec-t€d*s" 1,"3&i oad $recasts for peak-hour and average energy represent ldaho frryer's most probable outcome fbr load groMh during the planning period. Howev6tl=ihe actual path of., ure retail electricity sales will not precisely follow the path suggested b he expected case forecast. Therefore, Idaho Power prepared two additional load forecasts thfiE*ess the l$Ed variability associated with abnorrnal weather. The 7Oth-percentile and 90th-per."n'ffiloud forecast scenarios were developed to assist Idaho Power's review of the resource requirements that would result from higher loads due to adverse weather conditions. Idaho Power prepares a sales and load forecast each year as part of the company's annual financial forecast. The sales forecast is heavily influenced by the most recent economic forecast of national and regional economic activity developed by Moody's Analytics, Inc., a national econometric consulting firm. Moody's Analytics July 2014 macroeconomic forecast strongly influenced the 2015 IRP load forecast results. The national, state, metropolitan statistical area (MSA) and county economic projections are tailored to ldaho Power's service area using an in- house economic database. Specific dernographic projections are also developed for the service area fiom national and local censLls data. National economic drivers from Moodv's Analvtics are 2015 rRP Page 79 7. Planning Period Forecasts ldaho Power Company also used in developing the 2015 IRP load forecast. The forecasts of households, population, employrnent. output, and retail electricity prices, along with historical customer consumption patterns, are used to develop customer forecasts and load projections. Weather Effects The expected-case load forecast assumes median temperatlrres and median precipitation, which means there is a 5O-percent chance loads will be higher or lower than the expected-case load forecast due to colder-than-median or hotter-than-rnedian ternperatures and wetter-than-median or drier-than-median precipitation. Since actual loads can vary significantly depending on weather conditions, two alternative scenarios are analyzed to address load variability due to weather. Idaho Power has generated.load folecasts for 70tl'-percentile and 90th-percentile weather. Seventieth percentile,w'eather'means that in 7 out of l0 years, load is expected to be less than forecast, and in 3 Out of l0 years, l6ad is expected to exceed the forecast. Ninetieth percentile load has a similaf definition with a 1-in-l0likelihood the load will be greater than the lorecast. Weather conditions are the prirnary factor affecting the load forecast on a monthly or seasonal time horizon. Over the longer-term horizon, economic, demographic conditions, and changing technologies influence the load forecast. Economic Effects The national recession that began. in 2008 af6iied the local econory and energy use in the Idaho Power service area. The;ev-erity, of the re'cEssion resulted in a decline in new customer growh. Idaho Power added less than 2,500 new residential customers in 201 l. Recently, the number of new resid.ential customers added each year has increased to over 6,500. Likewise, overall systerii'*s O,g in€ " 3.8 percent in 2009, followed by a 0.9-percent decline in 2010 and a slight decline,,in,2O-ll. The 2009 through 201 I time period was the flrst tirne overall energy.us- uO O""11ned.5ince the energy crisis of 2000 to 2001 . In 2012,2013, and 2014 system electricity sales increasedty1.7 percent,0.5 percent, and 1.0 percent, respectively. The sales increases were due to economiC iecovery in the service area and higher irrigation sales. : The population in Idaho Po*ii's service area, due to migration to Idaho from other states, is expected toincrease throughout the planning period, and the population increase is included in the load forecast rnodels. ldaho Power also continues to receive requests from prospective large-load customers attracted to southern Idaho due to the positive business climate and relatively low electric'rates. In addition, the economic conditions in surrounding states rnay encourage some manufacturers to consider moving operations to ldaho. The number of households in ldaho is projected to grow at an annual average rate of 1.2 percent during the 20-year forecast period. GroMh in the nr-rmber of households within individual counties in ldaho Power's service area differs from statewide household growth patterns. Service-area household projections are derived from applying Idaho Power's share to county-specific household forecasts. GroMh in the number of households within Idaho Power's service area, combined with an expected declining consumption per household, results in a 1.3 Page 80 2015 tRP ldaho Power Company 7. Planning Period Forecasts percent average residential load-growth rate. The number of residential customers in Idaho Power's service area is expected to increase I .6 percent annually fiom 428,000 at the end of 2014 to nearly 591,000 by the end of the planning period in2034. The expected-case load fbrecast represents the most probable projection of load groMh during the planning period. The forecast for system load groMh is determined by summing the load forecasts for individualclasses of service, as described in Appenclix A-Sules ond Load Forecasl. For exarnple, the expected annual average system load growth of L2 percent (over the period 2015 through 2034) is comprised of a residential load growth of I .3 percenL a commercial load groMh of 1.0 percent, an irrigation load groMh of 0.5 percent, an industrial load groMh of 2.0 percent, and an additional firm load growth of 0.6 percent. 1., The 2015 IRP average annual system load forecast reflects the continued improvement in the service area economy. While economic conditions during the,$evelopment of the 2013 IRP were positive, they were less optimistic than the actual performance experienced in tlie interirn period leading up to the 2015 IRP. The improved economic and dernographic variables driving the 2015 forecast are reflected by a more positive sales outlook throughout the planning period. The stalled recovery in the national and, to a lesser exteni. service area econorny caused load growth to stallthrough 201L However, in 2012,the recovery wasevident. with strength exhibited in most all economic time series. Retail electricity price projections for the 201 5 I RP are lower relative to the 20l3lRP, servingto increasethefo,recast of average loads, especially in the second I 0 years ofthe forecast period. Significant factors and considerations that inflil.nced.the outcome of the 2015 IRP load forecast include the following:fl . The load forecask$;J for the ZOl5 IRP ,.ft..,, a near-term recovery in the service-area economy follo , a severe riiession in 2008 and 2009 that kept sales from growing through 201 l. ffiiiigllapse in ihe hou#iiigrector in 2008 and 2009 dramatically slowed the groMh,of new hU$ffilds and, consequently, the number of residential customers being pddH"io tqqno Pow-e_-r's service area. However, since 201 l, residential and coryrmercial customer growth along with hoLrsing and industrial activity, have shown odii$ii$ of a meanin$S-.};end sij*Ia'inable recovery. By 2017, custorner additions are forecast 'ts iEpproach the gro#th that occurred prior to the housing bubble (2000-2004). o The eleekicity pric recast used to prepare the sales and load forecast in the 2015 IRP reflects the additio l plant investment and variable costs of integrating the resources identifled i"rciOf : inp preferred portfblio, including the expected costs of carbon : "''""emissions assumed forthe 20l3lRP. When compared to the electricity price forecast used to prepare the 2013 IRP sales and load forecast, the 2015 IRP price lorecast yields lower future prices. The retail prices are most evident in the second l0 years of the planning period and impact the sales forecast positively, a consequence of the inverse relationship between electricity prices and electricity dernand. o There continues to be significant uncertainty associated with the industrial and special-contract sales forecasts due to the number of parties that contact Idaho Power expressing interest in locating operations within Idaho Power's service area. 201s tRP Page 81 7. Planning Period Forecasts ldaho Power Company typically with an unknown rnagnitude of the energy and peak-demand requirements. The current sales and load forecast ref'lects only those comrnercial or industrial customers that have made a sufflcient and significant investment indicating a cornmitrnent of the highest probability of locating in the service area. Therefore, the large numbers of businesses that have contacted Idaho Power and shown interest but have not made sufficient comrnitrtrents are not inclLrded in the current sales and load fbrecast. . Conservation impacts, including DSM energy efficiency programs and codes and standards, are considered and integrated into the sales fbrecast. Impacts of demand response programs (on peak) are accounted fbr in the load and resource balance analysis within supply-side planning. The amount of committed and implemented DSM programs for each month of the planning period is shown in the load and resource balance in Appendix c_Technical Appendix . '.,,. ,,,,, ,,,,,,,,,,, . The 2015 irrigation sales lorecast is higher than the 2013 IRP forecast ttlrorgtlout tn" entire forecast period, due to the signiticant growth in the dairy industry, hi$er commodity prices and changing crop planting palterns. Following the dairy ihdustry growth, there has been a trend towards more wak.intensiVe crops, prirnarily alfalfa and corn. Farmers have also taken advantage of the Commodities market by planting increasing levels of acreage. Additionally. the conveisioq of flood/furrow irrigation to sprinkler irrigation, prirnarily related to,farmers trying to reduce labor costs, explains most of the increased energy consumption in recent years. ,-. . Updated loss factors were determined by Idalrii Power's Customer Operations Planning department. The annual average energy loss coefficients are multiplied by the calendar- month load, yieldin#e systbm.load. inbluding losses. A system loss study of the year 2012 was completed'in May ).0.14. The results of the study concluded that on average, the loss coefficients are lower than those used in the 2013 IRP. This resulted in a permanent reduction of nearly 20 aMSFtdthe'load fdtecast, annually. r,=' p e a k _ H o u f,=E:d6,Cl i F o r e c e $ The systpmpeak-hour load forecast'includes the sum of the individual coincident peak demands of residbritial, commercial, industrial, and irrigation customers, as wellas specialcontracts. Idaho Power tises the 95tl'-percentile forecast as the basis for peak-hour planning in the IRP. The 95th-percefu forecast is based on the 95'l'-percentile average peak-day temperature to forecast month ly::p.-eak'hbu r load. Idaho Power's system peak-hour load record-3,407 MW-was recorded on July 2,2013, at 4:00 p.rn. The previous sulrmer peak demand record was 3,245 MW and occurred on July 12, 2012, at 4:00 p.rn. Summertime peak-hour load growth accelerated in the previous decade as A/C became standard in nearly all new residerrtial home construction and new commercial buildings. System peak demand slowed considerably in 2009,2010, and 2011, the consequences of a severe recession that brought new home and new business construction to a standstill. Demand response prograrns operating in the summertime have also had a significant effect on reducing peak demand. The 2015 IRP load forecast projects peak-hour load to grow by approximately 63 MW per year throughout the planning period. The peak-hour load forecast Page 82 2015 tRP ldaho Power Company 7. Planning Period Forecasts does not reflect the company's demand response programs, which are accounted for in the load and resource balance as a supply-side resource. Figure 7 .l and Table 7.1 summarize three forecast outcomes of Idaho Power's estimated annual system peak load-median, 9O'h-percentile, and 95th-percentile. The 95th-percentile forecast uses the 95th-percentile peak-day average temperature to determine monthly peak-hour demand and serves as the planning criteria for determining the need for peak-hour capacity. The alternative scenarios are based on their respective peak-day average temperature probabilities to determine forecast outcomes.,, ,.-^l ,i,ti:il':,1:;' 5,100 4,700 4,300 3,900 3,500 3,1 00 2,700 2,300 1,900 1,500 1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034 wActual less Astaris Fi g u re 7. 1 _-=.t=Ej:---H Table 7.1 ...-.,..,...toad fd,i -Actual -50th Percentile *90th Percentile -95th Percentile ' . r','F.4'a-'# ' il - -:;nii Year Median 9Oth Percentile 95th Percentite 2017 2018. 201 9. 2020. 2021 . 2022 2023. 2024. 3,184 3,313 3,401 3,463 3,514 3,562 3,615 3,670 3,725 3,780 3,839 3,184 3,537 3,630 3,696 3,752 3,805 3,862 3,922 3,981 4,041 4,1 05 3,184 3,576 3,669 3,736 3,793 3,847 3,905 3,965 4,026 4,086 4,151 20 1 6 ........................ :.r::.;::.=. ".':=:,r 2015lRP Page 83 7. Planning Period Forecasts ldaho Power Company Table 7.1 Load forecast-peak hour (MW) (continued) Year Median 90th Percentile 95th Percentile 2025 2026 2027. 2028 2029. 2030. 2031 2032 2033. 3,897 3,956 4,013 4,071 4,1 30 4,187 4,242 4,296 4,352 4,407 1.5% 4,1 68 4,231 4,293 4,355 4,419 4,481 4,540 4,599 4,659 4,719 1.s% 4,215 4,278 4,341 4,404 4,469 4,531 4,592 4,651 4,713 4,773 1.5% 2034..... .... . Growth rate 12015-2034).... . .. . The median or expected case peak-hour load forecast piedicts that peak-hour load will grow fiorn 3,3 I 3 MW in 2015 to 4,407 MW in 2034-an average ahtrual compound growth rate of 1.5 percent. The projected average annual compound growth rate of the 95tl'-percentile peak fbrecast is also 1.5 percent. In the gSth-pereentile forecast, summer peak-hour load is expected to increase from 3,576 MW in 2015 to 4,773MW in*0.3,4Jistorical peak-hour loads, as well as the three forecast scenarios, are shown in Figllf,q 71. :":;- i.... Idaho Power's winter peak-hour lo;d,pecord i#;aS MW, recorded on December I O,2OOg, at 8:00 a.m. Historical wiffipeak-hour load isml ch more variable than summenime peak-hour load. The winter peak var,,itibiility is duc,to peak-drlyi.,lemperature variability in winter months, which is far greater thaa* v*i"uiffiifr"fiy,m#n;A?i4mperatures in sunrmer months. ,,.h :, ., asf by customers in Idaho Power's service area is defined by three load fiiecasts that reflqst loaiiffibertainty resulting frorn differing weather-related assumptims. Figure 7 .2 and,Table 7.2 show the results of the three forecasts used in the 201 5 IRP reported as annual system load growth over the planning period. There is approximately a 50-percent pro.blbility Idaho Power's load will exceed the expected-case fbrecast, a 30-percent probability of load'exceeding the 70th-percentile forecast, and a l0-percent probability of exceeding the 90th.percentile forecast. The projected 20 year average cornpound annualgrowth rate in each of the forecasts is I .2 percent. ldaho Power uses the 7Oth-percentile forecast as the basis for monthly average-energy planning in the IRP. The 7Oth-percentile forecast is based on 7Oth-percentile weatherto forecast average nronthly load, 70th-percentile water to forecast hydroelectric generation, and 95th-percentile average peak-day temperature to fbrecast monthly peak-hour load. Page 84 2015 tRP ldaho Power Company 7. Planning Period Forecasts 2,500 2,200 1,900 1,600 1,300 1,000 700 1979 1984 1989 1994 1999 20c4 2009 xWA less Astaris -Weather Adjusted -Expected Case Figure7.2 Average4onthly load-growthforecast 2014 20',t9 2024 2029 2034 *70th Percentile -90th Percentile 2015 tRP Page 85 7. Planning Period Forecasts ldaho Power Company Table 7.2 Load forecast-average monthly energy (aMW) Year Median 7Oth Percentile 90th Percentile 2015. 2016. 2017. 2018. 2019. 2020. 2021. 2022. 2023. 2024. 2025. 2026. 2027. 2028. 2029. 2030. 2031. 2032. 2033 ... 2034... 1,786 1,835 '1,864 1,883 1,900 1 ,918 1,941 1,964 1,988 2,012 =::.1.,i',4. 2,o3lailNtt, ,,Q,fl,( ,,2,085\tiij:|lHl 2,107 7 2,133 1,829 1,878 1,908 1,928 1,946 '1,964 1re87 2,011 2,035 2,059 2,085 :|/;fPutto? zJzq 2,156 ":..,2,183;,.i:,i;,,,:,1izo6 ,,. 2,228 2,246 2,271 2,292 1.2% 1,900 1,950 1,981 2,002 2,021 2,040 2,064 2,OBB 2,113 2,139 :;.;2,165 2,190 2,215 2,238 2,266 2,290 2,312 2,331 2,356 2,378 1.2% " "' .liitii'' ::=.....- Growth rate (2015-2034). ................ . =.?;1j€ 2,:= ry' ,:::2,219 :?340 ':::.1:a;.,.:1'.1;;2% ,:#i 't.:':::.-:a;..:Allt)'' .:..4.r.+4n4Additional Firm Load , The additi al firm-load eategory c fl$ists of Idaho Power's largest customers. Idaho Power's tariff rffiirps the company serve requests for electric service greater than20 MW under a special-c6nlract schedule negotiated between Idaho Power and each large-power customer. The contract an riff sch&le are approved by the appropriate commission. A special contract allows a custornei c,.,!,,,{ -ost-of-service analysis and unique operating characteristics to be accounted for in the.