20150715Hearing Transcript Exhibits II-IV.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF AVISTA
CORPORATION'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPANY'S PETITION TO
MODIFY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENTS
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
CASE NO. PAC-E-15-03
E x h i b
BEFORE
. 1 t s
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISSIONER KRISTINE RAPER
PLACE:
DATES:
c ........, � c:::::,
I c.n
Commission Hearing Room �a c.; c: 472 West Washington Street f 'l r- C.'> Boise, Idaho ("') en
:i::o- :r;:
June 29-30, 2015 u: '?. er. - - c, (...)
VOLUME II-IV - Pages 87 - 1027
ORIGINAL CSB REPORTING
Certified Shorthand Reporters
Post Office Box 9774
Boise, Idaho 83707
[e-mail]
Ph: 208-890-5198 Fax: [phone]
Reporter:
Constance Bucy,
CSR
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 1
Exhibit No. 1
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of 1
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 2
Idaho Power Company
Renewable Energy Contracts List
SUMMARY
PURPA Projects
OregonSolar Projects
Non PURPA Projects
SUMMARY BY FACILITY TYPE
PURPA PROJECTS ONLINE
133 1,302.08 MW
60 0.46MW
3 135.65 MW
196 1,438.19 MW
Biomass 10 29.45 MW
CoGen 1 15.90 MW
Thermal 3 15.00 MW
Hydro 64 143.70 MW
Wind 27 576.92 MW
105 780.97 MW
PURPA PROJECTS UNDER CONTRACT NOT YET ONLINE
Solar
Hydro
Wind
19
4
5
461.00 MW
10.11 MW
50.00 MW
28 521.11 MW
OregonSolar PROJECTS ONLINE
OR Solar 55 0.42 MW
55 0.42 MW
OR Solar 5 0.04 MW
Oregon Solar PROJECTS UNDER CONTRACT NOT YET ONLINE
5 0.04MW
Non PURPA PROJECTS ONLINE
Geothermal
Wind
2
1
3
35.00MW
100.65 MW
135.65 MW
Totals Projects Capacity
196 1,438.19 MW
Exhibit No. 2
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of6
Idaho Power Company
Renewable Energy Contracts List
PROJECT DETAILS
PURPA PROJECTS ONLINE
� I : ProectSze
' I MW Pro ect Number T e Pro ect Name I State Count :
31616150 Biomass B6 Anaerobic Digester ID Gooding 2.28 41365515 Biomass Bannock County landfill ID Bannock County 3.20
31615100 Biomass Bettencourt Dry Creek BioFactory, LLC ID Twin Falls 2.25
31616100 Biomass Big Sky West Dairy Digester (OF-AP #1, LLC) ID Gooding 1.50 31616115 Biomass Double A D�ster Pro� ID Lincoln 4.50 21865113 Biomass Fighting Creek Landfill Gas to Energy Station ID Kootenai 3.06
21615100 Biomass Hidden Hollow Landfill Gas ID Ada 3.20
41455091 Biomass Pocatello Waste ID Bannock 0.46 31616110 Biomass Rock Creek Dairy ID Twin Falls 4.00 11766002 Biomass Tamarack Cspp ID Adams 5.00 Total Biomass Projects: 10 29.45
41866113 CoGen Simplot Pocatello ID Power 15.90
Total CoGen Projects: 1 15.90
31765150 Thermal Magic Valley ID Minidoka 10.00
21662100 Thermal Tasco - Nampa ID Canyon 2.00
31616082 Thermal Tasco - Twin Falls ID Twin Falls 3.00 Total Thermal Projects: 3 15.00
21615205 Hydro Arena Drop ID Canyon 0.45 21615078 Hydro Barber Dam ID Ada 3.70 31214058 Hydro Birch Creek ID Gooding 0.05 31415065 Hydro Black Canyon #3 ID Gooding 0.14
31615140 Hydro Blind Canyon 10 Gooding 1.63
31416013 Hydro Box Canyon ID Twin Falls 0.36 31515100 Hydro Briggs Creek ID Twin Falls 0.60 31715126 Hydro Bypass ID Jerome 9.96
31416020 Hydro Canyon Springs ID Twin Falls 0.13
31616081 Hydro Cedar Draw ID Twin Falls 1.55 31516014 Hydro Clear Springs Trout ID Twin Falls 0.52 31615057 Hydro Crystal Springs ID Twin Falls 2.44 31415023 Hydro Cuny Cattle Company ID Twin Falls 0.2.2
31615106 Hydro Dietrich Drop ID Jerome 4.50
44395973 Hydro Eightmile Hydro Project ID Lemhi 0.36 11615077 Hydro Elk Creek ID Idaho 2.00 41717137 Hydro Falls River ID Fremont 9.10
21615215 Hydro Fargo Drop Hydroelectric ID Canyon 1.27
31615121 Hydro Faulkner Ranch ID Gooding 0.87 31415134 Hydro Fisheries Dev. ID Gooding 0.26 31615098 Hydro Geo-Bon#2 ID Lincoln 0.93
31315093 Hydro HaileyCspp ID Blaine 0.06
31715128 Hydro Hazelton A ID Jerome 8.10 31715140 Hydro Hazelton B ID Jerome 7.60 11715144 Hydro Horseshoe Bend Hydro ID Boise 9.50 31415094 Hydro Jim Knight ID Gooding 0.34
31615031 Hydro Kasel & Witherspoon ID Twin Falls 0.90 31615030 Hydro Koyle Small Hydro ID Gooding 1.25 31615056 Hydro Lateral# 10 ID Twin Falls 2.06 31316015 Hydro Lemoyne ID Gooding 0.08
31615105 Hydro Little Wood Rvr Res ID Blaine 2.85
31515107 Hydro Littlewood I Moosh ID Lincoln 0.87 31715099 Hydro Low Line Canal ID Twin Falls 7.97
31615130 Hydro Low Line Midway Hydro ID Twin Falls 2.50
31615125 Hydro Lowline #2 ID Twin Falls 2.79
31715123 Hydro Magic Reservoir ID Blaine 9.07
31515009 Hydro Malad River ID Gooding 0.62 • 31615117 Hydro Marco Ranches ID Jerome 1.20
31615154 Hydro Mile28 ID Jerome 1.50
12618250 Hydro Mill Creek Hydroelectric OR Union 0.80 Exhibit No. 2
Case No. IPC-E-15-01
R. Allphin, IPC
Page 2 of6
Idaho Power Company
Renewable Energy Contracts List
12614070 Hydro Mitchell Butte OR Malheur 2.09
21615200 Hydro Mora Drop Small Hydroelectr'.c Facility ID Ada 1.85 31515004 Hydro Mud Creek/S & S ID Twin Falls 0.52
31414111 Hydro Mud Creek/White ID Twin Falls 0.21
12616071 Hydro Owyhee Dam Cspp OR Malheur 5.00
31615067 Hydro Pigeon Cove ID Twin Falls 1.89
31415164 Hydro Pristine Springs #1 ID Jerome 0.13
31415165 Hydro Pristine Springs Hydro #3 ID Jerome 0.20
21415119 Hydro Reynolds Irrigation ID Canyon 0.26 31615003 Hydro Rock Creek #1 ID Twin Falls 2.05
31615104 Hydro Rock Creek #2 ID Twin Falls 1.90
31515103 Hydro Sagebrush ID Lincoln 0.43
31617100 Hydro Sahko Hydro ID Twin Falls 0.50
41515122 Hydro Schaffner ID Lemhi 0.53
11415009 Hydro Shingle Creek ID Adams 0.22
31615158 Hydro Shoshone#2 ID Lincoln 0.58
31416001 Hydro Shoshone Cspp ID Lincoln 0.37
31315021 Hydro Snake River Pottery ID Gooding 0.07
31414075 Hydro Snedigar ID Twin Falls 0.54
41717139 Hydro Tiber Dam MT Liberty County 7.50
31415027 Hydro Trout-Co ID Gooding 0.24
12616072 Hydro Tunnel #1 OR Malheur 7.00 31315029 Hydro White Water Ranch ID Gooding 0.16 31715141 Hydro Wilson Lake Hydro ID Jerome 8.40
Total Hydro Projects: 64 143.70
21615101 Wind Bennett Creek Wind Farm ID Elmore 21.00
31765170 Wind Burley Butte Wind Park ID Cassia 21.30
31315050 Wind Camp Reed Wind Par1( ID Elmore 22.50
31318100 Wind Cassia Wind Farm LLC ID Twin Falls 10.50
21615115 Wind Cold Springs Windfarm ID Elmore 23.00
21615120 Wind Desert Meadow Windfarm ID Elmore 23.00
31315035 Wind Fossil Gulch Wind ID Twin Falls 10.50
31765160 Wind Golden Valley Wind Park ID Cassia 12.00
21615125 Wind Hammett Hill Windfarm ID Elmore 23.00
31315130 Wind High Mesa Wind Project ID Twin Falls/Elmore 40.00 41718140 Wind Horseshoe Bend Wind MT Cascade 9.00
21615105 Wind Hot Springs Wind Farm ID Elmore 21.00
12618200 Wind Lime Wind Energy OR Baker 3.00 21615130 Wind Mainline Windfarm ID Elmore 23.00 31720190 Wind Milner Dam Wind ID Cassia 19.92
31315075 Wind Oregon Trail Wind Park ID Twin Falls 13.50 31315060 Wind Payne's Ferry Wind Park ID Twin Falls 21.00
31315045 Wind Pilgrim Stage Station Wind Park ID Twin Falls 10.50
41455300 Wind Rockland Wind Farm ID Power 80.00
21615135 Wind Ryegrass Windfarm ID Elmore 23.00
31618100 Wind Salmon Falls Wind ID Twin Falls 22.00
21615110 Wind Sawtooth Wind Project ID Elmore 22.00
31315055 Wind Thousand Springs Wind Park ID Twin Falls 12.00
31315065 Wind Tuana Gulch Wind Park ID Twin Falls 10.50
31315150 Wind Tuana Springs Expansion ID Twin Falls 35.70
21615140 Wind TINO Ponds Wlndfarm ID Elmore 23.00
31315070 Wind Yahoo Creek Wind Park ID Twin Falls 21.00
Total Wind Projects: V 576.92
Exhibit No. 2
Case No. IPC-E-15-01
R. Allphin, IPC
Page 3 of6
Idaho Power Company
Renewable Energy Contracts list
PURPA PROJECTS UNDER CONTRACT NOT YET ONLINE
Fae1il!Y_ ! Pro ectS1ze Estimated
Pro eel Number T-e Pro eel Name State ' Count , MW- -- 0 erat1�-D�te
25586937 Solar American Falls Solar II, LLC ID Power 20.00 12/1/2016
25591644 Solar American Falls Solar, LLC ID Power 20.00 12/1/2016
25088520 Solar Boise City Solar, LLC ID Ada 40.00 1/1612016
25244913 Solar Clarie Solar 1, LLC ID Elmore 71.00 12/31/2016
25253149 Solar Clarie Solar 2, LLC ID Elmore 20.00 12/31/2016
25261336 Solar Clarie Solar 3, LLC ID Elmore 30.00 12/31/2016
25289173 Solar Clarie Solar 4, LLC ID Elmore 20.00 12/31/2016
12616100 Solar Grand View PV Solar Two ID Elmore 80.00 9/1/2016
12727358 Solar Grove Solar Center, LLC OR Malheur 10.00 12/31/2016
12739324 Solar Hyline Solar Center, LLC OR Malheur 10.00 12/31/2016
25031625 Solar Mountain Home Solar, LLC ID Elmore 20.00 12/31/2016
25524198 Solar Murphy Flat Power, LLC ID Owhyee 20.00 12/1/2016
12705219 Solar Open Range Solar Center, LLC OR Malheur 10.00 12/31/2016
25573998 Solar Orchard Ranch Solar, LLC ID Ada 20.00 12/1/2016
25075329 Solar Pocatello Solar 1, LLC ID Power 20.00 12/31/2016
12741175 Solar Railroad Solar Center, LLC OR Malheur 10.00 12/31/2016
25580735 Solar Simco Solar, LLC ID Elmore 20.00 12/1/2016
12745920 Solar Thunderegg Solar Center, LLC OR Malheur 10.00 12/31/2016
12719362 Solar Vale Alr Solar Center, LLC OR Malheur 10.00 12/31/2016
Total Soler Projects: 19 461.00
20140708 Hydro Black Canyon Bliss Hydro ID Gooding 0.03 11/15/2014
20140601 Hydro Clarie Canyon Hydroelectric MT Beaverhead 7.55 6/1/2017
20140328 Hydro Head of U Canal Project ID Jerome 1.28 5/1/2015
31515110 Hydro Little Wood River Ranch II ID Shoshone 1.25 6/1/2015
Total Hydro Projects: 4 10.11
12618240 Wind Benson Creek Windfarm OR Baker 10.00 12/31/2016
12618230 Wind Durbin Creek Windfarm OR Baker 10.00 12/31/2016
12618220 Wind Jett Creek Windfarm OR Baker 10.00 12/31/2016
12618210 Wind Prospector Windfarm OR Baker 10.00 12/31/2016
12618245 Wind Willow Spring Windfarm OR Baker 10.00 12/31/2016
Total Wind Projects: 5 50.00
Exhibit No. 2
Case No. IPC-E-15-01
R. Allphin, IPC
Page 4 of6
Idaho Power Company
Renewable Energy Contracts List
OregonSolar PROJECTS ONLINE
1�1 . 'ProectS-e
Pro eel Number' T e Pro ect Name State Count, r-.tw I
90001311 OR Solar 7 kW Shaffer Solar OR Malheur 0.01
90001416 OR Solar Chamberlain Dairy OR Malheur 0.01
90001413 OR Solar Chamberlain House OR Malheur 0.01
90000028 OR Solar Cliff and Pat Looney OR Malheur 0.01
90000005 OR Solar Clinton Kennington OR Malheur 0.01
90000079 OR Solar Dean Mackey_79 OR Malheur 0.01
90000025 OR Solar Findley Family Trust - Findley Land and OR Malheur 0.01 Livestock
90000075 OR Solar Findley Land and Llvestock_75 OR Malheur 0.00
90000081 OR Soiar �i'!_dley L!nd �nd Uvestock_81 .. OR Malheur 0.00
90000006 OR Solar Gary Taylor_06 OR Malheur 0.01
90000003 OR Solar Gordon D. Luther_03 OR Malheur 0.01
90000007 OR Solar Gordon Dale Luther_07 OR Malheur 0.01
90000077 OR Solar Jason Peters_77 OR Malheur 0.01
90001301 OR Solar Jensen Farms LLC_1301 OR Malheur 0.00
90001302 OR Solar Jensen Farms LLC_1302 OR Malhuer 0.01
90001303 OR Solar Jensen Farms LLC_1303 OR Malheur 0.01
90001307 OR Solar Jensen Farms LLg_1307 OR Malhuer 0.00
90001310 OR Solar Jensen Farms LLC_1310 OR Malheur 0.01
90000043 OR Solar Jensen Farms LLC_ 43 OR Malheur 0.01
90000045 OR Solar Jensen Farms LLC_ 45 OR Malheur 0.01
90000046 OR Solar Jensen Farms LLC_ 46 OR Malheur 0.01
90000047 OR Solar Jensen Farms LLC_ 47 OR Malheur 0.01
90000048 OR Solar Jensen Farms LLC_ 48 OR Malheur 0.01
90000050 OR Solar Jensen Farms LLC_SO OR Malheur 0.01
90000052 OR Solar Jensen Farms LLC_52 OR Malheur 0.01
90000054 OR Solar Jensen Farms LLC_54 OR Malheur 0.01
90000056 OR Solar Jensen Farms LLC_56 OR Malheur 0.01
90000057 OR Solar Jensen Farms LLC_57 OR Malheur 0.01
90000060 OR Solar Jensen Farms LLC_60 OR Malheur 0.01
90000076 OR Solar Jensen Farms LLC_76 OR Malheur 0.01
90000044 OR Solar Kenneth Jensen_ 44 OR Malheur 0.01
90001306 OR Solar Malheur County Fairgrounds #1 OR Malheur Q.01
90001313 OR Solar Malheur County Fairgrounds #2 OR Malheur 0.01
90001315 OR Solar Malheur County Fairgrounds #3 OR Malheur 0.01
90000073 OR Solar Mark Wettstein_73 OR Malheur 0.01
90000088 OR Solar Mark Wettstein_88 OR Malheur 0.01
90001414 OR Solar Michael McGourty OR Malheur 0.01
90001312 OR Solar Onion Storage_1312 OR Malheur 0.01
90000063 OR Solar Ontario City Hall_63 OR Malheur 0.01
90000072 OR Solar Ontario Golf Clubhouse_72 OR Malheur 0.01
90000062 OR Solar Ontario Public Works Shop_62 OR Malheur 0.01
90000059 OR Solar Ontario WTP East Bldg_59 OR Malheur 0.01
90000055 OR Solar Ontario WTP West Ponds_55 OR Malheur 0.01
90000080 OR Solar Ontario WWTP Aerators_80 OR Malheur O.o1
90000084 OR Solar Ontario WWTP Building_84 OR Malheur 0.01
90000086 OR Solar Ontario WWTP Lift Station_86 OR Malheur 0.01
90000051 OR Solar Pine Eagle High School OR Baker O.o1
90000064 OR Solar Pine Eagle Middle School OR Baker 0.01
90000078 OR Solar Pine Eagle Pump Station OR Baker 0.01
90000001 OR Solar Randy Bauer OR Malheur 0.01
90000067 OR Solar Robert Mairs_67 OR Malheur 0.01
90000002 OR Solar Roger Findley OR Malheur 0.01
90000061 OR Solar Roger Findley_61 OR Malheur 0.01
90001309 OR Solar Schuster OR Malheur 0.01
90000004 OR Solar Treasure Valley Community College OR Malheur 0.01
Total OR Solar Projects: 55 0.42
Exhibit No. 2
Case No. IPC-E-15-01
R. Allphin, IPC
Page 5 of6
Idaho Power Company
Renewable Energy Contracts List
OregonSolar PROJECTS UNDER CONTRACT NOT YET ONLINE - �' , ProectS ·e
T e Pro ect Name State Count· \1'// 1
90001412 OR Solar
90001411 OR Solar
90001415 OR Solar
90001410 OR Solar
90001417 OR Solar
Total OR Solar Projects: 5
Clark - 5th Ave Pivot
Clark - 6th Ave Rental
Clark - Jake's House
Clark - New Hoose
Jackie Hansen
OR
OR
OR
OR
OR
Malheur
Malheur
Malhuer
Malheur
Malheur
0.00
0.01
0.01
0.01
0.01
0.04
Non PURPA PROJECTS ONLINE ·�
Pro eel Number: T e 1 ' , Pro•ectS1:"e
Pro eel Name I State I Count MW
10000003 Geothermal Neal Hot Springs Unit #1 OR Malheur 22.00
10000002 Geothermal Raft River Unit #1 ID Cassia 13.00
Total Geothermal Projects: 2 35.00
10000001 Wind Elkhorn Wind Project OR Union 100.65
Total Wind Projects: 1 100.65
Exhibit No. 2
Case No. IPC-E-15-01
R. Allphin, IPC
Page 6 of6
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 3
2
3
4
s
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
:·<i: ��,:,- �l - . ··- ldlllo ,_, ColllfN, ,c\ . N; '- J¥ Propoted PUIU'A Wlr • Al ot -..ry 2Q, 201.5
,.t_ � ' J I Illa
Term Estlm1ted Estlm1ted Obllc1tlon Estlm1ted 2 Ye1r
Project N1me Pro)ect Developer MWIC (YHrs) St1te Oper1tlon (Includes lntqr1tlon) Obllcltlon (!ncluaes
01te inte-tlonl
Project Al Developer A 80 20 Idaho 12/01/16 $194,097, 773 $9,903,565
Project A2 Developer A 28 20 Idaho 12/01/16 $67,364,680 $3,418,565
Project A3 Developer A 30 20 Idaho 12/31/16 $58,638,038 $2,561,512
Project A4 Developer A 30 20 Idaho 12/31/16 $57,091,198 $2,435,210
Project 81 Developer B 20 20 Idaho 10/30/16 $48,117,629 $2,441,832
Project 82 Developer B 20 20 Idaho 10/30/16 $47,758,118 $2,413,450
Project Cl Developer C 20 20 Idaho 12/31/16 $53,382,246 $2,318.923
Project C2 OeveloperC 20 20 Idaho 12/31/16 $53.283,030 $2,337,229
Project C3 OeveloperC 20 20 Idaho 12/31/16 $49,203,964 $2,150,196
Project C4 OeveloperC 20 20 Idaho 12/31/16 $49,360,962 $2,148,558
Project CS OeveloperC 20 20 Idaho 12/31/16 $48,760,343 $2.084,643
Project C6 OeveloperC 20 20 Idaho 12/31/16 $51,486,568 $2,208,705
Project C7 OeveloperC 20 20 Idaho 12/31/16 $51,493, 788 $2,178,763
Project C8 OeveloperC 20 20 Idaho 12/31/16 SSl,355,246 $2,169,541
Project C9 Developer C 20 20 Idaho 12/31/16 $51,797,624 $2,148,386
Pro)ectClO OeveloperC 20 20 Idaho 12/31/16 $48,438,230 $2,048,049
Project 01 OeveloperO 6 20 Idaho 12/31/16 $13,450,419 $652,511
Project 02 Developer O 7.5 20 Idaho 12/31/16 $16,813,024 $815,639
Project 03 OeveloperO 10 20 Idaho 12/31/16 $22,417,366 $1,087,519
Project 04 OeveloperO 10 20 Idaho 12/31/16 $22,417,366 $1,087,519
Project El Developer E 13 20 Idaho 12/31/16 $29,142,575 Sl,413,775
Project E2 Developer E 20 20 Idaho 12/31/16 $44,834,731 $2,175,038
Project E3 Developer E 13 20 Idaho 12/31/16 $29,142,575 $1,413,775
Project E4 Developer E 20 20 Idaho 12/31/16 $44,077,867 $2,113,543
Project ES Developer E 20 20 Idaho 12/31/16 $43,264,238 $2,047,317
Project E6 Developer E 20 20 Idaho 12/31/16 $43,264,238 $2,047,317
Project E7 DeveloperE 20 20 Idaho 12/31/16 $43,264,238 $2,047,317
Project ES Developer E 20 20 Idaho 12/31/16 $43,264,238 $2,047,317
Project E9 Developer E 20 20 Idaho 12/31/16 $42,356,002 Sl,972,577
Project ElO OeveloperE 20 20 Idaho 12/31/16 $41,372,078 $1,893.106
Project Ell Developer E 20 20 Idaho 12/31/16 $41,372,078 $1,893,106
Project El2 Developer E 13 20 Idaho 12/31/16 $26,891,851 51,230,519
Project Fl Developer F 70 20 Idaho 12/31/16 $138,908.196 $6,145,736
Project Gl OeveloperG 3 20 Idaho 12/31/16 $5,863,804 $256,151
Project Hl OeveloperH 1 20 Idaho 12/31/16 $1,818,839 $74,315
Project 11 Developer I 20 20 Idaho 12/31/16 $36,376,776 $1,486,292
Subtotal 755 $1,711,941,939 $71,167,.516
Exhibit No. 3
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of2
37
38
39
40
41
42
43
44
45
46
47
48
� -. .... � -. .. .. �- - ldmllo ,__ Comtllny .. ·-
PropoMd PUIIPA Soll,· Aa of ,-,.,Y 20, 2015
.. Qlm!l
Term Scheduled Estimated Obll1atlon Estimated 2 Year
Project Name Project Developer MWac State Operation Obllcatlon (Includes (Yun) Date (lndudes lnte1ratlon) lnteirntlonl
Project J1 Developer J 10 20 Oregon 06/15/16 $30,282,970 $2,004,849
Project E13 Developer E 20 20 Oregon 12/31/16 $41,372,078 $1,893,106
Project Kl Developer I( 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project K2 Developer I( 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project K3 Developer I( 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project K4 Developer I( 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project KS Developer K 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project K6 Developer K 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project K7 Developer K 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project KS Developer K 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project K9 DeveloperK 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Project KlO Developer K 10 20 Oregon 12/31/16 $31,889,203 $2,084,319
Subtotal 130
Total us
$390,547,0IO
$2,102,489,01.9
$24,741,148
$103,608,664
Exhibit No. 3
Case No. IPC-E-15-01
R. Allphin, IPC
Page 2 of2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 4
l • 5
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Exhibit No. 4
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 5
EXHIBIT
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l � � t i � � t � i l 0 � CO � � � � � N � ... (4MW) ASJall] aiqeM3U;)ij Aq pa,1ddns (4MW) peo, l!l?l3� j0%
Exhibit No. 5
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 6
Idaho Power Company
Estimated Load, Must run Resources, Utility PPAs and PURPA
Calendar Years of 2016 and 2017
17,544 Hours
Total hours in
2016 and 2017
14%
2,492 Hours
PPAs
..
S,UO.._.
33%
5,709 Hours
plus all PURPA under
contract (including
solar)
Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of25
.. ... 0 N ... ·
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 2 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 3 of25
t "' c� .... < I .. :; 0.. 0 0 l: 0.. -i, v s -e .. ;-s "" i ... <( l .. c ;: .. I- �� � "' ;: � 3 i ::, e :g 0.. "C ::, � � .... � 0 • Q " ] � �1 � 3: 'i 3= l& "C .... 'Q .. ,. � < -e ,( ::. 0 0 ... 0.. c:. ::, 0 :e ..,
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 4 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 5 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 6 of 25
... ... 0 N ... · 8 g g 8 8 8 0 c
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 7 of25
... ... 0 .... ... - 8 s 0 0 0 0 0 8 o� 0 0 0 0 0 0 "' o. "' o. "' 0 .. .,- .. ... ,.; ... ... ...
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 8 of25
... .. 0 N ...;
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 9 of25
g
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 10 of 25
... ... 0 1--�������������+-�....:::,._����+-�===-���+-�����-4}
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 11 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 12 of 25
... ... 0 N .....
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 13 of 25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 14 of 25
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Exhibit No. 6
Case No. lPC-E-15-01
R. Allphin, IPC
Page 15 of 25
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Exhibit No. 6
Case No. lPC-E-15-01
R. Allphin, IPC
Page 16 of25
..... ... 0 N .;
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 17 of 25
., �· � -e c( � e ; 0 :. .. ... ... v ... 0 § -e .. i; "' j � < e ... .. � ] .., "' .; � � � s = e: � "" ... ::. i I ::, :, .... Q 0 Q 1 � Cf -e ... 3¥ :0: :: � .,, .,. .. ::, . .. s s < c( < :; 0 0 ... ... la. - :) 0 -a .., a, r "' 3 " . 0 0 :) :) "5 ..., v� ..,
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, I PC
Page 18 of 25
.... ... 0 N ...
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 19 of25
... .. 0 N .. · 0 0 8 0 0 0 0 g 0;; 0 0 0 0 0 0 .... o. "' 0 "' 0 "' 0 ... " ,.; wi ... N• ... .s
MVII
... "' =l l -e < e :. ,. .. .... g.., ... 0 � .., .. ;o "" i .... < . : :!: .. � ... J:; � Ii) � :. 5 .i :, - '° t .... ... � - '° a - • .... :, Cf� 0 i ,:: ?: ... 3] "3 lS � ii 'O .,. • :; .. -e -c -c :; :; 0 0 .,.! ... .... ... o� ,J a:: ! �� 0 0 :i :, v v;,r; ,J ... .... ... "' s. la ;. • I I I I - 3: �
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 20 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 21 of 25
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Exhibit No. 6
Case No. IPC-E-15·01
R. Allphin, IPC
Page 22 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 23 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 24 of25
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Exhibit No. 6
Case No. IPC-E-15-01
R. Allphin, IPC
Page 25 of25
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 7
T
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Exhibit No. 7
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 8
Approved Net Power Supply Expense In Base Rates (Normalized)
2010
FERC Account Expense Energy $/MWh
Account 501, Coal $ 167,718,084 7,169,601.0 $ 23.39
Account 547, Gas $ 6,062,472 42,552.4 $ 142.47
Account SSS, Purchases (Non-PURPA) $ 66,689,601 1,110,756.0 $ 60.04
Account 555, Purchases (PURPA) $ 62,851,454 1,043,642.0 $ 60.22
Account 447, Surplus Sales $ (92,642,114) (2,755,646.4) $ 33.62
2012
FERC Account Expense Energy $/MWh
Account 501, Coal s 167,192,744 7,145,609.2 s 23.40
Account 547, Gas $ 51,934,201 1,176,351.8 $ 44.15
Account 555, Purchases (Non-PURPA) $ 45,510,093 763,793.1 $ 59.58
Account SSS, Purchases (PURPA) $ 62,851,454 1,043,642.0 $ 60.22
Account 447, Surplus Sales s (124,916,153) (3,518,491.2) $ 35.50
2013
FERC Account Expense Energy $/MWh
Account 501, Coal $ 108,503,180 4,759,957.7 $ 22.79
Account 547, Gas $ 33,367,563 993,970.8 $ 33.57
Account SSS, Purchases (Non-PURPA) $ 62,606,593 1,236,373.4 $ 50.64
Account SSS, Purchases (PURPA) $ 133,853,869 2,141,849.4 s 62.49
Account 447, Surplus Sales $ (51,735,153) (2,309,046.6) s 22.41
Note: Account 547, Gas $/MWH 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 COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 9
EXHIBIT
I � .