-ia$ement. A special contract also allows Idaho Power to provide requested service consistent with system capability and reliability. ldaho Power currently has three special-contract customers recognized as firm-load customers: Micron Technology, Simplot Fertilizer, and the Idaho National Laboratory (INL). The special-contract customers are described briefly as follows. Micron Technology Micron Technology represents ldaho Power's largest electric load for an individual customer and employs approximately 5,000 workers in the Boise MSA. The company operates its research and development fabrication lacility in Boise and perforrns a variety of otheractivities, Page 86 2015lRP ldaho Power Company 7. Planning Period Forecasts including product design and support, quality assurance (Q/A), systems integration, and related manufacturing, corporate, and general services. Micron Technology's electricity use is expected to increase based on the market demand for their products. Simplot Fertilizer The Simplot Ferlilizer plant is the largest producer of phosphate f'eftilizer in the western US. The frrture electricity usage at the plant is expected to grow slowly through 2016 and then stay flat throughout the remainder of the planning period. ldaho National Laboratory The DOE provided an energy-consumption and peak-demand forecast through 2034 for the INL. The forecast calls for loads to slowly rise through 202l,rts,e dramatically through2024, and stay near that higher level throughout the remainder otl_!.,forecast P..'od. ,... Generation Forecast for Existing Resdurces - . To identifu the need and timing of future resources, Idaho Power prepares a load and resource balance that accounts for forecast load groMh and generation from all of the -t ,.,,;company's existing resources and planned , ., "'' purchases. Updated load and resource balance worksheets showing Idaho Power's existing , T e c h n i c a I A p p e n d i x. Th "e-,,&i il o w i n g sdr$}i on s provide a description of"Idaho Power'i hydroelectric, thermal. dnd transmiSsion ' ' ., resources and ho;thry arejra0b,oUnted for in the load and-re#ll lance.' "' Swan Falls Dam ,, o r%g,lff*f. tr i c Re s d,,#,)M" " = For the ZOtS?iRf, Idaho Po continues the practice of using 70tl'-percentile fbrecast streamflow ioilfuons for the Snake River Basin as the basis for the projections of monthly average hydroefttiic g-qileiition. The 70th percentile means basin streamflows are expected to exceed the planning,criteria 70 percent of the time and are expected to be worse than the planning criteria 30 pbrcent of the time. Likewise, for peak-hour resource adequacy, ldaho Power continues to assurre 90tl'-percentile streamflow conditions to project peak-hour hydroelectric generation. The 90tl' percentile means streamflows are expected to exceed the planning criteria 90 percent of the tirne and to be worse than the planning criteria only l0 percent of the time. The practice of basing hydroelectric generation forecasts on worse-than-median strearnflow conditions was initially adopted in the 2002 IRP in response to suggestions that Idaho Power 2015 tRP Page 87 7. Planning Period Forecasts ldaho Power Company record. Further discussion of flow modeling for the 201 5 IRP is included in Aff,{,#,t$ix C- TechnicalAppendix. ,s. ;iffi, use more conservative water planning criteria as a method of encouraging the acquisition of sufficient firm resources to reduce reliance on market purchases. However, Idaho Power continues to prepare hydroelectric generation fbrecasts fbr 5Oth-percentile (median) streamflow conditions because the median streamflow condition is still used for rate-setting purposes and other analyses. Idaho Power uses two primary models for forecasting future flows for the IRP. The Snake River Planning Model (SRPM) is used to deternrine surface-water flows, and the Enhanced Snake Plain Aquifer Model (ESPAM) is used to determine the effect of various a,$VSfer management practices on Snake River reach gains. The two models are used in cornbinfrli n to produce a normalized hydrologic record for the Snake River Basin from 1928 gh 2009. The record is normalized to account for specified conditions relating to S4gke River reach gains, water-management facilities, irrigation facilities, and operationr. ffi?50'h-,70'h-, and 90th-percentile streamflow forecasts are derived from the rmalized hydqq-logic record. Further discussion of flow modeling for the 2015 IRP+ included in Afffiff,ffi,y C- A review of Snake River Basin streamflow trends su$$d$ts" tha the Eastern Snake River Plain Aquifer (ESPA) is minored,uE# istent decline documented in ward trends in total surface- water outflow from the river basin. The ESPA ComprehenSffi,.Aquifer Management Plan (CAMP) includes demand reduction and Weathe-r*modification measu."s that will add new water to the basin water budget. Idaho Power belfffi-eS"tll6!$=9.;aj!4-y3 effect of the new water associated with the CAMP measures is likely to be teni'ii'6'rary. Thi$'i5qr*rt,;vater-use practices driving the steady decline over recent years ar€ expected t o-nffie reitltitg in declining basin outflows assumed to persist well into the.,?@The dedli:*ift basin outflows for this IRP are assumed to continue through the planni#$,i,[erio@,, .,1 Awater-managementpft{liceaffec-+ing .,.,.:=.. Snake River stream fl ow'S'/;'i o lvesiffierelease of water to augment flows dil almon outmigrationrii.1$riod"#..federalafienrcies involved i alinon migra_{gn studies have, in recent y.,effi, su ppoft ed effufis to sh ift,'d e I i very of flow au$qlentation water fiom the Upper SnriKlRjver and Boise River basins from the tradit{[i,,!.,.q montlrsof July and August to the spring mcifi of Apiit. May. and June. The objective of the, rCamflow augmentation is to more closely mimic the timing of naturally occurring flow conditions. Reported biological opinions indicate the shift in water delivery is most likely to take place during Oxbow Dam, part of the Hells Canyon Complex. worse-than-median water years. During 2013-a year with markedly worse-than-median water conditions-flow augmentation water from the Upper Snake River and Boise River basins was delivered during May. Because worse-than-median water is assumed in the IRP, and because of the imporlance of July as a resoLlrce-constrained month, Idaho Power continues to incorporate the shifted delivery of flow augmentation water from the Upper Snake River and Boise River Page 88 2015lRP ldaho Power Company 7. Planning Period Forecasts basins fbr the 2015 IRP. ALrgrnentation water delivered from the Payette River Basin is assumed to remain in July and AugLrst. Monthly average generation for ldaho Power's hydroelectric resources is calculated with a generation model developed internally by Idaho Power. The generation model treats the projects upstream of the HCC as ROR plants. The generation model mathematically manages reservoir storage in the HCC to meet the rernaining system load while adhering to the operating constraintson the level of Brownlee Reservoirand outflows from the Hells Canyon project. For peak-hour analysis, a review of historical operations was performed to y--..ield relationships between monthly energy production and achieved one-hour peak generation. The projected peak-hour capabilities for the IRP were derived from historical operation data. A representative measure of the streamflow condition for any gi"e,lllift;iiiii$e volume of inflow to Brownlee Reservoir during the April-to-July runoffrcribd. Figurel.3,,shows historical April-to-July Brownlee inflow as well as foreca-s.t3funlee inflow to-i:the SO'h. 70th, and 90tl' percentiles. The historical record demonstrates the variability of infiU#s to Brownlee Reservoir. The forecast inflows do not reflect-ihe historigl variability but do include reductions related to declining base flows in the Snake River. ,{s-n'dted previously in this section, these declines are assumed to continue through the planning pefiod. .1 ; 0 1 980 1985 '1990 1995 2000 2005 2010 2015 2020 2025 *Historical -50th Percentile w70th Percenlile *90th Percentile Figure 7.3 13 12 11 10 I 8 oaaLL 6't6 o_=5 =4 3 ) 1 201s tRP Brownlee historical and forecast inflows Page 89 Idaho Power recognizes the need to remain apprised of scientiflc advancements concerning climate change on the regional and global scale. ldaho Power believes there is too much uncertainty to predict the scale and timing of hydrologic effects due to climate change. Therefore, no adjustments related to climate change have been rnade in the 2015 IRP. A discussion of climate change, including expectations of possible ef-l'ects on the Snake River water supply, is included in Appendix C-Technical Appendix. Coal Resources , , Idaho Power's coal-fired generating facilities have typically operated as-baseload resources. Monthly average-energy forecasts in the load and resource balance for the coal-fired projects are based on typical baseload output levels. Idaho Power schedules periodic maintenance to coincide with periods of high hydroelectric generation, seasonally low markot priidsl and moderate customer load. With respect to peak-hour output, the coal-fire$:projects are ftiii.{,o4st to generate at the full-rated, maximum dependable capacity, minus 6 perCIeht to account foFfticed outages. A summary of the expected coal price forecast is includrqd:ii Appendix C-TechnicfilAppendix. Major plant modifications or changes in plant operations required to maintain compliance with air quality standards are projected for the Jim Bridger units in 2A15,2016,2021, and 2022 due to the Regional Haze final rulemaking. :, The 2015 IRP assumes Idaho Power's shaib ofthe;B.qar{nan plant yill not be available for coal- fired operations after December 31,2020. This,date is&e result of An agreernent reached between the ODEQ and PGE related to complianc.-e,$th Regional Haze rules on particulate matter, SO2, and NO* emissi:l$i- *-. 11,;1;,, ' Coat Analysis -,,,,,.:, 'r,,,4,% Idaho Power prepared un initul "qffiTffi, a3 pltr of the 201 I IRP Update and the report was fi led with the IPUC and OPffiilil'oFebruary 201 3. The 201 I stLrdy evaluated several investment alternatives ineltifi{fi&,conr.,ting.oal units to bum natural gas, installation of selective catalytic reduction (SCR) or selecti.ve non:Cat4lytic reduction (SNCR), and scrubber additions. In the end, 7. Planning Period Forecasts ldaho Power Company the study,recommended ifi llation=df,.SCn on Jirn Bridger Units 3 and 4 in 2015 and2016 respectively, Since the comp,ietion of that initial Coal Study, the Company has continued to monitor the cOsts and beneliJ3lssociated with the SCR investments for Jim Bridger Units 3 and 4 to ensure that:those invesffients remain cost-effective. An update to the economic analysis of the Bridger 3 and4 SCR investments that supports the continue<l installation of the SCRs for those units is presented in Appendix C - Technical Appendix of,the 201 5 IRP. There are no further environmental investment action items required by state or federal regulators prior to preparing and filing the 2017 IRP. In addition, there have been no material changes in the underlying forecast assumptions fiom the 201 I study. The Company will evaluate investment alternatives for SCRs at Jim Bridger 1 and 2 no later than the 201 7 IRP. Idaho Power seeks to balance the impacts of carbon regulation with the economic irnpact to customers, as well as customer needs forreliable service. Forthe 2015 IRP, the Company applied a more dynamic economic analysis of the existing coal units as compared to prior IRPs. Page 90 2015 tRP ldaho Power Company 7. Planning Period Forecasts The 2015 IRP evaluated numerous portfolios which included coal unit shutdowns on various dates. The Company believes the terrnination of operations at its coal-flred plants in the very near future would lead to increased risk of higher costs for custorners in the near-term without a commensurate long-term economic benefit. The Company is mindfirl that an early retirernent of an asset requires accelerating the recovery of the remaining investment in that asset. This increases the cost in the early years to achieve longerterm savings. Idaho Power has been in discr.rssions with the joint owner of the North Valrny plant regarding the future of that plant. State public utility commissions and Idaho Power's customers expect future costs to be mitigated and balanced with future risks. Cost and risk will continue to be important factorsintheutilities,discussionsanddecisionproceSSeS. _::,::4.", ::::r:, Idaho Power currently benefits from the diversity of its generation.f€Sour0es; 4nd that diversity helps mitigate the power supply cost risk bome by customers as the Compafi$itransitions to the new energy landscape. Natural Gas Resources Idaho Power owns and operates four natural gas-fired, SCC,Ts and one natural gas-fired, CCCT. The SCCT units are typically operated durin€ peak load e+e$lp- in summer and winter months. The monthly average-energy forecast for th$eQTs is based on,,the assumption that the generators are operated at full capacity for heavy-toad hours duringJanuary, June, July, August, and December and produce approximately Z,5A,,aMW9f,gas..fired generation for the five months. With respect to peak-hour output, ttre SCCTs@ as,,$qmed cap$1e of producing an on-demand peak capacity of 416 MW. While the peak dispatchable capacity is assumed achievable for all months, it is most critical torytem' bility d summer and winter peak-load months. Idaho Power's CCCT,&ngley Gulch, be",.4ry" " ercially available in June 2012. Because of its higher efficiency ratiil$;ilangley Gu:Ieh is expected to be dispatched more frequently and for longer runtimes th.,.q.,_!- the existing,.SCCTs. Langley Gulch is forecast to contribute approximately 165 aMW with=, ..:6dl.demandifeaking capacity of 318 MW. NatuglGas P rice, ForecastI Future natdml,-gas price assumptions significantly influence the financial results of the operational mode=ling used$ evaluate and rank resource portfolios. Forthe 2015 IRP, Idaho Power is using theUS Enbigy Information Administration (EIA) natural gas price forecast. Idaho Power also used the EIA as the solrrce for the natural gas price forecast for the 20 I 3 IRP, and continues to use the EIA forecast for ldaho-jurisdiction avoided cost calculation purposes. The natural gas price forecast was discussed during the flrst three monthly IRP Advisory Council meetings held in August through October 2014. During these discussions, Idaho Power provided comparisons of the EIA natural gas price forecast to an alternative forecast, as well as comparisons to observed settlement prices for futures trading in the natural gas rnarket. The Annual Energgt Outlook 2014 Reference case, published by the EIA in April 2014, is the source forthe natural gas price fbrecast fbrthe 2015 IRP. Forthe 2015 IRP, ldaho Power uses nominal prices as published by the EIA as inputs to analysis performed. A chaft showing forecast 2015 tRP Page 91 7. Planning Period Forecasts ldaho Power Company Henry Hub naturalgas prices is presented in Figure 7.4.The low and high case natural gas price forecasts used for the 2015 IRP and shown on the chaft correspond respectively to the high resource (high availability) and low resource (low availability) cases reporled by the EIA in the AEO 2014.ldaho Power applies a Sumas basis and transportation cost to the Henry Hub price to derive an Idaho city-gate price. The Idaho city-gate price is representative of the gas price delivered to Idaho Power's natural gas plants. ")4'*"""" $13 $12 $11 $10 j oc$9o ='- :$8 iEsz o Esu'cL3ssoE;$4z $3 $2 $1 s0 2015 20't6 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 ?031 2032 2033 2034 *Henry Hub 2014 EIA High Case (nominal) -Henry Hub 2014 EIA Planning Case (nominal) - Henry Hub 2014 EIA Low Case (nominal) Figure 7.4 st-ElA Annual Energy Outlook 2014 (nominal dollars) Reso b Cos ' !,|!a/.:!t:\conducted afirp$1 of resour- creening for the 2015 IRP. As described previously, cost inputs and operatinS ti,:ffigsed to develop the resource cost analysis are derived from the September 2014 LazarA repoffiXd{fr{J'Power engineering studies and operating experience, or consultation with specific resouriiildevelopers. Resource costs are presented as follows: o Levelized Capacity (fixed) Costs-Levelized fixed cost per kW of installed (nameplate) capacity per month . Levelized Cost of Production (at stated capacity factors)-Total levelized cost per MWh of expected plant output or energy saved, given assumed capacity factors and other operating assumptions Page 92 2015lRP ldaho Power Company 7. Planning Period Forecasts The capital cost of solar photovoltaic resources has been the subject of considerable IRP Advisory Council discussion over recent IRPs. As widely reporled. solar photovoltaic costs have declined rnarkedly over recent years, presenting unique challenges in deterrnining appropriate costs fbr solar resources. For the20l5 IRP, ldaho Power utilized the Lazard report's projected 2017 capital cost of S1,250 per kW lor utility-scale single-axis tracking solar photovoltaic resources. To fufthercapture reported trends in solar photovoltaic capital costs, the 20l5lRP capital cost of $ 1,250 per kW was not escalated according to the IRP's assunred level of inflation, as the capital costs for other considered resources were. Forthe 2015 IRP, Idaho Power is including in resource cost calculations the assumption that potential IRP resources have varying econonric life. Financial analysis forthe IRP assumes annual depreciation expense of capital costs is based on an apportioning of the capital costs over the entire economic life of a given resource. ..: The levelized costs for the various supply-side alternatives, ifulrd. capital costs, O&M costs, fuel costs, and other applicable adders and credits. The initial capital investrnent and associated cost of capital of supply-side resources include engine,ering development costs. generating and ancillary equipment purchase costs, installation costs. ailplicable balance of plant construction costs, and the costs for a transmission interconnection to ldaho Power's network system. The capital costs also include allowance forfunds used durinFonstruction (AFUDC) (capitalized interest). The O&M portion of$ilmsource's lmlized cost includes general estimates for property taxes and property insurance prerniums. The value of RECs is not included in the levelized cost estimates but is accounqed foi when analyzing the total cost of each resource portfolio . r:,::!it,i,tl ,:,:.,- . ., The levelized costs for each o bt*anO-ria. ."uor... options include annual administrative and marke!fficosts offie programj,Bn annual incentive, and annual participant costs. The demand-side ieiource costs {qnot reflect the financial elfects resulting from the load Specific resourQ ....-. goffirripputs, ftrEl recasts, key financing assumptions, and other operatingparamet howi'fi,'Ay.y,1nd*'A1-TechnicalAppendix. ResdUr.:ct Cost Ah.Olysis ll-Resource Stack Lev e I i z ed:C a p. .a c ity (F i x e d) Cosf The annual fixed-revenue requirements in nominal dollars foreach resource were surnmed and levelized overthe assumed econornic lifb and are presented in terms of'dollars per kW of plant nameplate capacity per month. Included in these levelized flxed costs are the initial resource investment and associated cost of capital, and flxed O&M estimates. As noted earlier, resources are considered to have varying econornic life, and the frnancial analysis to determine annual depreciation of capital costs is based on an apporlioning o1'the capital costs over the entire economic Iife. Figure 7.5 provides a combined ranking of allthe various resource options in order of lowest to highest levelized fixed cost per kW per month. The ranking shows that natural gas peaking resources and demand response are the lowest capacity cost alterrratives. The natural gas peaking resources have high operating costs. but operating costs are not as important 2015 tRP Page 93 7. Planning Period Forecasts ldaho Power Company fbr resources intended for use only during a lirnited number of hours per year to meet peak-hour demand. Levelized Cosf of Production Cerlain resource alternatives carry low flxed costs and high variable operating costs while other alternatives require significantly higher capital investment and fixed operating costs but have low variable operating costs. The levelized cost of production measllrement represents the estimated annual cost (revenue requirements) per MWh in nominal dollars for a resour,ce based on an expected level of energy outplrt (capacity factor) over the econornic life of the resource. ',,,i'The nominal, levelized cost of production assuming the expected capaciffifactors for each resource type is shown in Figure 7.6. Included in these costs are the cost ofbapital, non-fuel O&M, fuel, and emissions adders; however, no value for REQsvas assumdd,in$is analysis. The 82H transmission Iine is the lowest cost resolrrce for meeting baseload re<ffiryents. When evaluating a levelized cost tbr a project and compaiing it to.the levelized cost'of another project, it is important to use consistent assumptions foethrc computation of each number. The levelized cost of production metric represents the annual cost of production overthe life of a resource converted into an equivalent annual annuity. ThiS ii similar to the calculation used to determine a car payment; only, in this casejhe a,+L payment Wo.tld also include the cost of gasoline to operate the car and the cost of maintaining the car "' itr useful life. An important input into the levelized cost of production caElation for a generation resource is the assumed levelof annual capacity,,use overthe life of the resource, referred to as the capacity factor. A capacity factor of 50 perCeflt,Would suggest a resource would be expected to produce output at full capacity 50 percent of the hours durihg the year. Therefore, at a higher capacity factor, the levelized costwould be less because the plant would generate more MWh over which to spread the fixedcosts. Conversely, lower capacity-factor assumptions reduce the MWh, and the levelized cost would be higher. For portfolio,'Co5tahalyfu fixed iesource costs are annualized over the assumed economic life for each reiource and are4plied only to the years of production within the IRP planning period, therebyrra-iountin g fbr end'etfects. Page 94 2015 tRP tr)o) o(,)o o_ (L E. ro oN oo o .6 o!NO6.X r o@ 6ao(-) a6: o o =^ia5! oe oooo E'0)x =o(g CLa!o E'o .N o g (Eo ao(t u,t- o) J.9IL 99a9e9?i?ti?t9r9e?9etet??3tlet @ o @ o o Q N o o o o o o o o o o r, o @ o o @ o o-Q q' o o oi6j6E6ti-o;l-Nooo-66l,:39=9-s9- =g--j-- 9 =s9=Srge,EeeByt Eeg,lEp?eZ_ L.