Idaho Power Company
PURPA Solar projects under contract - As of January 20, 2015
Idaho --- -
scheduled
Term Operation Estimated Obligation Estimated 2 year Obligation
Project Name MWac (Years) State Date (includes Integration) (Includes Integration)
Grandview PV Solar Two, UC 80 20 Idaho 09/01/16 $312,729,719 $21,365,030
Boise City Solar, LLC 40 20 Idaho 01/01/16 $156,299,294 $10,345,907
Mountain Home Solar, LLC 20 20 Idaho 12/31/16 $79,877,543 $4,310,801
Pocatello Solar 1, LLC 20 20 Idaho 12/31/16 $74,712,956 $4,055,563
Clark Solar 1, LLC 71 20 Idaho 12/31/16 $243,227,312 $12,752,964
Clark Solar 2, UC 20 20 Idaho 12/31/16 $69,246,830 $3,705,030
Clark Solar 3, UC 30 20 Idaho 12/31/16 $102,774,966 $5,464,983
Clark Solar 4, UC 20 20 Idaho 12/31/16 $67,990,610 $3,633,830
Murphy Flat Power, LLC 20 20 Idaho 12/01/16 $69,184,146 $2,860,894
Simco Solar, LLC 20 20 Idaho 12/01/16 $69,951,245 $2,887,904
American Falls Solar, LLC 20 20 Idaho 12/01/16 $65,313,902 $2,621,813
American Falls Solar II, LLC 20 20 Idaho 12/01/16 $62,494,248 $2,378,384
Orchard Ranch Solar, LLC 20 20 Idaho 12/01/16 $65,605,413 $2,531,995
Subtotal 401 $1,439,408,185 $78,915,098
Ore2on -
Scheduled
Term Operation Estimated Obligation Estimated 2 year Obligation
Project Name MWac (Years) State Date (Includes Integration) (Includes Integration)
Grove Solar Center, LLC 10 20 Oregon 12/31/16 $37,638,450 $2,319,889
Hyline Solar Center, LLC 10 20 Oregon 12/31/16 $37,638,450 $2,319,889
Open Range Solar Center, UC 10 20 Oregon 12/31/16 $37,638,450 $2,319,889
Railroad Solar Center, LLC 10 20 Oregon 12/31/16 $37,638,450 $2,319,889
Thunderegg Solar Center, UC 10 20 Oregon 12/31/16 $37,638,450 $2,319,889
Vale Air Solar Center, LLC 10 20 Oregon 12/31/16 $37,638,450 $2,319,889
Subtotal 60 $225,830,701 $13,919,334
Total 461 $1,665,238,886 $92,834,432
Exhibit No. 9
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
IDAHO POWER COMPANY
ALLPHIN, DI
TESTIMONY
EXHIBIT NO. 10
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Exhibit No. 10
Case No. IPC-E-15-01
R. Allphin, IPC
Page 1 of 1
Idaho Power Company
PURPA Solar projects under contract - As of JaAwary :.lO, :.101, April 22, 2015
Idaho
'
Scheduled
Tenn Oper•tlon Estlm•ted Obll&•tlon (lndudes Estl�ted 2 ve•r Obll1•tlon
Project N•me MW•c (Yurs) Sute O.te lntear•tlon) (lndudes lntaratlon)
Grandview PV Solar Two, LLC 80 20 Idaho 09/01/16 $312,729,719 $21,365,030
Boise City Solar, LLC 40 20 Idaho 01/01/16 $156,299,294 $10,345,907
Mountain Home Solar, LLC 20 20 Idaho 12/31/16 $79;877,543 $4,310,801
Pocatello Solar 1, LLC 20 20 Idaho 12/31/16 $74,712,956 $4,055,563
QaFk §elaF 1, bl,� +l � � 1;!1t,Ufli $;!43,;!;!7,31;! $U17§;!19i4
�laFk §elaF ;!, bb� � � � l;!f31�1i $i9,;!4i,83Q $3,:;IQ§,Q3Q
QaFk §elaF 3, bb� � � � l;!f31Jli $1Q;!,n4,9ii $§,4i4,983
�laFk §elaF 4, bb� � � � l;!f3llli $i:;1199Q,UQ $3,i33,83Q
Murphy Flat Power, LLC 20 20 Idaho 12/01/16 $69,184,146 $2,860,894
Simco Solar, LLC 20 20 Idaho 12/01/16 $69,951,245 $2,887,904
American Falls Solar, LLC 20 20 Idaho 12/01/16 $65,313,902 $2,621,813
American Falls Solar II, LLC 20 20 Idaho 12/01/16 $62,494,248 $2,378,384
Orchard Ranch Solar, LLC 20 20 Idaho 12/01/16 $65,605,413 $2,531,995
Subtot.1 � 260 $1,0!MOll,lili $956,168,465 $7111915,0YII $53,358,291
Ore12n
Scheduled
Tenn Oper.tlon Estlm•ted Obll1•tlon (lndudes Estlm•t.ed 2 yur Obllptlon
Project N•me MWu (Yurs) Sute D•t• lntearmtlon) (lndudes lntesr-tlon)
Grove Solar Center, LLC 10 20 Oregon 12/31/16 $37,i38,4§Q $37,662,243 $2,319,889 $2,321,359
Hyline Solar Center, LLC 10 20 Oregon 12/31/16 $37,i38,4§Q $37,662,243 $2,319,889 $2,321,359
Open Range Solar Center, LLC 10 20 Oregon 12/31/16 $37,i38,4§Q $37,662,243 $2,319,889 $2,321,359
Railroad Solar Center, LLC 10 20 Oregon 12/31/16 $371i38, 4§Q $37,662,243 $2,319,889 $2,321,359
Thunderegg Solar Center, LLC 10 20 Oregon 12/31/16 $37,i38,4§Q $37,662,243 $2,319,889 $2,321,359
Vale Air Solar Center, LLC 10 20 Oregon 12/31/16 $37,i38,4§Q $37,662,243 $2,319,889 $2,321,359
Subtot•I 60 $;1;11i,8i0,700 $225,973,458 $U,8191ii4 $13,928,154
Tot.I � 320 $1,iii,;lill,a&i $1,182,141,923 $9;1,lli4,4i;I $67,286,445
Exhibit No. 11
ase Nos. IPC-E-15-01
AVU-E-15-01
PAC-E-15-03
R. Allphin, IPC
Page 2 of4
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sneMe3aw Exhibit No. 11
Case Nos. IPC-E-15-01
AVU-E-15-01
PAC-E-15-03
R. Allphin, IPC
Page 1 of'4
'
1
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
Subtotal � 1,081 u.1u,eu,eae $1,969,960,no ,11,•1.u, $94,140,101 Exhibit No. 11 Case Nos. IPC-E-15-01
AVU-E-15-01
PAC-E-15-03 R. Allphin, IPC
Page 3 of4
..,..,-c.......,
l'NlpaNd WASolmr·AI afJaAWU'I' 20, lOlli April 22, 2015
1111111
Te,m Estil'lletecl EstltMtad Obllptlon (lnducles &tiffletH J YNr Obllptlon l"nlject N•me l"nlject� MWK (YNrs) Sula Opentlon l11t-.,•tlcM1) (lndudes lfacmlon) 08te
Project Al Developer A 80 80 20 Idaho 12/01/16 ,u14,gg7,;i;ia $213,159,625 $9,!l!B,§i!i $9,052,344
Project A2 Developer A 28 28 20 Idaho 12/01/16 ,,.i,,Hi4,'8Q $62,482,130 U,U8,§i!i 52,843,0n
Project A3 Developer A 30 30 20 Idaho 12/31/16 ua.,.ia,o.a $40,316,768 ,u.uu $2,110,838
Project M Developer A 30 30 20 Idaho 12/31/16 $§7,091,1911 $40,316,768 ,�.4il§,UQ $2,110,838
Project Bl Developer 8 20 20 20 Idaho 10/30/16 $411,U;t,i� $48,378,647 .�.441,llil� $2,408,124
Project 82 Developer 8 20 20 20 Idaho 10/30/16 ,47,:;t§ll,UB $45,549,075 ,�.413,4§9 52,2n,533
Project 83 Developer B 20 5 Idaho 12/31/16 $42,588,215 52,059,783
Project 84 Developer B 20 5 Idaho 12/31/16 $42,415,239 52,053,467
Project BS Developer B so 5 Idaho 12/31/16 5103,750,045 $4,820,801
Project 86 Developer B 40 5 Idaho 12/31/16 $80,232,480 $3,666,449
Project Cl Developer C 20 20 20 Idaho 12/31/16 $53,382,246 $53,312,.246 52,318,923 $2,318,923
Project C2 Developer C 20 20 20 Idaho 12/31/16 $53,283,030 $53,213,030 52,337,229 $2,337,229
Project C3 Developer( 20 20 20 Idaho 12/31/16 $49,203,964 $49,203,964 $2,150,196 $2,150,196
Project C4 Developer( 20 20 20 Idaho 12/31/16 $49,360,962 $49,360,962 $2,148,558 $2,148,558
Project CS OeveloperC 20 20 20 Idaho 12/31/16 $48, 760,343 $48,760,343 52,084,643 $2,084,643
Project C6 Developer( 20 20 20 Idaho 12/31/16 $51,486,568 $51,486,561 $2,208,705 $2,208,705
Project C7 Developer( 20 20 20 Idaho 12/31/16 $51,493,788 $51,493,788 $2,178,763 $2,178,763
Project ca Developer( 20 20 20 Idaho 12/31/16 $51,355,246 $51,355,246 $2,169,541 $2,169,541
Project C9 Developer C 20 20 20 Idaho 12/31/16 $51,797,624 $51,797,624 $2,148,386 $2,148,386
Project ClO Developer( 20 20 20 Idaho 12/31/16 $48,431,230 $41,431,230 $2,048,049 $2,048,049
Project 01 Developer O 6 6 20 Idaho 12/31/16 $.a,4!iQ,09 $8,063,354 � $422,168
Project 02 Developer O 7.5 7.5 20 Idaho 12/31/16 Ui,Hil,0�4 $10,079,192 � 5527,709
Project 03 Developer O 10 10 20 Idaho 12/31/16 ,ii,o;i,a" 514,413,193 UQ8:;t1§MI $810,279
Project 04 Developer O 10 10 20 Idaho 12/31/16 ,��.4 i.i,.i&i $14,412,285 $19117,&MI $806,685
Project OS Developer D 10 20 Idaho 12/31/16 S19,3n,901 $1,001,813
Project 06 Developer D 10 20 Idaho 12/31/16 $18,700,526 $968,550
Project El Developer E 13 13 20 Idaho 12/31/16 $�9,10,§+' $17,470,600 U,4l3,:;i;i!i $914,696
Project E2 Developer£ 20 20 20 Idaho 12/31/16 $44,n4,+i11 $26,877,846 ,�,l+!i,Qil8 $1,407,225
Project E3 Developer E 13 13 20 Idaho 12/31/16 .�,14�.,;i, $17,470,600 U,U.l,;l;l!i $914,696
Project E4 Developer E 20 20 20 Idaho 12/31/16 $44,Q++,lli+ $26,8n,846 $i,1H,&4il $1,407,225
Project ES Developer E 20 20 20 Idaho 12/31/16 $43,�i4,�i18 $26,877,846 ,�,oo,ai;i: $1,407,225
Project E6 Developer E 20 20 20 Idaho 12/31/16 $4i,�i4,�a& $26,877,846 $�.04+,U+ $1,407,225
Project E7 Developer E 20 20 20 Idaho 12/31/16 $4i.�i4,�il8 $26,877,846 ,�.oo,u;i: 51,407,225
Project EB Developer E 20 20 20 Idaho 12/31/16 $4il.�i4,�il8 $26,877,846 ,a41,U+ $1,407,225
Project E9 Developer E 20 20 20 Idaho 12/31/16 •4�,a§i,QQ� $26,877,846 U97H;i:;t $1,407,225
Project ElO Developer E 20 20 20 Idaho 12/31/16 ,u,a1i,01a S26,an,846 U119il,10i 51,407,225
Project Ell Developer E 20 20 20 Idaho 12/31/16 ,o,a;i;i,o;i:a $26.877,846 Ull!lHOi $1,407,225
Project El2 Developer E 13 13 20 Idaho 12/31/16 Ui,891,IIU $17,470,600 o �.o,,w 5914,696
Project Fl Developer F 70 70 20 Idaho 12/31/16 ua11,11oa,.9, $94,072,460 ,,.us,::i.i, $4,925,289
Project Gl Developer G 3 3 20 Idaho 12/31/16 s,.au,104 54,031,6n � $211,084
Project Hl Developer H l l 20 Idaho 12/31/16 $1,UB,Bi!l 51,343,892 � $70,361
Project 11 Developer I 20 20 20 Idaho 12/31/16 ,a,.a1,,;i:;i, $26,877,846 0 48'.�!I� $1,407,225
Project Ll Developer L 28 20 Idaho 12/31/16 $3 7,628,984 51,970,115
Pro1ect L2 Developer l 28 20 Idaho 12/31/16 $37,628,984 $1,970,115
Project L3 Developer l 80 20 Idaho 12/31/16 5107,511,382 $5,628,901
Pro1ect 01 OeveloperO 20 20 Idaho 12/31/16 $26,877,846 $1,407,225
Pro1ect 02 DeveloperO 20 20 Idaho 12/31/16 S26,8n,846 $1,407,225
48
49
so
51
52
53
54
SS
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
... ,_ Compeny
,n,posed PUii,,. Soler- As of laAuuy :zo, :Z01i April 22, 2015
2lm!!
Term ScMdillH Estimated Obllption (Includes EstifNtN l Ynr Ollliptlon 'roJ«t N1me ,roi-ct Developer MWIC (YHrs) StMe Opemion lnt«lfltlOn) (lnducles lntecntlon) Date
Project Jl Developer J 10 10 20 Ore1on 06/15/16 ,�o.�e�.!l+O $30,325, 795 s�.004,84!1 $2,008,461
Project E13 Developer E 20 20 20 Oregon 12/31/16 $0,H�.078 $26,877,846 $U!l�.10, $1,407,225
Project Kl Developer I( 10 10 20 Ore1on 12/31/16 $U,889.�0� $31,934,668 $�,084,U!I $2,186,583
Project 1(2 Developer K 10 10 20 Or econ 12/31/16 ,�1.88!1,�oa $31.934,668 $�.08Ul!I $2,186,583
Project K3 Developer K 10 10 20 Oregon 12/31/16 $U,889.�Q; $31,934,668 ,�.084,il!I $2,186,583
Project K4 Developer K 10 10 20 Oree on 12/31/16 $H,889.�0a $31,934,668 R084,,U9 $2,186,583
Project KS Developer K 10 10 20 Oregon 12/31/16 $U,88!il,�Oa $31,934,668 $�.08Ul!I $2,186,583
Project K6 Developer K 10 10 20 Oregon 12/31/16 $U,889,�0a $31,934,668 $�.084,U!I $2,186,583
Project K7 Developer K 10 10 20 Oregon 12/31/16 $al,88!il.�O� $31,934,668 $�.08Ul!I $2,186,583
Project t<8 Developer K 10 10 20 Oregon 12/31/16 .�1.88!1,�0� $31,934,668 $�.084,U!I $2,186,583
Project K9 Developer K 10 10 20 Oregon 12/31/16 $a1,1111,;i.�oa $31,934,668 .�.084,il!I $2,186,583
Project KIO Developer K 10 10 20 Oregon 12/31/16 Ul.88!1,�oa $31,934.668 $� 084,U9 $2,186,583
Project Ml Developer M 5 20 Oregon 12/31/16 $15,967,334 $1,093,292
ProJect M2 Developer M 10 20 Oregon 12/31/16 $31,934,668 $2,186,583
Project M3 Developer M 10 20 Oregon 12/31/16 $31,934,668 $2,186,583
Pro1ect M4 Developer M s 20 Oregon 12/31/16 $15,967,334 $1,093,292
Project MS Developer M 10 20 Oregon 12/31/16 $31,934,668 $2,186,583
Pro1ect Nl Developer N 5 20 Oregon 12/31/16 $15,967,334 Sl,093,292
Project N2 Developer N 10 20 Oregon 12/31/16 $31,934,668 $2,186,583
Project N3 Developer N 10 20 Oregon 12/31/16 $31.934,668 $2,186,583
Proiect N4 Developer N 10 20 Oregon 12/31/16 $31,934,668 $2,186,583
Project NS Developer N 10 20 Oregon 12/31/16 $31,934.668 $2,186,583
Project N6 Developer N 10 20 Oregon 12/31/16 $31.934,668 $2,186,583
Proiect Pl Developer P 10 20 Oregon 12/31/16 $31,934,668 $2,186,583
Pro1ect Q1 Developer Q 5 20 Oregon 12/31/16 $15,967,334 $1,093,292
Project 02 Developer Q 5 20 Oregon 12/31/16 $15,967,334 Sl,093,292
Silbtotll uo 245 ueo,,o,oao $743,799,003 uvu,ua sso.421,m
Totll 885 1.326 U,10:z,411111018 $2,713,759,773 $10i,iOl,5'4 $144,567.331
Exhibit No. 11
Case Nos. IPC-E-15-01
AVU-E-15-01
PAC-E-15-03 R. Allphin, IPC
Page 4 of4
100
,,, 80 - 0 Cl) ·- 0 60 '- a..
It- 0 40 '- Cl) .c E 20 ::s z
0
Expiration of PURPA Contracts Over Time
I
l I I !
11 I ii I
I
111
I
I I � I I I I
Exhibit No. IO I
Case No. IPC-E-15-0 I
AVU-E-15-01
PAC-E-15-03
R. Sterling, Staff
4/23/15
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E-15-01, A VU-E-15-01, PAC-E-15-03
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBIT NO. 201
Don C. Reading
Present position Vice President and Consulting Economist
Educetion B.S., Economics; Utah State University
M.S., Economics; University of Oregon
Ph.d., Economics; Utah State University
Honors an
Profession
and busines
his to
Firm experieac
micron Delta Epsilon, NSF Fellowship
en Johnson Associates, Inc.:
1989 Vice President
1986 ---- Consulting Economist
Idaho Public Utilities Commission:
1981-86 Economist/Director of Policy and Administration
caching:
1980-81 Associate Professor, University of Hawaii-Hilo
1970-80 Associate and Assistant Professor, [daho State University
1968-70 Assistant Professor, Middle Tennessee State University
r. Reading provides expert testimony concerning economic and regulatory issues.
le has testified on more than 35 occasions before utility regulatory commissions in
Laska, California, Colorado, the District of Columbia, Hawaii, Idaho, Nevada, North
akota, North Carolina, Oregon, Texas, Utah, Wyoming, and Washington.
r. Reading has more than 35 years experience in the field of economics. He has
articipated in the development of indices reflecting economic trends, GNP growth
ates, foreign exchange markets, the money supply, stock market levels, and inflation.
e has analyzed such public policy issues as the minimum wage, federal spending an
ation, and import/export balances. Dr. Reading is one of four economists
roviding yearly forecasts of statewide personal income to the State of Idaho for
urposes of establishing state personal income tax rates.
n the field of telecommunications, Dr. Reading has provided expert testimony on th
issues of marginal cost, price elasticity, and measured service. Dr. Reading prepared a
tate-specific study of the price elasticity of demand for local telephone service in
daho and recently conducted research for, and directed the preparation of, a report t
e Idaho legislature regarding the status of telecommunications competition in that
1
Exhibit No. 20 I
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page I
r. Reading's areas of expertise in the field of electric power include demand
orecascing, long-range planning, price elasticity, marginal and average cost pricing,
roduction-simulation modeling, and econometric modeling. Among his recent case
as an electric rate design analysis for the Industrial Customers of [daho Power. Or.
eading is currently a consultant to the Idaho Legislature=s Committee on Electric
or the past three years Dr. Reading has been a consultant to Idaho Connects
n Line (ICON), a virtual charter school, providing data analysis and statistica
upport, In addition to building a model that replicated the [daho's Star Ratin
ystern he completed a study focused on the demographic and socioeconomi
haracteristics of the school's population and academic achievements. He is
urrently working with the measurement of ICON's Mission Specific goals fo
the 2014-2015 school year.
ince 1999 Or. Reading has been affiliated with the Climate Impact Group (CIG) at
e University of Washington. His work with the CIG has involved an analysis of
e impact of Global Warming oo the hydo facilities on the Snake River. It also
eludes an investigation into water markets in the Northwest and Florida. In
dditioo he has analyzed the economics of snowmaking for ski area's impacted by
lobal Warming.
ong Dr. Reading's recent projects are a FERC hydropower relicensing study (for
e Skokomish Indian Tribe) and an analysis of Northern States Power's North
akota rate design proposals affecting large industrial customers (for J.R. Simplot
ompany). Dr. Reading has also performed analysis for the ldaho Governor's Offic
f the impact on the Northwest Power Grid of various plans to increase salmon runs
the Columbia River Basin.
r. Reading has prepared econometric forecasts for the Southeast Idaho Council of
overnmeots and the Revenue Projection Committee of the Idaho State Legislature.
e has also been a member of several Northwest Power Planning Council Statistical
dvisory Committees and was vice chairman of the Governor's Economic Research
ouncil in Idaho
· eat [daho State Universiry, Dr. Reading performed demographic studies using
ohorr/survival model and several economic impact studies using input/output
nalysis. He has also provided expert testimony in cases concerning loss of income
esulcing from wrongful death, injury, or employment discrimination
r. Reading has recently completed a public interest water rights transfer case. He
as also just completed an economic impact analysis of the of the proposed Boulder
ire Clouds National Monument.
2
Exhibit No. 20 I
Case Nos. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 2
Publication 'Energizing Idaho", Idaho Issues Online, Boise State University, Fall 2006.
.boisestate.edu/history / issuesonline/ fall2006 _issues/ index. html
he Economic Impact of the 2001 Salmon Season Tn Idaho, Idaho Fish
nd Wildlife Foundation, April 2003.
he Economic Impact of a Restored Salmon Fishery in Idaho, ldaho Fish
d Wildlife Foundation, April, 1999.
e Economic Impact of Steelhead Fishing and the Return of Salmon
ishing in Idaho, Idaho Fish and Wildlife Foundation, September, 1997.
Cost Savings from Nuclear Resources Reform: An Econometric Model@
with E. Ray Canterbery and Ben Johnson) Southern Economic Journal, Sprin
1996.
Visitor Analysis for a Birds of Prey Public Attraction, Peregrine Fund,
nc., November, 1988.
nvestigat:i.on of a Capitalization Rate for Idaho Hydroelectric Projects,
daho State Tax Commission, June, 1988.
'Post-PURPA Views," In Proceedings of the NARUC Biennial Regulato
onference, 1983.
n Input-Output Analysis of the Impact from Proposed Mining in the
hallis Area (with R. Davies). Public Policy Research Center, Idaho State
niversity, February 1980.
bospbat« and Southeast: A Socio faonomit-Ana!Jsis (with J. Eyre, et al).
overnment Research institute of Idaho State University and the
outheast Idaho Council of Governments, August 1975.
stimating General Fund Rtvenues of the Stale of Idaho (with S. Ghazanfar and D.
olley). Center for Business and Economic Research, Boise State
niversity, June 1975.
"A Note on the Distribution of Federal Expenditures: An Interstate
ornparison, 1933-1939 and 1961-1965." In The American Economist,
ol. XVIII, o. 2 (Fall 1974), pp. 125-128.
"New Deal Activity and the States, 1933-1939." In Journal of Econormc
istoty, Vol. XXXIII, December 1973, pp. 792-810.
3
Exhibit o. 20 I
Case os. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 3
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E-15-01, A VU-E-15-01, PAC-E-15-03
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBIT NO. 202
§ 292.30 f Rata.:; tor purchases . I El C.F.R. � 2�l.3t!4
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
Part 292. Regulations Under Sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978
with Regard to Small Power Production and Cogeneration. (Refs & Annos)
Subpart C. Arrangements Between Electric Utilities and Qualifying Cogeneration and Small Power
Production Facilities Under Section 210 of the Public Utility Regulatory Policies Act of 1978 (Refs
&Annos)
18 C.F.R. § 292.304
§ 292.304 Rates for purchases.
Currentness
(a) Rates for purchases.
(I) Rates for purchases sh al I:
(i) Be just and reasonable to the electric consumer of the electric utility and in the public interest; and
(ii) Not discriminate against qualifying 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 of this paragraph, "new capacity" means any purchase from capacity of a qualifying facility, construction
of which was commenced on or after November 9, 1978.
(2) Subject to paragraph (b )(3) of this section, a rate for purchases satisfies the requirements of paragraph (a) of this section
if the rate equals the avoided costs determined after consideration of the factors set forth in paragraph (e) of this section
(3) A rate for purchases (other than from new capacity) may be less than the avoided cost if the 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 sufficient to encourage cogeneration and small
power production.
(4) Rates for purchases from new capacity shall be in accordance with paragraph (b)(2) of this section, regardless of
whether the electric utility making such purchases is simultaneously making sales to the qualifying facility.
WestlawNe;,:t
Exhibit o. 202
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page I
§ 292 J04 Rai.�s tor pu,·::hc1!;e,;., 18 c.r R. � 29t.Jl)4
(5) In the case in which the rates for purchases are based upon estimates of avoided costs over the specific term of the
contract or other legally enforceable obligation, the rates for such purchases do not violate this subpart if the rates for such
purchases differ from avoided costs at the time of delivery.
(c) Standard rates for purchases.
( 1) There shall be put into effect (with respect to each electric utility) standard rates for purchases from qualifying 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 I 00 kilowatts.
(3) The standard rates for purchases under this paragraph:
(i) Shall be consistent with paragraphs (a) and (e) of this section; and
(ii) May differentiate among qualifying facilities using various technologies on the basis of the supply characteristics of
the different technologies.
(d) Purchases "as available" or pursuant to a legally enforceable obligation. Each qualifying facility shall have the option either:
(I) To provide energy as the qualifying 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 qualifying 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. In determining avoided costs, the following factors shall, to the extent practicable,
be taken into account:
(I) The data provided pursuant to§ 292.302(b}, (c), or (d), including State review of any such data;
Westl,wvNext
Exhibit o. 202
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 2
� ·�o�.304 RaLs for 1J•111.:il:1<;-s., 18 c r.R. �. 2�� . .304
(2) The availability of capacity or energy from a qualifying facility during the system daily and seasonal peak periods,
including:
(i) The ability of the utility to dispatch the qualifying 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 qualifying facility can be usefully coordinated with scheduled outages
of the utility's facilities;
(v) The usefulness of energy and capacity supplied from a qualifying 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 qua Ii fying 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
faci Ii ties; and
(3) The relationship of the availability of energy or capacity from the qualifying facility as derived in paragraph (e)(2) of
this section, to the ability of the electric utility to avoid costs, including the deferral of capacity additions and the reduction
of fossil 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 qua Ii fying facility, if the purchasing electric utility generated an equivalent amount of energy itself or
purchased an equivalent amount of electric energy or capacity.
(t) Periods during which purchases not required.
(I) Any electric utility which gives notice pursuant to paragraph (t)(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 qualifying
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 of energy itself.
(2) Any electric utility seeking to invoke paragraph (t)( l) of this section must notify, in accordance with applicable State
law or regulation, each affected qualifying facility in time for the qualifying facility to cease the delivery of energy or
capacity to the electric utility.
W�stlawN;;:.:.: t
Exhibit o. 202
Case os. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 3
§ .l�'UO-l Rate,j ror purchas es , IS C.t=.H. § :wi.30 I
(3) Any electric utility which fails to comply with the provisions of paragraph (f)(2) of this section will be required to
pay the same rate for such purchase of energy or capacity as would be required had the period described in paragraph (t)
(I) of this 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
occurrence.
SOURCE: 44 FR 65746, Nov. 15, 1979; 45 FR 12234, Feb. 25, 1980; 50 FR 40358, Oct. 3, 1985; 52 FR 5280, Feb. 20, 1987;
52 FR 28467, July 30, 1987; 53 FR 15381, April 29, 1988; 53 FR 27002, July 18, 1988; 53 FR 40724, Oct. 18, 1988; 57 FR
21734, May 22, 1992; 60 FR 4856, Jan. 25, 1995, unless otherwise noted.
AUTHORITY: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.; Public Utility Regulatory Policies
Act of 1978, 16 U.S.C. 260 I et seq., Energy Supply and Environmental Coordination Act, 15 U.S.C. 791 et seq. Federal Power
Act, 16 U.S.C. 792 et seq., Department of Energy Organization Act, 42 U.S.C. 7101 et seq., E.O. 12009, 42 FR 46267.
Notes of Decisions ( 120)
Current through April 9, 2015; 80 FR 19036
l' "l ,•f ti,,, nt,
WestlavvNo=·xt
\ ; 11 \ h1l1l' 1 I{ ,ti t \ l,HI i t \ f<•11 11
Exhibit No. 202
Case Nos. IPC-E-15-0 I, A VU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page4
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E-15-01, A VU-E-15-01, PAC-E-15-03
J.R. SIMPLOT COMP ANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBIT NO. 203
12214 Federal Register / Vol: 45, No. 38 / Monday, February 25, 1980 /.Rules and Regulations
atnJctural £allure of the airframe, accomplish a comprehensive inspection of all areas modified by.The Raisbeck Group, as follo,vs:
A. Before further flight, Inspect for devlatioDJ Crom the supple.mental type design in accordance with Paragraphs I through IV, and VI. of PAA approved Raisbeck Service Bulletin No. 25. Inspect for discrepancies such as: ·
1. Pl11888d hole, 2.. Oblona. eggshaped, overalud. or Irregular holes 3. Tapered boles 4, Bxceaa holes 5. Inadequate edge distances 6.Cougn 7. lmP.roper fasteners (type and number) e. Improper clearances
9. Any other lm!gularitiea which are not conal,tent with standard aircraft practice. B. Before accumulation of 2,000 lllght hoW'S tlmo-ln·aervlce after modill.e&tion by STC SA087NW Inspect the horizontal stabilizer and elevator 1n accordance with Paragraphs V(A) and V(B) of FAA approved Raisbeck Service Bulletm No. 25. Repeat thls inspection at Intervals not exceec:Uni 5,000fllgbt hoW'I llmo-ln .. ervfce thereafter. C. Before accumulation of Z.000 night hours lime-ln·aervice af\ermodlficaUon by STC SA687NW or STC SA847NW, inapect the wing leadlng'l!dge ln accordance with Paragraph V(D) of PAA approved Raisbeck Service Bulletm No. 25. Repeat th1a Inspection at lnlenala not exceedh:is 5,000 flighthoun tlme-ln·•ervfce thereafter. ""· Before accumulaUon oft0,000 flight'
'I tlme·ln·aervlcd after modification by ..; SA887NW or STC SA847NW, Inspect the over\vins modifie&tlon In accordance with Paragraph V(C) of PAA approved Raisbeck Service Bulletm No. 25. Repeat th1a hispecUon al Intervals not exceeding 10.000 flight hourt lime·ln·serv&:e thereafter. E. lnspectiooa are to be conducted al facllltiea apecUically a'utborized by-the Chief, Engineering and Manufacturing Branch, FAA Northwest Region. 'F. Diacrepancles discovered as a result or the inspections are to be reported to the ·
Chief, Engineering and Manufactwins Branch. FAA Northwest Region. Repair or modifications required becauae of these problems are to.be FAA approved by the• Chief, Engineering and Manufacturing Branch. FAA. .Northwest Region or specifically authorized DERa. . G�Alrplanes may be [errled; In accordance with FAR 21.199, to a maintenance base. for the purpose of complying with this AD. H. 'Ibe Inspection, noted herein may be accomplished as noted or in a manner approved by the Chief, En.glneerlng and Manufacturing Branch. FAA. Northwest Region. L Areas previously inspected in . accordance with AmBlldment 39-3680'may be excluded from the inspections required bll Ibis AD. The manufacturer's specifications and procedures id.enUfied and de.scn'bed in thl.s directive are incorporated herein and made a ""rl hereof pursuant to 5 U.S.C. 552(a)(1). 11 persona afiected by this directive who
.! not already received these documents.
fro� the manufacturer, may obtain copies upon request to The Raisbeck Group, 7777 Perimeter Road, SeatUe, Washington 98106. : 'Ibis amendment becomes effective upon publication In the Federal Register and was effective earller to all recipients or the telegraphic AD TBO-NW-2 dated January 17,
1980.
(Secs. :tl3(i), 801, and 603, Federal Aviation Act of 1958. as amended (49 U.S.C.1354(a}. 14at, and 1423) and Section 6(c) of the. Department of Transportation A.cl (49 U.S.C. 1855(c)): and U CPR 11.89)
Note,-'Ibe FAA haa determined that this docwnent Involves a regulation whlch ls not considered to be significant under the provisions of ExecuUve Order 12044 and as implemented by Department of Transportation.Regulatory Policies.and Procedures (44 FR 11034: February 26, 1979).
Issued fn Seattle, Washington, on February
13, 1980.
Note,-'11ie Incorporation byreference provisions In the document were approved by the Director of Iba Federal Reglater on June
19, 1987,
C. B. Walle. Jr., Director. Northwest Region.
(flt Doo. lM838 flied s-a-«>: lt45 am)
81WHQ COO£ 4t10-1HI
OFflCE OF THE UNITED STATES TRADE REPRESENTATIVE
15 CFR Chapter XX
CFR Chapter Heading and Nomenclature Change
February 19, 1980.
AGENCY: Office of the United States . Trade Representative.
ACTIO�: Final rule.
,SUMMARY: This rule changes Chapter xx of Title 15, Code of Federal Regulations. · from "Office of the Special Representative for Trade Negotiations" , to "Office of the United States Trade Representative." Within the body of the Chapter XX. all �eferences to the "Office of the Special Representative for Trade Negotiations''. to the "Special · Representative for Trade Negotiations",
and to the "Special Representative" or "Deputy Special Representative" are changed to the "Office of the United States Trade Representative", to "the United States Trade Representative'.'. and the "Trade Representative" or "Deputy Trade Representative" respectively. These changes are authorized as part of Reorganization Plan No. 3 of 1979 (44 FR 69273) which was implemented by .Executive Order No. 12188 of January 2, 1980 (45 FR 989):
EFFECTIVE DATE: February 25, 1980.
FOR FURTHER INFORMATION CONTACT: Alice Zalik, General Council's Office, Office of the United States Trade
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 292
(Docket No. RM79·55, Order No. 69)
Small Power Production and
Cogeneratlon Faclllllea; Regulations Implementing Section 210 of tho Public Utlllty Regulatory Policies.Act of 1978 ' AGENCY: Federal Energy Regulatory Commission.
ACTION! Final rule.
SUMMARY: The Federal Energy Regulatory Commission boroby adopts regulations that Implement section 210 of the Public Utility Regulatory Policies Act of1978 (PURPA). The rulos require electric utilities to purchase electric power from and sell electric power lo qualifying cogeneratJon and small.powor production facllities, and provide for tho �xemption of qualifying facilities from certain federal and State regulation. Jmplemenlatlon of these rules Is reserved to Slate regulatory authorltles and nonregulated electric utilllies.
EFl'ECTIVE DATE: March 20, 1980,
FOR FURTHER INFORMATION CONTACT: Ross Ain. Office of the Genorol CounsuJ, Federal Energy Regulatory Commission, 825 North Capitol Slreot, N.E., Washington. D.C. 20426, 202-357-8446, John O'Sullivan, Office of tho General Counsel, Federal Energy Regulntory Commission. 825 North Capllol Strool, N.B .. Washington, D.C. 20420, 202-351-8477, Adam WeMer, Office or the Ganeral Counsel, Federal Energy Rogulutory Commission, 825 North Capitol Slroot, N,li .. Washington, D.O. 20426, 202-357-8033,
Represontotlve, 1800 G Strool, NW,, Washington, D.C. 20506, [phone],
.Accordingly, each reference to "tho Office of the Special Representative for Trade Negotiations" contulnod within Chapter XX of Title 15 of the Code or Federal Regulations, Including tho heading. Is changed to ''tho Office of tho United States Trade Representotlvo". · Bach reference to "the Spoclol Representative for Trade Negotiations" contained within the chapter ls changed to "the United States Trade Representative". Baoh reference to tho "Special Representative" and to tho "Deputy Special ReprosentoUve" rs changed to the 'Trade RepresEmtntlvo" and to the "Deputy Trade Representative" respectively.
Robert C. Cassidy,
General Counsel,
(FltDoc.�Flkdt�8:4Soa,J ,
BIWHO CODE 31to-oMl
Exhibit No. 203
Case Nos. IPC-E-15-0 I, A YU-E-15-0 l, PAC-E-15-03
D. Reading, Simplot/Clearwater
HeinOnline -- 45 Fed. Reg. 12214 1980 Page I
Federal Register / Vol. 45, No. 38 / Monday, February. 25, 1980 I Rules and Regulations
Many commepters at the · Commission's public hearings and in written comments recommended that the Commission should require the establishment of "net energy billing'.! for small qualifying facilities. Under this billlns method. the output from a ' qualifying facllity reverses the electric meter used to measm:e sales from the electric utility to the qualifybla facility. The Commlaslon believes that th.ls bllllns method may be an appropriate way of approximating 1lvoided cost in some circumstances, but does not believe that this is the only practical or appropriate method to establish rates for small qualifying facilities. The Commission observes that net energy billing is likely to be appropriate when the retail rates are marginal cost-baaed, time-of-day rates. Accordingly, the Commission will leave to the State regulatory authorities and the nonregulated electric utilities the determination as to whether to institute net energy billing. · Paragraph (c)(3)(i) provides that standard rates for purchase should take into account the factors set forth In paragraph (e). These factors relate to the quality of power from the qualifying fecllity, and its ability to fit into the purchasing uWity's generating mix. Paragraph (e)(vi) la of particular significance for facllities of100 kW or less. This paragraph provides that rates for purchase shall take into account "the individual and aggregate value of.energy and capacity from qualifying facilities on the electric utility's system •• ,", Several commenters presented persuasive evidence showing that an effective amount of capacity may be provlde4 by dispersed small systems, even in the case where delivery of energy from any particular facility fa · stochastic. Similarly, quallfylng facilities may be able to enter into operating agreements with each other oy which they are able to increase the assured availability of capacity to the utility PY coordinating scheduled maintenance and providing mutual back-up service. To the extent that this aggregate capacity value can be reasonably estimated, it must be reflected in standard rates for purchases. Several commenters observed that the pattems of availability of particular · - energy sources can and should be . reflected in standard rates. An example of this phenomenon is the availability of wind and photovoltaic energy on a summer peaking system. If it can be shown that system peak occurs when there is bright sun and no wind. rates for purchase could provide a higher capacity.payment for photovoltaic cells
than for wind energy conve�lori systems. For systems peeking on dark windy days, the reverse might be true. Subparagraph (S)(il) thus provides that standard rates Ior purchases may differentiate among qualifying facilities on the basis of the supply characteristics of the particular technology.
§ § 292.304 {b)(S) and (d) Legally enforceable obligations.
Paragraphs (b)(SJ and (d) are Intended to reconcile the requirement that the rates for purchases equal the utilities' avoided cost with the need for qualifying facilities to be able to enter into contractual commitments based, by necessity, on estimates of future avoided costs. Some of the comments received regarding this section stated that, if the' avoided coat of energy at the time it is supplied is leas than the price provided in the contract or obligation, the purchasing utility would be required to pay a rate for purchases that would subsidize the qualifying facility at the expense of the utility's other ratepayers. The Commission recognizes this possibility, but Ja cognizant that in other cases, the required rate will turn out to be lower than· the avoided coat at the time of purchase. T.be Commlasion does not believe 1hat the reference in the-­ statute to the incremental cost of alternative energy was intended to require a minute-by-minute evaluation of costs which would be checked against rates establlahed in long term contracts between qualifying facilities and electric' utilities. Many commenter& have stressed the need for certainty with regard to return on investment in new technologies. The Commiasion agrees with these latter arguments, and believes that, in the·tong run, "overestimations" and "underestimations" of avoided costs will balance out. Paragraph (b)(SJ addresses the situation in which a qualifying facility has entered into a contract-with an electric utility, or where· the qualifying facility has agreed to obligate Itself to deliver .at a future date e.nergy and capacity to the electric uillity. The import of this section is to ensure that a qualifying facility which bas obtained the certainty of an arrangement is not deprived of the benefits of its commitment as a result of changed circumstances. This provision can also work to preserve the bargain entered into by the electric utility; should the actual avoided cost be hlgher than those , contracted for, the electric utility is nevertheless entitled to retain the benefit of its contracted for, or otherwise legally enforceable, lower
price for purchases from the qua11Cy1ng facility. This subparagraph wlll thus ensure the certainty of rates for purchases from a qualifying foclllty which enters into a commitment to deliver energy or capacity to a utility, Paragraph (d)(1) provides that a quelifylns facility may provide energy or cepacity on an "a's available" bosls, Le., without legal obligation. The proposed rule provided that rates for such purchases should be baaed on "actual" · avoided coats. Many conunents noted that basins rates for purchases In such oases on the utility's "actual avoided costs" la ·misleading and could require retroactive ratemaking. In light of theao comments, the Commission Iias revised • the rule to provide that the rotes for purchases are to be baaed on the purchasing utility's avoided costs estimated at the time of delivery.14 Paragraph (d)(2) permits a quallCylng · facility to enter into a contract or othor legally enforceable obligation to provldo energy or capacity over a specified term, Use of the term "legally enforceable obligation" is Intended to prevent u utility from circumventing the requirement that provides capacity credit for an eligible qualifying faclllly merely by refusing to enter into a contract with the qualifying facility. Many commentera notecf the some problems for establishing rotes for purchases under aubporagropb (2) os In subparagraph (1), The Commlsalon intends that rates for purchases be based, at the option of the qualifying facility, on either the avoided costs ot the time of delivery or the avoided costs calculated at the time the obligoUon la Incurred. This change enables a qualifying facility to establish a fixed contract price for its energy and capacity at the outset of Ila obligotJon or to receive the avoided coats determined at the time of delivery. A facUity which enters into o long term contract to provide energy or capacity to a utility may wish to recelvo a greater percentage of the total purchase price during the beginning of the obligation. For example, a level payment schedule from the uUllly to the qualifying facility may be used to match more closely the schedule of debt service of the facility. So long oa tho total payment over the duration of tho contract tenn does not exceed the estimated avoided costs, nothing In these rules would prohibit a State regulatory authority or non-regulated electric utility from approving such on arrangement,
"In addition to Iha ovoldod coats of ono'l!Y, thuso costs must Include the prorolod 1horo of tho aggregate capacity value of such Caclllllcs.
0
Exhibit No. 203
. Case Nos. IPC-E-15-0 l , A VU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
HeinOnline - 45 Fed. Reg. 12224 1980 Page 2
..
Federal Register I Vol. 45, No. 38 I Monday, February 25, 1980 / Rules and Regulations
r
§ 292.304{c) Factors affecting rates for '!Jrchases.
opacity Value
An issue basic to this paragraph is the question of recognition of the capacity value of qualifying facilities. In the proposed rule, the Commission adopted the argument set forth in the Staff Discussion Paper that the proper interpretation of section 210{b) of Pt1RPA requires that the rates for purchases include recognition of the capacity value provided by qualifying cogeneration and small power production facilities. The Commission noted that language used in section 210 of PURPA and the Conference Report as well as in the Federal Power Act supports this proposition. ln the proposed rule, the Commission cited the final paragraph of the Conference Report with regard to section :210 of PURPA:
The conferees expect that the Commission. in judging whether the electric power supplied by the cogenerator or small power producer will replace future power wb.ich the utility wowd otherwile have to genmate itself either through existing capacity or additions lo capacity or purchase from other sources. will take into account the reUability or the power supplied by th� cogenerator or small power producer by reason of uy leselly enCoroeable obli.gation of such -ogenerator or small power producer to ,ply firm power to the utility. u
In addition to that citation, the Commission notes that .the Conference Report states that:
Ia interpreting the term "incremental costs or alternative energy', the conCerees expect that the Commiasion and the State, may look beyond the coats of alternative 1ourcea which are instantaneously available to the utility.11
Several commenters contended that. since section 210{a)(2) of PURPA provides that electric utilities must "purchase electric energy" from qualifying facilities, the rate for such purchases should not include payments for capacity. The Commission observes that the statutory language used in the Federal Power Act uses the term "electric energy" to describe the rates for sales for resale in Interstate commerce. Demand or capaclt) payments are a traditional part of such rates. The term "electric energy" is used throughout the Act to refer both to electric energy and capacity. The Commission does not find,.any evidence that the term "electric energy'' in section
210 of PURPA was intended to refer only to fuel and operating and maintenance
,.Conren:nce Report on H.R. 401.0.. Pul.,lic Util,ti Regulatory Polides Act of 1978. H. R�p. So. 175(\. !19. . "th Coni� ?.cl. Seu. (1978}. 'Id. pp. 9&-a
expenses, instead or all or the costs associated with the prods ion of electric service. In addition. the Commission notes that to interpret this phrase to include only enetJY would lead to the conclusion that the rates for sales to qualifyin& facilities could only include the ene131 component of the rate since section 210 also ref era to "electric energy" with regard to such aalea. lt is .the Commiuion's belief that this was not the intended resulL lbla provides an additional reason to interpret the phrase "electric energy" to include both energy and capacity. In implementing this statutory standard, it is helpful to review industry practice respectins sa1e1 between utilities. Sales of electric power are ordinarily cla11ified as either rum sales, where me seller provides power at the customer's request. or non-firm power sales, where the seller and not the buyer makea the decision whether or not power is to be available. Rates for fum po'ft-er purcbuea Include payments for the cost of fuel and operating expenses. and alao for the fixed coats associated with the construction of genera tins units needed to provide power at the purchaser'• discretion. The degree of certainty or deliverability required to constitute "firm power" can ordinarily be obtained only if a utility has several generating unit, and adequate reserve capacity. The capacity payment. or demand charse, will reflect t.he cost of the utility's,enerating units. In contrast. the ability to provide electric power at the selling utility's discretion impo1e1 no requirement that the seller construct or reserve capacity. In order to p,ovide power to customers at the seller'• diacreUon. the selling utility need only charge for the coat of operating ill generating units and administration. These costs. called "energy .. coats, ordinarily are the onK associated with non-firm sales of power. Purchase, of power from qualifying facilities will ran somewhere on the continuum between these two t)'J)el of electric tervice. 11ius, for example, wind mach�nea that furnish power only when wind velocity exceeds tweke miles per hour may be 10 uncertain in availability of output that they would only pennit a utility to avoid generating an equivalent amount of energy. In that aitualion. the utility must continue to pro,·ide capacity that is available to meet the needs ofit. customers. Since there are no avoided capacity costs, rates for such sporadic purchases should thus be based on the utility s1·1tem'1 avoided incremental cost or energy. On the other hand, testimony at the Commission's public hearings indicated that effective
amounts of firm capacity exist for dispersed wind systems. even though each machine, considered separately. could not provide capacity value. The osgregate c.apacity value of such facilities must be con&idered in the calculation or rates for purchases, and the payment distributed to the class providing the capacity. Some technolosies. such as photovoltaic cell,, although subject to some uncertainty in power output. have
the Jeoetal advantase of providiDB their maximum power coincident l'.ith the 1y1lem peak wbeu used on a summer pea kins syatem. The value of such power ia greater to the utility than power delivered during off-peak periods. Since the need for capacity is based. in part. on ay,te.m pew., the qualifying facility•, coincidence with the system peak should be re!lected in the allowance of aome capacity value and an enefBY component that reflects the avoided enezsy COila at the time of the peak. A facility barnins municipal waste or biomaaa may be able to operate more predic:t&bly and reliably than solar or wind systems. It can schedule its outage• durina times when demand on the utility•• system ia low. If such a unit demonstrates a degree of reliability that would permit the utility to defer or avoid construction or a aenerati.ns unit or the purchase of firm power from another utility, then the rate for such a purchase should be hued on the avoidance or both energy and capacity costs. In order lo defer or c:ancel the constructioo of new genentms units. a utility must obtain a commitment from a qualifying facility that provides contractual or other legally enforceable assurances that capacity from alternative sources will be available sufficiently ahead o£ the date on which the utility would otherwise have to commit itaelC to the construction or purchase or new capacity. If a qualifying facility provides auch assurances, it is entitled to recei,·e rates based on the capacity coats that the utility can avoid as a result of its obtaining capacity from the qualifying facility. Other comments with regard to the requirement to include capacity pa)7nenla in a,·oided costs generally track those aet forth in the Staff Discuision Paper and the proposed rule. The thrust of these comments is that. in order to recelve credit for- capacity and to comply with the requirement that roles for purchases not exceed the incremental cost of alternative energy. capacity pa)7nents can only be required when the availability 0£ capacity from a qualifying facilit)• or facilities actually pennils the purchasing utility to reduce
Exhibit No. 203
Case os. I PC-E-15-0 I, A VU-E-15-0 I, PAC-E-15·03
D. Reading, Simplot/Clearwater
HeinOnline •• 45 Fed. Reg. 12225 1980 Page 3
12226 · · Federal Register I Vol. 45, No. SS I Monday, February 25, 1980 I Rules and Regulations
its need to provide capacity by deferring the construction of new plant or commitments to rum power purchase contracts. In the proposechule, the Commission stated that i£ a qualifying facility offers energy of sufficient reliability and with sufficient legally enforceable guarantees of deliverability to pennit the purchasing electric utility to avoid the need to construct a generating plant, to 'enable it to build a smaller, less expensive plant, or to purchase less firm power from another utility.than it would otherwise have. p�rchased, then the rates for purchel[es from the qualifying facility must include ' the avoided capacity and energy costs. As Indicated by the preceding ... discussion, the Comm1sslon continues to believe l;hat these"princfples are yalid and appropriate, and that they properly fulfill the mandate of the statute. · The Commission also continues to believe, as stated In the proposed rule, that this rulemaking represents an effort to evolve concepts In a newly . developing area within certain statutory constraints. The Commission recognizes that the translation of the principle of avoided capacity costs from theory Into practice Is an extremelr. difficult exercise, and is one wliich, by . definition, Is based on estimation and forecasting of future occurrences. Accordingly, the Commission supports the recommendation made In the Staff Discussion Paper that it should leave to the States and nonregulated utilities "flexibtllty for experimentation and accommodation of special circumstances" with regard to Implementation of rates for purchases. Therefore, to the extent that a method of calculating the value of capacity from qualifying facillties reasonably accounts for the utility's avoided costs, and does not fail to provide the required encouragement of cogeneratiO!l and small power production, it will be considered as satisfactorily Implementing the Commission's rules.
§ 292.304(e) Factors affecting rates for purchases.
As noted.previously, several commenters observed that the utility system cost data required under § 292.302 cannot be directly applied to rates for purchase. The Commission acknowledges this point and, es discussed previously, has provided that these data ai:e to be used as a starting point for the calculation of an appropriate rate for purchases equal to the utility's avoided cost. Accordingly, the Commission has removed the reference to the utility system cost data from the definition of rates for· · purchases, and has inserted the
reference to these data In paragraph (e), as one factor to be considered In calculating rates for purchases. Subparagraph (1) states that these data shall, to the extent practicable, be taken into account In the. calculation of a rate for purchases. . Subparagraph (2) deals with the availability of capacity from a qualifying facility during system daily and · seasonal peak periods. If a qualifying facility can provide energy to a utility during peak periods when the electric utility Is running its most expensive generating units, this energy has a higher value to the utility than energy supplied during off-peak periods, during which only units wiJh lower running costs are operating. The preamble to th!! proposed rule provided that, lo the extent that metering equipment is available, the Stale re3ulatory·authorlty or • nonregulated electric utility should take Into account the time or season In which the purchase from the qualifying facility occurs. Several commenter& Interpreted this statement as implying that. by refusing to Install metering equipment, an electric utility could avoid the , obligation to consider the time at which purchases occur. This is not the intent of this provision. Clearly, the more precisely the time ·of purchase is recorded the more exact the calculation of the avoided costs, and thus the rate . for purchases, can be. Rather than · specifying that exact time-of-day or seasonal rates for purchases are required, �owever; the Commission believes that the selection of a methodology is best left to the State regulatory authorities and nonregulatea electric utilities charged with the implementation of these provisions. Clauses.(!) through (v) concern various aspects of the reliability of a qualifying facility. When an electric utility provides power from its·own generating units or from those of another electric utility, it normally controls· the production of such power from a central location. The ability to so control power production enhances a· utility's ability to respond .to changes In demand, and thereby enhances the value of that power to the utility. A qualifying facility may be able to enter Into an ' arrangement with the utility which gives the utility the advantage of dispatching the facility. By so doing, it Increases its value to the utility. Conve�sely, if a utility cannot dispatch a qualifying facil.ity, that facility may be of less value to the utility. Clause (ii) refers to the expected or demonstrated reliability of a qualifying facility. A utility cannot avoid the construction or purchase of capacity if ii
is likely the t the qualifying foclllty which would claim to replace such capacity may go out of service during the period when the utility needs Its power to meet system demand. Bnsod on the estimated erdemonstrated reliability of a qualifying faclllty, tho rate for purchases from a qualifying facility should be adjusted to reflect Its value to the utility.
Clause (iii) refers to the length of tlmu during which the qualifying facility hos contractually or otherwise guornntood that it will supply energy or capacity to the electric utility. A uUllty-owned generating unit nonnally will supply power for the life of the plant, or untll It is replaced by more effiolent capacity. ln contrast. a i:ogeneratlon or small powor production unit might cease to produce power as a result of changes In the industry or In the industrial processes utilized. Accordingly, the valuo of tho service from the qualifying facility to lho electric utility may be affected by the degree to which the qualifying focillly ensures by contract or other legally enforceable obligation that It }\'111 conUnu.e to provide power, Included In this determination, among other factors, are the term of the commitment, tho requlreme.nt for notice prior to termination of the commitment, ond nny penalty provisions for breach of the obligation.
In order to provide capacity value to an electric utility a qualifying foclllty need not necessarily agree to provldo power for the life of the plant. A utlllty's generation expansion plans often include purchases of flrm power from other utilities in years Immediately preceding the addition of a major generation unit. If a qualifyin8 facility contracts to deUver power, for example, for a one year period, It may enable tho purchasing utility to avoid entering Into ·a bulk power purchase arrangement with another utility. The rate for such n purchase should thus be based on lho price at which such power ls purchased, or can be expected to be purchased, based upon bone fide offers from · another utility.
Clause (iv) addresses periods during which a qualifying faciUty Is unable to provide power. Electric utUJtlos schedulo maintenance outages for their own generating units during periods when demand is low. If a qualifying facility can stmllarily schedule Its malntennnco outages during periods of low demand, or durlhg periods in which a utility's own capacity will be adequate to handle existing demand, it will enable the utility to avoid the expenses ossoclotod with providing an equivalent amount or
Exhibit No. 203
Case os. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
HeinOnline •• 45 Fed. Reg. 12226 1980 Page 4
Federal Register / Vol. 45, No. 58- / Monday, February 25, 1980 J Rules and Regulations
capacity. These savings should be illected in the rate for purchases. Clause (v) refers to a qualifying
facility's ability and willingness to
provide capacity and energy during system emeigencies. Section 292..307 of these regulations concerns the provision of e� service during system em�cles. It provides that. to the extent that a qualifying facility is williil8 to forego its own use of energy during system emergencies and provide power to a utility's aystem. the rate for purchases from the qualifying facility should reflect the value of that service. Small power production and cogeneration facilities could provide significant back-up capabili� to electrie sysrems during emergencies. One benefit of the encouragement of interconnected cogeneration and small power production may be lo increase
overall 511tem reliability during such emergency conditions. Any such benefit should be reflected in the rate for purehases from such qualifying facilities.
Another related factor which aff�ts the capacity value of a qualifying facility is its ability to separate its load
from its generation during system emergencies. During such emergencies an electric utility may institute load �bedding proced� which may, among lier things. require that industrial ..JStomers or other large loads stop
receiving power. As a result. to provide optimal benefit to a utility in an emergency situation. a qualifying facility might be required to continue operation as a generating plant. while simoltaneously ceasing operation as a load on the utility's system. To the extent that a facility ls unable to separate its load from its generation, its value to the purchasing utility decreases
during system emergencies. To reflect such a possibility, clause (v) provides that the purchasing utility may comider the qualifying facility's ability to separate its load from its generation during system emergencies in determining the value of the qualifying facility to the electric utility.
Clause (vi) refers to the aggregate capability of capacity from qualifying facilities to displace planned utility capacity. In aome instances, the small amounts of capacity provided from qualifying facilities taken individually might not enable a purchasing utility to defer or avoid scheduled capacity additions. The aggregate capability of such purchases may, however, be sufficient to permit the deferral or avoidance of a capacity addition. · wreover, while an individual qualifying cility may not provide the equivalent
or firm power lo the electric utflil1·, the diversity of these !acllitie. may ·collectively comprise the equivalent of capacity. Clause (vii) refers to the fact that the lead time auociated with lhe addition of capacity from qualifyi.Qg facilllies may be leu than the lead time that would have been required if the purchasing utility had constructed its own generating uniL Such reduced lead
time m.iaht produce savinga in the utility's total power production cotls, by permitting utilitiu lo avoid the "lwnpine-." and temporary excess capacity aaaociated therewith, which notmally occur when utilities bring oo line large generating units. In addition. reduced lead time provides the utility with greater Dexibility with which it can accommodate change• lo forecasts or ' peak demand. Subparagraph (3) concerns the relationship of energy or capacUy from a qualifying facility to the purchasing electric utility's need tor auch energy or capacilJ. If an electric utility h11 sufficient capacity to meet ill demand. and is not planning lo add any new capacity to its syatem. then the availability of capaclty from qualifying facilities will not immediately enable the utility to avoid any capacity costs. However, an el�bic utility 1y1tem with excess capacity may nevertheleu plan
to add new, more efficient capaclty to its syatem. U purchuea from qualifying facilities enable a utility lo defer or avofd the.e new planned capacity addition,, the rate for such purchase, should reflect the avoided cost. of these additions. However, u noted by several comm.enters, the def en-al or avoidance or such a unit will alao prevent the sul,Qtltution of the lower e.nergy coats that would have accompanied the ne"· capaclty. As a result. the price for the purchase of energy and capacity should
reflect these lower avoided energy coils that the utility would have incurred had the new capacity been added. This la not lo say that electric utilities which have excess capacity need not make purchases from qualifying facilities: qualifying facilities may obtain pa)'lllenl baaed on the avoided energy costs on a purchasing uUllty•, 1y1tem. Many utility system, with excess capacity have intermediate or peaking units which use high-cost fossil fueL As a result. during peak hours. lhc energy costs on the aystema are high. and thus the rate to a qualifying utility from which the electric utility purchases energy should similarly be high. Subparagraph (4) addresses the costs or savings resulting from line losses. An appropriate rate for purchases from a qualif}·ing facility should reflect the cost
liB'inga actually accruing to the electric ulility. If energy produced from a qualllyins facility undergoes line losses such that the delivered power is nol equivalent to the power th.at would hue been deliv� from the source of power it replaces. then the qualifying facility should not be reimbursed for the difference in loues. If the load served b1· lhe qualifying facility is closer to the qualifrin& facility than it is to the utility. it Is posaible that there may be net savings resulting from reduced line lo11ea. In such cues. the rates should be adjusted upwards.
I :!!>23tJ3{/J Pen'ods during �·hi�h purchase are not lt!(Juired,
The proposed rule provided that an electric ulility will not be required to pu:chue energy and capacity from qualifying facilities during periods in which such purchases will result in net Increased operating costs to the electric utility. Thia section wu intended to deal with a certain condition which can occur during light loading periods. If a utility operating only base load units during lhue periods were forced to cul back output from the units in order to accommodate purchases from qualif}illg facilitfes, these base load units might not be able to lncreue their output level rapidly when the system demand later increa�d. As a result. the utility would be required lo utilize less efficient. higher coat unita with Iasteratart-up to meet the demand that would have been supplied by the less expensive base load unit had 1t been permiUed to operate at a constant outpuL The result of such a transaction would be that rather than avoiding costs as a result of the purchase from a qualifying facilit1·. the purchasing electric utility would incur greater costs than it would have had it not purchased energy or capacity from the qualifying facilit)•. A strict application of the avoided cost principle sel forth lo this section would asseu these additional costs as negative avoided costa which must be reimbursed by the qualifying facility. In order to avoid the anomalous result of forcing a qualifying utility to pay an electric utility for purchasing its output. the Commiaaion proposed that an electric utility be required lo identify periods during which this situation would occur, so that the quelifying facility could cease delivery of electricity during those periods. Many or the comments received refleeted a suspicion that electric utilities would abuse this paragraph to circumvent their obligation to purchase from qualifylng facilities. In order to minimize that possibility, the Commls!lion has revised this paragraph
Exhibit No. 203
Case os. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
HcmOnline -45 Fed. Reg, 12227 1980 Page 5
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E-15-01, A VU-E-15-01, PAC-E-15-03
J.R. SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBIT NO. 204
Exhibit No._(GND- 7CT)
Docket UE-130043
Witness: Gregory N. Duvall
BEFORE THE WASHINGTON UTILITlES AND TRANSPORTATION COMMISSION
W ASHrNGTON UTILITIES AND
TRANSPORTATION COMMISSlON,
Docket UE-130043
Complainant,
v.
PACIFICORP d/b/a
Pacific Power & Light Company
Res ondent.
PACIFICO RP
REDACTED REBUTTAL TESTIMONY OF GREGORY N. DUVALL
August 2, 2013
Exhibit o. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page I
2
3 Q.
4 A.
should consider changes in this case as a part of the post-trial period review of the
WCA.16
Did parties accept any of the Company's proposed modifications to the WCA?
Yes. Staff explicitly supported the Company's proposal to include the entire Idaho
5 Power PTP transmission contract in the WCA, apparently on the basis that it reduces
6 NPC.17 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 Idaho Power PTP
9 contract. 18
IO California and Oregon QF contracts
11 Q. Does any party support the Company's proposal to include the costs associated
12 with Oregon and California QF contracts in west control area NPC?
13 A. No. Staff, Boise, and Public Counsel each argue against inclusion of California and
14 Oregon QF contracts in west control area NPC.19 In one form or another, the parties
15 all assert that allocating west control area QF contracts to Washington inappropriately
16 requires Washington customers to pay for QF-related policy choices made by Oregon
17 and California.
18 Q.
19 A.
Are all of the contested QF contracts from renewable resources?
Yes. The QF contracts are all connected to renewable resources located in Oregon
20 and California. Because the QF contracts do not include renewable energy credits
16 Id, 159. 17 Exhibit No._(DCG-ICT) at page 7.
18 Exhibit No._(MCD-1 CT) at pages 5-6. 19 See Exhibit No._(MCD-ICT) at pages 5-8; Exhibit No._(DCG-ICT) at pages 8-13; Exhibit No._(SC­
I CT) at pages I 5-18.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case os. !PC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
0. Reading, Simplot/Clearwater
Page 2
Exhibit No._(GND-7CT)
Page 13
2 Q.
3
4 A.
5
6
7
8 Q.
9
10 A.
II
12
13 Q.
14
15 A.
16
17
18
19
(RECs), however, the Company may not use them to comply with the EIA.20
Is one of the goals of PURP A 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 efficient 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."21
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.n
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
20 RCW 19.285 et seq. 21 In re Southern California Edison, 71 F.E.R.C. P 61,269, 62,079 ( 1995).
22 RCW 189.285.020; RCW 70.235.005; and RCW 80.80.005( I )(d).
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit o. 204
Case os. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 3
Exhibit No._(GND-7CT)
Page 14
2
3 Q.
4
5
6
7 A.
8
9
10
II
12 Q.
13
14 A.
15
16
17
18 Q.
19
20 A.
21
to help Washington's citizens and businesses participate in our state's efforts to
reduce greenhouse gas emissions.t''"
ls 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. lndeed, 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 rebuttal NPC. This update
also reduces the impact of parties' proposed adjustments to exclude Oregon and
California QF contracts by approximately 10 percent.
Does PURP A 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
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit lo. 204
Case os. IPC-E-1 S-0 I, A VU-E-1 S-0 I, PAC-E-1 S-03
D. Reading, Simplot/Clearwater
Page 4
Exhibit No._(GND- 7CT)
Page 15
2
3 Q.
4
5 A.
6
7
8
9
10
11
12
13
14 Q.
15 A.
16
17
18
19
20
a QF contract.24 The Company's proposal in this case modi ties the WCA to provide
for the full cost recovery for QF contracts dictated by PURPA.
What specific justification does Staff provide 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 California QFs may physically deliver
power to meet Washington load is irrelevant.25 Public Counsel makes the exact
opposite argumcnt.26 It 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, Staff claims 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.