^ oEs,..E -ft E:3 -s ft s:i p:6 ' p;6 S * 5; €; E g'H A r -E E -E g#E Pe6r ==3E{EEEE' $ ripfr 3*: g=tEs-ETHEE=€HE;fi!!5e i es'E,en ETEeEEtE"";F{i;EggiiiE * 3ps E EEE€EE*€alSii:-;=g!x? e -q.Q; €5=Eg'.uHEueB#E=?EE? j E doE lLas<E =xEcail-J,6a-oE6u,, ,.i liaad; Z E E E E-' tiP#- = aE==EB ; ? H E IA i E8116 i E u3 "' tt B - ECoiSE--o ooooo olJ-oo o(L O)C'- co o_ N c(I, o_ Eoo o =o o_ o-coE o_E. ro oN (oo,o(r)oo_ F o oo o N w ",14 z tsN NN s W :,4 '^& so so W Etr $ffiwM ffit sso6- ooN o3!= oq N P^=o o 6C)D(E o.E3o (s CLoaE3ot,o4G o6'!q!.Ez ao ,J E'oLo- o oooEo .No g L IEc) Ioat (o l- o J .Pll. EtiMswN* ilffi ruW ffi s-o:YN s<N-:: -o +_ERieE:l It oo 999 o t99 ooo 9=- oo 9t9999999?9t9t Goooo@oooooo@@@-d;-i6-6o;hvN-==_ =v t9t9 o o o o:@Y99Sl so ffi &twwffi s ts # H s:<FON-= €P rffi ffiMffi ffi s^ox_o6:<-6Er I $ I ilt E ffiK ffix ffiffi sfP i't ww MM s: -^+EEq9,e,,o-EBa=.:oga9S=-EE,q gf 6 E E E*rEEE{.g,;5 5g,:; iS gt E; g : p€pu.E : * =d.g.Et -*;o.!,ir-,X,q; o E Et9r: Ho;:E: E8s!!E tEES rgSS;EEeEgEiif#xT; Y StaF 62 xE oo=siFEEtE=-FsotrEE i:t;- s;+g EstEt[fi$;.*xFa;58S i 333 ; t5 E dL=l?='o ':q d5 s-= s ?s5 i E; ,. **9', 4a ii E; E P=. * : v'n E=EE-'-'64!@ao5 F #ee - E3 to e EE E Ao ,i Ba Co+ o C) o =oo- o-coE o U'(0(-) 0) oLLEo o)o- o).cCco(L t- ldaho Power Company 7. Planning Period Forecasts Supply-Side Resource Costs Idaho Power prefers to use independent estimates of the supply-side resource costs when the estimates are available. For the 2015 IRP, Idaho Power used Lazord's Levelized Cost of Energy Analysis-Version 8.0 as the primary source forsupply-side resource costs. Lazard, a leading independent financial advisory and asset management flrm, issued the levelized cost report in September 20l4.ldaho Power engineering studies and plant operating experience were also utilized. Costs for select resources not provided by the Lazard report and for which ldaho Power has limited engineering and operating experience were determined throughionsultation with The 2015 IRP forecasts load groMh in the Idaho Power service arel,and fi$pntifies supply-side resources and demand-side measures necessary to meet the futurgi fiergy'fl#rti of customers. The 2015 IRP has identified periods of future system deficientjies. New resource costs are levelized estirnates (based on expected annual generation) that include capital, fuel, and non-fuel O&M. Figure 7.7 shows the capital costs in nominal dollars per kilowatt (kW; f,or a new resource with a 2020 online date plotted against peak-hour cap ity for various supply-side resources considered in the 2015 IRP. The online date of 2020 is used because, depending on the coal retirement scenario, the earliest date for new resources in th:q,2Ol5 IRP is 2020]The use of the 2020 online date also allows projected 2015-2016 capital ccist d.eplines in utility-scale photovoltaic solar to be captured in the plottEd,..i1a14. " '. . .- $7,000 $6,000 $5.000 $2,000 $1,000 $0 Ii I ; M.oooo(J '6oF $3,oooo 20'13 tRP .B2H rSUUI rCCCT ECHP I Pumped-Storage Hydro . Small Hydro eResidential PV ;:; Utility PV aWind x Reciprocating Engines r lce TES xVFlow Battery r Geolhermal ti ..\ ,,1,,2015lRP &l Lower Risit_) hjgtr-..P9?L-!lqu-[ iCapacity, Low Capilat Cost X O , '";i;#"'1,"ff"H"'"i*' Figure 7.7 Capacity cost of new supply-side resources, online 2020 Resources in the lowerright portion of Figure 7.7 are considered to provide peak-hourcapacity at a relatively low capital cost. Among the resources in the lower right porlion, the B2H transmission line and various natural-gas fired generating resources provide the highest peak- 2015 tRP Page 97 7. Planning Period Forecasts ldaho Power Company hour capacity at the lowest cost. Ice-based thermal energy storage (TES) also appears in the lower right portion as a relatively low cost capacity resource. The dashed arrow on the figure represents the notable shift in assumptions since the 2013 IRP fbr utility-scale photovoltaic solar. The marked decline in photovoltaic solar capital costs has been extensively reported over recent years. The shift in peak-hourcapacity is based on analysis performed forthe 2015 IRP indicating peak-hour capacity slightly in excess of 50%o of nameplate capacity for single-axis photovoltaic solar power plants. This analysis is described in Chapter 5 of the 2015 IRP. While it is important to evaluate the costs presented in Figure 7.7,the costs represent only parl of the total resource cost. In preparing the IRP, Idaho Power also considersthTvalue each resorrrce provides in conjunction with the existing resources in the company's geneiation portfolio. Supply-side resources have different operating characteristics, makingsome better suited for meeting capacity needs, while others are better for providing energy. Figure 7.8 shows the levelized cost of energy in dollars per me$awatt-hour fM*f',) for various new supply-side resources considered in the 2015 IRP, w} costs considered iilcludp those related to building and operating the resource for a2}-feai period. The data used to Cieate Figure 7.8 allows for resource alternatives to be compiii.ed baseduofthe capacity cost and the total levelized cost of production. ,* ...:aar1 I - ---. - , i 1 1- - "" x t 2 I,,1w 3 oo:ooe (J $7,000 $6,000 $5,000 $4,000 $3,000 $2,000 $1,000 t-.Y' i.!} 2013 IRP ,^ .B2H rSCCT EICCCT OCHP , Pumped-Storage Hydro ,:rResidential PV i:Utility PV ^Wnd x Reciprocating Engines - lce TES x V Flow Battery * Geothermal $100 s150 $200 Cost of Production ($/MWh) Figure 7.8 Energy cost of new supply-side resources Resources in the lower left portion of Figure 7.8 produce (ordeliver) energy at low levelized cost and have relatively low capital cost. The B2H transmission line is among those resources having low levelized costs and lowcapital costs. FiguresT.T and 7.8 respectively demonstrate that the Boardman to Hemingwaytransmission Iine is attractive as a capacity resource (i.e.. one needed relatively infrequently) and energy resource (i.e., one needed for fiequent energy delivery). Page 98 2015 tRP ldaho Power Company T Planning Period Forecasts In contrast, a simple-cycle combustion turbine (SCCT) has cornpetitive costs with respect to the relatively infrequent delivery of capacity (Figure l.l), but is rnuch less competitive when required to deliverenergy (Figure 7.8). The dashed Iine represents the capital cost decrease observed in utility scale photovoltaic solar since the 2013 IRP. A complete discussion of the cost of capacity and the total cost of the resources analyzed in the 20 I 5 IRP is presented in Chapter 7. Load and Resource Balance Idaho Power has adopted the practice of assuming drier-than-nredian water conditions and higher{han-median load conditions in its resource planning process. Targeting a balanced position between load and resources while using the conservative waterand load conditions is considered comparable to requiring a capacity margin in excess of load while using median load and water conditions. Both approaches are designed to result in a systern having a sufficient generatingreServecapacitytomeetdailyoperatingreserverequirelnents. To identifo the need and timing of future resources, Idaho Power prepares the load and resource balance. which accounts lor generation frorn allthe cornpany's existing resources and planned purchases. Due to the uncertainty of the CAA Section I I 1(d) rule. many different assumptions can be made forthe future of ldaho Power's coal resources. To address these different coal futures, Idaho Powerhas analyzed nine load and,resource balance scenarios. o Status Quo: The first scenario urtUfieS'id?rho Power makes no changes in the operations of its coal fleet. This scenario is veri's,funilaitothe load and resource balance provided in the 2013 IRP and is designed to provide,a b4sis for comparison. j:o Maintain Coal Capac-ffiffij:;econd SC.eilario asslrmes Idaho Power will maintain its coal fleet, but reducEimissionftutput in C6mpliance with proposed the CAA Section 1 I I (d) rule by,l$iting or capping t|e am@ generators can run. r Retire Valmy CoaF=.P=la : A third Set bf'scenarios assurnes varying timing dates for the retiremeJtt of Units 'l=AA*2 of the Valmy coal plant. There are lour scenarios that reflect po=ssiblefiietiiefi:nt teS'for Units I and 2 of Va|my: .-riRetire Units I aEilby the end of 2019 ' " R;ri1e untts 1 a.W bY the end of 2025 . Retiie Ulljl 1'b, the end of 2019 and Unit2 by the end of 2025 . Retire Unit I by the end of 2021 and Unit 2 by the end ot'2025 o Retire Units I and2 of Bridger Coal Plant: Two sets ol-scenarios assume differing retirementdatesforUnits land2oftheBridgercoal plant.'l'hereareatotal offburunits at Bridger and Units 3 and 4 are not being considered fbr retirenrent. o Retire Unit I by the end of 2023 and Unit 2 by the end o1'2028 o Retire Unit I by the end of 2023 and Unit 2 by the end of 2032 2015lRP Page 99 7. Planning Period Forecasts ldaho Power Company . Retire Valmy Coal Plant and Units I and2 of Bridger Coal Plant: A final scenario assumes the retirement of Un its I and 2 of Valmy coal plant by the end of 2025, retirement of Unit I of Bridger coal plant by the end of 2023 and retirement of Unit 2 of Bridger by the end of 2032. Each scenario will include a load and resource balance using average monthly energy planning assumptions and peak-hour planning assumptions. Average-energy surpluses and deflcits are determined using 7Oth-percentile pater and 7Oth-percentile average load conditions, coupled with Idaho Power's ability tti import energy from firm market purchases using a reserved network capacity. Peak-hour load deficits are determined using 90tl'-percentile water al'a qj,E=gcentile peak-hour load conditions. The hydrologic and peak-hour load criteria are the major ftffi -s in determining peak-hour load deficits. Peak-hour load planning criteria ar l Ure stringent than average-energy criteria because Idaho Power's ability to irnport additional energy is typically limitiid during peak-hour load periods. All load and resource balances, irrespective of the "oui' ,dnJer consideration, Existing dernand reduction due to the,4glnand response programs and the forecast effect of existing energy efficiency programs: o Existing power purchase agreements with Ell rb= 4.!, Wind, Raft River Geothermal, and Neal Hot Springs.IdahoPower's agreement with Elkhorn Valley Wind expires at the end of 2027. The otlr,. greements do n-rt/!|; pre within the planning period. . Firm Pacific Northwest import bapability. This does not include the import capacity from the Boardman to,,Hemingway t [q;j ne or the Gateway West transmission line. . ':1.-'o Expected generation i?.ofiall ldaho Power-owned resources. Boardman coal plant has a planne.d retiremint date' 020. . .Efisting PURPA proj,ects and'contracts completed by Octobe r 31,2014 including 461 M of solar projects under contract but not yet operational. (Contracts for four solar proj€cts{otaling l4t MW of installed capacity were terminated on April 6, 2015. The relatively late termination date precludes the removal of these projects from load and resource balance analysis for the 2015 lRP.) Idaho Power assumes all PURPA contracts, with the exception of wincl projects, will continue to deliver energy throughout the planning period and the renewal of contracts will be consistent with PURPA rules and regulations existing at the time the new contracts are negotiated. Wind projects are not expected to be renewed. There is a total of 627 MW of wind under contract. Wind contractsbegintoexpireinOctober2025and total windundercontractdropsto l30MW at the end of the planning period. At times of peak surnmer load, Idaho Power is using all available transmission capacity (ATC) from the Pacific Nofihwest. If ldaho Power was to fbce a significant outage at one of its rnain generation facilities or a transmission interruption on one of the rnain import paths, the company Page 100 2015 tRP ldaho Power Company 7. Planning Period Forecasts would fail to meet reserve requirement standards. If Idaho Power was unable to meet reserve requirements, the company would be required to shed load by initiating rolling blackouts. Although infiequent, Idaho Power has initiated rolling blackouts in the past during emergencies. Idaho Power has committed to a build program, including demand-side programs, generation, and transmission resources, to reliably meet customer demand and minimize the likelihood of events that would require the implementation of rolling blackouts. Idaho Power's customers reach a maximum energy demand in the summer. From a resource adequacy perspective, the month of July has historically been the month du.ring which ldaho Power's system is most constrained. Based on projections for the 2015 IRP, July is likely to remain the most resource-constrained month. A secondary maximum eneigy demand occurs during the winter in the month of December. Tables 7.3 and 7.4 pro-y e for the months of July and December the monthly average energy deficits for each of th-e?;eb.'al fufures considered in the specified in the tables. Because no deficits exist prior to tables includ€'fua for only the period 2020-34. 2015 tRP Page 101 o_tr ro ON No o(r)(U o_ !tooN r{)(.,rr)(')ro (f) ro('), oooN I (o @ (o (o NooN I I I'sl ?AooN I I I oooN I I o oNoN I I N(f)I I oNoN I I I I FNoN I I I I (oNoN I I I I rr)NoN I I I I stNo .$s I I I I I :!rt"Nosl irr,,I I I NNeN ;,!I I I NoN 't1.:itu#r&:.I I .nti|i ii,li$ its I I o.N:o,!!.,+"=;E=ai!:.:E f*\ I ==o o.=o 0,o E'I o, IJJ 7ffi ofa f 6 U) --o6o(oo 6oo C'6 C'(g o oN c UJ 6o NEco o=C) o) {)E. -E6 oNoNDc UJ oo) NEcG q=Cf a) o)t Eo l/,, iiir v)NoN ctu G0)h:$l:t?; l' EcGo) ON Ec UJ 6 C) =Cl c) q) E. 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E!otrcLo=Eo.t\ o, ^A=oEC)oLo=oooE L o,:E, '-o <rrr-E O(E =E(!(l)FE opoaE LG EoEro a! !.>o.o. ot,o .E Eoo EItrc, E) .E .9,xo ! =3o (Eo.J .o ==oct)(!or^>Er(!rE -oEoO=E=*b-o>\LPt9-bb,\o_cD9skOu>d)a!e>E 50, o=E6>P =d)5o. Eoi- oci, oNPo:: =oFEFL co =oo 0) =oo-o.CoE ooooo o LL Eo o o_(r, .CCC(E o_ r- COo oO)o o_ o_t rr) oN oiooNEcUJ .:_6o N -_cfo -NENOPs!fi _G!2ofi>LLNGEoc>6 =.2fC-)o oqito>I,)EE!'=Gco> !t (E E6)EE (! !.>o-o. o l,o .E Eoo It .E El 'Eo'io =3o (Eo.,. ..*,,.9,)illi,:,t .:::.::11:: **!)1 |v" L, =1 $ = ,i.= = ..= 1!1.;: .., ..-g.. '.9ptFieE tE:=}E.oo)aEoeL-'tEo:r4'c,. a :uc /-ttg !Ji:to "t, oDfu.YE(EGoo.d}E5=cq)o=tcLo,o!J€6tso-C)raJ -^-9HLlvoo)oL @OF:EoL:otp)-o cc) hn e (l)H-l =Ex qcOO E-cN ch^(EUEE LV! o-UA= E .- (!9.- o)-cLEl3 o.'6'- =c,Y Oo: EC); dt-1l^.1JL-L !(l)FEn: 6 =otr38 EocQ $2; IP().= = -o -th H{:Xho o, A*! t.-5.= 3 Oa d)OJXLA-Y 3Hq<! 9(JEcC)(c0-(E -., I 3 -o€H I9t, =.-L,9 .9 pAE; :03v A EFi' a €g(-) - --.: >-8Ed E RcS LA (!E:a{ s3. = .X o- ^ @ \Y Et;eE 33cOo.)iicE.: A * Pn U 9 96 - h^S q!:-E; rsE^cio > e e ='EO o L YC!E,O torsE- - (J,-Aa-Lvx.:=0,,- f€ 5_o 5 5€ B'- .r -irE .?E - E'- l'* guc6?of ^U-= 0()-.o =otj€s #E U' U'o.)J)oIr Eo 0)(L o,.c Co(L l- coo- Eoo o)3oo- o-coE 8. Portfolio Selection ldaho Power Company 8. PonrFolro Srlrcnoru Portfolio Design In the 2015 IRP, Idaho Power continued the 2013 IRP's practice of analyzing a range of coal retirement poftfolios. The consideration of additional early coal retirement, or early shutdown portfolios is consistent with expectations expressed by the Idaho Commission in its Acceptance of Filing order for the 2013 IRP (Case No. IPC-E-13-15, Order No. 32980)Jhe 23 portfolios analyzed for the 2015 IRP can be grouped into the following ten categorie$: ,rt1.|k, ,. 1. Status quo portfulio-A single resource portfolio with no affiffififfilile.l retirement of coal- fired generating units other than Boardman in 2020 and w'.itlldut &. -uf constraints related to the proposed CAA Section I I l(d) regulation. The Sgtus Quo poft,ft,lio relies on the Boardman to Hemingway transmission line and rec"in-ffiting gas engiff.e- meet future resource needs. " ,i,"i jAll other portfolios considered in the 2015 IRP(l,fpsume odir,flfiliance with CAA Section I I l(d) based on various assumptions regarding tt-@$$fnal rule will contain. ' :+:'::';::"2. Maintain coal capacity portfolios . 1{s1:::l:= of three poft.fe.Ii with no retirement of coal capacity during the IRP planning n'€,i5-6ryip.1**Uexcepti66f the planned 2020 year-end Boardman shutdown. t# '*ns\\1,\-ui:i:,ii.:-.i,i :,,.,..,, -%= ':t=-====tt=t....,; 3. North Valmy retiremeniJlear"Kd 20li portfulios-A ffit of five porrl-olios with retirement of both-,N.ou$$t=Vhl , units at]$-end 2019. " ': t.: ";i1. 4. North Valmy re;,$$fuent tear^u$d Z0Z5 pii.{atios-A set of three portfolios with retirement of b ny= at_U,ear-end2O25. North Valmu laporffit-Lffi 2g[$"tti"OUnit2 f.,.*tirement year-end 2019 (Unit l) and year-end 2025 (Unit 2) port{9,ffi:Fffifuftwd:pfufolios with retirement ofNorth Valmy Unit I at year-end 2$19 and UnitZ"atifear-end 2025. "; E# ':. lW.?thValmy staggeffi retirement year-end 2021 (Unit l) and year-end 2025 (Unit 2) folio with retirement of North Valmy Unit I atyear-end 2021 portfolios-A set of two portfolios with retirement of Jim Bridger Unit I at year-end 2023 andUnit2 at year-end 2032.The early retirement of these portfolios is assumed to allow the avoidance of installation of selective catalytic reduction for Unit I in2022 and Unit 2 in 2021. All portfolios for the 201 5 IRP, including portfolios of this set, are assumed to have SCR installation for Jim Bridger Units 3 and 4 completed by 2016. 