How 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.?" Public Counsel's claim that a
detailed power flow study is necessary is incorrect. However, Staff is also incorrect
that the physical location of the Oregon and California QFs within the west control
area is irrelevant to their inclusion in west control area NPC.
24 16 U.S.C. § 824a-3{m){7). 2s Exhibit No._{DCG-ICT) at page 10.
26 Exhibit No._(SC-ICT) at page 17. 27 Wash. Utils. & Transp. Comm 'n v. PacifiCorp d/b/a/ Pacific Power & light Company, Docket UE-050684,
Order 04, ,i 68 {April 17, 2006).
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 5
Exhibit No._(GND-7CT)
Page 16
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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.28
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 eligible resources, contract term
lengths, and pricing for QF contracts are determined entirely by state-specific
policies.29 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 contracrs.r''
28 Wash. Utils. & Transp. Comm 'n v. PacifiCorp d/b/a Pacific Power & light Company, Docket UE-061546,
Order 08, � 53 (June 21, 2007). 29 Exhibit No._(DCG-JCT) at page 10. 30 Exhibit o._(MCD-ICT) at page 7.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 6
Exhibit No._(GND-7CT)
Page 17
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Is Staff correct 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.31 I also understand that FERC regulations govern the specific
requirements regarding the types of resources that are eligible for a QF contract," the
size of resources eligible for QF contracts,33 and the methodology for determining
avoided cost prices for purposes of QF contracting. 34
Staff claims that Commission policy dictates shorter contract lengths and
smaller capacity sizes than Oregon and California to better protect customers.35
Do you agree?
No. Staff's testimony states that the Commission has established policies that strictly
limit QF eligibility for standard contracts and strictly limits standard contract length.36
However, Staffs claims are at odds with the Commission's rules and Commission-
approved PURP A tariffs.
First, Staff states 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
31 See, e.g., 16 U.S.C. §§ 824a-3(b), (d); 18 C.F.R. § 292.304(2); American Paper Institute, Inc v, American
Elec. Power Service Corp., 461 U.S. 402, 413 ( 1983). 32 See, e.g.. 18 C.F.R. §§ 292.203-.205.
JJ See. e.g.. 18 C.F.R. § 292.304(c}. 34 See, e.g .. 18 C.F.R. § 292.304.
35 Exhibit o. (DCG-ICT) at page 13. 36 - Id at n. 29.
31 Id
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading. Simplot/Clearwater
Page 7
Exhibit No._(GND-7CT)
Page 18
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tariff for purchases from qualifying facilities rated at one megawatt or less."
Currently, both PSE's Schedule 91 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 smal I quantities of power."
Paci ft Corp' s current Schedule 37 publishes a I 0-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 15 years
of fixed prices. Of note, current Washington prices, which were set in PacifiCorp's
2011 general rate case, Docket UE-111190, include the end of a 25-year QF contract
with the City of Walla Walla with calendar year 2014 prices of$ I 56.90 per MWh.
Staff argues that the longer terms of QF contracts in Oregon and California
expose customers to increased risks from decreasing avoided cost rates in recent
years. 39 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
JS Id.
39 Exhibit No._(DCG-1 CT) at pages 12-13.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 8
Exhibit No._(GND-7CT)
Page 19
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included in this case, over 76 percent is from contracts entered in the last five years.40
The vast majority of the contracts that are included in NPC in this case have been 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." 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
40 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. 41 Exhibit No._(MCD-1 CT) at page 6.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit o. 204
Case Nos. I PC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 9
Exhibit No._(GND-7CT)
Page 20
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on a utility's avoided cost of energy and capacity, in compliance with PURPA. Each
state has an approved method for calculating these avoided costs, and the resulting
prices are heavily scrutinized and ultimately approved by the respective commissions.
The avoided cost calculation is designed to set QF contract prices at a level where
customers are indifferent between a utility purchasing from the QF or obtaining
energy and capacity from the next available resource. No party has provided
evidence that the avoided cost prices in Oregon or California exceed the Company's
actual avoided costs in violation of PURPA.
What justification does Public Counsel provide for the exclusion of the
Company's contracts with QFs in Oregon and California?
In addition to the arguments addressed above regarding the Company's lack of power
flow studies, Public Counsel claims that Oregon and California QF contracts are
priced higher than other long term purchase power costs for 2014.42
How do you respond to this argument?
It is improper for ratemaking purposes to compare the avoided cost price in QF
contracts that are several years old with the cost of other purchases in the current
NPC study. Such a comparison does not account for the information available at the
time the various contracts were entered. Nevertheless, the difference in price cited by
Public Counsel was less than seven percent. In addition, all of the long-term
contracts included in the comparison were executed more than IO years ago,
including two low-cost contracts entered in 1961 and 1989 that were based on cost-
42 Exhibit o._(SC-1 CT) at page 17.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit o. 204
Case os. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 10
Exhibit No._(GND- 7CT)
Page 21
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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.43 ls 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 all jurisdictions. 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.44 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
43 Id. at 16.
44 Exhibit No._(MCD-1 CT) at page 7.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 11
Exhibit No._(GND-7CT)
Page 22
California and Oregon QF contracts in the determination of west control area NPC in
2 the same manner as all other west control area generation resources, with a portion of
3 the costs allocated to Washington customers.
4 East Control Area Sale
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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?
Boise and Staff each 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.45
What is the basis for Boise's opposition to the Company's proposal?
Boise provides no factual argument, but instead rejects the proposal to remove the
east control area sale because the parties to the collaborative process did not agree to
the change.46 For the same reasons discussed above, this argument is unpersuasive.
What basis does Staff provide for the inclusion of the east control area sale?
Staff's argues that the imputed east control area sale remains an integral and crucial
part of the WCA and should therefore not be modified.47
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
45 Exhibit No._(DCG-1 CT) at pages 13-16; Exhibit No._(MCD-1 CT) at page 8. 46 Exhibit No._(MCD-1 CT) at page 8. 47 Exhibit No._(DCG-1 CT) at page 16.
Redacted Rebuttal Testimony of Gregory N. Duvall
Exhibit No. 204
Case Nos. IPC-E-15-0 I, A YU-E-15-0 I, PAC-E-1 S-03
D. Reading, Simplot/Clearwater
Page 12
Exhibit No. (GND- 7CT)
Page 23
CONFIDENTIAL PER WAC 480-07-160
Exhibit No._(GND-1 CT)
Docket UE- l 4
Witness: Gregory N. Duvall
BEFORE THE WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION
WASHfNGTON UTILITIES AND
TRANS PORT A TION COMMISSION,
Docket UE-14
Complainant,
v.
PACIFIC POWER & LIGHT COMPANY,
a division of PacifiCorp
Res ondent.
PACIFIC POWER & LIGHT COMPANY
REDACTED DIRECT TESTIMONY OF GREGORY N. OUV ALL
May 2014
Exhibit No. 204
Case Nos. I PC-E-15-0 I, AV U-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 13
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differences in west control area loads and resources by reducing actual short-term
balancing purchase or sales transactions.
PROPOSED TREATMENT OF QF RESOURCES
lN THE WEST CONTROL AREA
Please explain the Company's proposed treatment of PP As 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 PP As 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 PP As 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 Testimony of Gregory N. Duvall Exhioit No. 204
Case os. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 14
Exhibit No._(GND-ICT)
Page 8
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customers, but Washington customers only pay for PPAs with QFs located in
Washington.
• 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 from a [QF] ...
recovers all prudently incurred costs associated with the purchase.t"
• All of the Oregon and California PP As 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 PP As in rates implements the
El A's policy of encouraging renewable resource development on a regional basis
and diversifying the portfolio of renewable resources serving Washington
customers.
In the 2013 Rate Case, the Commission reasoned that the Company's proposal
was the equivalent of adopting the Revised Protocol method just for QF
resources.3 Do you agree?
No. The Company's proposal to include the costs of PP As with QFs in Oregon and
California 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.?" Oregon and California QFs are used to keep the west control area in balance
just like all other west control area generation resources. The only distinguishing
2 16 U.S.C. § 824a-3(m)(7)(A); see also Freehold Cogeneration Assocs .. l: P. v Bd. of Regula/Ory Comm 'rs of
the State of N.J., 44 F.3d 1178, 1194 (3d Cir. 1995) ("[A]ny action or order by the [state commission] to
reconsider its approval or to deny the passage of those rates to [the util it) 's J consumers under purported state
authority was preempted by federal law."). 3 Wash. Utils. & Transp. Comm 'n v. PacifiCorp dlbla Pacific Power & Light Co., Docket UE-130043, Order
05, � 110 (Dec. 4, 2013). 4 Order 05 110 (quoting Wash. Utils. & Transp. Comm 'n v Pacific Power & light Co., Docket UE-061546,
Order 08, � 53 (June 21, 2007).
Direct Testimony of Gregory N. Duvall Exhibit No. 204
Case Nos. JPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 15
Exhibit No._(GND-1 CT)
Page 9
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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 20 IO Protocol, which is the current inter-jurisdictional
allocation methodology used in the PacitiCorp's other five state jurisdictions,
allocates the costs of QF PP As 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 PP As 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 G RJ D study. Q F 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 Testimony of Gregory N. Duval I Exhibit No. 204
Case Nos. I PC-E-15-0 I, AV U-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 16
Exhibit No._(GND-1 CT)
Page 10
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Washington, for example, Schedule 37 rates compensate QFs for both energy and
capacity, with energy payments based on the incremental cost of market transactions
and thermal output, and capacity payments reflecting the fixed costs of a simple cycle
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.
PURPA 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 Order 05 in the 2013 Rate Case, did the Company analyze other
approaches to addressing Oregon and California QF PPAs in Washington?
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 NPC calculation, and excludes an equivalent
Direct Testimony of Gregory N. Duvall Exhioit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 17
Exhibit No._(GND-1 CT)
Page 11
amount of QF output from WCA loads used to calculate NPC and inter-
2 jurisdictional allocation factors; and
3 2) A "Washington re-pricing" approach, which includes Oregon and California QF
4 PPAs in the NPC calculation but re-prices them using the Washington avoided
5 cost rates in effect at the time of PPA execution.
6 Table 2 below compares the revenue requirement impact of these two alternative
7 approaches with the Company's proposal to include all west control area QF PPAs as
8 west control area resources. This table, and supporting detai I, is provided in Exhibit
9 No._(NCS-7) accompanying Ms. Siores testimony.
Table 2
Revenue Variance from
Requirement Filed
As Filed $27.2 million
Washington Re-Pricing $24.9 million ($2.3 million)
Load Decrement $23.1 mil lion ($4.1 million)
Situs Assigned (exclude OR and CA OF PPAs) $17.2 million ($10.0 million)
10 Q.
II A.
Please explain the load decrement approach.
Under this approach, Oregon and California QF PPAs are deemed to serve customers
12 in those states, consistent with the situs treatment ordered by the Commission in the
13 2013 Rate Case. Because Oregon and California QF PPAs are not recognized as
14 WCA resources, the costs and related energy are removed from the calculation of
15 west control area NPC. Next, because Oregon and California QF PPAs are deemed to
16 serve customers in those states, the retail load in those states served by these
17 resources is also removed from the calculation of west control area NPC. Finally, the
18 retail load in Oregon and California served by QF resources is subtracted (i.e.
19 decremented) from the energy and peak loads used to determine each state's
20 allocation factors under the WCA.
Direct Testimony of Gregory N. Duvall Exhibit o. 204
Case os. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 18
Exhibit No._(GND-1 CT)
Page 12
Q. What is the impact to Washington of removing Oregon and California QF PP As
2 and load?
3 A. Removing Oregon and California QF PPAs and load reduces west control area NPC
4 and reduces the total load served by west control area resources. The allocation of
5 remaining west control area costs is adjusted to account for the decremented load-
6 i.e. the share of the total costs allocated to Oregon and California is decreased
7 reflecting the reduced requirement to serve customers in those states. Washington's
8 allocated share of remaining WCA costs is increased as a result of the QF-PPA-
9 related decrements to Oregon and California load. The net impact is a reduction to
10 the Company's current filing of approximately $4. l million.
11 Q. Why is an adjustment to the inter-jurisdictional allocation factors required
12 under the load decrement approach?
13 A. Adjusting the inter-jurisdictional allocation factors under the load decrement
14 approach ensures that the full impact of treating QF PP As as situs resources is
15 reflected in Washington revenue requirement. If Oregon and California customers
16 are being served by specific resources, they should not also be allocated the cost of
17 the remaining west control area resources. Decrementing Oregon and California load
18 for allocation purposes appropriately reduces the share of west control area costs
19 al located to those states.
20 Q. Please explain the alternative approach of re-pricing Oregon and California QF
21 PPAs using Washington avoided costs.
22 A. Under this alternative, the Oregon and California QF PPAs are included in west
23 control area NPC but are re-priced using Washington avoided cost rates that were
Direct Testimony of Gregory N. Duvall Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 19
Exhibit No._(GND-1 CT)
Page 13
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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 PP As 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 California QF PPAs in the proforma 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 PP As 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-I 980s contracts in Oregon and
California, 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 and 20 years, respectively.
Washington's current administrative rules allow a utility to sign contracts for
electricity purchases for any term up to twenty years.5
s WAC 480-107-075(3).
Direct Testimony of Gregory N. Duvall Exhibit o. 204
Case Nos. I PC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 20
Exhibit No._(GND-1 CT)
Page 14
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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 PP As 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 alternative methods as a middle
ground between full recovery or full disallowance of the costs of all west control area
QFs in Washington NPC.
CHANGES 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 historical test
period (the 12 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.
Direct Testimony of Gregory N. Duvall Exhi6it o. 204
Case Nos. I PC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 21
Exhibit o. (GND-1 CT)
Page 15
Exhibit No. GND-4T
Docket U E-140762 et al.
Witness: Gregory N. Duvall
BEFORE THE WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND
TRANSPORTATION COMMISSION,
Complainant,
v.
PACIFIC POWER& LIGHT
COMPANY,
Respondent.
lo 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.
DOCKETS UE-140762 and UE-140617
( consolidatedy
DOCKET UE-131384 (consolidated)
DOCKET UE-140094 (consolidated)
PACIFIC POWER & LIGHT COMPANY
REBUTTAL TESTIMONY OF GREGORY N. DUVALL
Exhibit No. 204 November 2014
Case os. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 22
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its members, "including the Packaging Corporation of America, f/k/a Boise White
Paper, L.L.C. (PCA), PacifiCorp's largest customer in Washingtonj.]?" and further
stated that "ICNU indirectly participated in PacifiCorp's most recent general rate case
(UE-130043) as PCA[.]"15
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
9 in supplemental pre-filed testimony or in testimony at the hearing, provided the
IO Company has a chance to respond to this testimony.
11 COMPANY RESPONSES TO PROPOSED NPC ADJUSTMENTS
12 Exclusion of California and Oregon QF PP As
13 Q.
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Does any party support the Company's proposal to include the costs associated
with Oregon and California QF PP As in west control area NPC?
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
2013 general rate 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 California and Oregon QF PP As, but indicates
14 See Wash. Utils. & Transp. Comm 'n v. PacifiCorp, Docket No. UE-140617, Petition to Intervene and
Opposition of the Industrial Customers of Northwest Utilities, 1 3 (Apr. 25, 2014 ).
IS Id., ,I 4.
16 See Testimony of David C. Gomez, Exhibit No. DCG-1 CT at 9-1 O; Responsive Testimony of Bradley G.
Mullins, Exhibit No. BGM-ICT at 23.
Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204
Case Nos. IPC-E-15-0 l, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 23
Exhibit No. GND-4T
Page 12
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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 California 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 PP As 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 PP As 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.17
TABLE 1
Revenue Requirement Summary
Re1.enue
Requirement Change from Filed
Rebuttal Position 31,938,957
Re-Pricing at WA QFs A1.0ided Costs 29,763,224 (2, 175, 733)
Load Decrement 28,009,625 {3,929,332)
Situs-Assigned - Exel. OR/CA QFs 22,181,879 (9,757,079)
17 Rebuttal Testimony of Natasha Siores, Exhibit o. NCS-12.
Rebuttal Testimony of Gregory N. Duvall Exhib1t No. 204
Case Nos. I PC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 24
Ref NCS-11, Page 1:
Ref NCS-12, Page 2
Ref NCS-12, Page 3
Ref NCS-12, Page 4
Exhibit No. GND-4T
Page 13
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Did the parties address the Company's alternative proposals?
Yes. Both Staff and Boise dismissed the Company's alternative 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, Staff and 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.18 Staff and
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 PP As 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 PURP A's requirement, as interpreted by the
Commission in the Company's Schedule 37, that utilities purchase all energy 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
18 See, e.g., Testimony of David C. Gomez, Exhibit No. DCG-1 CT at 11; Responsive Testimony of Bradley G.
Mullins, Exhibit No. BGM-1 CT at 25-26 .
. Rebuttal Testimony of Gregory N. Duvall Exh1b11 No. 204
Case Nos. IPC-E-15-0I,AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 25
Exhibit No. GND-4T
Page 14
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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 PP As that were executed years ago
with avoided cost prices determined at the time of execution. PURP A allows QFs to
enter into long-term PP As 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 Power's 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 .
. Rebuttal Testimony of Gregory N. Duvall Exhibit o. 204
Case os. I PC-E-15-0 I, AV U-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 26
Exhibit No. GND-4T
Page 15
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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.19 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 off because 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 PP As 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
19 Testimony of Jeremy B. Twitchell, Exhibit No. JBT-1 T at 15-16. 20 Spokane Energy, Inc. v. Wash. Water Power Co., Cause No. U-86-114, 1987 WL 1498338 (Apr. 22, 1987) .
. Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204
Case os. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 27
Exhibit No. GND-4T
Page 16
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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.
Staff claims that the Company provided only vague assertions regarding the
benefits provided by the out-of-state QFs to Washington customers.21 Boise
claims that the Company did not identify any direct benefit provided by these
QFs that would support full cost recovery.22 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.
21 Testimony of David C. Gomez, Exhibit o. DCG-1 CT at 9. 22 Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-1 CT at 26 .
. Rebuttal Testimony of Gregory N. Duvall Exhibit o. 204
Case os. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 28
Exhibit No. GND-4T
Page 17
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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.v' The out-of-state QFs, like all of 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.24
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."25
Do the QFs allow the Company to avoid other costs?
Yes. Without the energy and capacity provided by the QFs, Pacific 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 2013 Electric Integrated Resource Plan, Docket No, UE-120416. Commission
Acknowledgement Letter (Nov. 25, 20 I 3). 24 Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-1 CT at 57. 25 Id. at 58 .
. Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 29
Exhibit No. GND-4T
Page 18
energy trade association ICNU submitted testimony from its expert Mr. Donald W.
contract with the out-of-state QFs at prices equal to Pacific Power's avoided cost.
including the following:
Schoenbeck. ICNU's testimony identified 11 different benefits provided by QFs,
PURPA makes the QF prices extremely relevant. PURPA requires the Company to
*
*
*
*
*
*
*
*
*
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
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.
irrelevant to cost allocation under the WCA.27 How do you respond?
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 I 00 times less likely to lose 1,000
MW of capacity simultaneously.
The fact that not a single party in this case has argued that the QF PPA prices exceed
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26 lnvestigatlon Relating to Electric Utility Purchases from Qualifying Facilities, OPUC Docket No. UM 1129,
Direct Testimony of Donald W. Schoenbeck on Behalf of the Industrial Customers of orthwest Utilities at 6-7
(Aug. 3, 2004). 27 Responsive Testimony ofBradley G. Mullins, Exhibit o. BGM-1 CT at 26.
E h.Rehuttal Testimony of Gregory N. Duvall x ,bit No. 204
Case os. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 30
Exhibit No. GND-4T
Page 19
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Pacific Power's avoided cost prices is significant because, without such a finding, it is
unreasonable to exclude the QF PPAs from rates.
Staff and 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 "set avoided cost rates at higher
or lower levels to reflect state renewable energy policies."29 How do you respond
to these claims?
I disagree with Staff and Boise for several reasons. First, I disagree with the
implication that California and Oregon have inflated the avoided cost prices in the QF
PP As as a reflection of those states' renewable energy policies. It is my
understanding that states cannot set an avoided cost price that includes a "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 Ion� as such action does not
result in rates above avoided cost. 0
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 PP As 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-1 CT at 9-1 O; Responsive Testimony of Bradley G. Mullins,
Exhibit No. BGM-1 CT at 24. 29 Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-1 CT at 27.
30 Re So. Calif. Edison Co., 70 F.E.R.C. � 61,215 at 61,676 ( 1995) (emphasis added).
Rebuual Testimony of Gregory N. Duvall Exh,blt No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 31
Exhibit No. GND-4T
Page 20
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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 alternative 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.31 How do you respond?
I disagree with this characterization. In my testimony, I stress the fact that the out-of-
state QFs provide energy and capacity to serve Washington customers because that
31 Testimony of David C. Gomez, Exhibit No. DCG-1 CT at IO; Responsive Testimony of Bradley G. Mullins,
Exhibit No. BGM-ICT at 25 .
. Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 32
Exhibit No. GND-4T
Page 21
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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 PP As.
Otherwise, Washington customers are receiving the benefits without paying the
associated costs. Thus, the Company's proposal is consistent with principles of cost-
causation.
Staff also discounts the fact that the Commission has allowed Avista
Corporation d/b/a Avista Utilities (Avista) to recover the full costs of out-of-state
QF PP As 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.
32 Testimony of David C. Gomez, Exhibit No. DCG-1 CT at 13 .
. Rebuttal Testimony of Gregory N. Duvall Exh1b1t No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 33
Exhibit No. GND-4T
Page 22
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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 Staff's position in this case?
No. Contrary to Staff's claim that the Commission situs assigned the Idaho QF PPA
costs to Idaho, 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 alternative proposal and 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.?" Thus, the
H Testimony of David C. Gomez, Exhibit No. DCG-ICT at 10 (citing Wash. Utils. & Transp. Comm 'n v. Wash.
Water Power Co., Cause o. U-83-14, Second Suppl. Order, 56 P.U.R.4th 615 (Nov. 9, 1983)). 34 Wash. Utils. & Transp. Comm 'n v. Wash. Water Power Co., Cause No. U-83-14, Second Suppl. Order, 56
P.U.R.4th 615, 1983 WL 909042 at 2 ( ov. 9, 1983).
.Rebunal Testimony of Gregory N. Duvall Exh1b1t No. 204
Case os. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 34
Exhibit No. GND-4T
Page 23
2
3
4
5
6
7
8
9
10 Q.
11
12
13 A.
14
15
16
17
18
19 Q.
20
21
22 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 Idaho.
ln 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.?" 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.
Staff testifies 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 Idaho state policies. In addition, Staff testifies in this case that once
the Commission chose to situs assign the costs to Idaho, the Idaho commission
accepted that decision. Again, however, the Commission did not situs assign the
costs to Idaho, and the order says nothing about how the Idaho commission responded
to the Commission's order.
Staff and Boise reject the Company's alternative proposal to re-price the out-of-
state QF PP As 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
rs Id. at 8.
16 Testimony of David C. Gomez, Exhibit o. DCG-1 CT at 13 n. 24 .
. Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204
Case os. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 35
Exhibit No. GND-4T
Page 24
2
3
4
5
6 Q.
7
8 A.
9
10
11
12
13
14
15
16
17
18 Q.
19
20 A.
21
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.38
Does the Company's 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 PPAs 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
17 Testimony of David C. Gomez, Exhibit o. DCG-1 CT at 15-16; Responsive Testimony of Bradley G.
Mullins, Exhibit o. BGM-ICT at 29-30. 38 Responsive Testimony of Bradley G. Mullins, Exhibit o. BGM-1 CT at 30.
.Rebuttal Testimony of Gregory N. Duvall Exhibit o. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 36
Exhibit No. GND-4T
Page 25
Oregon QF PPAs has allowed Washington customers to receive benefits for which
2
3 Q.
4 A.
5
6
7
8
9
10
11
12
13
14
15
16
17 Q.
18
19
20 A.
they have not paid.
ls there any precedent for this type of re-pricing?
Yes. As discussed above, the Commission used this approach in the 1983
Washington Water Power case relied on by Staff. It is also my understanding that the
North Carolina Utilities Commission (NCUC) took this same approach to a QF PPA
that was approved by the Virginia State Corporation Commission (VSCC). The
NCUC analyzed the QF PPA and concluded that the pricing exceeded the utility's
actual avoided costs.39 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 Idaho Power
Company that required Idaho Power to re-price its Idaho QF PPAs to reflect Oregon's
non-levelized pricing policy.41
Has any party alleged that the Washington avoided cost prices used in the re-
pricing alternative proposal do not accurately reflect the Commission's avoided
cost prices in effect at the time 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
39 Re N. Carolina Power, E-22, SUB 333, 1993 WL 216264 (Feb. 26, 1993} a.ff'd sub nom. N. Carolina Power,
450 S.E.2d 896.
40 State ex rel. Utilities Comm 'n v. . Carolina Power, 338 N.C. 412, 450 S.E.2d 896, 900 ( 1994). Importantly,
as I discuss above, since this case, FERC has been clear that PURPA prohibits inflating the avoided cost price
as the VSCC apparently did to promote state policies.
41 Re Idaho Power Co., Docket No. UE 257, Order o. 13-166 (May 6, 2013).
Rebuttal Testimony of Gregory N. Duvall Exhibit No. 204
Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 37
Exhibit No. GND-4T
Page 26
2
3 Q.
4
s
6 A.
7
8
9
10
11 Q.
12
13
14
15 A.
16
17
18
19
20
21
22
costs that would have been incurred if the out-of-state QF PPAs had been executed in
Washington.
Staff and Boise both reject the Company's alternative load decrement proposal
because they claim it is based on power flows, not cost causation.42 How do you
respond?
The load decrement approach is consistent with cost causation. No party disputes that
the out-of-state QFs serve Washington customers. Washington customers, however,
are not paying their fair share of the costs by paying only current market prices. The
load decrement alternative is intended to account for this fact by allocating additional
costs to Washington to reflect the benefits Washington customers receive.
Boise claims that the load decrement approach is unreasonable because it would
assign more transmission costs to Washington customers even though the
presence of QFs in California and Oregon does not reduce those states' use of
the Company's transmission network.43 Does this claim have merit?
No. Again, no party disputes that the QFs located in California and Oregon serve
Washington customers. As discussed above, Boise's trade group, ICNU, previously
testified before the OPUC that distributed generation, like the out-of-state QFs,
typically decreases the need for transmission because the electricity is generated
closer to load. This is particularly true for the out-of-state QFs because they are
typically located closer to California and Oregon load and therefore use less
transmission to serve that load. So it is reasonable to credit out-of-state customers for
reduced transmission usage due to the QF development in those states.
42 Testimony of David C. Gomez, Exhibit o. DCG-1 CT at 15; Responsive Testimony of Bradley G. Mullins,
Exhibit o. BGM-ICT at 29. 41 Responsive Testimony of Bradley G. Mullins, Exhibit o. BGM-ICT at 29 .
. Rebuttal Testimony of Gregory N. Duvall Exhibit o. 204
Case os. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 38
Exhibit No. GND-4T
Page 27
Q.
2
3
4
5
6 A.
7
8
9
10 Q.
11
12 A.
13
14
Boise claims that it would be unjust, unreasonable, and illegal to include the
costs of the out-of-state QF PP As in rates, in part, because the Commission does
not have jurisdiction over the QFs.44 Is it your understanding that the
Commission must have jurisdiction over PPA counterparties to allow cost
recovery of the PP As in rates?
No. Most, if not all, of the Company's long-term PP As 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 PP As in west control area NPC?
The Company recommends that the Commission allow the Company to include the
costs of California and Oregon QF PP As in west control area NPC in the same
manner as all other west control area generation resources, with a portion of the costs
15 allocated to Washington customers. Alternatively, the Company proposes the out-of-
16 state QF PPAs be re-priced using Washington avoided cost prices and then included
17 in the determination of west control area NPC or that the Commission adopt the
18 proposed load decrement adjustment.
19 Energy Imbalance Market
20 Q. Please describe Boise's adjustment to NPC related to the EIM. •
21 A. Boise proposes to reduce Washington NPC by more than $5 million based on the
22
23
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
44 Responsive Testimony of Bradley G. Mullins, Exhibit No. BGM-ICTat 25.
Rebuttal Testimony of Gregory N. Duvall Exhibit o. 204
Case os. IPC-E-1 S-0 I, A VU-E-1 S-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 39
Exhibit No. GND-4T
Page 28
Q. Does this conclude your rebuttal testimony?
2 A. Yes .
. Rebuttal Testimony of Gregory N. Duvall Exh1b1t o. 204
Case os. !PC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 40
Exhibit No. GND-4T
Page 67
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NOS. IPC-E-15-01, A VU-E-15-01, PAC-E-15-03
J.R. SIMPLOT COMP ANY AND
CLEARWATER PAPER CORPORATION
READING, DI
TESTIMONY
EXHIBIT NO. 205
EXHIBIT
� � �
An IDACORP company
DONOVAN E. WALKER LeadCounNI dwalkerafd1hopow1r.com
April15,2015
VIA HAND DELIVERY
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West. Washington Street
Boise, Idaho 83702
Re: Energy Sales Agreements Tenninations
Case No. IPC-E-14-28, Clark Solar 1, q .. c
Case No. IPC-E-14-29, Clark Solar 2, LLC
Case No. IPC-E-14-30, Clark Solar 3, LLC
case No. lPC-E-14-31, Clark Solar 4, LLC
Dear Ms. Jewell:
On April 6, 2015, Idaho Power Company ("Idaho Power") tenninated the Public
Utility Regulatory Policies Act of 1978 ("PURPA") Energy Sales Agreements ("ESAs•)
with each of the above-referenced PURPA qualifying facilities ("QF"). Each of the
referenced QF ESAs was approved by the Idaho Public Utilities Commission
("Commission") by Order, as noted in the table below.
Project Case Number Order Number Date of Order
Clark Solar 1, LLC IPC-E-14-28 Order No. 33208 01/08/15
Clark Solar 2, LLC IPC-E-14-29 Order No. 33209 01/08/15
Clark Solar 3, LLC IPC-E-14-30 Order No. 33204 01/08/15
Clark Solar 4, LLC IPC-E-14-31 Order No. 33205 01/08/15
Erratas 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 orders approving the ESAs. The required Security Deposits
were not paid, and Idaho Power provided Notice of Default and Material Breach on
March 2, 2015. Subsequently, Idaho Power and the projects' developer, lntennountain
Energy Partners, LLC, entered into an agreement (attached hereto as Attachment 1)
1221 W Idaho St. (83702)
PO. Box ?O Exhibit No. 205
Case Nos. IPC-E-15-0f,0Ji.VeJ�fS-OI, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page I
..
Jean D. Jewell
April15,2015
Page 2 of 2
setting forth the agreed to provisions by which the projects were to cure the Material
Breach of the ESAs. The Security Deposits were not so posted for the above­
referenced Clark Solar projects; thus, the associated ESAs were terminated 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, Idaho Power has
enclosed 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
concerns.
DEW:csb
Enclosures
cc: Dean J. Miller (w/encl.)-vla e-mail
Rick Sterling (w/encl.)-via e-mail
Donald L. Howell, II (w/encl.)- via e-mail
Exhibit No. 205
Case os. I PC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 2
..
ATTACHMENT 1.
..