8. Jim Bridger staggered retirement year-end 2023 (Unit l) and year-end 2028 (Unit 2) portfolio-A single poftfolio with retirement of Jim Bridger Unit I at year-end 2023 and Unit2 at year-end 2028.The early retirement ofthis portfolio is assumed to allow the and uni{fl;i,W}e?,!,:ffid 2o2s ' 7. Jim Bridgei'3,.t@gered retirement year-end 2023 (Unit l) and year-end 2032 (Unit 2) Page 104 20'15 tRP ldaho Power Company 8. Portfolio Selection 9. ,lin Bridger staggered retirement year-encl2023 (Unit l) antlyeor-end 2032 (Unit 2), North Valmy relirement year-entl 2025 portfolio--A single portfblio with retirement of Jirn Bridger Unit I at year-end 2023 and Unit 2 at year-end 2028, and retirement of both North Valmy units at year-end 2025.The early Jim Bridger retirement in this portfolio is assumed to allowthe avoidance of installation olselective catalytic reduction for Unit I in 2022 and Unit 2 in 2021 . 10. Alternative to Boardman to Hemingway portfolios-A set of four porrfolios in which the Boardman to Hemingway transmission line is replaced by alternative resources. Except for this set of portfolios, all other 2015 IRP portfblios have the Boiiidman to Hemingway transmission line. The coal retirement portfolios include the additional cost of iecovering the rernaininginvestment in the coal units prior to retirement. In addition. resource retirement, includes the accelerated decommissioning costs when estimating the resource portfblio costs. The coal retirement portfolios also include the cost savings associated with early investment recovery and shutdown. These savings include avoided future capital investments, fixed operating costs, and avoided return on investment. Treatment of the fixed-cost accounting is summarized in Table 8.1 below. avoidance of installation of selective catalytic reduction lor Unit I in2022 and Unit 2 2021. F i xe d - c ost, r r:.ln.o,,;fi l" o a l ret i rernentTable 8.1 Fixed-Cost Description Cost lmpact Accelerated Recovery of D-enreciatio, Ejnf-#;.::i.,l,.Yainihg lnvestments Cost Utility Rate of Return nppliedff6.r;,,, U'd6fXfB Savings Accelerated R""_g.X;fi1Xl g,fDlcomnits,g$ning and Demolrtion Costs (Net of Salvage) Cost Avoidance of F,$liiirfti lfioiem€'ntal Capita-llffcluding Avoidance of Environmental Retrofit lnvestments) - savlngs Portfolio Design and Selection Idaho Power analyzed 23 resource portfblios for the 2015 lRP. All portfblios are designed to balance forecast load with available or additionalresources to elirninate energy and capacity deficits according to the IRP planning criteria described in Chapter 7. Energy and capacity deficits for the considered coal retirement fltures are also provided in Chapter 7. Portfolios were designed in collaboration with the IRP Advisory Council and public participants in the IRP process. 2015 tRP Page 105 8. Portfolio Selection ldaho Power Company Sfafus Quo Portfolio The resource additions in the Status Quo portfolio are driven by the need to eliminate peak-hour capacity deficits beginning in July 2025 and reaching 523 MW by July 2034.The Status Quo portfolio is designated as resource portfolio Pl. P1-B2H, reciprocating engines, no coal capacity retirement, no CAA Section 111(d) restrictions Table 8.2 Resource portfolio Pl Resource lnstalled Capacity Peak-Hour Capacity Boardman to Hemingway Reciprocating engines P z(al-B2H on I i ne 2025, rec i p-.i..o_.c-l*i Table 8.3 $fi,,,.,,q, ..portf6.!! 2(a) 5oO t\A/V transfer caiiil:${ty epr 200 t\A,V transfe.f,lli#Facity Oct-Mar 0l\A/V 11.\'!::.ln llH,Ss*36 MW '=::i =,1ia Tota| re!*S rtapacity Total add* Net peak (o MVV) 536 MW 536 MW Resource additions of the set of portfolios Wittr i-fi"ftfue-ity n Boardman shutdown, are driven by capacity d,Qficits"ffifr'B g , excepting the planned iii"es, no coal capacity retirement Boardman shutdown, are driven by capacity deficits b6gifinin$,iir"1.July 2025 and reaching 523 MW by luly 2034. The portfolio+ this set difftr,.from portfolflo Pl only in the assumed online date for B2H, ranging frorn Za2t:ti2045. The folfolios are designated as resource portfolios P2(a), P2(b). and P2(c). I Resource lnstalled Capacity Peak-Hour Capacity 2025 2034 Boardman to Hemingway :: Reciijrocati n g en gines 500 I\A / transfer capacity Apr-Sep 500 NA,V 200 MW transfer capacity Oct-Mar 36 MW 36 MW Total retired capacity Total added capacity Net peak-hour capacity (0 MW) 536 MW 536 MW Page 106 2015 tRP ldaho Power Company 8. Portfolio Selection Pz(bl-BzH online 2023, reciprocating engines, no coal capacity retirement Table 8.4 Resource portfolio P2(b) Date Resource lnstalled Capacity Peak-Hour Capacity 2034 Boardman to Hemingway Reciprocating engines 500 MW transfer capacity Apr-Sep 500 l\A/V 200 MW transfer capacity Oct-Mar 36 MW 36 MW Total retired capacity Total added capacity Net peak-hour capacity (0 MW) 536 MW 536 MW Pzlcl-BZH online 2021, reciprocating engines, no coal capacity::ieairement Table 8.5 Resource portfolio P2(c) r; _ Date Resource a!w4l&. I n s ta I I dtl4.g.-.4 pa c i ty Peak-Hour Capacity 2021 2034 Boardman to Hemingway Reciprocating engines 500 MW trah$#i, aapacity Apr-Sep 500 MW . 00 l\ilw transfer caoElity Oct-Mar ,r36;MW 36 MW Totat"rctied pacity Lota r -a-aa-a'Cipacity **'Fii-norr capacity (0 MW) 536 MW 536 MW N o rth va t m y Re$ili e"f-#,fi,(i*qf;,ji?,,fl^,?,,f;fr9 p o rtfot i os Resource additions for portfih.Li6with North Valmy retirement in 2019 are driven by capacity deficits beginning-in'Juty 2020 arld reaching 786 MW by July 2034. These resource portfolios are designated as P3, P4(A)J4(b)#(c), and P5. The P4 porlfolios differ primarily in assumed on I i n e dafg for B2H, r angiilig- ;from 2,A21 b 2025 . ,". P3-North Valmy retirem-ent 2019, ice-based thermal energy storage, utility-scale PV 1 -axis, BZH onlin e.?:025, EE accrue by 2034 to 16 MW (average energyl and 24 MW ( pea k-h ou r cap€City) The resource portfolio P3 adds 60 MW of ice-based thermal energy storage and 330 MW of utility-scale single-axis photovoltaic solar in the early 2020s and the 82H transmission line in 2025.|n 2033,75 MW of additional utility-scale single-axis photovoltaic solar is added. P3 also adds energy efficiency beyond the amount identified as cost effective in the DSM potential study included in all portfblios. The extra energy efficiency ramps gradually during the IRP planning period, reaching l6 MW olaverage energy and 24 MW of peak-hour capacity by 2034. 2015 tRP Page 107 8. Portfolio Selection ldaho Power Company Table 8.6 Resource portfolio P3 Resource lnstalled Capacity Peak-Hour Capacity 20't9 2020 2021 2021 2023 2025 2033 2034 2020-34 Retire North Valmy (both units) lce-based thermal energy storage lce-based thermal energy storage Utility-scale solar PV 1-axis Utility-scale solar PV 1-axis Boardman to Hemingway Utility-scale solar PV 1-axis Reciprocating engines Energy efficiency* (262 t\A/V) 25 MW 35 MW 150 MW 180 t\at/ 500 MW transfer capacity O?r.#ip. 200 MW transfer caOacity.*?#.4:r 75 MW 36 MW N/A f:;;".:=;;jiiii 38 MW "r{:'\'til:l:i'1' 36 MW ri::2i[. MW (262 MW) 25 MW 35 MW 77 MW 92 MW 5OO MW €S,ffiI ) 827 tNU 550 MW P4(a)- North Valmy , rge jt6,[iprocating engines, 82H -Note: Extra energy efficiency beyond cost-effective amount delermined by DSM potenlial study. 2019 2020 2021 2021 2023 2025 2030 2030 2030 203',! 2033 35 MW 35 MW 90 MW 90 MW 108 MW 108l\A/ 500 MW transfer capacity Apr-Sep 500 MW 200 MW transfer capacity Oct-Mar lnstalled Capacity (262 MW) 25 MW (25 MW) 25 MW (35 MW) 35 MW 54 MW Peak-Hour Capacity (262 MW) 25 MW (25 MW) 25 MW (35 MW) 35 MW 54 MW 2020 battery storage end of life V redox flow battery storage (replace) 202'l ballery storage end of life V redox flow battery storage (replace) Reciprocating engines Total retired capacity Total added capacity Net peak-hour capacity (322 MW) 872 1\A / 550 MW Page 108 2015 tRP ldaho Power Company 8. Portfolio Selection P4(b)- North Valmy retirement2019, battery storage, reciprocating engines, B2H online 2023 The resource portfolio P4(a) adds 60 MW of Vanadium redox flow battery storage ,90 MW of reciprocating engines in2020-21, and the B2H transmission line in 2023.The 60 MW of battery storage is replaced in 2030-31 with additionalbattery storage, followed by the addition of 162 MW of reciprocating engines in2032-34. Table 8.8 Resource portfolio P4(b) lnstalled Capacity .ll:i.ii+;ki Resource Peak-Hour Capacity 2019 2020 2021 2021 2023 2030 2030 2030 2031 2032 2033 2034 Retire North Valmy (both units) V redox flow battery storage V redox flow battery storage Reciprocating engines Boardman to Hemingway 202Q batlery storage end of life V redox flow battery storage (replace) 2021 batlery storage end of life , V redox flow battery storage (replace):.= Reciprocating engines Reciprocating engines (262 MW) 25 MW 35 MW 90 MW 500 l\ar/. 200 (25MW)'1,; 25 MW MW) (262 MW) ]lr,'?',f '*',41.&5.MW n*wk, 500lvMI ,.1 Reci p ro cati n s"-^t;,ffi,@ ) .*,P4(c)- t l odffi ffii#y)lretli: :r:;r - vt$ll5 -{r!,!ltlif&Lonline 2.21 ':'L . ffi+ PonfoliUr.F4(c) adds 25 MVFfof Vanadium redox flow battery storage in 2020 and the B2H ",t,':\ ' ::.i:a:?.!:!i transmissi6hline in 202l.Th*portfolio also includes35 MW of Vanadium redox flow battery storage aOOeailgOZg, *.ll.ii MW of battery storage replacement in 2030. Reciprocating engines totaling ZS2WW'me added in the early 2030s. (25 MW) 25 MW (3s MW) 35 MW 54 MW 72MW 36 MW T6.ffietired capacity Totiffided capacity 2015 tRP Page 109 8. Portfolio Selection ldaho Power Company Table 8.9 Resource portfolio P4(c) Date Resource lnstalled Capacity Peak-Hour Capacity 2019 2020 2021 2029 2030 2030 2030 2031 2033 Retire North Valmy (both units) V redox flow battery storage Boardman to Hemingway V redox flow battery storage Reciprocating engines 2020 battery storage end of life V redox flow battery storage (replace) Reciprocating engines Reciprocating engines (262 MW) 25 MW 500 MW transfer capacity Apr-Sep 200 MW transfer capacity Oct-Mar 35 MW 36 MW (25 MW) 25 MW 108 MW 108 MW (262 MW) 25 MW 5OO MW 35 MW 36 MW (25 MW) 25 MW 108 MW 108 MW Total retired capacity Total added:irpacity Net peqf.i-hou r ca pacity {287 MW) B37 t\A / 550 l\a/u P5- North Valmy retirement2019, CCCT, B2H ohlihe.,2025 Resource porlfolio P5 adds a 300 MW cofi{Sh$d=cJ"t" "orirttlbn turbine in 2020 and the B2H transmission line in 2025. u"',',,,' ='=='-'=,,,., Tabre 8.10 Resource portforiofs = 1i:|ti ,'t. .'a'1t . Date Resource ln'Ctalled Capacity Peak-Hour Capacity 2019 2020 2025 Retire North vaffi{'oth units)ffi$ ComOined-cvb bustion 1@e Boardman to Hemingway ll li;il:r:. S00 l\A/V transfer capacity Apr-Sep 500 MW 200 MW transfer capacity Oct-Mar (262 w)_:tll:i;::,.:lt, 990'|l,\ru (262 MW) 3OO MW Total retired capacity Total added capacity Net peak-hour capacity (262 MW) BOO MW 538 MW n.- N o rth V d iniff,11fi eti reffi n t Y e a r- E n d 20 2 5 P o rtf o I i o s ii.ii:,:: Portfolios with No'iih:Vit-y retirement in 2025 experience capacity deficits beginning in July 2025 and reaching 786 MW by July 2034. These resource portfblios are designated as P6, P6(b), and P7. P6-North Valmy retirement2025, B2H online 2025, CCCT Resource portfolio P6 adds the B2H transmission line in 2025 prior to retiring North Valnry year-end 2025. A 300 MW combined-cycle combustion turbine is added in2030. Page 110 20'15 tRP ldaho Power Company 8. Portfolio Selection Table 8.11 Resource portfolio P6 Resource lnstalled Capacity Peak-Hour Capacity 2025 2025 2030 Boardman to Hemingway Retire North Valmy (both units) Combined-cycle combustion turbine 500 MW transfer capacity Apr-Sep 500 MW 200 MW transfer capacity Oct-Mar (262 MW) 3OO MW (262 MW) 3OO MW Total retired capacity Total added capacity Net peak-hour capacity (262 MW) BOO MW 538 [Ar/ P6(b)-North Valmy retirement2025, B2H online 2025, demahd response, ice- Resource portfolio P6(b) is a variation of P6 in which the inclusion in 2030 of 6014W of dernand response and20 MW of ice-based thermal energy storage allows the 3Oryi[Y combined-cycle combustion turbine to be detbrred by one year to 2031. The 60 MW of,demand response is above and beyond the 390 MW olsLrmrner demand response included as an existing resource in all portlolios. Table 8.12 Resource portfolio P6(b) .l Date Resource lnstalled Capacity Peak-Hour Capacity 2025 2025 2030 2030 2031 Boardman to Hemingway Retire North Valmy (bothunit=. Demand response Ice-based the!,ry,r=qJjbhergy storage, com bined-cyd :.|ifl fyrPi,fe. 1 500 MW transfer capacity Apr-Sep 200.[4/V transfer capacity OclMar (262 Mw) 60 t\,I\l/ 20 lvl\A/ 3OO MW 5OO MW (262 MW) 60 MW 20 MW 3OO MW Total retired capacity Total added capacity Net peak-hour capacity (262 MW) 880 MW 618 MW -. P7-Nofth.Valmy retirement 2025, B2H online 2025, The resource portfolio P7 adds the B2H transmission Iine in at year-end 2025t; A 300 MW pumped-storage hydro pro.iect Table 8.13 Resource portfolio P6 pumped-storage hydro 2025 prior to retiring North Valmy is added in 2030. Date Resource lnstalled Capacity Peak-Hour Capacity 2025 2025 2030 Boardman to Hemingway Retire North Valmy (both units) Pumped-storage hydro 500 MW transfer capacity Apr-Sep 500 MW 200 MW transfer capacity Oct-Mar (262 MW) 3OO MW (262 MW) 3OO MW Total retired capacity Total added capacity Net peak-hour capacity (262 MW) 8OO MW 538 MW 2015 tRP Page 111 8. Portfolio Selection ldaho Power Company North Valmy Sfaggered Retirement Year-End 2019 (Unit 1) and Year- End 2025 (Unit 2) Portfolios Resource additions of portfblios with North Valmy retirementin20l9 (Unit l) and 2025 (Unit2) are driven by capacity deflcits beginning in July 2021 and reaching 786 MW by July 2034.The pofifolios of this set are designated as P8 and P9. P8-North Valmy retirement2019 (Unit 1) and 2025 (Unit 2), ice-based thermal energy storage, utility-scale PV 1-axis, B2H online 2025, smal! hydro, reciprocating engines, EE accrue by 2034 to 16 MW (average energy) and 24 MW(peak-hourcapacity) , ,,". Resource pofifblio P8 adds 60 MW of ice-based thermal energy stoiage and 70 MW of utility- scale single-axis photovoltaic solar in202l-24 and the B2H tranSmission line in.2025. P3 adds 45 MW of canal hydro in 2031 and 126 MW of reciprocating engines in 2032'-3*: Equivalent to resource poftfolio P3, portfolio P8 also adds energy effig,,,,,,,,.i.epty beyond the amount identified as cost effective in the DSM potential study. The extra egtiigy efficiency ramps gradually during the IRP planning period. reaching l6 MW of averag srgy and 24 MW of peak-hour capacity bv 2034. itlltrlt)Llt Table g.14 Resource portforio pg ,. , :j:.::::::,::,,.._ ,,,ri,fi ; .:.4.:4 4:r,tts,. I n s tC I le.$,,Q qp..,q 9 i tyResource Peak-Hour Capacity 2019 2021 2023 2024 2024 2025 2025 2031 2032 2033 2020-34 Retire North Valmy (Unit 1) lce-based thermal energy,;torage l1-baseo. tnermalllirov storase Utility-scale solar P,Y'1 -axis lce-based thermal energy storage Boardman t" rpV Retire North Varmy (Unit Z) Canal hydro Recrprocating engines Reciprocating engines Energy efficiency* t126 W), ''';,.=:.''! 1.S lWry 30 MW, 70 [v.HV 15 MW SOO UW transfer capacity Apr-Sep 200 MW transfer capacity OctMar (136 MW) 45 MW 72MW 54 MW N/A (126 MW) 15 MW 30 MW 36 MW 15 MW 5OO MW (136 MW) 45 MW 72MW 54 MW 24 MW Total retired capacity Total added capacity Net peak-hour capacity .Note: Extra energy efficiency beyond cosl-effective amounl determined by DSM potential study. P9- North Valmy retirement 2019 (Unit 1)and 2025 (Unit 2), demand response, reciprocating engines, B2H online 2025, SCCT The resourcc portfblio P9 adds 60 MW of dernand response in202l-24.The 60 MW of dernand response is above and beyond the 390 MW olsurnmer demand response included as an existing resoLrrce in all porrfblios. P9 also adds 54 MW of reciprocating engines in2024. The B2H (262 MW) 791 MW 529 MW Page 112 2015IRP ldaho Power Company 8. Portfolio Selection transrnission line is added in2025, followed by l8 MW of reciprocating engines in 2031 and a I 70 MW simple-cycle combustion turbine in 2032. Table 8.15 Resource portfolio P9 Date Resource lnstalled Capacity Peak-Hour Capacity 2019 2021 2023 2024 2024 2025 2025 2031 2032 Retire North Valmy (Unit 1) Demand response Demand response Reciprocating engines Demand response Boardman to Hemingway Retire North Valmy (Unit 2) Reciprocating engines Simple-cycle combustion turbine (126 rvr\r/) 15 MW 30 MW 54 MW 500 MW transfer capaclly;,Apir$ep 200 MW transfer capa0ity Oct-Mar. (136 MW) ;,'. , 18 MW 't:'tr 170 MW (126 MW) 15 MW 30 MW 54 MW .15 MW 5OO MW i1,,,= ,{=ll MW) 18,.!d=Y=., 170 Total retired capacityr ' Total added capacity Net peak-hour capacity (262 MW) 802 MW 540 rvlw Jim Bridger Staggered Retirement Year-End 2023 (Unit 1) and Year- End 2032 (Unit 2) Porttotios '1{;u ;:.1,,, : : The resource additions to po-$,oli'6s: th Jim Bfidger retirement in2023 (Unit l) and2032 (Unit 2) are driven by peak-hoqfiiffiacity d&its beginning in July 2024 and reaching 874 MW by July 2034. These reso portfolios _,....,.,. gnated tu Pl0 and Pl l. .P10-Jim Bridger retireffi-e.iiffZO23 (Uiiit"II and 2032 (Unit 2), SCCT, B2H online 2025, CCCT :. \ 'tt, ,.The resource portfolio? Li0ladds'd -0 MW SCCT in 2024 and the B2H transmission line in 2025. plg adds a 300 MW// 6;nea;qcle combustion turbine in2033. Table 8.16 Resource portfolio P10 Resource lnstalled Capacity Peak-Hour Capacity 2023 2024 2025 2032 2033 Retire Jim Bridger (Unit 1) Simple-cycle combustion turbine Boardman to Hemingway Retire Jim Bridger (Unit 2) Combined-cycle combustion turbine (177 MW) 170 MW 500 MW transfer capacity Apr-Sep 200 MW transfer capacity Oct-Mar (176 t\A/V) 3OO MW (177 MW) 170 MW 5OO MW (176 t\A/V) 300 l\a/v Total retired capacity Total added capacity Net peak-hour capacity (353 N[\ /) 970 MW 617 MW 2015 tRP Page '1 13 8. Portfolio Selection ldaho Power Company P1 l-Jim Bridger retirement 2023 (Unit 1) and 2032 (Unit 2), SCCT, B2H online 2025, CCCT TheresourceportfblioPlladds60MWofice-basedthermal energystorageand l55MWof utility-scale single-axis photovoltaic solar in2024 and the B2H transmission line in2025.Pl1 also adds 180 MW of reciprocating engines and a 45 MW combined heat and power facility in 2033. Like portfolio P3 and P8, Pl I also adds energy efficiency beyond the amount identified as cost ef'fective in the DSM potential study. The extra energy efficiency ramps gradually during the IRP planning period, reaching l6 MW of average energy and24 MW of peak-hour capacity by 2034. Table 8.17 Resource portfotio P11 =' Date Resource lnstalled Capacity Peak-Hour Capacity 2023 2024 2024 2025 2032 2032 2033 2033 2034 2020-34 {iI.7-7,,MW) 60 MW. 80 MW' 5OO MW 108 t\A/V (176 MW) 45 MW 36 MW 36 MW 24MW Retire Jim Bridger (Unit 1) lce-based thermal energy storage Utility-scale solar PV 1-axis Boardman to Hemingway Reciprocating engines Retire Jim Bridger (Unit 2) CHP Reciprocating engines Reciprocating engines (177 MW) .,::::.,:t]= 60 MW ,;:li- 155 MW-,.'.; it ,rlt:z 5OO MW transfer capacity Apr-Sep 2OO MW tranir"r,capl"ity Oct-Mar :.::::a:1 :.:a . , "r*l!'fuo n+rQ uwl "'ii:Pi!k 45 rU\ / 36 MW : .a. "=.. 