Exhibit No. 205
Case Nos. I PC -E-15·0 I. A VU-E-15-0 I, PAC -E-15-03
D. Reading, Simplot/Clearwater
Page J
�IDAHO ... POWER0
An IOACORP comp�
DONOVAN E. WALKER LeedCounHI ft'IOWOldahooonLcoro
March 17, 2015
[e-mail] Dean J. Miier McOevitt & Miiier LLP
420 W. Bannock Street P.O. Box 2564-83701 Boise, Idaho 83702
VIA ELECTRONIC MAIL
Re: Security Deposits - Mountain Home Solar 1, Pocatello Soler 1, Clark Solar 1, Clark Solar 2, Clark Solar 3, Clark Solar 4.
Joe:
Idaho Power Is In receipt of the memo from Mark van Gullk dated March 17,
2015, regarding the specific arrangements being pursued by lntermountain Energy
Partners (•tEP•) to cure the material breach of the Energy Sales Agreements ("ESN) for
each of the above referenced solar projects •as expeditiously as possible."
Idaho Power will accept your proposed schedule of events outlined In your March
17, 2015, memo which outlines activities starting today to secure the necessary
deposits and continuing through the stated deadMnes of March 31, 2015, for Mountain
Home Solar and Pocatello Solar - and April 3, 2015, for Clark Solar 1 through 4.
Idaho Power will further accept the proposal of a "Non-Appealable" agreement
and provision that If the deposits are not paid In accordance with these dates, that the
Energy Sales Agreements will immediately terminate, and that IEP will not contest the
termination at the Idaho Public Utilities Commission, or elsewhere. Because of the
shortness of time before tomorrow's ESA termination deadline, please let this letter
serve as both parties' written acknowledgement of this agreement:
Consequently, both Idaho Power Company and lntermountaln Energy Partners
hereby agree that the final and definitive deadline with which IEP ls to cure the material
breach of the ESAs for each of the above referenced solar projects under contract with Idaho Power is March 31, 2015, for Mountain Home Solar and Pocatello Solar - and
April 3, 2015, for Clark Solar 1 through 4, as set forth In IEPs March 17, 2015, memo,
Incorporated herein by this reference.
IEP shall cause the appropriate amount of security deposit, as referenced In
each project's respective ESA, as well as in Idaho Power's March 2, 2015, Notice of
1221 w Idaho SI (83702)
PO 8ox 70
Bnis�. ID 83707
Exhibit No. 205
Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page4
•
Dean J. MIUer
March 17, 2015
Page 2 of 2
Default: Material Breach - and Idaho Power's March 4, 2015, Notice to Tennlnate, to
be posted on or before 5:00 p.m., mountain time, on Tuesday, March 31, 2015, for the
Mountain Home Solar and Pocatello Solar projects - and on or before April 3, 2015, for
Clark Solar 1, Clark Solar 2, Clark Solar 3, and Clark Solar 4. If the required security
deposit Is not paid by these deadlines, then each associated ESA will immediately
tenninate. IEP wlll accept said tennlnatlon and shall not contest said termination In any
manner what-so-ever, either In law or equity, before the Idaho Public Utilities
Commission or any other forum. Idaho Power understands from IEP's March 17, 2015,
memo, and from Its conversations with Mr. van Gullk, and Mr. Miller, that the required
security wlll be posted In cash. If an alternative method Is utlHzed (I.e., letter(s) of credit
or parent guarantees) then the necessary arrangements and approvals of such
altematlve methods must be completed on or before the deadline, or the deadline shall
be deemed to have NOT been met.
If this Is agreeable, please execute this letter below and return a signed copy
back to me.
( 7Lt.«J«-
Donovan E. Walker
Lead Counsel
Idaho Power Company
'\ ------
Agreed to and Accepted by, on behalf of lnterrnountaln Energy Partners:
/J{#,/dv- <:f4x (SO;inature)
l'-'\AR:14: ,.,. •. ,1 ?tu, as- (Printed Name)
M '=+ •A:fa17)/"'P'i2-i» 1'.Dc-':?f (Title)
DEW:csb cc:
Exhibit No. 205
CaseNos. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
D. Reading, Simplot/Clearwater
Page 5
REQ����- �OR PRODUCTION.NO. 22: Reference the Company's response to
J.R. Simplot Co.'a production request no. 4(a)-(c), Indicating that of the 48 prospective
solar QFs comprising the 885 MW of solar QFa that were In the queue at the time Idaho
Power flied the application In this case, 23 had not even provided enough Information to
obtain indicative pricing and only one project had provided enough Information to Idaho
Power to obtain a draft FESA under the IPUC tariff.
a. Please provide an update to the tabte aupplled in response to request no.
4(a)-(c) and for the projects that have not provided enough information to even obtain
Indicative pricing please also explain what lnformatk>n was supplied to Idaho Power that
leads It to believe the project was mealy to be constructed and sell lta output to Idaho
Power. Please also provide an update of the number of projects and MW capacity that
are sun In the PURPA queue and actively seeking FESAa.
b. Please atate the number of projects and MN of capacity that have
provided Idaho Power with evidence that they poa8888 site control In the form of real
property rights to develop the project.
c. Does Idaho Power agree that there ii inaufflclent Information to conclude
that the 880 WI of projects are likely to be buHt and sell their output to Idaho Power? If
not, please explain what Information or basis Idaho Power relies upon and provide all
supporting dOC\.fflents.
RESPONSE TO REQUEST FOR PRODUCTION NO. 22: Idaho Power objects e
to the premise of this Request that Idaho Power has made any aasessment as to the
viability of any project. Idaho Power provided a list of projects seeking ESAa. Idaho
Power is unable to reconcile the referenced table with the count of 23 projects identified.
IDAHO PO'NER COMPANY'S RESPONSES TO THE SECOND
PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY· 8
Ex.h
Case Nos. IPC-E-15-0 I, AVU-E-1.
Witness:
The table referenced Includes proposed qualifying facility {°QFj projects in both the
state of Idaho and Oregon; 22 of the Idaho projects were identified as having not
received indicative pricing and 11 of the Oregon projects had not received Indicative
pricing at the time the information was collected for this table.
a. The updated table ia provided below, the Items highlighted in yellow are
revisions to the table as originally provided in Idaho Power's response to Simplot'a
Request for Production Nos. 4.M.c. Idaho Power includes on this listing, not only the
projects that have provided enough information to obtain Indicative pricing, but also
project requests that have provided information beyond an Initial Inquiry that the project
has potential of being viable. This information is in numerous forms: complete or partial
Schedule 73 or 85 applications, detailed contract questions beyond Initial Inquiry,
e-mails or letters of apparent intent, detaHed phone inquiries, Interconnection inquiries,
etc. In many instances, a single piece of information does not warrant including a
proposed project on this list, but a combination of various pieces accumulated that
suggest a project may be viable.
The last part this Request asks for information on projects that are "still in the
PURPA queue and actively seeking FESAs: The updated list provided in response to
the initial part of this Request is a list of PURPA projects that have contacted Idaho
Power with varying degrees of interest and that are seeking PURPA contracts with
Idaho Power. The level of "activity" of each of these proposed projects differs by project
and by day. This updated list includes an additional 15 projects for 331 MW of potential
projects that have contacted Idaho Power since the preparation of the tabkt provided in
IDAHO POWER COMPANY'S RESPONSES TO THE SECOND PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY· 7
Exhibit No. --- Case Nos. IPC-E-15-0 l, A VU-E-15-0 I, PAC-E-15-03
Witness: ------
the Company', reaponH to Simplot'• Request for Production No. 4. The total number
of potential PURPA projects is now 73 projects for 1,326 MW.
ldlho ,.., COfflplflY
PropoNd PURPA.SOlar • Al of ••11111¥ JI, 1811 April ZZ. 2015 ...
Provided All Provided All
lnformltlon IS Information 11
required In Schedule required In Schedule
73to obtain 73 to otuln a draft Project Is In
Indicative Prldna entf'IYSlles compliance with
(Schedule 73 Items •reement (SChedute SChedule 73 Pace 1,
1.a.l-1dv, paps 4 and 73 items 1.e.1-lv, pqes subpart 1.n or
S) or equlvalent If 5 Ind 6) or equivalent equivalent If process
provided before If provided before was Initiated before
Schedule 73 process SChedule 73 process Schedule 73 process Interconnection
Ntme Initiated Initiated was lnlttated Queue#
1 Project Al Yes Yes Yes
2 Project A2 Yes No Yes
3 Project A3 No No Yes
4 Project A4 No No Yes
5 Project 81 Yes No Yes 467
6 Project 82 Yes No Yes
7 Project Cl Yes No Yes
8 ProjectC2 Yes No Yes
9 Project O Yes No Yes
10 Project C4 Ves No Yes
11 Project CS Yes No Yes
12 Project C6 Yes No Yes
13 ProjectO Yes No Yes
14 ProJectC8 Yes No Yes
15 ProjectC9 Yes No Yes
16 Project CO Yes No Yes
17 Project 01 Yes No Yes
18 Project 02 Yes, No Yes
19 Project 03 Y.91 No Ves
IDAHO POWER COMPANY'S RESPONSES TO THE SECOND
PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY· 8
Exhibit No. ---- Case Nos. lPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
Witness: -------
. . -� ' 415
J •• ··-�-. -'-·"' ·,,
Yes
Yes
Yes
Yes
Yes
Yes
VII
Yes
Yes
No
No
No
No
No
No , ........ ,.- ... _. .... . ... , ........ -: ....
No
.. � ••. ,.,... ·�·. •' .�·- ·,•, •• , •• � \., *"ii'.. ••• • • • �. .!,•• •• ._. •, •, •,. :•. , ..•
. ·-··· ... _ .• . . ... .,... ....
- ·- '· \� ., , ,, . . ,.,... , '�. .. ���- .,,,. �· .·� - .. , - ·�·:
,,.
No
No
Yes
Yes
Yes
No
Yu
Yes
..• .. . t,,., .••.•• ·····--;•+ .... •
Yes
'tts No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
No No Yes
.. ··�. , .: .o • ;Ae.s _, , I.� ( s x�, � .. :.:. t.� •. : a .. u •.•
No """"'�,.,,...._.,....,,..,....,,.. __ ...,,...,..,._._.�.,.._-,-,�.....,.......,,-......,...�,,,._,,,_�,,_.��·�.,�,�,--M.-�·�· .. �"�'�··�-�" .. � ... � .. �.-= ... � .. ���·.�·•�'. No
20 Project D4
21 Project El
22 Project E2
23 Project E3
24 Project E4
25 Project ES
26 Project E6
27 Project E7
28 Project £8
29 ProjectE9
30 Project E10
31 Project Ell
32 Project E12
33 Project Fl
34 Project Gl
35 Project Hl
36 Project 11 . . ' .. ... 37 ProfectU
38 Pro)lctN .. ·.: ... .,;,,. .. , ... •• •",< -· .- ·- :; ...••• \;1·,-.,,. �- ' .•.• 39 Project IS
40 I Profectl&
41 Project OS
42 ProjectD& '..,., .....
43 Profec:I u
44 Project l2
45 Project u No No
.. ,;.1.!..•- :,:. .....•.••. ., .·�··.·'' •\ - •• ,, •••• _. :-. "·�·· � £ ••••• ·,,-1,·-·.·· .. ·.-�.1 -,-._,. ., . Yes
�· ... ,._, ... • • '• - •\,', l J
... � !4,°J',Nil O• •'•"•• o'o""•'• +wO ..... ::-•: ... :. • ,;0'-.)•\• ••U•"lr• • "••• \'
46 ' ProJect 01 No No Yes 419
47 11 Pn,ject 02 1 No No -·-·--' Yes 490
IDAHO POWER COMPANY'S RESPONSES TO THE SECOND
PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY - 9 Exhibit No. ---- Case Nos. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
Witness: -------
ld1ho Power Com,-nv
Preposld PUIIPA Saar· As of ..... "\1:ao, aiU i"'9 22. 2015
Qtmn
Pro)lct Name Sdlldllle n 1s not eppllclbll In or..-
48 ProjectJl Yes· Schedule 85 Yes - Schedule 85 N/A Published Rates Process
49 Protect E13 No No N/A 458
so Project K1 No No NIA
51 ProJectlC2 No No N/A
52 Projec;t IC3 No No N/A
5i Project K4 No No N/A
54 Project KS No No N/A
55 Project IC& No No N/A
56 Project K7 No No N/A
57 Pro.i-ct � No No N/A
SI �K9 No No N/A
59 Project K10 No No N/A
'° Project M1 No No N/A ffl
6% P.ro)ect MZ No No N/A 411
'2 Pr.o)ect M3 No No N/'A
63 �M4 No No N/A
64 P.ro1'ctM5 No � tt/A 479
65 Project Nl No No N/-A 474
" Protect N1 No No N/A 471 :
61 ProiedNS No No N/A •n
61 Ptolect N4 No No ff/A 415
6t Proilct NS No No Pf/A 471
70 Project N& No No N/A - 71 Project Pl No No N/A ...
12 Project Qt No No tf/A 417 ' I
73 Pro)lctQ2 No No N/A ...
IDAHO POWER COMPANY'S RESPONSES TO THE SECOND
PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY -10
Exhibit No. ---- Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
Witness: -------
b. None of the projects listed in the updated table provided in the Companys
response to Simplot's Request for Production No. 22.a have provided specific
information on site control. As this table indicates, only one draft contract has been
provided and the request for that draft contract was made prior to Schedule 73 being
approved by the Commission. Schedule 73 established the specific requirement to
provide evidence of site control prior to a draft contract being provided.
c. This Request references 880 WI of projects. This response is based on
an assumption that the Request intended to reference the 885 MW stated eartier in this
Request. No, Idaho Power does not agree. In addition, as indicated in the Companys
response to Simplot' Request for Production No. 22.a, the 885 MW has now grown to
1,326 MW. Individual QF projects are in sole control of the viability, contracting
process, construction process, and time lines of their specific projects and Idaho Power
has no information to definitively determine what proposed projects do not intend to
complete their respective projects.
The response to this Request is sponsored by Randy Allphin, Energy Contracts
Coordinator Leader, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSES TO THE SECOND PRODUCTION REQUESTS OF THE J. R. SIMPLOT COMPANY - 11
Exhibit No. --- Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
Witness: ------
•
REQUEST NO. 11: For each PURPA contract where the price was set (or to be
set) using an IRP Methodology, please provide the following:
a. The date that the QF originally submitted a request for contract approval;
b. The date that the contract was approved by the Commission;
c. The Commission case number.
d. The nameplate capacit)';
e. The type of project (wind, solar, cogeneration, etc.); and
f. The contracted price for the pwchaee of the output of the facility.
RESPONSE .JO.:. REQUEST �-· 11: lnfonnation for "set (or to be set)" Is
requested; however, items a through f request information In regards to signed and
Commission-approved contracts and much of the requested Information does not yet
exist for contracts that prices are io be set" Therefore, Idaho Power has provided
information for only projects that Include IRP methodology pricing, have been signed by
both parties, and submitted to the Commission requesting it to either accept or reject
the contract.
a. The qualifying faclity does not submit a request for contract approval with
the Convnlsslon as suggested In this Request. Instead, after both parties have
executed a contract. Idaho Power prepares an application and flies this with the
Commission requesting it to either accept or reject the contract. The table below lilts
projects submitted to the Commission to date.
American Fala Solar II, LLC
American Fella Solar, LLC ao. City Solar, LLC
Clari< Saar 1, LLC
Clark Solar 2, LLC
Ctark Sclar 3, LLC
10l20l2014
10l20/2014
07125/'2014
10/17/2014
10/17/2014
10/17/2014
IOAHO POWER COMPANY'S RESPONSE TO THE IDAHO
IRRIGATION PUMPERS ASSOCIATION, INC.'S FIRST DATA REQUEST - 17
E
Case Nos. IPC-E-15-0 I, A VU-E- l
Witness:
Clarie Solw 4, LLC
Grand View Pl/ Solar Two
Mountain Home Solar, LLC
Murphy Flat Power, LLC
Orchard Ranch Solar, LLC
Pocetelo Solar 1, LLC
Simco Solar, LLC
Tuana Springs Expansion
Rockland Wind Fann
High Mesa Wind Project
10/17/2014
07/25/2014
10/17/2014
10120/2014
10/20/2014
10/17/2014
10/20/2014
08/11/2009
09/0812010
11122/2011
b-e. The table below lists projects approved by the Commission to date.
Comm la Ion N.....,._ Tys-of
Pro)lctName Approql Dllte C..Number Cap9clty lMW>. Prolect
American Fills Solar II, LLC 12/Sl2014 IPC-E-14-35 20.00 Solar
American Falls Solar, LLC 121291'2014 IPC-E-14-34 20.00 Solar
Boise City Solar, LLC 11/14/2014 IPC-E-14-20 40.00 Solar
Clark Solar 1, LLC 01/01'2015 IPC-E-14-28 71.00 Solar
Clark Solar 2, LLC 01/01/2015 IPC-E-14-29 20.00 Solar
Clark Solar 3, LLC 01/01/2015 IPC-E-14-30 30.00 Solar
Clark Solar 4, LLC 01/01/2015 IPC-E-14--31 20.00 Solar
Grand View PV Solar Two 11/1412014 IPC-E-14-19 80.00 Solar
Mountain Home Solar, LLC 01/01/2015 IPC-E-14-26 20.00 Solar
Murphy Flat Power, LLC 12/29/2014 IPC-E-14-32 20.00 Solar
Orchard Ranch Solar, LLC 12/29/2014 IPC-E-14-36 20.00 Solar
Pocatello Solar 1, LLC 01/08/2015 IPC-E-14-27 20.00 Solar
Simco Solar, LLC 12/29/2014 IPC-E-14--33 20.00 Solar
Tuana Springs Expansion 10IOSl2009 IPC-E-09-24 35.70 Wind
Rockland Wind Farm 11/24/2010 lPC-E-10-24 80.00 Wind
Hgh Mesa Wind Project 02/17/2012 IPC-E-11-26 40.00 Wind
f. All of the contracts listed above contain a fixed schedule of non-levellzed
prices; therefore. there are different prices for each year and, In some cases, for each
month and for heavy load and light load hours. Provided below are estimated levellzed
prices that are calculated based upon the non-levellzed schedule of prices contained in
each of the above-fisted contracts. These levellzed prices are not specifically stated In
the contracts but are commonly used to provide general information.
IOAHO POWER COMPANY'S RESPONSE TO THE IOAHO
IRRIGATION PUMPERS ASSOCIATION, INC.'S FIRST DATA REQUEST-18
Exhibit No. ---- Case Nos. lPC-E-15-01, AVU-E-15-01, PAC-E-15-03
Witness: ------
American Falla Solar II, LLC
American Falla Solar, UC
Boise Cky Solar, LLC
Clark Solar 1, LLC
Clark Solar 2, LLC
Clark Solar 3, UC
Clark Solar 4, UC
Grand View PV Sol• Two
Mountain Home So&ar, LLC
Mll'phy Flat Power, LLC
Orchard Ranch Solar, LLC
Pocatello Solar 1, LLC
Simco Solar, LLC
Tuana Springs Expansion •
Rocldand Wind Farm
High Mesa Wind Project
$62.86
$63.81
$72.15
$59.97
$81.03
$80.87
$80.87
$73.41
$61.43
$83.80
$62.21
$61.33
$63.94
$75.53
$71.29
$56.43
•Note: The Tuana Springe Expaneion was a negotiated combination of an existing contract with a new contract for expansion d the existing project. In theee negotlationa, the value of the
existing contract was maintained and the expanston was valued at an IRP-bated vakJe
and the two pricee were then blended together to create the morwhly energy prtcee. The value lilted Is the levellzed value d this negotiated blended valle.
The response to this Request Is sponsored by Randy Allphin, Energy Contracts
Coordinator Leader, Idaho Power Company.
DATED at Boise, Idaho, this 11th day of M
DONOVAN E. WALKER
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE IDAHO
IRRIGATION PUMPERS ASSOCIATION, INC.'$ FIRST DATA REQUEST -19
Exhibit No. ---- Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
Witness: ------
REQUEST NO. 9: Please provide a copy of all 20-year levellzed avoided cost
indicative prices provided to the developers of any or all of the solar projects comprising
the 885 Wv of potential new projects referred to In Idaho Power's Petition.
RESPONSE TO REQUEST NO. I: Of the 885 MW of potential projects, 16
projects for 368 MW have been provided some form of avoided cost indicative pncing.
Two of the solar projects were provided 20-year avoided cost Indicative pricing prior to
the filing of this case.
Project Name as Contained Within
Allphin Exhibit No. 3 Estimated Levellzed $/MWh
ProJectA1
Project A2.
$52.83
$54.10
The response to ttils Request is sponsored by Randy Alphin, Energy Contracts
Coordinator Leader, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE COMMISSION STAFF -15
Exhibit No. --- Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
Witness: ------
IDAHO POWER CONPANY
AVOIDED COST RATES FOR WIND PROJECTS
June 1, 20111
$iMW, New Contracts and Realacement Contracts without FuU Canacltv Pavmentl
Ellglbillty for th•• ratlN la llmlted to profec:ta 100 kW or emaller.
LEVELIZED NON-LEVELIZED
CONTRACT OH-LINE YEAR LENGTH CONTRACT NON-LEVELIZED
IYEARSl 2015 2018 2017 2018 2019 2020 YEAR RATES
1 33.38 3<4.08 3<4.<42 35.98 38.37 <43.05 2015 33.38
2 33.70 34.23 35,03 37.<48 41.14 46.99 2018 34.08
3 33.92 34.&a 38.38 39.17 43.81 <47.85 2017 34.42 • 34.31 ss.n 37.84 <41.39 45.33 48.89 2018 35.89
5 35.17 38.&e 39.n 43.09 411.88 411.88 2019 39.37
8 36.24 38.82 41.35 <4<4.47 47.75 50.88 2020 43.05
7 37.88 40.0<4 42.67 '46.59 <48.81 61.87 2021 49.17 8 38.118 41.24 43.78 48.88 49.8-4 52.71 2022 51.40
9 <40.10 42.33 '4U5 '47.73 50.72 53.37 2023 53.25
10 41.09 43.35 45.88 4U3 51.42 53.M 2024 54.59
11 42.05 <44.34 <48.78 48.37 52.03 54.,47 2025 57.23
12 '42.98 <45.20 47.52 50.01 52.80 611.02 2028 69.111
13 43.80 46.93 48.17 50.60 53.17 55.59 2027 60.85
1-4 4-4.50 48.57 48.77 51.19 53.75 58.15 2028 81.00
15 45.13 47.18 49.'8 51.78 54.32 !e.73 2029 81.118
18 45.70 47.7<4 49.114 52.35 54.118 57.33 2030 82.91 17 48.27 48.31 50.51 52.92 65.411 57.95 2031 84.88
18 48.82 48.57 61.07 53.51 58.09 58.54 2032 87.39
18 47.38 49.42 51.65 54.10 58.87 59.17 2033 89.48 20 47.88 49.117 52.23 54.87 57.28 59.83 203,4 71.93
2035 75.31
2038 78.62 2037 80.55
2038 84.88
2039 90.07 2040 95.53
Note: The4e rates ¥111 be further adjusted with the app"Cllble lnllgration charge.
Note: The 111te1 shown In this table h- been computed using the U.S. Energy lnformallon Admlriatratlon (EIA)'I Annual Energy
Outlook 2015, rale.ased Ap,1114, 2015. See Annual Energy Outlook 20i5, Table 3.8 Energy Prioel lYf Sector-Mountain at
hltp:J/www.eia.gov/forl!Cllstsl111olleble1_ref.cfm#supplementl
Exhi
Case Nos. IPC-E-15-01, AVU-E-15-
Witness:
IOAHO POWER COMPANY P9ge 1
IDAHO POWER COMPANY
AVOIDED COST RATES FOR SOLAR PROJECTS
June 1, 2015
S/MWh
New Contracta and R1Dlacem1nt Contracts without Full CaDacltv Pavmenta
EIJglblllty for theae ratea fa limited to projecta 100 kW or amaller.
LEVELIZED NON-l.EVELIZED
CONTRACT ON-LINE YEAR LENGTH CONTRACT NON-LEVELIZED IYEARSl 2015 2018 2017 2018 2019 2020 YEAR RATES
1 33.35 34.08 34.42 35.89 39.37 43.05 2015 33.35
2 33.70 34.23 35.03 37.48 41.14 tl0.03 2015 34.0tl
3 33.92 34.68 38.38 39.17 52.80 88.50 2017 34.42
4 34.31 35.72 37.84 47.88 58.90 70.23 2018 36.89 5 35.17 38.98 44.73 53.50 83.05 72.78 20111 39.37
tl 36.24 42..59 49.88 117.55 ee.o4 74.&II 2020 43.05
7 40.94 48.87 53.42 60.82 68.52 78.89 2021 78.-40
8 44.89 50.28 56.38 83.20 70.85 78.19 2022 81.07 9 47.78 53.05 58.91 85.44 72.41 79.40 2023 &3.35
10 50.32 SS.4tl 81.13 87.31 73.84 110.43 2024 85.12
11 52.57 57.59 83.01 89.88 75.07 111.37 2025 88.22
12 54.59 59.43 64.59 70.18 78.17 112.28 20211 91.35 13 511.35 80.89 85.97 71.39 77.21 83.17 2027 92.75
14 57.88 62.35 97.20 72.51 78.21 84.03 2028 93.37
15 59.19 63.58 88.35 73.57 79.18 84.88 2029 84.51 111 80.39 84.73 88.43 74.57 80.07 115.73 2030 98.23
17 81.51 85.80 70.45 75.52 80.98 88.58 2031 98.78
18 82..58 811.81 71.41 78.45 81.87 87.39 2032 101.69
Ill 83.55 87.n 72.35 77.311 82.71 88.22 2033 104.28
20 84,411 88.70 73.27 78.22 83.58 89.07 2034 107.25 2035 111.14
2038 114.113
2037 117.44
2038 122.31 2039 128.05
2040 134.07
Note. These ratas wRI be further adjusted with the applicable in1eorat1on charge.
Nota: The rat11 shown in this table have b11en com.putlld using Iha U.S. Energy lnlormaUon AdminlSlraUon (EIA)'s Annual Energy
Outlook 2015, raleased April 14, 2015. See Annual Energy Outlook 2015, Table 3.8 Energy Prices by Sector-Mounlaln ,t
hl(p:/lwww.eia.gov/lon!casts/aea/tables _ref.cfm#supplemenV IDAHO POWER COMPANY Paga 2
Exhibit No. ----- Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
\ ' .
IDAHO POWER COMPANY
AVOIDED COST RATES FOR NON-SEASONAL HYDRO PROJECTS
June 1, 2015
1/MWh
New Contracts ind Reolacement Contracts without Full Clp1cltv P1vmenta
Ellglbllity for thffe rates 19 limited to project. smaller thin 10 1MW.
LfVELIZED NON-LEVEUZED
CONTRACT ON·LlNE VEAR
LENGTH CONTRACT NON.tEVEUZEO
CYEARSI 2015 20111 2017 20111 2019 2020 YEAR RATES
1 33.38 3-C.08 34.42 35.89 39.37 43.0S 2015 33.311
2 33.70 34.23 35.03 37,411 41.14 58.117 2016 34.011
3 33.92 34.Ba 36.38 39.17 51.72 84.87 2017 34.42 4 34.31 35.72 37.84 47.23 57.58 Ba.18 2018 35.89 5 35.17 38.96 44.25 52.49 111.-411 70.53 2019 39.37 6 38.24 42.20 411.65 58.211 84.27 72.53 2020 43.05 7 40.82 48.21 52.37 59.18 88.80 74.2.11 2021 75.56
II 44.13 48.41 55.18 61.80 11&.83 75.72 202:2 711.19
9 47.02 52.01 57.54 83.72 70.30 79.87 2023 &o.43 10 49.42 S.t.28 59.85 115.49 71.88 n.116 2024 82.18 11 51.55 66.31 81.43 68.116 72.83 78.76 2025 115.21
12 53.47 �.04 112.9'1 811.23 73.1111 79.113 202e 118.30
13 55.13 59.52 84.24 119.37 74.88 80.50 2027 89.65 14 66.58 eo.112 55,.41 70.44 75.84 81.33 2028 II0.23 15 57.82 111.99 66.51 71.<45 711.75 112.14 2029 91.33 16 58.97 83.08 67.54 72.41 77.63 82.97 2030 n99
17 60.03 &4.11 68.51 73.32 711.50 113.80 2031 85.50
18 61.04 85.07 89.44 74.23 7U7 84.159 2032 811.36
19 &1.98 115.99 70.34 75.11 80.111 85.40 2033 100.IIO
20 62.88 1!11.118 71.22 75.94 111.01 86.23 2034 103.112
2035 107.56
2038 111.45
2037 113.118
2038 1111.87 2039 124.37
2040 130.33
Note: The r,tas shown In lhl111ble have been compvled using the U.S. Enetgy lnformalton .AdmfnlsnUon (EIAY• Annual Energy Outlook 2015, relnaed AprH 14, 2015. Saa Annual Energy Outlook 2016, Tabla 3.6 Energy Prices b'( Sector-Mountain at
http:1/www.eia.gov/foreea.ttslaaolllblee_ref.cfm#supplemanV IOAHO POWER COMPANY Page 3
Exhibit No. ----- Case Nos. IPC-E-15-01, AVU-E-15-01, PAC-E-15-03
Witness: ��������-
IOAHO POWER COMPANY
AVOIDED COST RATES FOR SEASONAL HYDRO PROJECTS
June 1, 2015
S/MV\ltl
New Contractl and Rt1>l1cement Contracts without Full Caoacltv Pavmentl
Ellglblllty for thete ratlta la llmlted to projects smaller tt,,.n 10 aMW.
LEVELIZfD NON-LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-l£VEUZEO
IYEARSI 2015 2018 2017 2018 2019 2020 YEAR RATES
1 33.36 34.oe 34.42 SS.89 39.37 43.0S 2015 33.34
2 33.70 34.23 35.03 37.48 41.14 88.22 2018 34.08
3 33.92 34.88 38.36 39.17 57.84 77.411 2017 34.42
4 34.31 35.72 37.84 51.83 811.41 82.87 2018 35.89
5 35.17 38.96 47.63 59.57 72.80 88,11 2019 39.37
6 36.24 <14.90 54.51 85.18 78.72 88.85 2020 43.05
7 42.8<1 50.&6 59.88 69.:HI 80.01 91.17 2021 95.45 8 <18.03 55.53 83.72 72.83 82.78 113.08 2022 93.37
9 52.23 511.30 87.11 76.78 85.08 94.58 2023 100.90
10 55.70 62.52 70.02 78.20 88.92 95.89 2024 102.93
11 Sa.Tl 85.32 72.<18 80.22 a&.51 97.07 2025 106.29
12 81.37 87.72 74.55 81.97 89.92 98.18 2028 108.89
13 83.68 89.77 78.35 83.52 91.24 99.27 2027 111.35 14 85.85 71.58 77.95 84,114 92.48 100.30 2028 112.24
15 67.39 73.16 79.43 88.28 93.65 101.30 2029 113.87
18 88.98 74.63 80.80 87.52 94.76 102.30 2030 116.66 17 70.40 76.01 82.08 88.70 95.84 103.28 2031 118.50 18 71.75 77.26 83.28 89.94 98.90 104.22 2032 121.70 19 73.00 78.48 84.43 90.93 97.90 105.17 2033 124.58
20 7-4.17 79.83 85.54 91.98 98.89 108.13 2034 127.84
2035 132.04
2036 136.111
2037 138.96
2038 144.14
2039 160.21
2040 158.55
Note: A ·seasonal hydro projeci'' II defined as a genenilloo l'adlty which produces aueast 55� of Its annual generation during lh•
month! of June, July, and August Order 32802.