36 MW N/A',' rotdi'retireO capacity Total added capacity Net peak-hour capacity *Note: Extra energy efliciency beyo ,.lco f-effedive amount determined by DSM potential study. Jr.i - .?r l, : Jim Br,,!, ir Staggered Retirement Year-End 2023 (lJnit 1) and Year- End i nit 2) @otio The resource*ditions of !.h! portfolio with Jim Bridger retirement in 2023 (Unit I ) and 2028 (Unit 2) are aiilen:by.upa.ity deficits beginning in July 2024 and reaching 874 MW by July 2034. This ,.ror."e pofifolio is designated as P12. P12- Jim Bridger retirement2023 (Unit 1) and 2028 (Unit 2), SCCT, B2H online 2025, CCCT The resource portfolio Pl2 adds a 170 MW simple-cycle combustion turbine in2024 and the B2H transmission line in 2025.P12 also adds a 300 MW combined-cycle combustion turbine in 2029. (353 MW) 889 MW 536 MW Page 114 2015 tRP ldaho Power Company 8. Portfolio Selection Table 8.18 Resource portfolio P'l 2 Resource lnstalled Capacity Peak-Hour Capacity 2023 2024 2025 2028 2029 Retire Jim Bridger (Unit 1) Simple-cycle combustion turbine Boardman to Hemingway Retire Jim Bridger (Unit 2) Combined-cycle combustion turbine (177 rvw) 170 MW 500 f\A/V transfer capacity Apr-Sep 200 rVI\,V transfer capacity Oct-Mar (176|\A/V) 300 [A/V (177 t\r\ /) ,I70 MW 5OO MW (176 MW) 3OO MW Total retired capacity --; !1iNet peak-hour capacity".{-i:.{il;' (353 MW) 970 MW 617 MW End 2032 (Unit 2), North Valmy Retireme;it Yea1yEltd 2025 Portfolio The resource additions of the portfolio with Jim eridgef=ffig,ffient in 2023 (Unit I ) and 2032 (Unit 2), and North Valmy retirement in2025, are driven ffiflpacity deficits beginning in July 2024 and reaching 1,137 MW by July ZOlg.fUi rce pciffiilio is designated as Pl3. P13- Jim Bridger retirem ent2}23tr,# ri' retirement2O2S, SCCT, B2H online 202.5+C Jim Bridger Sfaggered Retirement Year-Ed 2023 (Unit 1) and,.Year- 142=(Unif 2), North Valmy l Resource portfolio Pl3 adds a=.'1 ffi simple;.-yde combustion turbine in2024 and the 82H transmission line in 2025.,,Y.rt.lflIso ad a:dO naW combined-cycle combustion turbine in2029, and a second combined'fidle combust[on turbine:-.i*2033. Table 8.19 Resourcefb.ry iS :="'::::':;:"':;':= Resource4.t!i r't?:lnstalled Capacity Peak-Hour Capacity 2023 2024 2025 2025 2029 2032 2033 ,:,:',Rdtire Jim BridgCj,t it 1; ":.=,= lriiSimple-cycle combli$.Llpn turbinC ',ti-:l:l".,o,",,,n?., Retiier North Va]mr',(both u n its) Combined+ypfq combustion turbine Retire Jim Bridger (Unit 2) Combined-cycle combustion turbine (177l\A//) 170 t\a / 500 MW transfer capacity Apr-Sep 200 IvlW transfer capacity Oct-Mar (262l\A/V) 3OO TVIW (176 MW) 3OO MW (177 MW) 170 f\A/U 500 [A/V (262 MW) 3OO MW (176 MW) 3OO MW Total retired capacity Total added capacity Net peak-hour capacity (615 MW) 1,270 MW 655 MW 2015 tRP Page 115 8. Portfolio Selection ldaho Power Company Alternative to Boardman to Hemingway Portfolios This set of four portfolios replaces the Boardman to Hemingway transrnission line with alternatives. Each Boardman to Hemingway alternative poftfblio assLrmes a different coal retirement future. Resource portfolio Pl4 assumes coal capacity is maintained. Resource portfolio Pl5 assurnesNorth Valmy retirement in 2019. Resource portfblio Pl6 assunres staggered retirementofNorth Valmy Unit I and Unit2 respectively in 20l9and 2025. Resource portfolio Pl7 assumes staggered retirement of Jim Bridger Unit I and Unit 2 respectively in 2023 and 2032. :P14-lce-based thermal energy storage, reciprocating enginCs, CCCT, SCCT, no coal capacity retirement Resource portfolio Pl4 adds 60 MW of ice-based thermal energy storage in2025-26,18 MW of reciprocating engines in2026, a 300 MW combined-cycle combustion turbinei*2027, and a 170 Table 8.20 Resource portfolio P14 .,ilt1 Resource lnstalled Cepaeity Peak-Hour Capacity 2025 2026 2026 2027 2032 lce-based thermal energy storage lce-based thermal energy storage Reciprocating engines Combined-cycle combustion turbine Simple-cycle combustionitUibine 15 MW 4..5$.{.-,,,. i 8 MVu. .;:,] 300 M\AI,.. €gi'ffi 15 MW 45 MW 18 MW 3OO MW 170 MW Tio!B|, tired capacity rolfif,Bdded capacity ,,:rrr,,,l_tl.et p€ak-hou r ca pacity (0 MW) 548 MW 548 MW P 1 5-N o rth N ;a1lmiX;eli refi:€il 20 1 9, batte ry s to ra g e, rec i p rocati n g e n g i n es, S C CT,cccr ....-,,= , ,= =,,Resour,,ci?p''onfolio Pl5 add { MW'of Vanadium redox flow battery storage in2020-2021 and 252 MW4l :reciprocating eh* es in 2020-25. P I 5 also adds a I 70 MW simple-cycle combustion turbine andaSQp MW comb.ined-cycle combustion turbine in the second half of the 2020s,60 MW of batteiy.,:,l rage rep-latement and 36 MW of reciprocating engines in 2034. Page 116 2015 tRP ldaho Power Company 8. Portfolio Selection Table 8.21 Resource portfolio P15 Resource lnstalled Capacity Peak-Hour Capacity 2019 2020 2021 2021 2023 2025 2026 2029 2030 2030 2031 2031 2034 Retire North Valmy (both units) V redox flow battery storage V redox flow battery storage Reciprocating engines Reciprocating engines Reciprocating engines Simple-cycle combustion turbine Combined-cycle combustion turbine 2020 battery storage end of life V redox flow battery storage (replace) 2021 ballery storage end of life V redox flow battery storage (replace) Reciprocating engines (262 MW) 25 MW 35 MW 90 MW 108 MW 54 MW 170 MW 3OO MW (25 MW) 25 MW (35 MW) 35 MW 36 MW (262 MW) 25 MW 35 MW 90 MW ,108 MW 54 MW '170 l\a/v 3OO MW (25 MW) 25 MW (AJ MW) n 36 MW:, Total retired capacrty . Total added::6apacity Net peak-hoUr capacity (322 MW) 878 r\A / 556 t\A/U P16-North Valmy retirement 201 I (Uhit,1) and 2025 (Unit2), demand response, reciprocating engines, CCGT, SCCT The Resource portfolio Pl6 adds 60 MW of demand responSE and 90 MW of reciprocating engines in 2O2l-25. The 60 MW of demand response is beyond the 390 MW of summer demand response included as an existifu resource in all portfblios. Pl6 also adds a 300 MW combined- cycle combustion turbinqand a 170 MW simple-cycle cornbustion turbine in the second half of the 2020s. In the early 2,030s, I 8 MW,of rec.ip-1gcating engines and a 170 MW simple-cycle Table 8.22 R€S'D'urce portfolio P16 Resource lnstalled Capacity Peak-Hour Capacity 20't9 2021 2023 2024 2024 2025 2025 2026 2029 2031 2032 l' Retire North Valmy (Unit 1) =i Demand response ''''' Demand response Demah'd*sponse Reciprocating,engines Reciprocating engines Retire North Valmy (Unit 2) Combined-cycle combustion turbine Simple-cycle combustion turbine Reciprocating engines Simple-cycle combustion turbine (126 MW) 15 MW 30 MW 15 MW 54 MW 36 MW (136 MW) 3OO MW 170 MW 18 MW 170 MW (126 MW) 15 MW 30 MW 15 MW 54 MW 36 MW (136 MW) 3OO MW 170 MW 18 MW 170 MW Total retired capacity Total added capacity Net peak-hour capacity (262 MW) 8OB MW 546 MW 2015 tRP Page 117 8. Portfolio Selection ldaho Power Company P17- Jim Bridger retirement2023 (Unit 1) and 2032 (Unit 2), ice-based thermal energy storage, PV, CHP, geothermal, CCCT, SCCT Resource portlolio Pl7 adds a variety of resources, including 250 MW of utility-scale, single- axis, solar PY, 162 MW of reciprocating engines, 45 MW of CHP, 30 MW of geothermal, and 60 MW of ice-based thermal energy storage in2024-29.In the 2030s, Pl8 adds a 300 MW combined-cycle combustion turbine and a 170 MW simple-cycle combustion turbine. Table 8.23 Resource portfolio P17 Resource lnstalled Capacity Peak-Hour Capacity 2023 2024 2024 2025 2026 2027 2027 2028 2029 2030 2032 2033 Retire Jim Bridger (Unit 1) lce-based thermal energy storage Utility-scale solar PV 1-axis CHP Reciprocating engines Geothermal Utility-scale solar PV 1-axis Reciprocating engines Reciprocating engines t Combined-cycle combustion turbine Retire Jim Bridger (Unit 2) Simple-cycle combustion turbine (177 t\A//) 60 MW 175 MW 45 MW j.:: 54 MW .::::::::.::.= 30 MW::=,=..:::.= 7s MW "rc.= 54MW = ',,,,,ry,i,11,,,fr,M.y= l,il 3oo.%= t (176 MW ... .170.1\i{$\}::' (177 MW) 60 MW 9! M\r/ 45MW 54 Mw' 30 MW 38 MW 54 MW 54 MW 3OO MW (176 MW) 170 MW f etireO capacity TOtal=dded capacity Net.iiiilak-frou r capacity (353 MW) 895 MW 542 MW North Valmy$aggered Retirement Year-End 2021 (Unit 1) and Year- E n d 202 5, (Uiit 2),, Ro rtfol i,o After the April 2015 IRP Advisory Council meeting, Idaho Power received from Advisory Council member David Hawk (Oil and Cas Industry Advisor), in partnership with Advisory Council member Ben Otto (ldaho Conservation League), a submittal requesting the analysis of a portfblio with retirernent ofNorth Valmy Unit I in202l. New resources specified by the subrnittal included B2H, dernand response, combined heat and power, small hydro, geothermal, and residential photovoltaic solar. ldaho Power developed a resource portfolio usingthese specifications, adding retirement of North Valmy Unit 2 in2025. With retirernent of North Valmy Unit I in202l and Unit2in2025, capacitydeficitsbegin in luly2022 and reach 786 MW by July 2034. The resulting resolrrce portfolio, designed to meet these deficits and the subrnitted request for specific resource actions, is designated as resource portfolio Pl8. Page 1 18 2015lRP ldaho Power Company 8. Portfolio Selection P18-North Valmy retirement202l (Unit 1) and 2025 (Unit 2), residential PV solar, demand response, CHP, B2H online 2025, geotherma!, small hydro, reciprocating engines Resource portfolio Pl8 adds 20 MW of residential photovoltaic solar, 60 MW of demand response, a 45 MW combined heat and power facility in2022-24 and the 82H transmission line in2025. The 60 MW of dernand response is above and beyond the 390 MW of surnmer demand response included as an existing resource in all portfolios. PIB adds 3 MW of residential photovoltaic solar per year in 2031-34, 40 MW of geothermal in 2031 , 45 MW of combined heal and power in2032,60 MW of smallhydro in2033, and l8 MW of reciprocating engines in 2034. Table 8.24 Resource portfolio P18 Date Resource lnstalled Capacity Peak-Hour Capacity 2021 2022 2022 2023 2023 2024 2024 2024 2025 2025 2031 2031 2032 2032 2033 2033 2034 2034 5 MW ,rlilffi'10 MW iil" 5 MW '.:, 30 MW 10,! . ,,,l,,,,._ 20 f@.,.'''' .',:t|l,iitl:|:E 45 MW,:'1, ':-:.:,= Boardman to Hemingway -- 500 MwittaqsJeriaapacity Apr-Sep "i:J' - -'"'ffi;!l$ffp2,20 o MW tigii'5fe r ca p a c i ty o ct- M a r,r, ,'- ,', , Retire North Valmy (Uiiit 2) . - (136 tvlvv) . Retire North Valmy (Unit 1) (126lvlv/) Residential PV solar Demand response Residential PV solar Demand response Residential PV solar Demand response CHP Residential PV.,SaEi : rtlo MW i 45 MW ll. to uw ?.r-r'60 MW ,IO MW 18 MW .;Geothermar'-'lihr,,tli!!fi"llll,ff$.-q",,Y.,'i^li/,,e t " Residential PY soldtiltt t I I rr' 10 MW "."" cqP.,t,{&!!ffi(!fi11t,,r,,,- ? R.ssidentiat p\tW. Small hydro +;') Residential PV solar ".', Reeiprocating engine$ (126 MW): 2MW ,10 MW 2MW 30 MW 3MW 20 MW 45 MW 5OO MW (136 MW) 3MW 40 MW 3MW 45 MW 3MW 60 MW 3MW .,I8 MW Total retired capacity Total added capacity Net peak-hour capacity (262 MW) 766 MW 504 MW Portfolio Design Summary The 23 portfolios analyzed for the 20 I 5 IRP consider a range of alternatives with regard to early coal retirement and the Boardman to Hemingway transmission line. The fbllowing table provides a summary of the 2015 IRP portfolio scenarios on the basis of early coal retirement and the Boardman to Hemingway transmission line. 2015 tRP Page 119 8. Portfolio Selection ldaho Power Company Table 8.25 Resource portfolio scenario summary No coal capacity retirement Early retirement - North Valmy Early retirement - Jim Bridger Early retirement - North Valmy and Jim Bridger Alternative to B2H 4 11 3 1 I 2 1 Page 120 201s tRP ldaho Power Company 9. Modeling Analysis and Results 9. MooELTNG Arvalvsrs AND Resulrs Idaho Power evaluated the costs of each resource portfolio over the full 2O-year planning horizon. The resource ponfolio cost is the expected cost to serve customer load using all resources in the portfolio. Portfolio costs are expressed in tenns of net present value (NPV) in the IRP's cost comparison analysis of portfolios. The IRP portfolio costs consist of fixed and variable components. The fixed component inclrrdes annualized capital costs for new portfblio resources, including transrnission:interconnection costs fbr new generating facilities, and fixed operations and maintenance (-Q-&M) costs and return on investment. Capital costs for new resollrces are annualized over the.reSoufce's estimated economic life. Annualized capital costs beyond the IRP planning window (2fr15-2034) are not included in portfolio costs. :':: , .,.,._:.,., Coal retirernent porlfolios include costs for accelerated-,.rdFery of remaining depreciation expense and accelerated recovery of decommissioning and demolition costs (net of salvage). The costs of coal retirement porlfolios are countered by saF'ifu frq,Fjiroiding future coal plant capital upgrades, including environmental retrofit upgraffi tifid from avoiding future fixed operating expenses and return on investmeni.ffi;:. retired df-i !:.Unit(s). Idaho Power uses the AURORAxmp@ (Auit6iffiryil6. -..q,..14c rnurket model as the primary tool for modeling resoLrrce operations and determining'operat-i- --osts,for the 20-year planning horizon. AURORA rnodeling results provide detailed estimatei of wholeiale market energy pricing and The AURORA software- applies ecory,iihic princiffi and dispatch sirnulation to model the relationships between €ineration,=1r,fl8$,#fp,ui9=p"..==.?" emand to forecast market prices. The operation of existingand,,-fll.hqp6/iffi6Uf'66$:,..',iSbased on forecasts of key fundamental elernents, such as demand, fudlr.fiices, hydroelectric conditions, and operating characteristics of new resources., Vari6us mathematical algorithms are used in unit dispatch, unit commitment, and regional,pool pricing logic. The algorithms simulate the regional electrical system to determinghbw utility Seneffign and*iansmission resources operate to serve load. Multiple eledtricity markets nes, and hubs can be modeled using AURORA. Idaho Power rnodels the ehtifp WECC -wh evaluating the various resource portfolios for the IRP. A database of WECC data iSrlaintain€d and regularly updated bythe software vendor EPIS, Inc. Priorto starting the IRP analysis, ldaho Power updates the AURORA database based on available information on generation resources within the WECC and calibrates the model to ensure it provides realistic results. Updates to the database generally add additional hourly operational detail and move away from flat generation output, de-rates, and fixed-capacity factors. The updates also incorporate detailed generating resource scheduling, which results in a rnodel that is more deterministic in character and provides a more specific operational view of the WECC. Portfof io costs are calculated as the net present value (NPV) of the 2l-year strearn of annualized costs, fixed and variable, foreach portfolio. The full set of financial variables used in the 2015 tRP Page 121 9. Modeling Analysis and Results ldaho Power Company analysis is shown in Table 9.1. Each resource porlfolio was evaluated using the same set of financial variables. Table 9.1 Financial assumptions Plant Operating (Book) Life 30 Years Discount rate (weighted average cost of capital) Composite tax rate ::::::ljffi"."",,.,"..,".",. Annual property tax escalation rate (Yo of investment) ..,..;..ri":.."............... I t ,'a,L-. . Annual insurance premium (% of investment) ............... .,...... . lnsurance escalation ra1e................ ............. i..-.... .- ......... I 6.74% 39.10% 35.00% 2.20% 0.29% 3.00% 0.31% 2.000h 7.750 CAA Section 111(d) Sensitivity Analysis Idaho Power developed multiple sensitiviiie$,forrt * npA', o.ofu rule for regulating CO2 emissions from existing generating sources ffier CAffi-b,c.li.g l I I (d). The rnultiple sensitivities are a reflection of the considerable uncerlainty,ielatefib the *tipulations of the finalized rule scheduled to be issued in Summer,20l5. Each $p,fi*:itivity, with the exception of a null sensitivity in which no restrictions arffiffmedli;ff5't$asea on:6 set of assumptions on compliance stipulations for the final rule. Analyziffi'tnultiple gensitivities allows the estimation of a range of possible cost impacts from CAAt$i'ction I !-j_(d.)=6*[herost Sgitivity analysis could provide information to state-level agencies taSffid,,yi flfiie{lfistate plans for CAA Section I I I (d) ,*{1 . 11 l(it)li5e.nsitivities are described by four categories: Section I I l(d)) compliance . Emissions intensity compliance utilizing the EPA's compliance building blocks. Null sensitivity (no CAA Secfion 111(d)) Idaho Power analyzes a null sensitivity to provide a comparison with portfolios cornplying with regulations on COz emissions for existing power plants. The only portfolio analyzed under the nullsensitivity isthe statusquo porlfolio (Pl), which nraintains coalcapacityand meets planning period deficits with B2H in 2025 and 36 MW of reciprocating engines in 2034. Page 122 2015 tRP ldaho Power Company 9. Modeling Analysis and Results State-by-Sfafe M ass- Based Com pl ian ce Under state-by-state mass-based cornpliance. CAA Section I I l(d)'s proposed state-specific target reductions are the basis for compliance.'fhe proposed rule's treatment of Langley Gulch is uncertain as it was brought online rnidway through EPA"s 2012 baseline year. Consequently Langley Gulch is assumed to be constrained at one of three possible annual capacity factors: 30% (837,01 8 MWh), 55% (1,534,533 MWh). or 70oh (1.953.042 MWh). The proposed target reductions are deflned in Table 9.2. Table 9.2 Proposed target reductions - State-by-state mass-based compliance (lPC share) Affected Source 2020-2029 Target MWh 2030- Target MWh Jim Bridger North Valmy Boardman Langley Gulch 3,914,502 MWh (13 8% below 2012 MWh) 574,382 MWh (29.5% below 2012 MWh) 149,967 MWh (43 2% below 2012 MWh) 3,67s,60& l/\A/h : :1:: (19":1:/,9 Uetow ZO12 MWH 533,343 MWh (34.5%o below 2012 MWh) 137,029 rvlt4/n (48 1% below 2012 MWh) Target 30%, 55oh, or TOoh annual capacity:factor 2020-2034 Sysfem-Wi de M ass- Based C o m pl i an Ce Under system-wide mass-based compliance, CAA Section 111(d) compliance is based on adherence to COz limits irnposed at an individual utility system level. The assumed Idaho Power system-level limits were deriVed to be,consistentwith EPA's proposed state-specific target reductions. [Jnder this approach, system-wide emissions, which include emissions from Langley Gufch and Idaho Power's share of Jim Bridger andiNorlh Valmy, are constrained to 6,332,020 tons of CO2 for2020-2029 andro.5,925|814 tons of COz for 2030 and beyond. Compared to 2012 system-wide emissions$se constraint levels are lower by 20%o (2020-2029 constraint) and25%o (Zr!,:0,anA b ond cohstraint) Emisslohs intensity compliance utilizing the EPA's compliance building blocks The EPA in its proposed rule proposal describes building blocks to assist in the development of a plan for achieving coryrpliance. Key to the building block approach for achieving compliance are the reduction of COFmissions through re-dispatch of af fected sollrces, and the developrnent of renewable energy and energy efficiency resources leading to a reduction in emissions intensity. Idaho Power makes the following assumptions in Lrtilizing the EPA's building blocks as the basis for CAA Section I I l(d) compliance: . Boardman coal plant is reduced to a zero production level and retired by year-end2020 o North Valrny coal plant is reduced to a zero production level and retired as early as year- end 2019 or as late as year-end 2025; until retirernent Idaho Power's share of North 2015 tRP Page 123 9. Modeling Analysis and Results ldaho Power Company Vahny is assumed to have an annualproduction constraint equalto its 2012 production level (lPC share: 814,264 MWh) . Jim Bridger coal plant is reduced to a production level 53,320 MWh less than irs2012 production level of 4,541,712 MWh (lPC share);the redispatch of Jim Bridger is to a new 95 MW cornbined-cycle combustion turbine under construction in Wyoming . The Langley Gulch natural gas-fired plant is limited to one of three levels based on annual capacity factors of 30%o (837,01 8 MWh), 55% (1,534,533 M t ), or 70Yo Baseline CAA Secfion 111(d) Among the sensitivities developed for the 2015 IRP, for initial portfolio cost analysis. The baseline CAA assumes state-by-state mass-based compliance with La capacity factor. The selection of these assumptions for the 6i ne analysis is not a reflection of Nor is it dfii.1,ffi-ication of the company's view in comparing costs between portfolios. The bri-spline cosdiiOentify fortfolios foi under other CAA Section I I I (d) sensitivities"and fof tl'le stochEStic risk analysir the baseline CAA Sectio, t t,l,r(d}r vitV affiffi are provided in Table 9.3. i, "" '1' ";": t. ",'::_ _:::_ :: .1": ,r^. "s ?:) Page 124 2015 tRP roN oo,oo- o_d. rr) o(\ G E E an 8.3(J>c -E o^gls h9 aeEJ :$EeJ a E.g ? Lgi'-]n GG IIE5 E O OO OO N@tOOir OO)@O6O O66OO@ @F- mV (OF-(ONNb(\ OrO*N@ ONOO-€- (O_ . 