Note: The rates shown In this table have been computed using the U.S. Ene<gy lnfonnation Administration (EIA)'s Atvwal Energy Outlook :2015, releeied April 14, 2015. s .. Amual Energy Outlook 2015, Table :u Energy Prices by Sector-Mountain at
http:/lwww.aia.gov/forece1tslaeol1ables_ref.cfm#wpplemenV IOAHO POWER COMPANY Page 4
Exhibit No. ----- Case Nos. IPC-E-15-0 l, A VU-E-15-0 l, PAC-E-15-03
Witness: ��������-
I ,
I
IDAHO POWER COMPANY
AVOIDED COST RATES FOR OTHER PROJECTS
June 1, 2015
$/MWh
New Contracts and Raglacemant Contracts without FuU Capacity Pavments
Eligibility for thue rate• la nmltad to prefects smaller than to aMW.
LEVEUZED NON·LEVELIZED
CONTRACT ON-LINE YEAR
LENGTH CONTRACT NON-LEVEUZEO
CYEARSl 2015 2018 2017 2018 2019 2020 YEAR RATES
1 33.36 34.06 34.42 35,69 39.37 43.05 2015 33.36
2 33.70 34.23 35.03 37.4& 41.14 54.97 2018 34.06
3 33.92 34.68 38.36 39.17 '49.35 59.70 2!117 34.'42
4 34.31 35.72 37.84 '45.52 54.01 62.53 2018 35.69
5 35.17 38.96 42.94 49.74 57.15 64.50 2019 39.37
6 3&.24 41.18 48.66 52.83 59.45 68,20 2020 43.05
7 39.76 44.41 49.54 55.20 81.41 87.74 2021 67.86
8 42.82 47.03 51.84 57.24 63.15 69.00 2022 70.37
9 45.00 49.19 53.84 59.05 64.59 70.01 2023 72.50
10 46.99 51.09 55.83 60.57 65.76 70.88 2024 74.11
11 4a78 52.81 57.16 61.83 66.76 71.67 2.025 n.05
12 50.41 54.30 58.44 82.92 67.1!:7 72.45 2026 80.02
13 5182 SS.58 59.55 83.90 88.54 73.23 2027 81.25
14 53.04 58.88 80.56 64.82 89.39 73.98 2028 81.70
15 54.12 57.88 81.50 65.71 70.20 74.73 2029 82.88
18 55.10 58.60 82.41 68.58 70.99 75.49 2!l30 84.22
17 56.01 59.50 83.26 87.37 71.79 76.26 2031 86.59
18 56.89 60.34 84.08 88.18 72.58 78.99 2032 89.32
19 57.71 81.15 84.89 68.98 73.32 77.74 2!133 91.74
20 58.50 81.95 65.63 69.73 74.08 78.53 2034 94.51
2035 98.22
2036 101.87
2037 104. 14
2038 108.&1
2039 114.38
2040 120.18
Note: ·0111er projects• refers to projects other than wind, solar, non-uasonal hydro, and seasomil hydro projects. These •other projects"
may lndude (but are not lrnited lo}: cogeneration, biomass, bioga.s, landfill gas, or geothennal pllljects.
Note: The ,ates shown in this !able hll\/e been computed using the U.S. Energy lnfomlatlon Adninistration (EIA}'s Annual Energy
Outlook 2015, released April 14, 2015 See Anllual En91W OUtlook 2015, Table 3.8 Energy Prices by Sector-Mountain al
hltp://www.ela.govlfo<et8sts/aeollables_ref.dm#s1.1pplamentl lOAHO POWER COMPANY Page 5
Exhibit No. ----- Case Nos. IPC-E-15-0 I, A VU-E-15-0 I, PAC-E-15-03
Witness: ---------
I •
R. THOMAS BEACH
Principal Consultant Page 1
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 energy markets in California, the western U.S., Canada,
and Mexico.
Since 1989, Mr. Beach has participated actively in most of the major energy 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
0 Renewable 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.
0 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.
0 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.
0 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.
0 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-15-01
BEACH,Di
Idaho Conservation League and Sierra Club
Exhibit
R. THOMAS BEACH
Principal Consultant
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
Page 2
•
l. Prepared Direct Testimony on Behalf of Pacific Gas & Electric Company/Pacific Gas
Transmission (I. 88-12-027 - July 15, 1989)
2.
b.
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)
Prepared Rebuttal Testimony on Behalf of the Canadian Producer Group (A.
89-08-024- November 30, 1989)
Natural gas procurement policy; gas cost forecasting.
3. Prepared Direct Testimony on Behalf of the Canadian Producer Group (R. 88-08-018- December 7, 1989)
Brokering of interstate pipeline capacity.
4. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A. 90-08-029 -
November 1, 1990)
Natural gas procurement policy; gas cost forecasting; brokerage fees.
5. 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
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
2
R. THOMAS BEACH
Principal Consultant Page 3
6. a.
b.
Prepared Direct Testimony on Behalf of the Alberta Petroleum Marketing
Commission (R. 88-08-018-January 25, 1991)
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.
7. Prepared Direct Testimony on Behalf of the Canadian Producer Group (A.
90-08-029/Phase II -April 17, 1991)
Natural gas brokerage and transport fees.
8. Prepared Direct Testimony on Behalf of LUZ Partnership Management (A. 91-01-027 -
July 15, 1991)
Natural gas parity rates for cogenerators and solar power plants.
9. Prepared Joint Testimony of R. Thomas Beach and Dr. Robert B. Weisenmiller on Behalf
of the California Cogeneration Council (I. 89-07-004 - July 15, 1991)
10. a.
b.
Avoided cost pricing; use of published natural gas price indices to set avoided cost prices for qualifying facilities.
Prepared Direct Testimony on Behalf of the Indicated Expansion Shippers (A.
89-04-033 - October 28, 1991)
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.
11. Prepared Direct Testimony on Behalf of the Independent Petroleum Association of
Canada (A. 91-04-003-January 17, 1992)
12. a.
b.
Natural gas procurement policy; prudence of past gas purchases.
Prepared Direct Testimony on Behalf of the California Cogeneration Council
(1.86-06-005/Phase II -June 18, 1992) Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council
{I. 86-06-005/Phase II - July 2, 1992)
Long-Run Marginal Cost (LRMC) rate design for natural gas utilities.
13. Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
92-10-017-February 19, 1993)
Performance-based ratemaking for electric utilities.
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
3
R. THOMAS BEACH
Principal Consultant Page4
14. Prepared Direct Testimony on Behalf of the SEGS Projects ( C. 93-02-014/ A. 93-03-053 - May 21, 1993)
15
16.
a.
b.
a.
b.
Natural gas transportation service for wholesale customers.
Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum
Producers (A. 92-12-043/ A. 93-03-038 - June 28, 1993)
Prepared Rebuttal Testimony of Behalf of the Canadian Association of Petroleum Producers (A. 92-12-043/A. 93-03-038 - July 8, 1993)
Natural gas pipeline rate design issues.
Prepared Direct Testimony on Behalf of the SEGS Projects ( C. 93-05-023 -
November 10, 1993)
Prepared Rebuttal Testimony on Behalf of the SEGS Projects (C. 93-05-023 -
January 10, 1994)
Utility overcharges for natural gas service; cogeneration parity issues.
17. Prepared Direct Testimony on Behalf of the City of Vernon (A. 93-09-006/ A.
93-08-022/ A. 93-09-048 - June 17, 1994)
Natural gas rate design for wholesale customers; retail competition issues.
18. 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.
19. Prepared Direct Testimony on Transition Cost Issues on Behalf of Watson Cogeneration
Company (R. 94-04-031/I. 94-04-032- December 5, 1994)
Policy issues concerning the calculation, allocation, and recovery of transition costs
associated with electric industry restructuring.
20. Prepared Direct Testimony on Nuclear Cost Recovery Issues on Behalf of the California
Cogeneration Council (A. 93-12-025/I. 94-02-002-February 14, 1995)
Recovery of above-market nuclear plant costs under electric restructuring.
21. Prepared Direct Testimony on Behalf of the Sacramento Municipal Utility District (A. 94-11-015-June 16, 1995)
Natural gas rate design; unbundled mainline transportation rates.
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
4
R. THOMAS BEACH
Principal Consultant Page 5
22. Prepared Direct Testimony on Behalf of Watson Cogeneration Company (A. 95-05-049 - September 11, 1995)
23. a.
b.
Incremental Energy Rates; air quality compliance costs.
Prepared Direct Testimony on Behalf of the Canadian Association of Petroleum Producers (A. 92-12-043/ A. 93-03-038/ A. 94-05-035/ A. 94-06-034/ A.
94-09-056/A. 94-06-044-January 30, 1996)
Prepared Rebuttal Testimony on Behalf of the Canadian Association of Petroleum Producers (A. 92-12-043/A. 93-03-038/A. 94-05-035/A. 94-06-034/A. 94-09-056/A. 94-06-044- February 28, 1996)
Natural gas market dynamics; gas pipeline rate design.
24. Prepared Direct Testimony on Behalf of the California Cogeneration Council and
Watson Cogeneration Company (A. 96-03-031 - July 12, 1996)
Natural gas rate design: parity rates for cogenerators.
25. Prepared Direct Testimony on Behalf of the City of Vernon (A. 96-10-038 -August 6,
1997)
Impacts of a major utility merger on competition in natural gas and electric
markets.
26. a.
b.
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-January9, 1998)
Natural gas rate design for gas-fired electric generators.
27. Prepared Direct Testimony on Behalf of the City of Vernon (A. 97-03-015-January 16, 1998)
Natural gas service to Baja, California, Mexico.
Crossborder Energy
IPC-E-15-01
BEACH,Di
Idaho Conservation League and Sierra Club
Exhibit 301
5
R. THOMAS BEACH
Principal Consultant Page6
28. a.
b.
c.
Prepared Direct Testimony on Behalf of the California Cogeneration Council and
Watson Cogeneration Company (A. 98-10-012/A. 98-10-031/A. 98-07-005- March 4, 1999).
Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
98-10-012/A. 98-01-031/A. 98-07-005-March 15, 1999).
Prepared Direct Testimony on Behalf of the California Cogeneration Council (A.
98-10-012/A. 98-01-031/A. 98-07-005-June 25, 1999).
Natural gas cost allocation and rate design for gas-fired electric generators.
29. a.
b.
c.
d.
e.
Prepared Direct Testimony on Behalf of the California Cogeneration Council
and Watson Cogeneration Company (R. 99-11-022 - February 11, 2000).
Prepared Rebuttal Testimony on Behalf of the California Cogeneration Council and Watson Cogeneration Company (R. 99-11-022-March 6, 2000).
Prepared Direct Testimony on Line Loss Issues of behalf of the California
Cogeneration Council (R. 99-11-022 -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- 11-022 -April 28, 2000).
Prepared Rebuttal Testimony on Line Loss Issues on behalf of the California
Cogeneration Council (R. 99-11-022 - May 8, 2000).
Market-based, avoided cost pricing for the electric output of gas-fired cogeneration facilities in the California market; electric line losses.
30.
31.
a.
b.
a.
b.
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 l , 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.
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
6
•
R. THOMAS BEACH
Principal Consultant Page 7
32.
33.
34.
35.
a.
b.
a.
b.
a.
b.
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. 00-11-002-April 25, 2001).
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- 11-022-May 7, 2001).
Prepared Rebuttal Testimony on behalf of the California Cogeneration Council
(R. 99-11-022-May 30, 2001).
A voided cost pricing for alternative energy producers in California.
Prepared Direct Testimony of R. Thomas Beach in Support of the Application of
Wild Goose Storage Inc. ( A. 01-06-029-J une l 8, 2001).
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Wild Goose Storage (A. 01-06-029-November 2, 2001)
Consumer benefits from expanded natural gas storage capacity in California.
36. Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Bernardino (I. 01-06-047-December 14, 2001)
Reasonableness review of a natural gas utility's procurement practices and
storage operations.
37. a.
b.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 01-10-024-May 31, 2002)
Prepared Supplemental Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R. 01-10-024-May 31, 2002)
Electric procurement policies for California's electric utilities in the aftermath of the California energy crisis.
Crossborder Energy
IPC-E-15-0L
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
7
R. THOMAS BEACH
Principal Consultant
38. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers & Technology Association (R. 02-01-011-June 6, 2002)
"Exit fees" for direct access customers in California.
39. Prepared Direct Testimony of R. Thomas Beach on behalf of the County of San
Bernardino {A. 02-02-012-August 5, 2002)
General rate case issues for a natural gas utility; reasonableness review of a
natural gas utility's procurement practices.
40. Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Manufacturers and Technology Association (A. 98-07-003 - February 7, 2003)
Page8
..
41.
42.
a.
b.
a.
b.
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 O 1-10-011 - 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 & 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. 02-06-041-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 Energy Association (R. 01-10-024 - April 1, 2003)
Design and implementation of a Renewable Portfolio Standard in California.
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
8
R. THOMAS BEACH
Principal Consultant Page9
44. a.
b.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California
Cogen era ti on Council (R. 01-10-024 - June 23, 2003)
Prepared Supplemental Testimony of R. Thomas Beach on behalf of the California
Cogeneration Council (R.01-10-024- June 29, 2003)
Power procurement policies for electric utilities in California.
45. Prepared Direct Testimony of R. Thomas Beach on behalf of the Indicated Commercial Parties (02-05-004-August 29, 2003)
46. a.
b.
Electric revenue allocation and rate design for commercial customers in southern California.
Prepared Direct Testimony of R. Thomas Beach on behalf of Calpine Corporation and the California Cogeneration Council (A. 04-03-021 - July 16, 2004) Prepared Rebuttal Testimony of R. Thomas Beach on behalf of Calpine
Corporation and the California Cogeneration Council (A. 04-03-021 - ] uly 26,
2004)
Policy and rate design issues for Pacific Gas & Electric's gas transmission system (Gas
Accord III).
47. 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.
48.
49.
a.
b.
a.
b.
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 - January 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- January 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.
Crossborder Energy
IPC-E-I5-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
9
R. THOMAS BEACH
Principal Consultant Page 10
I'
50. 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.
51. 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- July 29, 2005)
52.
53.
54.
a.
b.
a.
b.
a.
b.
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)
A voided cost rates and contracting policies for QFs in California
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 -January 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, revenue allocation, and rate design for commercial and industrial electric customers in southern California.
Prepared Direct Testimony of R. Thomas Beach on behalf of the California Producers ( R. 04-08-018 - January 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.
55. 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.
56. Prepared Direct Testimony of R. Thomas Beach on behalf of the California Cogen era ti on Council (A. 05-12-030-March 29, 2006)
Review and approval of a new contract with a gas-fired cogeneration project.
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
10
)
R. THOMAS BEACH
Principal Consultant Page 11
57. a.
b.
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-July 14, 2006)
Prepared Rebuttal Testimony ofR. Thomas Beach on behalf of Watson
Cogeneration, Indicated Producers, the California Cogeneration Council, and the California Manufacturers and Technology Association (A. 04-12-004-July 31, 2006)
Restructuring of the natural gas system in southern California to include firm capacity rights; unbundling of natural gas services; risk/reward issues for natural gas utilities.
58. Prepared Direct Testimony ofR. Thomas Beach on behalf of the California Cogeneration Council (R. 06-02-013- March 2, 2007)
Utility procurement policies concerning gas-fired cogeneration facilities.
59.
60.
61.
a.
b.
a.
b.
a.
b.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance
(A. 07-01-04 7 - August 10, 2007)
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 -June 13, 2008)
Utility subscription to new 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)
lssues concerning the design of a utility-sponsored program to install 500 MW of utility- and independently-owned solar photovoltaic systems.
Crossborder Energy
IPC-E-15-0 l
BEACH,Di
ldaho Conservation League and Sierra Club
Exhibit 301
I I
R. THOMAS BEACH
Principal Consultant Page 12
62. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
08-03-002 - October 31, 2008)
Electric rate design issues that impact customers installing solar photovoltaic
systems.
63.
64.
65.
a.
b.
a.
a.
b.
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,
2008)
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 - January 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. 10-03-028-0ctober 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)
Revisions to a program of firm backbone capacity rights on natural gas pipelines.
66. 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.
67. 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 & Electric natural gas pipeline system.
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
12
R. THOMAS BEACH
Principal Consultant Page 13
68. a.
b.
c.
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.
69. Prepared Direct Testimony of R. Thomas Beach on behalf of The Vote Solar Initiative
(A. 10-11-015-June 1, 2011)
Distributed generation policies; utility distribution planning.
70. Prepared Reply Testimony of R. Thomas Beach on behalf of the Solar Alliance (A.
l 0-03-014-August 5, 2011)
Electric rate design for commercial & industrial solar customers.
71. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries
Association (A. 11-06-007-February 6, 2012)
Electric rate design for solar customers; marginal costs.
72. a.
b.
Prepared Direct Testimony of R. Thomas Beach on behalf of the Northern
California Indicated Producers (R.11-02-019-January 31, 2012)
Prepared Rebuttal Testimony of R. Thomas Beach on behalf of the Northern
California Indicated Producers (R. 11-02-019-February 28, 2012)
Natural gas pipeline safety policies and costs
73. 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.
74. Prepared Direct Testimony of R. Thomas Beach on behalf of the Southern
California Indicated Producers and Watson Cogeneration Company (A. 11-
11-002-J une 19,2012)
Natural gas pipeline safety policies and costs
Crossborder Energy
IPC-E-15-0 I
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 30 I
13
R. THOMAS BEACH
Principal Consultant Page 14
75.
76.
a.
b.
a.
b.
Testimony of R. Thomas Beach on behalf of the California Cogeneration
Council (R. 12-03-014-June 25, 2012)
Reply Testimony of R. Thomas Beach on behalf of the California Cogeneration
Council (R. 12-03-014-July 23, 2012)
Ability of combined heat and power resources to serve 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. 11-11-002, 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. 11-
11-002, Phase 2-December 14, 2012)
Allocation and recovery of natural gas pipeline safety costs.
77. Prepared Direct Testimony of R. Thomas Beach on behalf of the Solar Energy Industries Association (A. 12-12-002-May 10, 2013)
Electric rate design for commercial & industrial solar customers.
EXPERT WITNESS TESTIMONY BEFORE THE COLORADO PUBLIC UTILITIES COMMISSION
I. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Colorado Solar
Energy Industries Association and the Solar Alliance, (Docket No. 09AL-299E - October 2,
2009).
Electric rate design policies to encourage the use of distributed solar generation.
2. Direct Testimony and Exhibits of R. Thomas Beach on behalf of the Vote Solar Initiative and the Interstate Renewable Energy Council, (Docket No. l 1A-418E- September 21,
2011).
Development of a community solar program for Xcel Energy.
Crossborder Energy
IPC-E- 15-0 I
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
14
R. THOMAS BEACH
Principal Consultant Page 15
EXPERT WITNESS TESTIMONY BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
1. Direct Testimony of R. Thomas Beach on behalf of the Idaho Conservation League (Case No. IPC-E-12-27-May 10, 2013)
Costs and benefits of net energy metering in Idaho.
EXPERT WITNESS TESTIMONY BEFORE THE PUBLIC SERVICE COMMISSION OF NEV ADA
l. Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 97-2001-May 28, 1997)
A voided cost pricing for the electric output of geothermal generation facilities in
Nevada.
2. Pre-filed Direct Testimony on Behalf of Nevada Sun-Peak Limited Partnership (Docket No. 97-6008-September 5, 1997)
3. Pre-filed Direct Testimony on Behalf of the Nevada Geothermal Industry Council
(Docket No. 98-2002-June 18, 1998)
Market-based, avoided cost pricing for the electric output of geothermal generation facilities in Nevada.
EXPERT WITNESS TESTIMONY BEFORE THE NEW MEXICO PUBLIC REGULATION
COMMISSION
1. Direct Testimony of R. Thomas Beach on Behalf of the Interstate Renewable Energy
Council (Case No. 10-00086-UT-February 28, 2011)
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, 2011)
Cost cap for the Renewable Portfolio Standard program in New Mexico
Crossborder Energy
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
15
R. THO.MAS BEACH
Principal Consultant Page 16
EXPERT WITNESS TESTIMONY BEFORE THE PUBLIC UTILITIES COMMISSION OF
OREGON
1.
2.
a.
b.
a.
b.
Direct Testimony of Behalf of Weyerhaeuser Company (UM 1129-
August 3, 2004)
Surrebuttal Testimony of Behalf of Weyerhaeuser Company (UM
1129- October 14, 2004)
Direct Testimony of Behalf of Weyerhaeuser Company and the Industrial Customers of Northwest Utilities (UM 1129 I Phase II -
February 27, 2006)
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 TESTIMONY BEFORE THE VIRGINIA 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-
2011-00088, October 11, 2011)
Standby rates for net-metered solar customers, and the cost-effectiveness of net energy metering.
EXPERT WITNESS TESTIMONY BEFORE THE MINNESOTA PUBLIC UTILITIES
COMMISSION
I. 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 [OAH Docket No. 8-2500-30760, MPUC
Docket No. E002/CN-12-1240, September 27 and October 18, 2013])
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 CAROLINA 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 Utility Purchases from Qualifying Facilities- 2014;
Docket E-100 Sub 140; April 25, May 30, and June 20, 2014)
Testimony on avoided cost issues related to solar and renewable
qualifying facilities in North Carolina.
IPC-E-15-0 l
BEACH,Di
Idaho Conservation League and Sierra Club
Crossborder Energy
R. THOMAS BEACH
Principal Consultant
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:
Page 17
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 Qualifying 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-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 301
2
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
CASE NO. PAC-E-15-03
Idaho Conservation League and the Sierra Club
Direct Testimony of R. Thomas Beach
Exhibit 302
Idaho Power Responses to:
A. Commission Staff Request No. 2
B. !CL/Sierra Club Request No. 5
C. Commission Staff Request No. 18
D. J.R. Simplot Request No. 16
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
0
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
CASENO. AVU-E-15-01
CASE NO. PAC-E-15-03
Idaho Conservation League and the Sierra Club
Direct Testimony of R. Thomas Beach
Exhibit 302
Idaho Power Responses to:
A. Commission Staff Request No. 2
B. !CL/Sierra Club Request No. 5
C. Commission Staff Request No. 18
D. J.R. Simplot Request No. 16
--
IPC-E-15-01
BEACH,Di
Idaho Conservation League and Sierra Club
Exhibit 302
0
)
REQUEST NO. 2: Idaho Power's Petition states on page 21 "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 Idaho Power expects rates will
increase, has the Company estimated the approximate rate or revenue requirement
increase? If so, please provide the estimate.
RESPONSE TO REQUEST 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 satisfy any near-term capacity or energy requirements.
The response to this Request is sponsored by Mike Youngblood, Regulatory
IPC-E-15-0 I
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
Account 547.
RESPONSE TO REQUEST NO. 5:
c. If available, please provide the data in Exhibit No. 8, plus the data
(
2
Exhibit 302
REQUEST NO. 5: Please reference the Direct Testimony of Mr. Aliphin Exhibit
capital additions, or the costs associated with the return on rate base and associated
gas, oil, kerosene, and gasoline used in other power generation (FERC Account 547).
No. 8 that shows certain FERC account expenses for the years 2010, 2012, and 2013:
a. Do FERC Account Nos. 501 (coal) and 547 (gas) include either fixed O&M
Uniform System of Accounts definitions for those respective FERC accounts. In this
and associated taxes for Idaho Power-owned coal and gas plants?
a. No. The cost items that fall within Federal Energy Regulatory Commission
requested in Part (a) of this question, for the years 2011 and 2014.
b. Please provide the fixed O&M costs, incremental capital additions, and the
Projects Manager, Idaho Power Company.
electricity (FERC Account 501) and cost of fuel delivered at the station of all fuel, such as
case, they are fuel-related expenses for the production of steam for the generation of
revenue requirements associated with the return on rate base and associated taxes for
They do not include fixed operation and maintenance ("O&M") costs, incremental
("FERC'') Accounts 501 (coal) and 547 (gas) are those items which fall within the FERC
costs, incremental capital additions, or the costs associated with the return on rate base
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
taxes.
IPC-E-15-0 l
B.t.ACH, Di
Idaho Conservation League and Sierra Club
)
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
h ttp://www. puc.idaho.qov/ fiteroom/ cases/ sum mary/1 PCE081
O.htm I
Year2012- CaseNo.IPC-E-11-08
h ttp://www. puc.idaho.qov/fileroom/ cases/ summary/IPCEI I
OS.html
Year20l3-Case No. IPC-E-12-14
http :Ilwww.puc.idaho.gov/fileroom/cases/summary/l
PCE1214.html
c. The information requested for 2011 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 Manager, Idaho Power Company.
IPC-E-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
3
REQUEST NO. 18: 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 REQUEST NO. 18: No.
The response to this Request is sponsored by Mike Youngblood, Regulatory
Projects Manager, Idaho Power Company.
IPC-E-15-0 l
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 potential way to reduce costs associated with intermittent generation or
for any other reasons? Jf not, why not? Please provide all studies or analyses of the
impacts of Idaho Power joining the PacifiCorp-California ISO energy imbalance
market.
I ANSWER TO REQUEST FOR PRODUCTION NO. 1 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 energy 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-15-0 I
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 302
5
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
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-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 303
0
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
'
�.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
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-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 303
0
California ISO
Shop ng o Renewed Future
.,.NV Energy
, • MIDAMtflCAI', c,,.-,v.v HOU)INGS COMN.HY
.-,
t'
Seven states participating in the Energy Imbalance Market
The /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
(FERG) and the Public Utilities Commission of Nevada (PUCN) and will go live with the Energy Imbalance Market
(EIM) in fall of 2015 Studies conducted by both companies of their participation in EIM show significant economic
and reliability benefits that accrue to customers in the NV Energy. PacifiCorp, and ISO areas. Participants in the EIM
can leverage genera/Jon 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 important tool for operators across the region to
facilitate increased integration of renewable resources.
Background
The /SO announced a partnership with Portland-based PacifiCorp in February 2013 to develop an EIM that would
operate across participating balancing areas. Following a robust public stakeholder process. the /SO developed a
market design that was approved by the ISO Board in November 2013. PacifiCorp began participating in the EIM in
November 2014. With NV Energy, the expanded EIM would cover seven states 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
operators real-time visibility across neighboring
grids. The /SO is leveraging its existing market
systems to identify fluctuations in supply and
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
systems automatically manage congestion on
transmission lines.
Renewable integration benefits
While the nation's energy supply becomes
more diverse, regional coordination and finely
tuned dispatches become more important as
changing 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-15-01
BEACH, Di Idaho Conservatioi, _:ague _
Exhibit 303
integrated onto the grid By combinmg the NV Energy PacifiCorp and ISO 's diverse portfolio. the
seven-state EIM will make it possible 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-state EIM footpnnt outweigh the costs of
part1c1patmg in the EIM In 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 part1c1patmg balancmg authorities mamtain
operational control over their generatmg resources retam all their obligations as a balancmg area. and
must still comply with all regional and national rellabillty standards For example. obligations to provide
reliab1/1/y compliance ancillary services. physical schedulmg nghts and bdateraf trades do not change
with EIM
A market-based solution
The /SO already operates a successful real-time fifteen mmute market with tive-mmute dispatch
capability This is a tned and true service that exists m a s1m1/ar form m two-thirds of the United States.
particularly tn the Northeast and Midwest as well as much of Canada This partnership signals
contmumg mterest from other balancmg areas m ;oinmg what 1s already workmg effectively to lower
costs and at the same time expandmg the pool of resources available to meet supply and demand
needs in real time ft is a voluntary and natural step toward the more efficient management of energy
systems for the benefit of customers
Governance
The ISO EIM expansion requires that all entities. whether inside or outside California. are qtven a voice tn the decision-making process going forward In May 2014 the ISO Board of Governors appomted the
EIM Transitional Committee that is workmg towards the development of a long term mdependent
governance proposal that will go through a stakeholder process in 2015 The Board advisory
committee is composed of 9 members who were nommated 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 makmg the EIM a truly western
market and encourage broad participation
Next steps
Work is underway to integrate NV Energy into the EIM in October. 2015. The ISO began publishing in
February 2015 quarterly reports of the actual EIM benefits based on actual operating data.
Beginning in 2014 and contmuing 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 EIM They will then seek FERG acceptance in mid-2015
During 2015. the ISO will complete the stakeholder process for Year 1 Enhancements to EIM. to
address FERG compliance. commitments made dunng the original stakeholder process. and others
identified during tmplememeuon Continued stakeholder mvolvement will be critical to the 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-15-01
BEACH, Di
Idaho Conservation League and Sierra Club
Exhibit 303
2
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
CASE NO. PAC-E-15-03
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 Institute, July 2012) (Executive Summary)
based on actual Mid-C prices in Year 11, which could be higher or lower than the originally
2 forecasted $45 per MWh.'1
3
4
5
Q:
A:
Does this conclude your rebuttal testimony as of May 14, 2015?
Yes.
11 This simplified example uses annual prices. lt is my understanding that the !RP method uses much more
granular prices disaggregated by month and High Load/Low Load hours, so the calculation proposed here would be
performed on that more granular basis.
IPC-E-15-01 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 July 2012
Roe Ky
MOUNTAIN INSTITUTE•
Rnr1<v IVIOUNT.6.1 1 c;T1T1 tTE I RM• nRr,
2317 Snowmass Creek Rd. Snowmass, CO 81654
Acknowledgements
Special thanks to Amory Lovins, Dan Seif and Jon Creyts of Rocky Mountain Institute,
and the following individuals for their valuable insight:
Will Babier, 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
Jenny Heeter, NREL
Dr.Takulde,Koveva
Buck Martinez and David Bates, Florida Power & Light
Edward May, US Renewables Group
Duncan Mcintyre, 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.
2
Table of Contents
ACKNOWLEDGEMENTS 2
EXECUTIVE SUMMARY 4
BACKGROUND 5
WHAT IS VOLATILITY? 6
HISTORICAL VOLATILITY 7
IMPLIED VOLATILITY 7
RISK DISTRIBUTION 8
VOLATILITY PRICING 10
THEORETICAL MODELS 11
UTILITY HEDGING STRATEGIES 12
SOLUTIONS 15
CASE STUDIES 17
UTILITY: PUBLIC SERVICE COMPANY OF COLORAD0 17
INDUSTRIAL AND LARGE COMMERCIAL CUSTOMERS: ALTENEX BUSINESS MODEL. 19
COMMERCIAL AND RESIDENTIAL CUSTOMERS: AUSTIN ENERGY GREENCHOICE 19
CONCLUSION 20
APPENDIX 21
3
EXECUTIVE SUMMARY
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 risks 1:
• 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 generation 2.
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.
• 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 must 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
Office of the Secretary
Service Date
October 29, 2014
BEFORE THE mAHO PUBLIC UTILITIES COMMISSION ..