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F- 3 .,Q oE*=I,!IE Hg ;g'o(J*&** F-e 62ng2coEom*bfr.^(/)UN,Nt;,;;u- 81-' H, aP-'T-OOq>fr61 o'6'oo- dIFEa.oSEqY'"'' P.,dY--SAf f fP EbxE"l,3 EEEEE EBEE*- ><:::> =i;:::;:$J3:!: ;l :l -r -r -r -l *r I -r -r -l "N;.,OOOciOJ.;O)Orn- \! r r r U r U/ - - N <PEEEE9bEFEEE5.=E6EE.=o6()686 -ire3@i ios 6 -r<iS*r-r6-N(L(I(L(IO_(L,,O_(L(LO-O- :6) .:::.:.:::::=::.cr::::,. = (off$ .,,i . $ ::,' I0(o\+u.l r.r.r F 3u- ,r, t t',, b ,,:: o,t cL o- (J () :.. 0 6 fEEN.b-c ee ?h -'?E86. HE FHE ilHU.(/.j|r,g.--oE-Fts.--sl,Ee,8EE 8Et,;r * el !dA- a >-rN---xco-,'r;.EEEES-q tZ $ e= * fi- f 3 R, $ AI P* E pI I s q !, F E p Eg=esEEc**sesE :E a EE i a E > X s ER d,: 3 s: ,"t, 3 R R "t, 3 Plo'lj - llj o'- I lo'- |i tsu R. P-s E s & & H r iE 3H =' EH I =' E E 3 -' E 6'E\ N 6! = N 6 6 = N 6> 06'co >6 d] d] > > cD co > oc 06 0) EC)'a 0) =Go6o Goooc^ u;,a.!/oooE ooN'l=I9N- E.^o ooaU) =2EtAQ L tr-: O. bOO i"g"OrAt.O-N(OOTNO(L(L(LtL[L(I[O-O-O-O- ,9o.>o .! .Y .9,L .9 o(E -coo oo ; .9E ooLo 3 o(l., L ct, oEo oo EotsEoo- o .Eo Loo e? (Dg (EF a=f't) l.)& !c(E a'6 oC o) .Eo!o o) c(! o_ EoO o =oo- oc(EE 9. Modeling Analysis and Results ldaho Power Company Noles: 1 All portfolios assume CAA Section 1 1 1 (d) implementation except for Portfolio P'l . 2 AURORA simulates the variable fuel & O&M costs and REC sales (when applicable). This includes the existing system, the effects of coal plant shutdowns (when applicable), plus lhe new portfolio resources and compliance with CAA Section 'l 11(d) (vvhen applicable). The reservation charge for new & existing NG plants is calculated in AURORA. 3 Fixed costs of existing resources are excluded excepl as needed in accounting for coal retirement porlfolios. ' Denotes portfolios that were studied in the stochastic risk analysis The selection of poftfolios fbr furtheranalysis indicated in the table above is based on the results of the baseline CAA Section ll l(d) analyses as well as discussions held at IRP Advisory Council meetings in which pafticipants voiced a desire to ftrrther analyze a relatively broad Spectrumofportfoliotypes(e.g',por.tfolioswithandwithoutB2H). CAA Secfion 111(d) sensitivity analysis - resu/ts , The analysis of portfolio costs under the difl'erent CAA Section I I l(d) sensitiVlties indicates that portfolio relative performance does not change significanq icross the sensitivitieq w cost portfolios under the baseline CAA Section I I I (d) sensitivity tend to have low cosiSfijider the other sensitivities. Cost impacts of CAA Section lll.{dfue greateit when individual coal plant dispatch decisions are rnandated under a state-by-state$$,roac,h;Likewise the more severely Langley Gulch generation is reduced the higher the cost of compliance. Cost impacts are least when the EPA's building blocks are the bas.i.q CAA SectioninlXl"l(d) compliance and Langley Gulch is assumed to be able to run gp to ? capacity factoiof 70 percent (approximately 1.95 million MWh annually). Under the bui['d,ilg block'approgch, TdSho Power also assumes that North Valmy can be operated at2Ol2 production le.vels (annqdiry) until retirement, and Jim Bridger can be operated at anng;,9!;p,,y.;t,luction le;e.l 3,320 MWh less than 2012 production Ievels. For reference, portfoli6=?.1==-6@under the null sensitivity are $4,417 million. Table 9.4 provides the results of the CAA Section I I l(d) iensitivity analysis. Page 126 20'l5 tRP f.-N oo)(U o_ o_t tr) Oc\l 64646 646A6ooooooooo()Ot ()! O! O! Ot6 .5or.Eot.Eclr.Eor o o .Esr o o@ ;'f ;F ;+ ;+ @ N ;+ 6s-i;:6:6:6:a$.;:s,a3 3.8 fiE fiE fiE 3 3 3E 3 S 999e9oooaqO :O O O O(J()()()o Oc lDc Or 0) - d) -o .=E) .=_p .=-S, .=E o @ .=E, o @9Er6-6181956-9os- q^ @^ o^ a^ v. v. q- : 93 8.E3E3.E8E33 3E3 S aaaaa6 6 iti:t',t6 :::::::::.1,i:,' fi,,.;.,,:O O::::. :l (} :::::ili=t}: o:::.=:.OU()()(J9-c q-c Q= !!-c Q-c@ .:o).=(,,,=q.!O) N o .=q 6 @ = E= E= ET 6= : I EI e? oo_ 6= 6= 6= 6= o_ 6_ 6-^ \r_ t_$ A!{ oH (sX (oX { $ (6H \r *@ CA.lj cn.Y m.g coIJ @ @ m.Y @ G z {z z z Z '€'lv a <'-4< OE:E {aza z qrrOIYoi_ a <'-o46f r) E @zo z rEIY :f, :-o<;q *.9EEE saza z '4 6od)-.g-g) @ o oTI 3 9 E(oY s s sm.H6@@ C'L': Oc '=.Y' r v;iT $ o oi,--s9u2(B9 * r rCO! @ 6 @ g-:::.:a.a.::.,,*,,:::.a::::;.:.9::t' I lrlotn.too:ooo Q1:1r:;:.,:, ; 11.;,1t"}. (). !P"c !U-c qc q.c.5q).!(,r.!Or.- O) co6=6=E=E=ep 3.8 3E SE S.E 3 3 i:;':.:1.'.i.:,, i,:::,',',, .: att:itt:t:;r6 i fr .,fr..:qt/;t-;O 6 :t fr"Oililltilt(,i t O ..:: :: e:r,.:.()illrriil.i_(), () :.: a...::qE o,c 6),c oq.t .9, .h.g) .= .9) .! .P - sEI 6IEIEIl>!S6^ O^ O- 6_ *1.4SE fiE fi.E 3E 3 S I t,,alt 'lo. )i :ii:r:- o a..:,-.; :.1.:::,::,=..(}l.I =O-x -EEi oro 7'f 6o :^- o$ OY t@ CO.Y e='= ,liii aa:ab.:a-a ;;at:fuilNtl :=6:::::::.:::a= :.)?rlit)tll =o::::::::= aa,o..,,:,a.4={Dio .S .a: co(O ;iE (O E fiE E ot--ooo!+trj)N$ONO{(OOOTOF-N@()_ (O- @_ t'-- l'r- (O- N- (o- 'lO- O- O- .O- 0_$$l'$S$$$.{<'j\t$@@@e@@@@Q@@vro >>9..?Eo 6 2 Fsl 3 R Ro 6 .Y q a o N r) .= ;i 3= |S s >: 3 3 3 rr Id 5 >E€ r'U U 6-3 b 6 6 cy (J 6 a 6-u.rE p il e R [i> - ] . F N, Fi N, Iial-' il Fu o F-o o o 6 it _t '.1 _t F* e"a L Oc q sH E E E E ** * uu;E 3s s >H= > E > > >: > >sI Eh:'6 6 outE o, o) o o o oL o oPE o[ U? P7 9F -ril* -r -r -r -r -r -rG -t -,Eg -,6 ;lg *g rE in,; E-*, 3-n,3-r i & q3 !.s 3-sA E-p N 9 ..' 9 r' I Er'3 Er' Er' Er' E E Eui Ep Er'K E;' SBE SE SE SS? Sil Sil SS S I SP S; 9Ea 95 E3 o EL oooo .9o Eo(! .9E Eo TL G)_lLtoEEo=>:oa E'. GOJN @)_lttoEEo=>=oig)-cSGDJ6 G)_l!io =Eo=>=-eaPs6oJO ,irloloiroi aDl .=l mt.l;lololctcl o. IEIoiol>. I =tqlctolct ,r, Ictolbl6l.-lctuJl , = g 9 g::--.9,:..:::* g.I f, : 0: O O. ,::..t1:.:....aa:-:.10.: O .-:,I F ,. o Q ol'j::::1:;c[::::.::=-,o: o, ::g ; c> 'u <)"";'::i:ici'::'"r) o 'aa'- Qc .qE q.c qc q-c q-c;>E 6 6) .E.q, c ,t .E.Sr.5:.e,9-Q.g.S, to N .E.qr o to to;dt6 3 EI 6. ITIEIEIEI 3.q gI 3. s. Si;28} 3 fiES S-Efi"Efi"EfiE33 S.ES ; 3 tooi- a <'-q ^<.E 3 =Ufi @.9oE +AZA @ r9o ,:-o<;a46 r:"e()'* ,X.9od +@za 6 rEa- Q <'-q<.E S5 \J tt bEoE +IDZU> @ c<. =6qo o !?oa g o - c.=n oii .l,EE PN= gm g^ a>}= a 6q- n 6Xo N66a co G) -ltt() =Eo=>=oa 3sooJF. e)_l!ioEEof>---etE' _tr:<rgbJh €), -lrioE'iao=>=qra Ps6oJM oo e Eoo ooGdlooG =0) Go ll o 6o o -:Eo =.z =oCoU' r- .9 ooo C) -oo ooo eo o(L GOO6000 ONNNO{-t!'6@(oF-@O'o_ (I tL o- (I (L tL o- o- (L0- (I o- (I (L ao)Itt(EF o=f,1, t)t Eco .aa oC O)C oEo o, c(o o_ EoO o) BoI ILu lo oN @N ot,,otL o@lo+@ e) -IlioEEOT>:-saPslEO 9,.i(,EEo=>=s&Ps(EroJTD 9*toEEo:>:-EiPs.EOJF, ox(,e@ E".g E @E 3or,)trg CL Eo(J -otrosoEeo .9, Elrl -c.9)Eoo 0) (B o @ooo (oort+o ro-{6 q)!frl$o 9,.toEGo:>:-94Ps.EC)Jt\ c)toE3o=>=-cePsoutJrO @r -tLtoE?9: -cePsls6Jo co CL (,o0,o eo Eo4 .9oEoo- o(,ceEL Eootooooottd =o IE ul tto IEo t, Q) c oo oc E Eq := =ocoo l, o ooU' o tt o 10oo eotoo- ao)g -Et(E ocoofo3}o'=ro=o@NC2\o(o@C^oL E= E.oo6Ed)ofnH<E< 0eo6ii3omz, F-ro@-t@ hto _(o_$e, tr t-_t@ N@@ttOtlO@-@-\co_rt$$$s@a@ P*F_ (O_ster@ 6.N,5 -'e;8 sEHs iEgg EEEg EES; nE -l-o '-ti L tsE- igb Po-b Eo-o .=ro 6-a dt()o, >o ls=il F g s ?P;Iu Eul"A; ugq=g *39#E E tii x l't e1a is itp-i g t-- sr* - -€'ii gE gg t; F[ E =SP:Pg(L(L(L(L(L(L F-O tL(L coo- Eoo o) =o(L o.c.o!, o=fooE. Eco .9o oC o,.g6E'o =oi ldaho Power Company 9. Modeling Analysis and Results Stochastic Risk Analysis The stochastic analysis assesses the effect on portfolio costs when select variables take on values different frorn their planning case levels. Stochastic variables are selected on the basis of the degree to which there is unceftainty regarding their forecasts, and to the degree they can affect the analysis results (i.e., portfolio costs). Idaho Power identified the following three variables fbr the stochastic analysis: L Natural gas price-Natural gas prices lbllows a log-normal dist#lon centered on the planning case forecast. Natural gas prices are serialcorrelated,J'#&he serial correlation is based on the historic year-to-year correlation from 1 99A n ,4. The serial correlation factor is 0.65. - .- -',i1,i,!,!, 2. Customer loatl-Customer load fbllows a normal distribution and is "o* O *itn Pacific Northwest regional load. Idaho Power worked with the Northwest PbWer and Conservation Council (NWPCC) as part of research conducted for the 2013 IRP to estimate the correlation between Idaho Power CuSt-omer$ad and regional customer load. The correlation factor is 0.50. i1,";3. Hydroelectric variabilily-Hydroele@ic variability fon6ff;.a normal distribution. Idaho Power-owned hydroelectric @ration is,correlateriwiih the Pacific Northwest regional hydroelectric generation, and the correlation ftietor is 0.70. This correlation was derived using historical gtre4qrflow daia t$OZt ttrrougtr ZOO9. ,, The three selected stochastic variables are key drivers of variability in year-to-year power supply costs, and thus providg illi:able stolhasticshocks to:allow differentiated results for analysis. Stochastic analysis was perQrrned:uhder th€' Stem-wide mass-based limits on COz emissions. This assumptio.n w,,_q1selected because all eleven pomfolios can comply with CAA Section I1 I(d) under this compliafice approachi Moreover, the objective of the stochastic analysis is to determine.,the cost irnpact when portfolios are stochastically shocked. The purpose of the analysis,i$ to understand the range of portfolio costs across the full extent of stochastic shocks (i.e., acro$$lf,he flull set of stochastic iterations), and how the ranges for portfolios differ. Idaho Power created a setd 100 iterations based on the three stochastic variables. Idaho Power then calculated the'portfolio cost for eleven portfolios, where the eleven portfolios were selected basedonresultsofinitialcostanalysisunderthebaselineCAASection lll(d)sensitivityorto provide a wide range of resource types (e.g.. with and without B2H). Each stochastic iteration was reduced to one numerical value-the NPV of the total cost to serve customer load over the 2l-year planning period. FigLrre 9.1 shows the stochastic analysis results. 2015 tRP Page 129 (Ltr lr) oN o(t, o)o)o(L =oo CD,rn =ooN tJ, =oo1O_ro =oo("_ 14, =oorta o ==Eoq8-a'<lzto oN =oH6.f .9oELo=1oao35 rl o%.o l! G'(j ot! (,oo o=o Loo. (D o El lt sssoooooro =oo(r)+ =oo{ =oo CD.o =oof.-_ o =ooro_oso $ o =3 o B .c, o co!oox x s8m6i6'ONNSui ri ;i5g $* oEt64o GUuc'Etgc <i6N6o6r'$srod+ E;i =so (} o R 3o oc6!oa xo dod@ddod6d E;>= : co =6o Lo =o TLoEoc, o=:,vtotr E'c(E .oo oc cn.EoE'o oi ldaho Power Company 9. Modeling Analysis and Results ln Figure 9.1, the horizontalaxis is the portfblio cost (NPV) and the vertical axis is the exceedance probability. Each line on the figure corresponds to one of the eleven portfolios stochastically analyzed, and the line is the connection of ranked NPV observations forthe 100 stochastic iterations. The figure illustrates portfblio costs at the 5o/o and 95o/o exceedance probabilities, as well as portfolio costs with planning case inputs for the three stochastic variables (natural gas, customer load, hydro condition). Reassuringly, the planning case results approximate well the 50oh exceedance Ievel. Figure 9.1 illustrates portfolio P9, a North Valmy early retirernent portfblio with B2H, is least cost for the full set of 100 iterations. Portfblios are relatively clustered across the top nine least cost portfolios, with B2H alternative portfblios Pl6 and Pl7 somewhat sef apart with higher costs. While not easily discerned, there is some crossing of the portfbliS'specific lii'is in Figure 9.1. Significant crossing of lines in the exceedance graph is an indication of substantial portfolio disparity; portfblio cost performance in this case is markedly dil-ferent across the setof stochastic iterations. As an example, a portfolio consisting of exOlffiS'ively natural gas-fired generation would be expected to conspicuously cross lines on Figure 9.1 as portfolio costs range greatly from low to high natural gas price futures. Finally. the lack of significant crossing of lines is testament to the resource diversity of Idaho Power's existing portfolio and the portfolios of new resources considered in the IRP; under no set of stochastic futilies is a portfolio a clear and runaway cost winner, only to be countered bry a differentst of futures fbr which it's just as clearly a losing portfolio susceptible to signi{!.cpntly high gf}s.than other portfolios. Portfotio cosf - asses,s ment.of yeai:lo-year variability At the request of participadt$ in the IRF Advisory Council process, Idaho Power has expanded the stochastic analysis .fol$e 20 I 5 I&P. ,to inc lude an assessment of year-to-year portfolio cost variability. This assessmen{of y9g;-16-yearvaiiability allows portfolios to be compared on the basis of their susceptjbility'tffifi$yge year-to-year price swings. Idaho Power assesses the year-to- year variability-.ii6yltllBe of the siandard deviation metric. For each stochastic iteration, the standard deviation o,fthe 2}-year stream of AURORA-deterrnined variable costs (converted to base 2015 dollarqB,€alculated. Thui#ch ofthe eleven portfblios for which stochastic analysis is performCll,has 100 different sfandard deviation measures corresponding to the 100 different stochastic-itirations. Portfoli susceptible to large year-to-year price swings tend to have larger standard deviations. .=':l An exceedance gr@of the standard deviations for each of the eleven portfolios is shown as Figure 9.2.The exceedance graph indicates that pofifolio P3, which adds just over 400 MW of utility-scale photovoltaic solar, is least susceptible to large year-to-year swings. Portfolio Pl6, which adds more than 700 MW of natural gas-fired generating capacity, is most susceptible to large year-to-year swin gs. 2015 tRP Page 131 9. Modeling Analysis and Results ldaho Power Company s; 60%E E !o E3 qv. u 2O9o : Oo/o t' 20M 40M30 tvt 50t 60M 70tvl 80M 90M Standard Deviatlon (2015 S milllons).ewa1 .. Figure 9'2 Exceedance n'"1,1,.-",',T:" no^' u Tipping-Point Anaffii$ttl'l.,4 lu* "'_: ' "qH" To test the sensitivity "qffi}al portfal$$j'co-s!"..).g."capj'fficost estimates, Idaho Power conducted a tipping point analysis fdffi6folie.?,\W;{;#liiB.ffihigh penetration of utility-scale single-axis photovoltaic solar, and poit&l[i+= , which has'300 MW of pumped-storage hydro. In the tipping point analysiygl$ft;phange in total portfolio cost is determined as a function of change in capital cost. The ffitrdt coit'b0ffie sola'i',r$source is varied for potfolio P3, and the capital cost of pumpeffi,Sage hydro is'V1iff,!td forp-.6rtfolio P7. The percent change in capital cost is relative to planniffi,4qp capital costs d,ffimates, where the solar resource under planning case is estimated at $1,250/k$/r=(for capacity Constructed in 2017 or later) and pumped-storage hydro is estimated at $5,000/kW, graph of;$ii ltipping point analysis results is provided in Figure 9.3. As an example, the giffiillustrates that a change in utility-scale single-axis photovoltaic solar of -30%o results in an estimdtd$ecrease in total portfolio costs forportfolio P3 of $50 million (NPV). Page 132 2015 tRP ldaho Power Company 9. Modeling Analysis and Results o e=E oo .9E oo- EoF.; ED o o $225 M $200 M $175 M sls0 M $125 M s100 M $75 M $s0 M $25 M $M -$25 M -$50 M -s7s M -$100 l\il -$125 M -$1 50 M -$175 M -$200 M -sook -4Oo/o -3Oo/o -20Yo Figure 9.3 Tipping point analysis results 6Portfolio P3 only varying capital cost for single axis SOLAR PV -Portfolio PT only varying capital cost for PUMPED HYDRO STORAGE 100/o 0o/o 10o/o 20o/o 30% 40% Change in Capital Cost (%) i Example: 30% reduction ini SOLAR PV costs leads lo i about$50 million reduction ini P3 costs Portfolio Emissions For the 2015 IRP, Idaho Power analyzed the'total po-r+folio,6dissions for the Z\-year planning period by the following four emir l. CO2-A g as scid,ifrf'ted wi th'"1tdjlm ate c h an ge ;2. NO*_Contrib{t@"r"r];,ffiw*u:,. _ , j,3. Sor-Cg.,.L illes tdlaflii i'iain formation _, *i"ita Jll(1fuoutdeposits Total eEl$sions by type wd@alculated using AURORA emissions modeling. The total emissions tUr',,cach portfolio*lude emissions from new resources in addition to emissions fiom Idaho Power'*::eLr-isting resCItiices. With the exception of portfolios retiring Jirn Bridger Units I and 2 withort iT fuution,of NOx-controlling environmental retrofits, all porrfblios iomply with environmental reg*lbtioni. Illustrations of the four emission types for the eleven portfblios on which CAA Section I I I (d) sensitivity and stochastic analysis were performed are provided in the Appe n d ix C -Te c hn i c al A ppe ndix. Qualitative Risk Analysis The qualitative risks associated with the poftfolios are more difficult to assess. The goal is to select a portfolio that is likely to withstand unfbreseen events. The portfolios contain a diverse range of resource futures. Each future includes existing and new generating resources with differing implementation, fuel, and technology risks. The following section highlights specific 2015 tRP Page 133 9. Modeling Analysis and Results ldaho Power Company risks within the pofifolios and describes Idaho Power's interpretation of the risk profiles associated with each resource and acknowledges that the portfblios may contain unique and differing risks. Existing Generation Hydro-Water Supply Risk The Iong-term sustainability of the Snake River Basin streamflows is irnportant fbr Idaho Power to sustain hydro generation as a resource to meet future demand. Several assumptions related to the management of streamflows were made in developing the twenty-yeai streamflow forecasts for the IRP. These assumptions include: . The implementation of aquifer management practices on tli6 .ort.i#*uke River Plain including aquifer recharge, system conversions, and the Conservation Reserve Enhancement Program (CREP) ii , i, o Future irrigation demand and return flows ,lliiiltrt"r' .,= o Declines in reach gains tributary to the Snake River ; .r ,...,.,- t"l=":: . The expansion of weather modificati6E:i€i., ,,",qloud seedinglsfforts. The assumptions used in developing the twenty year streamttory .ust are carefully planned and based on the current knowle-9.g,.q=of Idaho'P-6,,,rye $taff in idnsultation with other stakeholders. Those assumptions are also s=1p,bj.FE*:'tE-+he limitat$s of the cLrrrent models used in developing the twenty-year streamflo cast F#the 201'f P. Additional risks to atUffiirdr" *" oo*n1ffided in the development of the twenty-year streamflow outlook cons ljli6,f liini;tiiz''-"'"'r:f iil'i Ir - "' .11" ttil;.-l:;aaaaa:1,.1..:. * 1ij.i,l,::.. Ch:,,Ffllfr={idi,#W* ry,:t"nd for irrigation water due to climate variability :.:i:!.:.aa: ',h:l:;..aaa: a:a::::::a1. -.!h.gnges to the sorl@Fs of flo*lugmentation water and the potential for overestimation ffi *tmentatio=-:pvailability in low water years . Long:&Mhangq,stififithe timing of flood control releases at Brownlee Reservoir in respon se':'t&arlier. sn owm e I t . The potentiai'for underestimation of the decline in reach gains within the Snake River Basin . Changes to funding or ability to achieve forecasted levels of aquif,er management on the ESPA. Relicensing Risk Working within the constraints of the original FERC licenses, the Hells Canyon Complex has historically provided operational flexibility which has benefited Idaho Power's customers. The Page 134 2015 tRP ldaho Power Company 9. Modeling Analysis and Results operational flexibility of the Hells Canyon Cornplex is increasingly criticalto the successful integration of variable energy resolrrces. As a result of the FERC relicensing process, operational requirements such as minimum reservoir elevations, minimum flows, and limitations on ramping rates, may become more stringent. The loss of operational flexibility will limit Idaho Power's ability to optirnally rnanage the Hells Canyon Cornplex, making the integration of variable energy resources more challenging and ultirnately increasing power supply costs. Fossil fuel-fired power generation and proposed EPA CAA Section 11 1(d) rule risks ln 2014, the EPA released, under CAA Section I I I (d), a proposed rule foi addressing greenhouse gas emissions from existing fbssil fuel-fired electric gel.,eratihg units. The EPA's proposal requires that states meet their goal by 2030, with interim,,$iiHls +om 2020 to 2029. The EPA has stated that it expects to flnalize the rulemaking by summer 2015.'St-et€ implementation plans would be due by June 20,201 6, sub.iect to extension for portions of the p[an to June 30, 2017 for state plans or June 70,2018 fbr multi-state plans, under certain circum5tlii'ces. Since this is a proposed rule, it is subject to interpretation and change. flgi. is considerable uncertainty on the stipulations ofthe final rule, and theiesultingiirilihct on fossil fuel-fired generation on Idaho Power's system and throughout tti?ftig,.# Regulatory risk i,, ""'"| ,r*,.,,.. Idaho Power is a regulated utility with an oblfuatio-.-='tto.-==s=,g,.,1le cuSffiFr load in its service area and therefore is subject to regulatory risk. Idaho Powerexpects that future resource additions and removals will be approved for inclusion in rate,base'ard tharitwill be allowed to earn afair rate of return on investments related to resoLrrce actioni of the IRP porlfolios. Idaho Power includes public involvement in the lRP process through a1 IRP Advisory Council and by opening the IRP Advisory Council meeti.q{i$ft the public. The openlpublic process allows a public discussion of the IRP and establishes aftundation o-f,customer understanding and support for resource additions and removals when the plan is submitted for approval. The open public process reduces the regulatory risk associatedlwith developing a resource plan. NOx Compliance alt€rnatives- risk Portfol:,i with early retirem0nt of Jim Bridger Units 1 and 2 assume these units are permitted to operate tihtil retirement with'out installation of selective catalytic reduction (SCR) retrofits necessary for eornpliance w.iiI EPA region al haze regu lations. All other portfolios assume the SCR retrofits hre installed on schedule in 2021 for Unit 2 and2022 for Unit l. The permitting associated with the Jirn Bridger early retirernent compliance alternatives is highly speculative at this point. An inability to successlully achieve perrnitting consistent with the assumptions of these compliance alternatives would likely have significant effect on the costs and feasibility of portfolios with early retirement of Jirn Bridger Units I and 2. New Generation Resource Commitment Risk Idaho Power faces risk in the timing of-, and colnrnitrnent to, new resources. There are a number of factors that inflLrence the actual timing olresource planning including the pace of PURPA 2015lRP Page 135 9. Modeling Analysis and Results ldaho Power Company resource development, siting issues, partnership influences, and the performance of existing resources. PURPA Development In the IRP's assessment of resource adequacy, Idaho Power assumes PURPA projects having signed contracts are parl of system resources. The forecast of PURPA development is a unique challenge in the IRP's assessment of resource adequacy; PURPA development happens independent of the IRP process, and can abruptly alterthe resource adequacy pictLrre. Idaho Power's practice is to inclLrde PURPA projects that are operational or under signed contract. ::. Since the 2015 IRP process began in late summer 2014,ldaho Power, signed contracts for 461 MW of solar PURPA projects, and has received inquiries fbr andd:itional 885 MW. Since including the 461 MW of solar contracts as part of committed systern resources in the 2015 IRP, contracts for four solar PURPA projects totaling l4l M:V(.,have been terminated, Ieaving 320 MW still under contract. Table 9.5 illustrates the effeffif removing the l4l MW of solar PURPA projects with tenninated contracts on the 20fifRP first deticit year. Table 9.5 First peak-hour capacity deficit - "f"iigtat,removing 141 MW of solar PURPA Status quo 1;:;:.= Maintain coal capacity = :; Varmy retire units 1 and 2 year-end ,^gE _,.,, -'iia**i,,, Valmy retire units 1 and 2 yeat-end-?AZU = $ Valmy retire unit 1 year-end2},19aho unit 2ye'ir-end202i''.!4r:!l Vatmy retire unit 't year-end2A21...and "n,!=1.;VeySyn].,,,!,,,1j,,,'tXii Bridger retire unit 1 year-end ZOl.5,3 y;ai-a;; i0iS ll:l:il:i: :: r'il B rid ger reti re u n it 1, year:en..!. 2023 andjun it 2 y ear-end 2Q32 Bridger retire unit t year-enO ZOZS anO;nitZ year-end2032, 1tt deficit without 141 MW solar PURPA1"r dcfioit 20ls tRP July 2025 Jylv zozs July 2O2O July 2025 July 2021 July 2022 July 2024 July 2024 July 2024 July 2024 July 2024 July 2020 July 2024 July 2021 July 2022 July 2024 July 2024 July 2024 ="fuAs unbuilt resources, uncertainty persists in relation to the remaining 320 MW of solar PURPA projects. Further contract terminations will lead to earlier onsets of system deflciencies, and ultirnately rnay require ldaho Powerto construct system resources earlierthan expected and with larger capacities. While uncertainty related to potential over-fbrecasting of PURPA development is a critical risk element fiom the perspective of resource adequacy, PURPA development also carries the potential fbr under-forecasting. The potential for under-forecasting is evidenced by the October 13,2014 filing of signed contracts for 401 MW of solar PURPA projects. out of the 461 MW in total; over the course of a day, the PURPA forecast grew by 401 MW. While under-forecasting does not-ieopardize systern resource adequacy, it does increase the likelihood that Idaho Power will encounter issues associated with energy oversupply during system operations. Issues associated with periodic energy oversupply have grown increasingly frequent over recent years. Page 136 20'15 tRP ldaho Power Company 9. Modeling Analysis and Results The expansion of variable and intermittent generation will increase this reliability challenge. The flexible resource needs assessment performed for the 2015 IRP corroborates concerns related to reliability impacts from periodic energy oversupply. The flexible resource needs assessment is described later in this chapter. Boardman to Hemingway transmission line Significant challenges have been encountered during the permitting phase of the B2H transmission line. Environmental requirements related to siting of the transmission line have the project is subject to these siting, permitting, and regulatory approval r-qgftflf - ..--.i nnA -l^-:,--,---a1l--:-- ------:-- f -L- ,';.ll1;the partners, PacifiCorp and BPA, also impact the in-service date. ..] Regional Resource Adequacy potentialto bring about project delays and increased permitting costs. The.e.6mpletion date of the proiect is subiect to these sitins. permittins. and resulatory aDproval reqdfll€fxents. The needs of ':'"tn "= "illV'i1/s"'-Regional resource adequacy is part of the regional transmissffi planning proCess.la July 2013, ,- ^ -: ^ /Ed"i,_ - rc6{s;}gJuly 2013, er ffffiffiesource power Klipply .; The NWPCC has adopted an adequacy stagd_ard used by the' as a metric for assessing resource adequacy. The purpose of the res6. d€:a--?.euuaw stanffi{ii}riflp, to provide an early warning should resource development failto keep pa rtE d|8#,#|F+,rfrIowthL'The analytical information generated with each resource adequacy asses nt as6i EtHi#ffi$ional utilities when preparing their individual IRPs. The statis-tiretsed to asse- =-e. pliance with the adequacy standard is the adequacy in the Northwest. Idaho Power has particiflaie$j.rr the C since its inception, and also participated in the NWPCC's Resource AO"qru"y fi ich preceded the RAAC. For the 2021 increases to a little over 8 percent. The draft RAAC report the 2021 operating year is the result of planned retirements erating ;l.v-'*batralia, Washington and the Boardman power plant. The uacy assessm ifffutralia, Washington and the Boardman power plant. The tli6t the 2021 LOLP would be brought to below the 5 percent level by RAAC alsci generating re licensed. In general, the Pacific Northwest experiences peak energy demand in the winter, whereas Idaho Power experiences peak demand in the summer. The 2015 IRP analysis indicates Idaho Power resource deficits occur in the summer months, with July being the most critical month. The Northwest Regional Adequacy Assessment indicates that January, February, and to a lesser extent August are the most critical months for the overall Pacific Northwest region. The Boardman to Hemingway transmission line is a regional resource that will assist Idaho Power and the larger Pacific Nofthwest in addressing their opposing seasonal capacity deficits. likelihood of supply shortagej,!..*trf&G,L1&./Eommonly_known as the loss of load probability (LOLP). Under the adequacy stanffi;ihe LO is held to 4-maximum level of 5 percent.Under the adequacy sta,, $t the LOi.=E ts held t axrmum level of'5 percent. The RAAC has issued'€i.{ffi rep .ses_srnent of LOLP forthe 2020 and2027 operating years. The LOLP for the"ffiffi*ting ydiil'f t/jfist under the 5 percent adequacy standard level. resources p6viding the equivalent of 1,150 MW of dispatchable generation. The ry that the I;9jP analysis for both operating years does not include planned new:s that the LOLP analysis for both operating years does not include planned new rces in ffiregion, because these resources, while planned, have yet to be sited or'==!=;ffirr 2015 tRP Page 137 9. Modeling Analysis and Results ldaho Power Company The Idaho Power resource planning process is consistent with the NWPCC resoLrrce adequacy studies. The Idaho Power stochastic analysis indicates that even under high load, high electricity/natural gas prices, and low water conditions, resource portfolios containing 82H are the lowest cost ponfblios. DSM implementation While ldaho Power has considerable experience in DSM programs, there is always an implementation risk with a new program. The actual energy savings and peak reductions may vary significantly fiom the estirnated amollnts if customer participation rates are not achieved. Many of the portfolios include technologies that Idaho Power has timited eiperience in developing, building, or operating. This lack of direct experience increases the risk associated with the development of these resources including: ,., o Price Risk: Cost estimates fbr solar are based -o 2014 Lazatd report. While this report provides an objective, third parly estimate oflieS'ource costs.:there is risk that trends in solar pricing may not be properly captured by the [-azard'report. . Siting Risk: Several of the technologi'es,,involve diffeient risks associated with the type of resource being developed: ' 1,' . . Fuel types such as gas may encouhtgr pu-b,ft and political pressure against a project being located near 1oad,,",,,=g,,..,, * or bei nstructed at all. . Technologies ,t"i'u, CHF*O i..-UuseO TES would require a large commercial or industrial customer to partner _*,,.1,,,,!. uho Power. Geothermal, pumped stor@,.and canal drop hydro require the facility to be sited at the source of the motive forcg, T.! e projectsare often located in remote locations far from load centers which increase the development and t@sm-ission costs associated with the resource. Preferred Portfolio,::: On the basis of the 2015 IRP:S quantitative and qualitative analysis, the preferred ponfolio selected by Idah6Fower isportlolio P6(b). P6(b) balances the cost, risk and environmental concerns identifled in this lRP. The retirement of the Norrh Valmy plant and the cornpletiorr of B2H in 2025 balances the risks of CAA Section I I I (d), increases in unplanned intenr ittent and variable generation, and is slrown to be cost competitive. Porlfolio P6(b) also includes the addition of 60 MW of demand response and 20 MW of ice-based thermal energy storage in 2030. In 2031, portfolio P6(b) also adds a 300 MW combined-cycle combustion turbine. l-hese resource additions late in the planning period address projected needs fbr resources providing peaking capability and system flexibility. With expected long-term expansion of variable energy resources, the need fordispatchable resources that provide system flexibility will also increase. Page 138 2015lRP ldaho Power Company 9. Modeling Analysis and Results Analysis of Shoshone Falls Upgrade For the 2015 lRP, ldaho Power analyzed the benefits and costs of the 50 MW expansion of the Shoshone Falls power plant. The incremental electrical generation the plant would produce with the expansion is on average approximately 200 CWh annually. Using the AUROA model, an analysis was perforrned to deterrnine the value this incremental hydro generation would provide to the systenr. The incremental generation is assumed to be eligible fbr Renewable Energy Certiflcates (REC) and the value of these certificates is included in the beneflt calcLrlation. The cost of the pro-iect was updated using 2015 IRP assumptions i The analysis indicates that the incremental energy produced from the eipansion is projected to yield over the 2O-year planning period a benefit to the preferred portfolio of approxirnately $ 13.8 rnillion on an NPV basis under planning case assurxptions for natural gas price, customer load, and hydroelectric generation. However, as noted in Chapter 5, nearly 75oh of the,incremental energy in an average year is produced during the six-rnonth period frorn January through June, with substantially less production during the months of July through Septernber. Thus, while the analysis indicates some economic benefit from the in,cfementalenergy, the 50 MW Shoshone Falls expansion cannot be linked to an lRP-determined resource need as it provides little to no capacity or energy during peak summer load months. : As a result, Idaho Power will explore constnibai ofa smallei.iiied upgrade to more cost effectively replace the aging 0.6 MW and 0i#flWftifs=.a.! oshone Falls. The srnaller upgrade will allow energy benefits to be realized through a much higherannual capacity factor and lulfill license requirements associated withleneficial u.sffstreamflow at the project location. Conceptual-level analysis infli,gpte3ii4$+pgrad" !{ng capacity ranging in size frorn 1.7 MW to 4.0 MW is well suited fot# hydrau@haracteffiics of the existing facilities. Cost analysis conducted as pafi of the.conceptual-,ffi1study indicates energy from the smaller upgrade can be produced at a 4}-year le#df rzed cprL.yj:.ff.fi;i" ::F, n:tpa.tely S50-S55 per MWh fbr the 4.0 Mw upgrade and $60-$65 per MW.Sr,Sfthe 1.7 MW upgrade. As indicated in the Action Plan in Chapter 10, Idah,q,F,o-wer will cohtinue study of the smaller upgrade options, and seek an amendment ofthE'Current FERCIlicense to allow for construction of a smaller-sized capacity upgrade to Cornmenc e in 2017 . CapaGity Plan n i n0:Marg in Idaho Power di$ssed p-lanhing criteria with state utility commissions and the public in the early 2000s befoie'ado t-ing the present planning criteria. Idaho Power's future resource requirements are not b-ased directly on the need to meet a specified reserve margin. The cornpany's long-terrn resource planning is driven instead by the objective to develop resources sufficient to meet higher-than-expected load conditions under lower-than-expected water conditions, which effectively provides a reserve margin. As part of preparing the 2015 IRP, Idaho Power calculated the capacity planning rnargin resulting frorn the resource development identified in portfolio P6(b), the preferred resource poftfolio. When calculating the planning margin. the total resources available to nreet demand consist of the additional resources available Lrnderthe preferred portfblio plus the generation 2015 tRP Page 139 9. Modeling Analysis and Results ldaho Power Company from existing and committed resources assuming expected-case (50th-percentile) water conditions. The generation from existing resources also includes expected firm purchases from regional markets. The resource total is then compared with the expected-case (50th-percentile) peak-hour load, with the excess resource capacity designated as the planning margin. The calculated planning margin provides an alternative view of the adequacy of the preferred portfolio, which was formulated to meet more stringent load conditions under less favorable water conditions. ldaho Power maintains 330 MW of transmission irnport capacity above the,forecast peak load to cover the worst single planning contingency. The worst single planning_coffihgency is defined as an unexpected loss equal to Idaho Power's share of two units at the JinrSridger coal facility or loss of Langley Gulch. The reserve level of 330 MW translatesintynl,{,ffif.ry€ margin of over l0 percent, and the reserved transmission capacity allows Idaho Powerio ini[6rt energy during an emergency via the NWPP. A 330-MW reserve margin also resultS in the att6i ent of a loss-of- load expectation (LOLE) of roughly I day in l0 years, a slandard industry me{iqie,genl. Capacity planning margin calculations for July of,each year through the planning Pffiod are shown in Table 9.6. -- . tr :.::::::::] a:ia,:r:,a1. ,,, liNlil, I lllli;r:iiii:i'i#" Page 140 2015 tRP s oo)G o_ o_E. rr) c)N @ @ @ co 6 (,N oN oN ( oF o-o- lco lco l@ l@ lco l@ lo o@ o@ ()CO r)@ oo ro@ no o@ ooo oo$ o$ @t*- orot- (.)6a- Nes_ rt(ot_ N(o$- r.