. ' �-THE MATl"Ell OF THE APPLICATI6N )
OFID�POWERCOM.PANYFOlt · ) CASE:NO.IPC�l�ll
CONFIRMAT-ION OF THE CAPACITY )
DEl.clCIENCY PERJffllFOR }
IN�ALOOS'l',@'EG�TED ) . RFSOUllCE- PLAN, AVOIDED COST . )
METHODOLOGY� ) ---------------
Idaho Power Company filed aa Application with the Commission on August 13,
2014, requesting that � Commissloe issue aa Order con.firming the use of a July 202.\ capacity
deficiency period in . the. approved incremental cost, integrated resource pJan, �v� cost
methqcio.logy .(IRP. methodology) .applicable. to aegotiated. avoided. �.rates--� proposed
PURPA qualifyiag facilities (QFS).
On September 4� 2014, the Commission issued a Notice of. Application and, Notice of
Modified Procedmc setting a comment-deadline of Sepeember 30, 2014., and-a reply-deadline of.
October 7, 2014. Idaho Conservation League (ICL) and Intamountain Eaergy. Partners LLC ..--. ..
petitiODCd for, and were granted, intervention. Order Nos. �3135 and l3't46. ·On September 29, . . ; . . 2014, ICL filed a-motion to extend tltc com.meat �line an additional OO�day.s. Idaho Power
opposed f,be 1DQtion .but � �as an altemative to ��te �- respoases, extend the
comment deadline to October 6 and allow until October 10 for the Company1 to file a reply. ICL . . .
accepted Idaho ·Power's proposal to modify the schedule. On September 30, 2014, the
Commission approved the modified schedule. Order No. 33147.
By this Order, and as set out in greater detail below, we confirm July 2021 as Idaho
Power's capacity deficieocy period for purposes of incremental avoided cost calculations within :
the 1RP �logy. .
bACKGROUND
On December 18. 2012. the Commission Issued Ordcc No. 32697 authorizing the use .. . .. • . '
of Idaho Power's incre�tal cost IRP methodology. Solar and wind QF projects that exceed
• • • ,I
100 k.U<>�atts (kW) and· all otfkas QF. generation that exceeds 10, avenge, �watts (aMW) . . � �·
ne� avoided cost .rates based· on the approved incremental cost, �. �logy� In _i�
Order, the Comm.imon stated "We (urtber find it appropriate to identify each utilit,y's C3paCity
OR.DER NO 33159· • < ..
ORDER NO. 33159 l
___ ,·
-----
FINDINGS AND CONCLUSIONS
The Idaho Public Utilities Commission has jurisdiction over Idaho Power. an electric
utility. and the issues raised in this matter pursuant to the authority and power granted it under
Title 61 of the Idaho Code and the Public Utility Regulatory Policies Act of 1978 (PURP A). The
Commission bas authority under PURP A and the implementing regulations of the Federal
Energy Regulatory Commission (FERC) to set avoided costs, to order electric utilities to enter
into fixed-term obligations for the purchase of energy from qualified facilities (QFs) and to
. implement FERC rules.
PURP A requires that utilities purchase generation produced by QFs under a federal
rate mechanism (i.e., avoided cost) that is established and implemented by state utility
commissions. Order No. 32697 at 7. The rates at which Idaho electric utilities purchase QF
power must be approved by this Commission. Idaho Power Co. v. Idaho Public Utilities
Commission. 155 Idaho 780, 789. 316 P.3d 1278. 1287 (2013). The IRP methodology, at issue
here, takes into account many different variables and produces a result based on the
characteristics of the generation and each individual utility's need for the resources. Specifically .
with regard to capacity, we have previously stated that
In calculating a QF's ability to contribute to .a utility's need for capacity, we
find it reasonable for the utilities to only begin payments for capacity at such
time that the utility becomes capacity deficient. If a utility is capacity surplus;
then capacity is not being avoided by the purchase of QF power. By including
a capacity payment only when the utility becomes capacity deficient, the
utilities are paying rates that are a more accurate reflection of. a true avoided
cost for the QF power.
Order No. 32697 at 21. Consequently. it would be unreasonable to ignore more than 400 MW of
demand response resources when determining Idaho Power's capacity deficit as it pertains to the
IRP methodology.
We acknowledge that demand response was not a variable that this Commission
recognized would be updated in the IRP methodology between IRP filing cycles (every two
years.) Order No. 32697. However, because we are a regulatory agency that performs both
judicial and legislative functions, we are not so rigidly bound by the doctrine of stare decisis.
Idaho Power Co: v. Idaho PUC, 155 Idaho 780, 788, 316 P.3d 1278. 1286 (2013). Under
ordinary circumstances, Idaho Power' s demand response resources would have been considered
within the Company's integrated resource planning process and already taken into account..
ORDER NO. 3�159 7
Idaho Power Company
I.P.U.C. No. 29, Tariff No. 101 Original Sheet No. 73-1
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per Q.N. 33197
Jean D. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO
AVAILABILITY
In all electric territory served by the Company in the State of Idaho.
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 Idaho,
or (ii) delivering the output to the Company at a point of delivery ("POD") on the Company's electrical
system within the State of Idaho.
A Customer 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 Idaho 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.
Cogeneration Facility means equipment used to produce electric energy and forms of useful
thermal energy (such as heat or steam) used for Industrial, commercial, heating, or cooling purposes,
through the sequential use of energy.
Dally Shape Adjustment 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.
Eligibility Cap means for all Qualifying Facilities except wind and solar Qualifying Facilities, 1 O
average megawatts in any given month. For wind and solar Qualifying Facilities, "Eligibility Cap"
means 100 kilowatts ("kW") nameplate capacity.
Facility means the electric generation facility owned by the Customer that ls located on the
Customer's side of the POD, and all facilities ancillary and appurtenant thereto, including
Interconnection equipment.
Heavy Load Hours means the daily hours from hour ending 0700 - 2200 Mountain Time, (16
hours) excluding all hours on Sundays, New Years Day, Memorial Day, Independence Day, Labor Day,
ThanksgMng Day, and Christmas Day.
Light Load Hours means the daily hours from hour ending 2300 - OMO Mountain Time, (8
hours) plus all hours on Sundays, New Years Day, Memorial Day, Independence Day, Labor Day,
Thanksgiving Day, and Christmas Day.
IDAHO
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, R ·
1221 West Idaho St
Idaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Original Sheet No. 73-2
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per O.N. 33197
Jean D. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE- IDAHO
(Continued)
DEFINITIONS (continued)
Integration Charges means the Commission-approved integration charge applicable to any
intermittent generation resource, including but not limited to, wind and solar generation.
Generator Interconnection Agreement ("GIA"). 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. If 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 Delivery (POD) is the location specified in the GIA (or Transmission Agreement) where
the 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.
Qualifying Facility shall mean a Cogeneratlon 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. § 292.101(b)(1) (2010), as may be amended or superseded.
Seasonal Factors means a seasonal weighting of 0.735 for the months of March, April, and
May, 1.20 for the months of July, August, November, and December and 1.00 for the months of
January, February, June, September, and October.
Small Power Production Facility 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 Agreement. If 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
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 2 of 10
Idaho Power Company ·
1.P.U.C. No. 29, Tariff No. 101 . Original Sheet No. 73-3
IOAHO PUBLIC UTILITIES COMMISSION
Approved Effective Jan.8,2015 Jan.1,2015
Per O.N. 33197
Jean 0. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO
(Continued)
RATES OPTIONS (Continued)
1. Levellzed 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 Integration Charges.
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 Integration Charges.
3. Levellzed 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 fossil fuels 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 Integration 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 Daily Shape Adjustment, and Integration
Charges.
5. Rates Determined at the Time of Delivery. Please see the Company's tariff Schedule
86.
6. Integrated Resource Plan {"IRP") Based Rate. The IRP Based Rate is required for all
Qualifying Facilities that do not meet the Eligibility Cap and shall be calculated based on the
Incremental Cost IRP Methodology tailored to the individual characteristics of the proposed Qualifying
Facility.
CONTRACTING PROCEDURES
The Company agrees to adhere to the following contract procedures for the purchase of output
from Customers who own Qualifying 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
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 3 of 10
Idaho Power Company
I.P.U.C. No. 29, Tariff No. 101 Original Sheet No. 73-4
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per O.N. 33197
Jean D. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE- IDAHO
(Continued)
CONTRACTING 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 Agreement
Application utilizing the Application template included In this Schedule. The information required
within the application Is general information as listed below.
i. Qualifying Facility owner name, organizational structure and chart, contact
information, and project name;
ii.
Facility;
Generation and other related technology applicable to the Qualifying
iii. Maximum design capacity, station service 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 Qualifying Facility electric output, in an 8,760-hour
electronic spreadsheet format;
v.
Company;
Ability, if any, of Qualifying Facility to respond to dispatch orders from the
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, tf
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. Interconnection agreement status; and
lDAHO
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 4 oflO
' 1-
1
Idaho Power Company
I.P.U.C. No. 29, Tariff No. 101 Original Sheet No. 73-5
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per O.N. 33197
Jean D. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO
(Continued)
CONTRACTING 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 t.a., the Company shall, within 10 business days, notify the
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 proposal within 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. If 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. In
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.
ii.
IDAHO
Issued per Order No. 33197
Effective - January 1, 2015
Updated information of the categories described in Section 1.a.
Evidence of site control for the entire contracting term
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, .Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 5 of 10
Idaho Power Company
I.P.U.C. No. 29, Tariff No. 101 Original Sheet No. 73-6
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per O.N. 33197
Jean D. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO
(Continued)
CONTRACTING PROCEDURES (Continued)
1. Procedures (Continued)
iii.
to include:
Anticipated timelines for completion of key Qualifying Facility milestones,
(a)
(b)
(c)
(d)
(e)
(f)
(g)
applicable.
Licenses, permits, and other necessary approvals;
Funding;
Qualifying Facility engineering and drawings;
Significant equipment purchases;
Construction agreement(s);
Interconnection agreement(s); and
Signing of third-party Transmission Agreements, where
iv.
proposal.
Additional information as explained in the Company's indicative pricing
f. If the Company determines that the Customer has not provided sufficient
information as required by Section 1.e., the Company shall, within 1 O 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.g., the Customer shall review the draft ESA and shall (a) notify the
Company in writing that it 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, Customer shall
contact the Company to schedule ESA negotiations at such times and places as are mutually
agreeable to the parties.
IDAHO
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 6 of 10
Idaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Original Sheet No. 73-7
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan. 1,2015
Per O.N. 33197
Jean D. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO
(Continued)
CONTRACTING PROCEDURES (Continued)
1. Procedures (Continued)
j. In 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
Qualifying Facility or proposed terms of the draft ESA;
iv. Shall Include any revised contracting terms, standards, or requirements
that have occurred 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.
I. 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. If the Customer does not execute the final
ESA per Section 1.1, such final ESA shall be deemed withdrawn and the Company 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
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXillBIT 401
Page 7 of 10
Idaho Power Company
I.P.U.C. No. 29. Tariff No. 101 Original Sheet No. 73-8
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per O.N. 33197
Jean D. Jewell Secretary
SCHEDULE 73
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE- IDAHO
(Continued)
CONTRACTING PROCEDURES (Continued)
2. Interconnection. Transmission Agreements. and Designated 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
Company'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. Qualifying Facility Energy Sales Agreement Application
(FORM STARTS ON NEXT PAGE)
IDAHO
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 8 of 10
Idaho Power Company
I.P.U.C. No. 29, Tariff No. 101 Original Sheet No. 73-9
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per O.N. 33197
SCHEDULE 73 Jean D. Jewell Secretary
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE- IDAHO
(Continued)
QUALIFYING FACILITY ENERGY SALES AGREEMENT APPLICATION
Idaho Power Qualifying Facility (OF) contact Information:
Mailing Address:
Physical Address:
Telephone number:
E-Mail Address:
Preamble and Instructions
Attn: Energy Contracts, PO Box 70 Boise. ID 83702
1221 W. Idaho Street, Boise. ID 83703
208-388-6070
[e-mail]
All generation facilities that qualify pursuant to Idaho Power Company Schedule 73 for a OF Energy
Sales Agreement and wish to sell energy from their facility to Idaho Power must complete the following
Information and submit this Application by hand delivery, mail or E-mail to Idaho Power.
Upon receipt of a complete Application, Idaho Power shall process this request for a OF Energy Sales
Agreement pursuant to Idaho Power Company Schedule 73.
Qualifying Facility Information
Proposed Project
Name of Facility:
Resource Type: (i.e. wind, solar, hydro, etc): _
Facility Location: GPS Coordinates: _
Nearest City or landmark: _
County and State:. _
Map of Facility, including proposed Interconnection point.
Anticipated commencement date of energy deliveries to Idaho Power: _
Facility Nameplate Capacity Rating (kW):
Facility Maximum Output Capacity (kW):
Station Service Requirements (kW):
Facility Net Delivery to Idaho 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 Idaho Power Company (Yes or No):
IDAHO
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 9 of 10
Idaho Power Company
I.P.U.C. No. 29, Tariff No. 101 Original Sheet No. 73-10
IDAHO PUBLIC UTILITIES COMMISSION
Approved Effective
Jan.8,2015 Jan.1,2015
Per O.N. 33197
SCHEDULE 73 Jean 0. Jewell Secretary
COGENERATION AND SMALL POWER PRODUCTION SCHEDULE - IDAHO
(Continued)
QUALIFYING FACILITY ENERGY SALES AGREEMENT APPLICATION
(Continued)
Please include the following attachments:
./ Hourly estimated energy deliveries (kW) to Idaho 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.
,/ If 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.
./ If the Facility will not be interconnecting directly to the Idaho 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 Idaho Power.
Owner Information
Owner I Company Name: _
Contact Person: _
Address: _
City: _
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
State: Zip: _
IDAHO
Issued per Order No. 33197
Effective - January 1, 2015
Issued by IDAHO POWER COMPANY
Gregory W. Said, Vice President, Regulatory Affairs
1221 West Idaho Street, Boise, Idaho
IEP EXHIBIT 401
Page 10 of 10
Article
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Appendix A
AppendixB
AppendixC
AppendixD
AppcndixE
AppendixF
AppcndixG
AppendixH
Appendix I
ENERGY SALES AGREEMENT
BETWEEN
IDAHO POWER COMPANY
AND
CLARK SOLAR 1, LLC
TABLE OF CONTENrS
TITLE
Definitions
No Reliance on Idaho Power
Warranties
Conditions to Acceptance of Energy
Tenn and Operation Date
Purchase and Sale of Net Energy
Purchase Price and Method of Payment
Environmental Attributes
Facility and Interconnection
Metering, Metering Communications and SCADA Telemetry
Records
Operations
Indemnification and Insurance
Force Majeure
Liability; Dedication
Several Obligations
Waiver
Choice of Laws and Venue
Disputes and Default
Governmental Authorization
Commission Order
Successors and Assigns
Modification
Taxes
Notices and Authorized Agents
Additional Terms and Conditions
Severability
Counterparts
Entire Agreement Signatures
Generation Scheduling and Reporting
Facility and Point of Delivery
Engineer's Certifications
Forms of Liquid Security
Solar Facility Energy Prices and Integration Charges
Alternative Solar Facility Energy Prices and Integration Charges
Insurance Requirements
Solar Energy Production Forecasting
Estimated 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 1. LLC
Project Number: 25244913
This Energy Sales Agreement ("AGREEMENT"), entered into on this _l3_ day of
tflek
and IDAHO POWER COMPANY, an Idaho corporation (Idaho Power}, hereinafter sometimes referred to
collectively as "Parties" or individually as "Party."
WITNESSETH:
WHEREAS, Seller will design, construct, own, maintain and operate an electric generation
facility; and
WHEREAS, Seller wishes to sell, and Idaho Power is required to purchase, electric energy
produced by a PURP A Qualifying Facility.
TIIEREFORE, In consideration of the mutual covenants and agreements hereinafter set forth, the
Parties agree as follows:
ARTICLE I: DEFINITIONS
As used in this Agreement and the appendices attached hereto, the following terms
shall have the following meanings:
1.1 "Adjusted Estimated Net Energy Amount" - 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 "Authorized Agent" - a person or persons specified within paragraph 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 "Documents") and to take actions on
behalf of the Seller, and that Idaho Power Company and its directors, officers, employees, and / __..l
agents are entitled to consider and deal with such persons as agents of the Seller for all purposes,
2014 between CLARK SOLAR 1, LLC, an Idaho Limited Liability Company (Seller),
1 IEP EXHlBIT 402
Page 2 of34
until such time as an authorized officer of the Seller shall have delivered to Idaho Power
Company a notice in writing stating that such person is and shall no longer be an agent on behalf
of the Seller. Any Documents executed by such persons shall be deemed duly authorized by the
Seller for all purposes.
1.3 "Base Energy' - Monthly Net Energy less any Surplus Energy as calculated in paragraph 1.46.
1.4 "Commission" - Toe Idaho Public Utilities Commission.
1.5 "Contract Year'' - The period commencing each calendar year on the same calendar date as the
Operation Date and ending 364 days thereafter.
1.6 ''Delay Cure Period" - 120 days immediately following the Scheduled Operation Date.
1.7 "Delay Damages" - ((Current month's Estimated Net Energy Amount as specified in paragraph
6.2 divided by the number of days in the current month) multiplied by the number of days in the
Delay Period in the current month) multiplied by the current month's Delay Price.)
1.8 "Delay Period" -All days past the Scheduled Operation Date until the Seller's Facility achieves
the Operation Date or the Agreement is terminated by Idaho Power.
1.9 ''Delay Price" - The current month's Mid-Columbia Market Energy Cost minus the current
month's Base Energy Light Load Purchase Price as specified in the Solar Facility Pricing
Schedule of this Agreement. If this calculation results in a value less than 0, the result of this
calculation will be 0.
1.10 ''Designated DiSJ)atch Facility" - Idaho Power's Load Serving Operations, or any subsequent
group designated by Idaho Power.
1.11 "Effective Date" - The date stated in the opening paragraph of this Energy Sales Agreement
representing the date upon which this Energy Sales Agreement was fully executed by both
Parties.
1.12 "Environmental Attnoutes" - means any and all credits, benefits, emissions reductions, offsets,
and allowances, howsoever entitled, attributable to the generation from the Facility, and its
avoided emission of pollutants. Environmental Attributes include but are not limited to: (1) any
avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen
Page3 of34 2
oxides (NOx), carbon monoxide (CO) and other pollutants; (2) any avoided emissions of carbon
IEP EXHIBIT 402
dioxide (C02), methane (CH.), nitrous oxide, hydrofluorocarbons, pcrfluorocarbons, sulfur
hexafluoride and other greenhouse gases (GHGs) that have been determined by the United
Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the
actual or potential threat of altering the Earth's climate by trapping heat in the atmosphere;' (3)
the reporting rights to these avoided emissions, such as REC Reporting Rights. REC Reporting
Rights are the right of a REC purchaser to report the ownership of accumulated RECs in
compliance with federal or state law, if applicable, and to a federal or state agency or any other
party at the REC purchaser's discretion, and include without limitation those REC Reporting
Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or
future federal, state, or local law, regulation or bill, and international or foreign emissions trading
program. RECs are accumulated on a MWh basis and one REC represents the Environmental
Attributes associated with one (1) MWh of energy. Environmental Attributes do not include (i)
any energy, capacity, reliability or other power attributes from the Facility, (ii) production tax
credits or investment tax credits associated with the construction or operation of the Facility and
other financial incentives in the form of credits, reductions, or allowances associated with the
Facility that are applicable to a state or federal income taxation obligation, (iii) the cash grant in
lieu of the investment tax credit pursuant to Section 1603 of the American Recovery and
Reinvestment Act of 2009, or (iv) emission reduction credits encumbered or used bythe Facility
for compliance with local, state, or federal operating and/or air quality permits.
1.13 "Estimated Net Energy Amount Adjustment Percentage" - (Price Adjustment Adjusted Estimated
Net Energy Amount divided by the applicable month's Monthly Estimated Generation) expressed
as a percentage. If this calculation results in a value greater than 100%, the result of this
calculation will be 100%.
1.14 "Facility" - That electric generation facility described in Appendix B of this Agreement.
Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided
emissions arc included in the list of Environmental Attributes, this inclusion does not create any right to use those
avoided emissions to comply with any GHQ regulatory program.
3 IEP EXHIBIT 402
Page4 of34
1.15 "First Energy Date" - The day commencing at 00:01 hours, Mountain Time, following the day
that Seller has satisfied the requirements of Article IV and after the Seller requested First Energy
Date.
1.16 "Forced Outage" - a partial or total reduction of a) the Facility's capacity to produce and/or
deliver Net Energy to the Point of Delivery, orb) 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: 1)
equipment failure which was not the result of negligence or lack of preventative maintenance, or
2) responding to a transmission provider curtailment order, or 3) unplanned preventative
maintenance to repair equipment that left unrepaired, would result in failure of equipment prior
to the planned maintenance period, or 4) planned maintenance or construction of the Facility or
electrical lines required to serve this Facility.
1.17 "Generation Interconnection Agreement (GIA}" - The interconnection agreement that specifies
terms, conditions and requirements of interconnecting to the Idaho Power electrical system,
which will include but not be limited to all requirements as specified by Schedule 72.
1.18 "Generation Unit" - a complete solar pv electrical generation system within the Facility that is
able to generate and deliver energy to the Point of Delivery independent of other Generation
Units within the same Facility.
1.19 "Heavy Load (Ill,) Hours" -The daily hours from hour ending 0700 - 2200 Mountain Time, (16
hours) excluding all hours on all Sundays, New Years Day, Memorial Day, Independence Day,
Labor Day, Thanksgiving and Christmas.
1.20 "Hourly Energy Estimates" - the hourly energy estimates provided by the Seller and included in
Appendix I of this Agreement. These hourly energy estimates are a material input used in the
calculation of the energy prices specified in Appendix E and F.
1.21 "Interconnection Facilities" -All equipment specified in the GIA.
1.22 ''Light Load (LL) Hours" - The daily hours from hour ending 2300 - 0600 Mountain Time (8
hours), plus all other hours on all Sundays, New Years Day, Memorial Day, Independence Day,
Labor Day, Thanksgiving and Christmas.
4 IEP EXHJBIT 402
Page S of34
1.23 "Losses" - The loss of electrical energy expressed in kilowatt hours (kWh) occurring as a result
of the transformation and transmission of energy between the point wherethe Facility's energy is
metered and Facility's Point of Delivery. The loss calculation formula will be as specified in
Appendix B of this Agreement.
1.24 "Market Energy Reference Price" - Eighty-five percent (85%) of the Mid-Columbia Market
Energy Cost.
1.25 "Material Breach" -A Default (paragraph 19.2.1) subject to paragraph 19 .2.2.
1.26 "Maximum Capacity Amount'' - The maximum capacity (MW) of the Facility will be as
specified in Appendix B of this Agreement.
1.27 "Mid-Columbia Market Energy Cost" - is 82.4% of the monthly arithmetic average of
each day's Intercontinental Exchange (''ICE") daily firm Mid-C Peak Avg and Mid-C
Off-Peak Avg index prices in the month as follows:
The actual calculation being:
D .824 * ( L {(ICE Mid-C Peak Avg, * HL hours for day)+ x-r
(ICE Mid-C Off-Peak Avgx • LL hours for day)} I (n*24))
where n = number of days in the month
If the ICE Mid-C Index prices are not reported for a particular day or days, prices derived from the
respective averages of HL and LL prices for the immediately preceding and following reporting
periods or days shall be substituted into the formula stated in this definition and shall therefore be
multiplied by the appropriate respective numbers of HL and LL Hours for such particular day or
days with the result that each hour in such month shall have a related price in such formula. If the
day for which prices are not reported has in it only LL Hours (for example a Sunday), the respective
averages shall use only prices reported for LL hours in the immediately preceding and following
reporting periods or days. If the day for which prices are not reported is a Saturday or Monday or is
adjacent on the calendar to a holiday, the prices used for HL Hours shall be those for HL hours in
the nearest (forward or backward) reporting periods or days for which HL prices arc reported.
5 I EP EXHIBIT 402
Page 6 of34
1.28 "Monthly Estimated Generation" - the monthly estimated generation as specified in Appendix I
identified as the Monthly estimated kWh adjusted for any applicable Solar Panel Degradation.
1.29 "Monthly Nameplate Energy" - Nameplate Capacity multiplied by the hours in the applicable
month.
1.30 ''Nameplate Capacity" -The full-load electrical quantities assigned by the designer to a
Generation Unit and its prime mover or other piece of electrical equipment, such as transformers
and circuit breakers, under standardized conditions, expressed in amperes, kilovolt-amperes,
kilowatts, volts or other appropriate units. This value is established for the term of this
Agreement in Appendix B, item B-1 of this Agreement and validated in paragraph 4.1.4 of this
Agreement.
1.31 ''Net Energy" - All of the electric energy produced by the Facility, less Station Use and Losses,
expressed in kilowatt hours (kWh) delivered by the Facility to Idaho Power at the Point of
Delivery. Subject to the terms of this Agreement, Seller commits to deliver all Net Energy to
Idaho Power at the Point of Delivery for the full term of the Agreement.
1.32 "Operation Date" - The day commencing at 00:0 I hours, Mountain Time, following the day that
all requirements of paragraph 5.2 have been completed and after the Seller requested Operation
Date.
1.33 "Point of Delivery" - The location specified in the GIA and referenced in Appendix B, where
Idaho Power's and the Seller's electrical facilities are interconnected and the energy from this
Facility is delivered to the Idaho Power electrical system.
1.34 ''Price Adjustment Adjusted Estimated Net Energy Amount " - the Estimated Net Energy
Amount specified in paragraph 6.2 including any adjustments that have been made in accordance
with paragraphs 6.2.2 and any applicable Solar Panel Degradation adjustments.
1.35 "Pricing Adjustment Percentage" - Estimated Net Energy Amount Adjustment Percentage plus
2%. If this calculation results in a value greater than 100%, the result of this calculation will be
100% or if this calculation results in a value less than 90%, the result of this calculation will be
90%.
6 IEP EXHIBIT 402
Page 7 of34
1.36 ''Prudent Electrical Practices" - Those practices, methods and equipment that are commonly and
ordinarily used in electrical engineering and operations to operate electric equipment lawfully,
safely, dependably, efficiently and economically.
1.37 "Renewable Energy Certificate" or "REC" means a certificate, credit, allowance, green tag, or
other transferable inclicia, howsoever entitled, indicating generation of renewable energy by the
Facility, and includes all Environmental Attributes 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 "Scheduled Operation Date" - The date specified in Appendix B when Seller anticipates
achieving the Operation Date. It is expected 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 Operation Date.
1.39 "Schedule 72" - Idaho Power's Tariff No 101, Schedule 72 or its successor schedules as
' approved by the Co�sion.
1.40 "Security Deposit" - $45 per kW Nameplate Capacity of the entire Facility.
1.41 "Solar Energy Production Forecast" - A forecast of energy deliveries from this Facility provided
by an Idaho Power administered solar forecasting model. The Facility shall be responsible for an
allocated portion of the total costs of the forecasting model and to provide solar irradiation and
weather data specified in Appendix H.
1.42 "Solar Facility Pricing Schedule" - The pricing schedule to be applied to all energy purchases
within this Agreement as determined by paragraph 7.1.
1.43 "Solar Integration Charge" - a per kWh charge as specified in the Solar Facility Pricing Schedule
applied to all Net Energy to be deducted from the monthly energy payments in accordance with
Article VIl of this Agreement.
1.44 "Solar Panel Degradation" - shall be the degradation as specifically documented by the solar pv
panel manufacturer for the actual solar panels installed at this Facility, stated in a percentage
value for each Contract Year. These values will be provided and validated as specified in
paragraph 4.1.6 of this Agreement.
7 IEP EXHIBIT 402
Page 8 of34
1.45 "Station Use" - Electric energy that is used to operate equipment that is auxiliary or otherwise
related to the production of electricity by the Facility.
1.46 "Surplus Energy" - Is (1) Net Energy produced by the Seller's Facility and delivered to the Idaho
Power electrical system during the month which exceeds \110% of the monthly Adjusted
Estimated Net Energy Amount for the corresponding month specified in paragraph 6.2, or (2) if
the Net Energy produced by the Seller's Facility and delivered to the Idaho Power electrical
system during the month is less than 90% of the monthly Adjusted Estimated Net Energy Amount
for the corresponding month specified in paragraph 6.2, then all Net Energy delivered by the
Facility to the Idaho Power electrical system for that given month, or (3) all Net Energy produced
by the Seller's Facility and delivered by the Facility to the Idaho Power electrical system prior to
the Operation Date, or ( 4) all monthly Net Energy that exceeds the Monthly Nameplate Energy.
1.47 "Termination Damages" - Financial damages the non defaulting party bas incurred as a result of
termination of this Agreement.
ARTICLE Il: NO RELIANCE ON IDAHO POWER
2.1 Seller Independent Investigation- Seller warrants and represents to Idaho Power that in entering
into this Agreement and the undertaking by Seller of the obligations set forth herein, Seller has
investigated and determined that it is capable of performing hereunder and bas not relied upon
the advice, experience or expertise of Idaho Power in connection with the transactions
contemplated by this Agreement.
2.2 Seller Independent Experts - All professionals or experts including, but not limited to, engineers,
attorneys or accountants, that Seller may have consulted or relied on in undertaking the
transactions contemplated by this Agreement have been solely those of Seller.
ARTICLE ID: W ARRANT1ES
3.1 No Warranty by Idaho Power - Any review, acceptance or failure to review Seller's design,
specifications, equipment or facilities shall not be an endorsement or a confirmation by Idaho
Power and Idaho Power makes no warranties, expressed or implied, regarding any aspect of
8 IEP EXHIBIT 402
Page 9 of34
Seller's design, specifications, equipment or facilities, including, but not limited to, safety,
durability, reliability, strength, capacity, adequacy or economic feasibility.
3.2 Qualifying Facility Status - Seller warrants that the Facility, once constructed, will be a
"Qualifying Facility," as that term is used and defined in 18 CFR 292.201 et seq. After initial
qualification, Seller will take such steps as may be required to maintain the Facility's Qualifying
Facility status during the term of this Agreement and Seller's failure to maintain Qualifying
Facility status will be a Material Breach of this Agreement. Idaho Power reserves the right to
review the Facility's Qualifying Facility status and associated support and compliance documents
upon reasonable request during the term of this Agreement.
3.3 Solar Project Qualifications - Seller warrants that the Facility is a "Solar Project," as that term is
used in Commission Order 32697. After initial qualification, Seller will take such steps as may be
required to maintain the Facility's Solar Project status during the full term of this Agreement and
Seller's failure to maintain Solar Project status will be a Material Breach of this Agreement.
Idaho Power reserves the right to review the Facility's Solar Project status and associated support
and compliance documents upon reasonable request during the term of this Agreement.
3.4 Hourly Energy Estimates - Seller warrants that the Hourly Energy Estimates provided by the
Seller and contained in Appendix. I are accurate estimates of the Facility's expected hourly energy
production based on the characteristics of the solar generation equipment being installed,
configuration and orientation of the equipment installation, location specific solar radiation and
any other information available as of the Effective Date. Material deviations from these Hourly
Energy Estimates will be a Material Breach of this Agreement.
ARTICLE IV: CONDITIONS TO ACCEPTANCE OF ENERGY
4.1 Prior to the First Energy Date and as a condition of Idaho Power's acceptance of de1iveries of
energy from the Seller under this Agreement, Seller shall:
4.1.1 Submit proof to Idaho Power that all licenses, permits, determinations or approvals
necessary for Seller's operations have been obtained from applicable federal, state or
local authorities, including, but not limited to, evidence of compliance with Subpart B, 18
9 IEP EXHIBIT 402
Page 10 of34
CFR 292.201 et seq. as a certified Qualifying Facility and evidence of compliance with
the eligibility to be classified as a Solar Project as referenced in Commission Order
32697.