-v- r)F.tt- o)F.j- Nt-@@ O l'-(o@ N@t'- @'aN noNO @o,i.- o o@o) o)N Noit :r;,:ttitt oiotl', $@ F-@ ,, ..Y.:,:-, :|i:i-+.iii:r::::::::.i5 )1;:,:.:,. - $oo, o) N()oo, " e3 eEE 6+ iao ol olo 6+ 6+q 9i.. 9Xi s-E F"BI @ F- (o N (o N (o t- (o N t- (o F- N (o F. ,to N o B (9jj o (a:o arl..,,,t--". o€ !,Wru ilfr' <o g:1 0) (',]-N --j...aaia.. "rtlit&t b'\!15?r'k 6ruNrooo,N- C! o)()O, O, oooo (o N ttr 1 t'1, (o; F? r.r (o N (o N ol F.o)t- roo) #-rOo,c! 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E ct .E sCL .=or! CL(Eo \O)I -o(EF co+coO 0) =oo_os(UE U'==aq)tr 15CG .oo oC o) .C 0)!o oi ldaho Power Company 9. Modeling Analysis and Results Flexible Resource Needs Assessment Idaho Power analyzed the need for flexible resource as directed by the Oregon PUC in Order l2- 013. Idaho Power determined that there are adequate flexible resources to address up-regulation (up-regulation is required when intermittent generation is less than the quantity scheduled and Idaho Power generation must overcotne the generation shortfall). Idaho Power detennined that there are likely to be insufficient down-regulation resoLrrces available at certain times of the year. Specifically, down-regulation deflciencies occur during periods of oversupply when all of the Idaho Power generation resources are reduced to saf-e operating levels, yet company generation plus the intermittent generation exceeds customer load. : :::::.::j.::]. Idaho Power analyzedthe flexible resource needs using the data aeveio6--A for the solar integration study. The data consist of actual load, actual wind, and simulated:FV solar generation for 500 MW of solar plant at six geographic locations throughout ldaho Power's service area. The data were developed at five-rninute intervals over three water years from October 201 0 through September 201 3.t',tr. tt/ The first step in the analysis was to estimate the flexiblerelource requirement. ldaho Power calculated the flexible need requirement in 5-, l0-, l5-, 30"ii4 i-, and 60-minute intervals from the dataset and the results are presented in,.,Eigu5e.9.7 below. ihe one-percent likelihood shown in Figure 9.4 is the total likelihood; the one-percent tikelihood is composed of one-half percent up plus a one-halflpercent down. it 20% 15o/o 10% 5o/o 0% -5o/o -10o/o -15% -20o/o 50 Minutes Load Net (V/ind, Solar) - Load Figure 9.4 Flexibility need (500 MW solar, existing wind, 1% likelihood) Figure 9.4 shows that adding intermittent resources to the Idaho Power system increases the flexibility need, both up and down. Idaho Power has a second solar integration study underway to further analyze the effects of adding intermittent utility-scale solar PV generation to the Idaho Power system. E'(Eo o,z o fl oo o,IL i I i t I I 706040302010 2015 tRP Page 143 9. Modeling Analysis and Results ldaho Power Company ldaho Power used a resollrce dispatch simulation of the ldaho Power system to forecast available system flexibility after adding 500 MW of PV solar to the generation rnix. The purpose of the simulation is to assess both the regulation requirement and supply. The simulation was performed r"rsing a one-hour time step. Up-regulation and down-regulation quantities were assessed to detennine the net result of flexible resource needs and flexible resource supply. A representative graph of system regulation during the spring is shown in Figure 9.5 (April2012 historical data with the addition of 500 MW of PV solar on the system). 1000 800 600 400 200 =o-200 400 -1 000 3t31t2012 4t5t2012 411012012 411512012 412012012 Figure 9.5 System regllition ..,.., ' l.ii.. F i g u re 9 . 5 sh o w s t h e fi v e a!.$nti t rip,51.,, ", " ",l,,;Eifulill@li"' I ., o regula!il;=r.,:.1,.y1 iti61+,., "'=.,, i:,:.i1. ',,,i:.. . i..2. UFrEgu lation requirementi,.-.'.. .:t .::=| :,a:.3. RcggJation violatiorftffioth up and down) tttt: t:t: 4. DowFregulation re$irement ,,.i,rl. t-'' 5. Down-regulation available Figure 9.9 below is simplified to focus on the regulation the regulation requirement and the regulation available. 4t25t2012 4t30t2012 violation by removing the lines showing - Reg Up Avail - Reg Up Req - Reg Up Violation - Reg Down Violation - Reg Down Req - Reg Down Avail -600 -800 Page 144 20'15 tRP ldaho Power Company 9. Modeling Analysis and Results 1 000 800 600 400 200 =0-200 -400 -600 -800 ,-'1000 : - - 3t31t2012 - Reg Up Violation - Reg Down Violation - Reg Up Avail "*-Reg Up Req - Reg Up Violation -Reg Down Violation -Reg Down Req - Reg Down Avail 4t5t20'12 4t10t2012 4t15t2012 4t20t2012 4t25t20',t2 4t30t2012 generation resources are reduced to safe ls, yet cofE-$.any generation plus the intermittent generation exceeds customer April study period. up-re$,11'lation violations during the year and determined that regulation is summer, fall, and winter are shown in 1000 800 600 400 200 =o-20O i -400 -600 -800 -1000 i-- 7t10t2012 7t15t2012 7t20t2012 7t25t2012 7t30t2012 Figure 9.7 Regulation violations, summer 2012 ..ffi. , Idaho Power analyzedtne oS$,ffi primarily an issue during-$9. spring. ' figures 9.7 through 9.9ffiw: .,A 2015 tRP 814t2012 8t9t2012 Page 145 9. Modeling Analysis and Results ldaho Power Company 400 200 0 -200 -400 -600 1 000 800 600 1 000 800 600 11t4t2011 '1',U9t2011 - Reg Up Avail - Reg Up Req - Reg Up Violation - Reg Down Violation - Reg Down Req - Reg Down Avail - Reg Up Avail - Reg Up Req - Reg Up Violation - Reg Down Violation - Reg Down Req - Reg Down Avail -800 ll ,-1000 l 101'tot201'l Figure 9.8 10t't5t2011 10t20t20't1 10t25t2011 10t30t201',1 Regulation viotations, tall 2011 400 200 =o-200 -400 -600 -800 -1000 '- -- 122012011 1?,251201',1 1213012011 1t4t2012 1t9t2012 1t14t20121?,15t2011 Figure 9.9 Regulhtion violations, winter 201112012 As shown in the graphs, the regulation violation line shows zero violations through the summer, fall, and winter seasons (please note that the system simulation shows a single small down- regulation violation in one hour of the summer season. The summer down-regulation violation is less than ten MW, however down-regulation could possibly become an issue during some summer hours). Several times during the four seasons, the regulation available equals the regulation requirement indicating that the ldaho Power system is operating at the regulation limits. The simulations show that it is more Iikely for the Idaho Power system to face down- regulation limits than up-regulation limits. Page 146 2015 tRP ldaho Power Company 9. Modeling Analysis and Results ldaho Power is currently conducting a second solar integration study. ldaho Power anticipates that additional regulation analysis will occur as paft of the second solar integration study. Idaho Power expects to update the flexibility analysis with results of the second solar integration study in the 2017 Integrated Resource Plan. Down-regulation is a significant concern during periods of oversupply for ldaho Power and other utilities in the region. Idaho Power is currently investigatin g d ifferent rnethods to address potential down-regu lation violations. Loss of Load Expectation (LOLE) j ldaho Power used a spreadsheet rnodel8 to calculate the LOLE for the efeven portfolios studied in the stochastic risk analysis in the 2015 lRP. The assessment assum-e$4tical water conditions at the existing hydroelectric facilities and the planned additions for the selected pofifolios. As mentioned in the Capacity Planning Margin section, Idaho Power uses a capacity benefit rnargin (CBM) of 330 MW in transmission planning to provide the necessary reserves for unit contingencies. The CBM is reserved in the transmission sy,s and is sold on a non,finn basis until forced unit outages require the use of the transmission capacity- The 2015 lRP,analysis assumes CBM transrnission capacity is available to qget dencilffto forced outages. The model uses the IRP forecasted hourly load profile, g.nc*tliand purchase outage rates (EFORd), and generation and transmission capacities to comp111q a LOLE for each hour of the 20 year planning period. Demand response programs -qrcre modeffi.$'p-----..,.a reduction in the hourly load forthe l0 peak days in a given year, although eiistingp{ogrSms allow use up to l5 days. The 10 day assumption was chosen as a conservative reflectioX of 4eatity where it is assumed sorne days will be left in reserve fbr unexpected extreme W.P.atli{i:"tce TES resources were modeled as a reduction to hourly load during:aftem'bon/evening hours in summer months and an increase in hourly load during night hou:is in surh&r rnontK$ffihe LOLE analysis is performed monthly to permit capacity de-rates for'rnaintenahE or a lackr,l-diE fuel (water). Resource capacities are assumed to be constant foriall houry..,g$;.rh,ryn$l*rX-ffi the exception of demand response and ice TES as explained above, aS,.wsll aSsolar ph'otd\rri'ltaic resources. Photovoltaic resources are modeled with a capacity thafuaries by hour for each month according to changing daylight hours and sun position. The typ,jcal metric Lrsed in the utility industry to assess probability-based resource reliability is a LOLE of; l'day in l0 years.'Idaho Power chose to calculate a LOLE on an hourly basis to evaluate thereliability at a more granular level. The l-day-in-10-years metric is roughly equivalent to 0.5 to I hourper year. The results of the LOLE probability analysis are shown in Figure 9.10. Several porlfolios result in a LOLE greater than2 hours per year, which indicates that additional purchases or generation capacity would be necessary in the future to achieve acceptable performance. The results indicate that resource portfolios 2(a), 6(b), 8, I 0, I I and I 3 are the best performers with LOLE under 2.0 hours per year over the 20-year planning horizon. Additional data can be found in Appendix C- Technical Appendix. 8 Based on Roy Billinton's Power System Reliability Evaluation, chapters 2 and 3. 1910. 20'l5 tRP Page 147 9. Modeling Analysis and Results ldaho Power Company o.m 2017 2019 2921 +Pz(a) -r-P3 .+P6(b) -*-P8 Figure 9.10 LOLE ( 20zi 2t25 2027 ePg +P10 +P11 -*-P13 2W 2G3t 203:i "*---P16 *P17 ...r-P18 20't5 Page 148 2015lRP ldaho Power Company l0 Action Plan 10. PneFERRED PonrroLro AND Acrrorv Plarrr Preferred Portfolio (201 5-20341 Analysis forthe 2015 IRP consistently indicates favorable economics associated with two significant resolrrce actions: the 82H transmission line and the early retirement of the North Vahny power plant. IRP analysis suggests a strong connection between these resource actions, both of which are characterized by uncefiain timetables. Specifically, an acceleration in the completion of the B2H line can be expected to provide the system reliabilify and access to markets allowing for a corresponding acceleration in the early retirern-g$North Valmy. ':::::::':::::::=::The B2H transmission line and early Norlh Valmy retirement are twdker'major resource actions of portfolio P6(b), the 2015 IRP's preferred resource portfolio. Porlfolio P6(b) contains both actions in the year 2025,with the completion of the transmission line preceding the end-of-year coal plant retirement. Porlfolio P6(b) contains no other resp-uice actions through ihe e1d of the 2020s, adding 60 MW of demand response and 20 MW;i$f ice-based thermal energy'in 2030, and a 300 MW combined-cycle combustion turbin e in 203t:- The absence of resource needs in portfblio P6(b) prior,o *;'ZOZS retirement of North Valmy is noteworthy. The resource sufficiency through4e early 2l2tsshields portfolio P6(b) frorn risk exposure associated with the fbllowing flactors: l. Uncertainty related to planned, but yei;to-b.-UUlli=FE$.a solar; further project cancellations beyond thosg afready observed will have freater impact on portfolios requiring capacity additidiis in fie earlyi!'020s. 2. Uncertainty related to EPA's proposed regulation of COz emissions from existing power plants under CAA Section.tl 1(d), p@icufaily the effect of the final rule on operations at coal- and natural gas-frred power plEfits iil the proposed interim compliance period 3. Uniertainty related to the completion date of the B2H line due to permitting issues and the needs ofproject partners. ,ta- t.4. UnC€fuinty related to retirement planning for a jointly owned power plant (Nofih Valmy);,Specifically the challenges associated with arriving at a mLrtually feasible retirernent dftte, ,,-, Uncertainty is a common part of long tenn integrated resource planning. Even with the increased uncertainty surrounding the 2015 IRP the analysis indicates completion of the 82H line and early retirement of the Norlh Valrny power plant are prudent actions. The timing of the actions can be appropriately adjusted as conditions related to the four factors listed above become actionable. Action Plan (2015-2018) The action plan forthe 2015-2018 period includes iterns specifically related to the prefbrred portfolio P6(b) and other itenrs irrespective of portfblio selected. The P6(b) action items include 2015 rRP Page 149 10. Action Plan ldaho Power Company continued perrnitting and planning tbr the 82H transmission line, and irrvestigation of North Valrny retirement in collaboration with plant co-owner NV Energy. The pursuit of these items over the action plan period is critical to the successfirl and tirnely implementation of the preferred portfblio. The Gateway West transmission line remains a key future resource to ldaho Power and the region prornoting continued grid reliability in a time of expanding variable energy resources. Thus, the plan inclLrdes continued permitting and planning associated with the Gateway West proiect. CAA Section I I l(d) will potentially have pronounced impact on coal- and natural gas-fired power plant operations on Idaho Power's system, and throughout the nation. Idaho Power will remain involved as a stakeholder as CAA Section I I I (d) moves towards finalization and irnplementation. As stipulations of the final rule become clearp.r, and as irnplementation planning is developed, Idaho Power will assess the impacts:{fcAA Section I I 1(d)on the preferred portfolio. The action plan also includes the following items: :,1: i#filiii o Continued pursuit of cost-effective energy efficiency,'working with stakeholder groups such as the Energy-Efficiency Advisory Croup and regional groups such as the Northwest Energy Efficiency AlliaiiCe"' ':::::i'::::,:.:,::,:,= 'i li',,,., r ,;: i1,. Table f,Oll,provides actionfi1M,-lth daffi&r the 20ls-2018 period. Table 10.1. ', Action plan (2$'15-2018) . Filing to amend the FERC license to adjust tlle 50 MW Shoshone Falls hydroelectric project expansion, and.e,ffi-r-t. lated to dii5tirdy and construction a smaller upgrade of the project with a *6uaa@e date'idthe first quarter of 2019 l. Completion of t " "u:rtM._,-tfil cn) retrofits for Jim Bridger Units 3 and 4 { ryJ*.*i. Begin economic ena[11"A;,,NSNt of SCR retiofits for Jim Bridger Units I and 2 (SCR i nstal larioh??-EQ,u-ired ffiffi it 1 in 2022 and for U nit 2 in 202I ) Year Resource Action 2015-2018 2015-2018 2015-2018 2015 2015 20't5-2016 2016 Boardman toHemingway Gateway West Energy Efficiency Shoshone Falls Jim Bridger Unit 3 Shoshone Falls Jim Bridger Unit 4 Ongoing permitting, planning studies, and regulatory filings Ongoing permitting, planning studies, and regulatory filings Continue pursuit of cost-effective energy efficiency File to amend FERC license to adjust 50 MW expansion Complete installation of selective catalytrc reduction emission-control technology Study options for smaller upgrade ranging in size up to approximately 4 MW Complete installation of selective catalytic reduction emission-control technology Page 150 2015 rRP ldaho Power Company '10. Action Plan 2016 2017 2017 2019 North Valmy Units I and 2 Shoshone Falls Jim Bridger Units 1 and 2 Shoshone Falls Continue to work with NV Energy to synchronize depreciation dates and determine if a date can be established to cease coal-fired operations Commence construction of a smaller upgrade Evaluate the installation of SCR technology for Units 1 and 2 at Jim Bridger in the 2017 IRP Online date for smaller upgrade during first quarter Idaho Power has several choices when procuring long term energy. It can develop and own generation assets, rely on PPA and market purchases or use a combination of the two strategies. During the action plan period, ldaho Power expects to continue participatihg in the regional power market and enter into mid-term and long-term PPAs. However;iin the long run, Idaho Power believes asset ownership results in lower costs for customers due to the capital and rate- of-return advantages inherent in a regulated electric utility. i ''t,i| 1,,,,, Conclusion The 2015 IRP analysis indicates favorable results for the B2H transmission line and the early retirement of the North Valmy power,@*,. plant. The analysis also suggests linkage ::I:f;:ii["W between the B2H line and the early retirem6,li&,ofry4.1 North Valmy. Acceleration in the completioiilffi the transmission line could brin corresponding acceleration i f,or North Valmy retirement. Idaho Power has t B2H line as an uncommitted View of the Hemingway Substation beginning with every IRP, including t has been a top performing resource alternative. The partne the various these an Yffi,.p,,,,"p,,that it is time for Idaho Power, the transmission line ry dild governmental agencies to complete a final permitting CONSI and Boardman to Hemingway transmission line. lrts public involvement in the planning process. Idaho Power thanks hrembers and the public for their contributions to the 2015 IRP. The IRP Advisory @..,.,{ifiti| discussed many technical aspects of the 2015 resource plan al with a significant number of political and societaltopics at the meetings, portfolio design 2015 resource plan along workshop, and field trip to an ldaho Power facility. Idaho Power's resource plan is better because of the contributions from the IRP Advisory Council members and the public. Idaho Power prepares an IRP every two years, and the next plan will be filed in 2017. As described in this plan, the coming years are characterized by considerable uncertainty associated with energy-related issues on the state, regional, and national levels. Idaho Power anticipates that as unceftainty related to these issues clears the 2015 IRP preferred pofifblio and action plan may be adjusted in the next IRP filed in2017, or sooner if directed by the IPUC or OPUC. ion schedule :a:t:l,E 2015 tRP Page 151 10. Action Plan ldaho Power Company intentionally. 2015 tRPPage 152