4.1.2 Opinion of Counsel - Submit to Idaho Power an Opinion Letter signed by an attorney
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 are legally and validly issued, are held in the name of the Seller and, based on a
reasonable independent review, counsel is of the opinion that Seller is in substantial
compliance with said permits as of the date of the Opinion Letter. The Opinion Letter
will be in a form acceptable to Idaho Power and will acknowledge that the attorney
rendering the opinion understands that Idaho Power is relying on said opinion. Idaho
Power's acceptance of the form will not be unreasonably withheld. The Opinion Letter
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 - Confirm with Idaho Power that Commission approval of this
Agreement in a form acceptable to Idaho Power has been received.
4.1.4 Nameplate Capacity - Submit to Idaho Power manufacturer's and engineering
documentation that establishes the Nameplate Capacity of each individual Generation
Unit that is included within this entire Facility and the total of these units to determine the
Facility Nameplate Capacity rating. Upon receipt of this data, Idaho Power shall review
the provided data and determine if the Nameplate Capacity specified is reasonable based
upon the manufacturer's specified generation ratings for the specific Generation Units.
The Nameplate Capacity shall be measured in Alternating Current (AC).
4.1.5 Completion certificate - Submit a certificate executed by an authorized agent of the
Seller attesting that all mechanical and electrical equipment of the designated Generation
Unit(s) of the Facility bas been completed to enable the Generation Unit(s) to beginning
testing and delivery of Test Energy in a safe manner.
10 IEP EXHIBIT 402
Page 11 of 34
4.1.6 Solar Panel Degradation - submit Solar Panel Degradation values (expressed as a
percentage) for each Contract Year for the full term of this Agreement and the panel
manufacturer documentation and certification that clearly identifies and validates these
exact values. Only values that are within reasonable solar industry standards and
specifically validated by the manufacturer documentation will be acceptable.
4.1.7 Insurance- Submit written proof to Idaho Power of all insurance required in Article xm.
4.1.8 Interconnection - Provide written confirmation from Idaho Power's business unit that
administers the GIA that Seller has satisfied all interconnection and testing requirements
that will enable the Facility to be safely connected to the Idaho Power electrical system.
4.1.9 Network Resource Designation - Confirm that the Seller's Facility has been designated
as an Idaho Power network "resource capable of delivering energy up to the amount of the
Maximum Capacity at the Point of Delivery.
4.1.9.l As specified in Appendix B item B-7 of this Agreement, the Seller's Facility
must have achieved the status of being an Idaho Power Designated Network
Resource (''DNR") prior to Idaho Power accepting any energy from this Facility.
Appendix B item B-7 provides information on the initial application process
required to enable Idaho Power to determine if network transmission capacity is
available for this Facility's Maximum Capacity Amount and/or if Idaho Power
transmission network upgrades will be required. The results of this study process
and any associated costs will be included in the GIA for this Facility.
4.1.9.2 Only after the Facility has completed all requirements of the GIA that enable the
Facility to come online can Idaho Power begin the final process of designating
this resource as an Idaho Power DNR. The final process must be initiated at a
minimum 30 days prior to the First Energy Date. Therefore, Idaho Power will
begin this process 30 days prior to the Scheduled First Energy Date specified in
Appendix B of this Agreement and only after Idaho Power has received
confirmation that the GIA requirements have been completed. If the Seller
Page 12 of34 11
estimates that the actual First Energy is expected to be different then the
IEP EXHIBIT 402
Scheduled First Energy Date specified in Appendix B of this Agreement, the
Seller must notify Idaho Power of this revised date no later than 30 days prior to
Scheduled First Energy Date. Under no circumstances will the project be able to
deliver any energy to Idaho Power until such time as Idaho Power has designated
this Facility as an Idaho Power DNR.
4.1.10 Written Acceptance-Request and obtain written confirmation from Idaho Power that all
conditions to acceptance of energy have been fulfilled. Such written confirmation shall be
provided within a commercially reasonable time following the Seller's request and will
not be unreasonably withheld by Idaho Power.
ARTICLEV: TERMANDOPERATIONDATE
5.1 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 period of 20 (not to
exceed 20 years) Contract Years from the Operation Date.
5 .2 Operation Date - A single Operation Date will be granted for the entire Facility and may occur
only after the Facility has achieved all of the following:
a) At the minimum, 75% of the Nameplate Capacity of this Facility as identified in
Appendix B, item B-1 has achieved First Energy Date.
b) Seller has demonstrated to Idaho Power's satisfaction that all mechanical and
electrical testing has been completed satisfactorily and the Facility is able to provide
energy in a consistent, reliable and safe manner.
c) Engineer's Certifications - Submit an executed Engineer's Certification of Design &
Construction Adequacy and an Engineer's Certification of Operations and
Maintenance (O&M) Policy as described in Commission Order No. 21690. These
certificates will be in the form specified in Appendix C but may be modified to the
extent necessary to recognize the different engineering disciplines providing the
certificates.
12 IEP EXHIBIT 402
Page 13 of34
d) Seller has requested an Operation Date from Idaho Power in a written format
e) Seller has received written confirmation from Idaho Power of the Operation Date.
This confirmation will not be unreasonably withheld by Idaho Power.
5.3 Operation Date Delay-;- Seller shall cause the Facility to achieve the Operation Date on or before
the Scheduled Operation Date. Delays in the interconnection and transmission network upgrade
study, design and construction process (This includes any delay in making the required deposit
payments set forth in the Facility's GIA) that are not caused by Idaho Power or Force Majeure
events accepted by both Parties, shall not prevent Delay Damages or Termination Damages from
being due and owing as calculated in accordance with this Agreement.
5.4 Tennination - If Seller fails to achieve the Operation Date prior to expiration of the Delay Cure
Period, such failure will be a Material Breach and Idaho Power may terminate this Agreement at
any time until the Seller cures the Material Breach.
5.5 Delay Damages billing and payment- Idaho Power shall calculate and submit to the Seller any
Delay Damages due Idaho Power within 15 days after the end of each month or within 30 days of
the date this Agreement is terminated by Idaho Power.
5.6 Tennination Damages billing and payment- Idaho Power shall calculate and submit to the Seller
any Termination Damages due Idaho Power within 30 days after this Agreement has been
terminated.
5.7 Seller Payment - Seller shall pay Idaho Power any calculated Delay or Termination Damages
within 7 days of when Idaho Power presents these billings to the Seller. Seller's failure to pay
these damages within the specified time will be a Material Breach of this Agreement and Idaho
Power shall draw funds from the Security Deposit provided by the Seller in an amount equal to
the calculated damages.
5.8 Security Deposit - Within thirty (30) days of the date of a fmal non-appealable Commission
Order approving this Agreement as specified in Article XXI, the Seller shall post and maintain
liquid security in a form as described in Appendix D equal to or exceeding the amount specified
within this Agreement as the Security Deposit until such time as the Security Deposit is released
by Idaho Power as specified in paragraph 5.8.1. Failure to post this Security Deposit in the time
13 IEP EXHIBIT 402
Page 14 of34
specified above will be a Material Breach of this Agreement and Idaho Power may terminate 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 Agreement has been
terminated and only after all Delay and Termination Damages have been paid in full to
Idaho Power.
ARTICLE VI: PURCHASE AND SALE OF NET ENERGY
6.1 Net Energy Purchase and Delivery - Except when either Party's performance is excused as
provided herein, Idaho Power will purchase and Seller will sell all of the Net Energy to Idaho
Power at the Point of Delivery.
6.2 Estimated Net Energy Amounts - shall be equal to Monthly estimated kWhs as specified in
Appendix I and as listed below:
January
February
March
April
May
June
July
August
September
October
November
December
Total
8,178,485
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
184,922,421
These Estimated Net Energy Amounts will be adjusted to reflect the applicable Solar Panel
Degradation throughout the term of this Agreement.
6.2.2 Seller's Adjustment of Estimated Net Energy Amounts - After the Operation Date, the
Seller may revise any future monthly Estimated Net Energy Amounts by providing
written notice no later than 5 PM Mountain Standard time on the last business day of the
Notification Month specified in the following schedule:
14 IEP EXHIBIT 402
Page 15 of34
Notification Month
November
December
January
February
March
April
May
June
July
August
September
October
Future monthly Estimated Net
Energy Amounts eligible to be
revised
January and any future months
February and any future months
March and any future months
April and any filture months
May and any future months
June and any future months
July and any future months
August and any future months
September and any future months
October and any future months
November and any future months
December and any future months
a.) This written notice must be provided to Idaho Power in accordance with paragraph
25.1 or by electronic notice provided and verified via return electronic verification of
receipt to the electronic notices address specified in paragraph 25.1.
b.) Failure to provide timely written notice of changed Estimated Net Energy Amounts
will be deemed to be an election of no change from the most recently provided
Estimated Net Energy Amounts.
c.) Any Seller provided Adjustment of Estimated Net Energy Amounts will include any
Solar Panel Degradation. The Solar Panel Degradation adjustment will only be
applied to Estimated Net Energy Amounts that have not been adjusted by the Seller
since the inception of the current Contract Year.
6.2.3 Idaho Power Adjustment of Estimated Net Energy Amount - If Idaho Power is excused
from accepting the Seller's Net Energy as specified in paragraph 12.2.1 or if the Seller
declares a Suspension of Energy Deliveries as specified in paragraph 12.3.1 and the
Seller's declared Suspension of Energy Deliveries is accepted by Idaho Power, the
Estimated Net Energy Amount as specified in paragraph 6.2 for the specific month in
which the reduction or suspension under paragraph 12.2.1 or 12.3.1 occurs will be
temporarily reduced in accordance with the following and only for the actual month in
which the event occurred:
15 IEP EXHIBIT 402
Page 16 of34
Where:
NBA = Current Month's Estimated Net Energy Amount (Paragraph 6.2)
SGU = a.) If Idaho Power is excused from accepting the Seller's Net
Energy as specified in paragraph 12.2.1 this value will be
equal to the percentage of curtailment as specified by
Idaho Power multiplied by the TGU as defined below.
b.) If the Seller declares a Suspension of Energy Deliveries as
specified in paragraph 12.3.1 this value will be the sum of
the individual Generation Units size ratings as specified in
Appendix B that are impacted by the circumstances
causing the Seller to declare a Suspension of Energy
Deliveries.
TGU Sum of all of the individual generator ratings of the Generation
Units at this Facility as specified in Appendix B of this
agreement.
RSH
TH
Actual hours the Facility's Net Energy deliveries were either
reduced or suspended under paragraph 12.2.1 or 12.3.1
= Actual total hours in the current month
Resulting formula being:
Adjusted ( ( ) ( Estimated = NEA - ��� X NEA X R��
Net Energy
Amount
) )
This Adjusted Estimated Net Energy Amount will be used in applicable Surplus Energy
calculations for only the specific month in which Idaho Power was excused from accepting the
Seller's Net Energy or the Seller declared a Suspension of Energy.
6.3 Failure to Deliver Mini.mum Estimated Net Energy Amounts - Unless excused by an event of
Force Majeure, Seller's failure to deliver Net Energy in any Contract Year in an amount equal to
at least ten percent (10%) of the sum of the Monthly Estimated Generation shall constitute an
event of default.
ARTICLE VII: PURCHASE PRICE AND METHOD OF PAYMENT
7.1 The Solar Facility Pricing Schedule to be included in this Agreement is disputed by the Parties.
Page 17 of34 16
Idaho Power believes Appendix E is the appropriate Solar Facility Pricing Schedule as it includes
IEP EXHIBIT 402
an Idaho Power capacity deficit period beginning in 2021. The Seller believes Appenclix F is the
appropriate Solar Facility Pricing Schedule and it includes an Idaho Power capacity deficit period
beginning in 2016. Both of these pricing schedules were calculated using the Commission
approved Incremental Cost IRP Avoided Cost Methodology, with the only difference �eing the
starting date of the Idaho Power capacity deficit period. The Parties may submit to the
Commission written argument or Comments in support of their respective positions, in
accordance with a procedural schedule mutually agreeable to the Parties and the
Commission. The Parties have agreed to all other terms and conditions of this Agreement and
hereby agree to submit this Solar Facility Pricing Schedule dispute to the Commission for
resolution. The Parties agree to abide and be bound by the Commission's decision on this issue.
The final Order of the Commission resolving this dispute will be included and become an integral
part of this Agreement, which the Parties agree to support and uphold.
7 .2 Base Energy Heavy Load Purchase Price - For all Base Energy received during Heavy Load
Hours, Idaho Power will pay the monthly Base Energy Heavy Load Purchase Price as specified in
the Solar Facility Pricing Schedule including any applicable Price Adjustment, less the Solar
Integration Charge.
7 .3 Base Energy Light Load Purchase Price - For all Base Energy received during Light Load Hours,
Idaho Power will pay the monthly Base Energy Light Load Purchase Price as specified in the
Solar Facility Pricing Schedule including an applicable Price Adjustment, less the Solar
Integration Charge.
7.4 Surolus Energy Price - For all Surplus Energy, Idaho Power shall pay to the Seller the current
month's Market Energy Reference Price or the Base Energy Light Load Purchase Price including
any applicable Price Adjustment, less the Solar Integration Charge for that month, whichever is
lower.
7 .5 Price Adjustment - Upon acceptance of a Seller Adjustment of Estimated Net Energy Amounts as
specified in paragraph 6.2.2, Idaho Power will calculate the Pricing Adjustment Percentage for
the applicable month(s). All pricing contained within the Solar Facility Pricing Schedule for the
17 IEP EXHIBIT 402
Page 18 of34
current applicable month(s) and all future applicable months will be multiplied by the Pricing
Adjustment and the resulting revised prices will replace the prices contained within the Solar
Facility Pricing Schedule until such time as the Seller submits a new Seller Adjustment 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 Price Adjustment applicable to January 2018 will also be applied to all
months of January for the remaining term of the Agreement. This
revised January pricing will then remain in effect until such time as the
Seller requests an additional Adjustment of Estimated Net Energy
Amounts that would be applicable to future months of January.
7.6 Delivering Net Energy that exceeds the Monthly Nameplate 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 Agreement and Idaho Power may terminate this Agreement within sixty ( 60) days after the
Material Breach has occurred.
7.7 Payments - Undisputed Base Energy and Surplus Energy payments inclusive of Price
Adjustments, less Solar Integration Costs, less Solar Energy Production Forecasting Costs, and
less any payments 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 Energy
actually delivered to Idaho Power as specified in Appendix A.
7 .8 Continuing Jurisdiction of the Commission - This Agreement is a special contract and, as such,
the rates, terms and conditions contained in this Agreement will be construed in accordance with
Idaho Power Company v. Idaho Public Utilities Commission and Afton Energy, Inc., 107 Idaho
781, 693 P.2d 427 (1984), Idaho Power Company v. Idaho Public Utilities Commission, 107
Idaho 1122, 695 P.2d 1 261 (1985), Afton Energy. Inc. v. Idaho Power Company, 111 Idaho 925,
729 P .2d 400 (1986), Section 210 of the Public Utility Regulatory Policies Act of 1978 and 18
CFR §292.303-308.
18 IEP EXHIBIT 402
Page 19 of34
ARTICLE VITI: ENVIRONMENTAL ATTRIBUTES
8.1 Idaho Power will be granted ownership of 50% of all of the Environmental Attributes associated
with the Facility and Seller will likewise retain 50% ownership of all of the Environmental
Attributes associated with the Facility. Title to 50% of the Environmental Attributes shall pass to
Idaho Power at the same time that transfer of title of the associated Surplus Energy or Net Energy
to Idaho Power occurs. Idaho Power's title to 50% of the Environmental Attributes shall expire at
the end of the term of this Agreement, unless the parties agree to extend in future agreements. If
after the Effective Date and during the term of this Agreement any additional Environmental
Attributes or similar environmental value is created by legislation, regulation, or any other action,
including but not limited to, carbon credits and carbon offsets, Idaho Power shall be granted
ownership of 50% of these additional Environmental Attributes or environmental values that are
associated with the Net Energy delivered by the Seller to Idaho Power. Seller shall use prudent
and commercially reasonable efforts to ensure that any operations of the Facility do not
jeopardize the current or future Environmental Attribute status of this solar generation Facility.
8.2 The Parties shall cooperate to ensure that all Environmental Attribute certifications, rights and
reporting requirements are completed by the responsible Parties.
8.2.1 At least sixty (60) days prior to the First Energy Date, the Parties shall mutually
cooperate to enable Idaho Power's Environmental Attributes from this Facility to be
placed into Idaho Power's Western Renewable Energy Generation Information System
("WREGIS") account or any other Environment Attribute accounting and tracking
system selected by the Idaho Power. The Seller at the Seller's sole expense will be
responsible to establish and maintain the Seller's WREGIS or other Environmental
Attribute account and/or system that enables the creation of the Environmental Attribute
certificates associated with this Facility and the transfer of 50% of the Environmental
Attributes to Idaho Power for the Term of this Agreement. If the Environmental
Attribute accounting and tracking system initially selected by Idaho Power is materially
altered or discontinued during the Term of this Agreement, the Parties shall cooperate to
IEP EXHIBIT 402
Page 20 of34 19
identify an appropriate alternative Environmental Attribute accounting and tracking
process and 'enable the Environmental Anributes be processed through this alternative
method.
8.2.2 Each Party shall only report under Section 1605(b) of the Energy Policy Act of 1992 or
under any applicable program the 50% of the Environmental Attributes that such party
owns and shall refrain from reporting the Environmental Attributes owned by the other
Party.
8.2.3 If Idaho Power requests additional Environmental Attribute certifications beyond what is
provided by the WREGIS process the Seller shall use its best efforts to obtain any
Environmental Attribute certifications required by Idaho Power for those Environmental
Attributes delivered to Idaho Power from the Seller. If the Seller incurs cost, as a result
of Idaho Power's request, and if the additional certification provides benefits to both
parties, the parties shall share the costs in proportion to the additional benefits obtained.
If Idaho Power elects to obtain its own certifications, then Seller shall fully cooperate
with Idaho Power in obtaining such certification.
ARTICLE IX: FACILITY AND INTERCONNECTION
9.1 Design of Facility - Seller will design, construct, install, own, operate and maintain the Facility
and any Seller-owned Interconnection Facilities so as to allow safe and reliable generation and
delivery of Net Energy to the Idaho Power Point of Delivery for the full term of the Agreement in
accordance with the GIA.
ARTICLE X: METERING, METERING COMMUNICATIONS AND SCADA TELEMETRY
10.1 Metering - Idaho Power shall, provide, install, and maintain metering equipment needed for
metering the electrical energy production from the Facility. The metering equipment will be
capable of measuring, recording, retrieving and reporting the Facility's hourly gross electrical
energy production, Station Use, maximum energy deliveries (kW) and any other energy
measurements at the Point of Delivery that Idaho Power needs to administer this Agreement and
20 IEP EXHlBIT 402
Page 21 of34
integrate this Facility's energy production into the Idaho Power electrical system. Specific
equipment, installation details and requirements for this metering equipment will be established
in the GIA process and documented in the GIA. Seller shall be responsible for all initial and
ongoing costs of this equipment as specified in Schedule 72 and the GIA.
10.2 Metering Communications - Seller shall, at the Seller's sole initial and ongoing expense, arrange
for, provide, install, and maintain dedicated metering communications equipment capable of
transmitting the metering data specified in paragraph 10.1 to Idaho Power in a frequency, manner
and form acceptable to Idaho Power. Seller shall grant Idaho Power sole control and use of this
dedicated metering communications equipment. Specific details and requirements for this
metering communications equipment will be established in the GIA process and documented in
the GIA.
10.3 Supervisory Control and Data Acquisition (SCADA} Telemetry-If the Facility's Nameplate
Capacity exceeds 3 MW, in addition to the requirements of paragraph 10.1 and 10.2, Idaho Power
may require telemetry equipment and telecommunications which will be capable of providing
Idaho Power with continuous instantaneous SCADA telemetry of the Seller's Net Energy and
Inadvertent Energy production in a form acceptable to Idaho Power. Seller shall grant Idaho
Power sole control and use of this dedicated SCADA and telecommunications equipment.
Specific details and requirements for this SCADA Telemetry and telecommunications equipment
will be established in the GIA process and documented in the GIA. Seller shall be responsible for
all initial and ongoing costs of this equipment as specified in Schedule 72 and the GIA.
ARTICLE XI - RECORDS
11.1 Maintenance of Records - Seller shall maintain monthly records at the Facility or such other
location mutually acceptable to the Parties. These records shall include total generation, Net
Energy, Station Use, Surplus Energy, Inadvertent Energy and maximum hourly generation in
(kW) and be records in a form and content acceptable to Idaho Power. Monthly records shall be
retained for a period ofnot less than five years.
11.2 Inspection - Either Party, after reasonable notice to the other Party, shall have the right, during
21 IEP EXHIBIT 402
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normal business hours, to inspect and audit any or all records pertaining to the Seller's Facility
generation, Net Energy, Station Use, Surplus Energy, Inadvertent Energy and maximum hourly
generation in kW.
ARTICLE XII: OPERATIONS
12 .1 Communications - Idaho Power and the Seller shall maintain appropriate operating
communications through Idaho Power's Designated Dispatch Facility in accordance with the
GIA.
12 .2 Acceptance of Energy-
12.2.1 Idaho Power shall be excused from accepting and paying for Net Energy which would
have otherwise been produced by the Facility and delivered by the Seller to the Point of
Delivery:
a.) If energy deliveries are interrupted due an event of Force Majeure or
Forced Outage.
b.) If interruption of energy deliveries is allowed by Section 210 of the
Public Utility Regulatory Policies Act of 1978 and 18 CFR §292.3041•
c.) If temporary disconnection and/or interruption of energy deliveries is in
accordance with Schedule 72 or other provisions as specified within the
GIA.
d.) If Idaho Power determines that curtailment, interruption or reduction of
Net Energy deliveries is necessary because of line construction, electrical
system maintenance requirements, emergencies, electrical system
operating conditions, electrical system reliability emergencies on its
system, or as otherwise required by Prudent Electrical Practices.
12.2.2 If, in the reasonable opinion of Idaho Power, Seller's operation of the Facility or
Interconnection Facilities is unsafe or may otherwise adversely affect Idaho Power's
I Any electric utility which gives notice ... will not be required to purchase electric energy or capacity during any period
during which, due to operational circumstances, purchases from qualifying 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 of energy itself.
22 IEP EXHIBIT 402
Page 23 of34
equipment, personnel or service to its customers, Idaho Power may temporarily
disconnect the Facility from Idaho Power's transmission/distribution system as specified
within the GIA or Schedule 72 or talce such other reasonable steps as Idaho Power deems
appropriate.
12.2.3 Under no circumstances will the Seller deliver energy from the Facility to the Point of
Delivery in an amount that exceeds the Maximum Capacity Amount at any moment in
time. Seller's failure to limit deliveries to the Maximum Capacity Amount will be a
Material Breach of this Agreement and must be cured immediately.
12.2.4 If Idaho Power is unable to accept the energy from this Facility and is not excused from
accepting the Facility's energy, Idaho Power's damages shall be limited to only the value
of the estimated energy that Idaho Power was unable to accept valued at the applicable
energy prices specified in the Solar Facility Pricing Schedule. Idaho Power will have no
responsibility to pay for any other costs, lost revenue or consequential damages the
Facility may incur.
12.3 Seller Declared Suspension of Energy Deliveries-
12.3.1 If the Seller's Facility experiences a Forced Outage, and Seller initiates a Declared
Suspension of Energy Deliveries, Seller shall, after giving notice as provided in
paragraph 12.3.2 below, temporarily reduce deliveries of Net Energy (kW) to Idaho
Power from the Facility to not exceed the reduced energy deliveries (kW) stated by the
Seller in the initial declaration for a period of not less than 48 hours ("Declared
Suspension of Energy Deliveries"). The Seller's Declared Suspension of Energy
Deliveries will begin at the start of the next full hour following the Seller's telephone
notification as specified in paragraph 12.3.2 and will continue for the time as specified
(not less than 48 hours) in the written notification provided by the Seller. In the month(s)
in which the Declared Suspension of Energy occurred, the Estimated Net Energy Amount
will be adjusted as specified in paragraph 6.2.3.
12.3.2 If the Seller desires to initiate a Declared Suspension of Energy Deliveries as provided in
paragraph 12.3.1, the Seller will notify the Designated Dispatch Facility by telephone.
23 IEP EXIDBIT 402
Page24 of34
The beginning hour of the Declared Suspension of Energy Deliveries will be at the
earliest the next full hour after making telephone contact with Idaho Power. The Seller
will, within 24 hours after the telephone contact, provide Idaho Power a written notice in
accordance with Article XXV that will contain the beginning hour and duration of the
Declared Suspension of Energy Deliveries, a description of the conditions that caused the
Seller to initiate a Declared Suspension of Energy Deliveries, and the reduced level (kW)
of energy deliveries the Facility is requesting that will be set as the maximum energy
deliveries to Idaho Power for the duration of the Declared Suspension of Energy Delivery
event (not less than 48 hours). Idaho Power will review the documentation provided by
the Seller to determine Idaho Power's acceptance of the described Forced Outage as
qualifying for a Declared Suspension of Energy Deliveries as specified in paragraph
12.3.1. Idaho Power's acceptance of the Seller's Forced Outage as an acceptable Forced
Outage will be based upon the clear documentation provided by the Seller that the Forced
Outage is not due to an event of Force Majeurc or by neglect, disrepair or lack of
adequate preventative maintenance of the Seller's Facility.
12.4 Scheduled Maintenance - On or before January 31 '1 of each calendar year, Seller shall submit a
written proposed maintenance schedule of significant Facility maintenance for that calendar year
and Idaho Power and Seller shall mutually agree as to the acceptability of the proposed schedule.
If the Seller intends to perform planned maintenance at approximately the same time every year,
the Seller may submit a maintenance schedule for the first calendar year and include a statement
that this maintenance schedule shall be consistent for all future years, until such time as the Seller
notifies Idaho Power of a change to this schedule. The Parties determination as to the
acceptability of the Seller's timetable for scheduled maintenance will take into consideration
Prudent Electrical Practices, Idaho Power system requirements and the Seller's preferred
schedule. Neither Party shall unreasonably withhold acceptance of the proposed maintenance
schedule.
12.S Idaho Power Maintenance Information - Upon receiving a written request from the Seller, Idaho
Power shall provide publically available information in regards to Idaho Power planned
24 IEP EXHIBIT 402
Page 25 of34
maintenance information that may impact the Facility.
12.6 Contact Prior to Curtailment - Idaho Power will make a reasonable attempt to contact the Seller
prior to exercising its rights to interrupt interconnection or curtail deliveries from the Seller's
Facility. Seller understands that in the case of emergency circumstances, real time operations of
the electrical system, and/or unplanned events, Idaho Power may not be able to provide notice to
the Seller prior to interruption, curtailment, or reduction of electrical energy deliveries to
Idaho Power.
ARTICLE xm: INDEMNIFICATION AND INSURANCE
13.1 Indemnification - Each Party shall agree to hold harmless and to indemnify the other Party, its
officers, agents, affiliates, subsidiaries, parent company and employees against all loss, damage,
expense and liability to third persons for injury to or death of person or injury to property,
proximately caused by the indemnifying Party's, (a) construction, ownership, operation or
maintenance of, or by failure of, any of such Party's works or facilities used in connection with
this Agreement, or (b) negligent or intentional acts, errors or omissions. The indemnifying Party
shall, on the other Party's request, defend any suit asserting a claim covered by this indemnity.
The indemnifying Party shall pay all documented costs, including reasonable attorney fees that
may be incurred by the other Party in enforcing this indemnity.
13.2 Insurance - During the term of this Agreement, Seller shall secure and continuously carry
insurance as specified in Appendix G.
ARTICLE XIV: FORCE MAJEURE
14.1 As used in this Agreement, "Force Majeure" or "an event of Force Majeure" means any cause
beyond the control of the Seller or of Idaho Power which, despite the exercise of due diligence,
such Party is unable to prevent or overcome. Force Majeure includes, but is not limited to, acts of
God, fire, flood, storms, wars, hostilities, civil strife, strikes and other labor disturbances,
earthquakes, fires, lightning, epidemics, sabotage, which, by the exercise of reasonable foresight
such party could not reasonably have been expected to avoid and by the exercise of due diligence,
25 IEP EXHIBIT 402
Page 26 of34
it shall be unable to overcome. Fluctuations and/or changes of the motive force and/or the fuel
supply are not events of Force Majeure. If either Party is rendered wholly or in part unable to
perform its obligations under this Agreement because of an event of Force Majeure, both Parties
shall be excused from whatever performance is affected by the event of Force Majeure, provided
that:
(1) The non-performing Party shall, as soon as is reasonably possible after the
occurrence of the Force Maj cure, give the other Party written notice describing
the particulars of the occurrence.
(2) The suspension of performance shall be of no greater scope and of no longer
duration than is required by the event of Force Maj cure.
(3) No obligations of either Party which arose before the occurrence of the Force
Majeure event and which could and should have been fully performed before
such occurrence shall be excused as a result of such occurrence.
ARTICLE XV: LIABILITY: DEDICATION
15.1 Limitation of Liability-Nothing in this Agreement shall be construed to create any duty to, any
standard of care with reference to, or any liability to any person not a Party to this Agreement.
Neither party shall be liable to the other for any indirect, special, consequential, nor punitive
damages, except as expressly authorized by this Agreement.
15.2 Dedication - No undertaking by one Party to the other under any provision of this Agreement
shall constitute the dedication of that Party's system or any portion thereof to the Party or the
public or affect the status of Idaho Power as an independent public utility corporation or Seller as
an independent individual or entity.
ARTICLE XVI: SEVERAL OBLIGATIONS
16.1 Except where specifically stated in this Agreement to be otherwise, the duties, obligations and
liabilities of the Parties arc intended to be several and not joint or collective. Nothing contained in
this Agreement shall ever be construed to create an association, trust, partnership or joint venture
26 IEP EXHIBIT 402
Page 27 of34
or impose a trust or partnership duty, obligation or liability on or with regard to either Party. Each
Party shall be individually and severally liable for its own obligations under this Agreement.
ARTICLE XVIl: WAIVER
17 .1 Any waiver at any time by either Party of its rights with respect to a default under this Agreement
or with respect to any other matters arising in connection with this Agreement shall not be
deemed a waiver with respect to any subsequent default or other matter.
ARTICLE XVIII: CHOICE OF LAWS AND VENUE
18. I This Agreement shall be construed and interpreted in accordance with the laws of the State of
Idaho without reference to its choice oflaw provisions.
18.2 Venue for any litigation arising out of or related to this Agreement will lie in the District Court of
the Fourth Judicial District ofldaho in and for the County of Ada.
ARTICLE XIX: DISPUTES AND DEFAULT
19.1 Pimutes -All disputes related to or arising under this Agreement, including, but not limited to,
the interpretation of the terms and conditions of this Agreement, will be submitted to the
Commission for resolution.
19 .2 Notice of Default
19.2.1 Defaults - If either Party fails to perform any of the terms or conditions of this
Agreement (an "event of default"), the non-defaulting Party shall cause notice in
writing to be given to the defaulting Party, specifying the manner in which such
default occurred. If the defaulting Party shall fail to cure such default within the sixty
(60) days after service of such notice, or if the defaulting Party reasonably
demonstrates to the other Party that the default can be cured within a commercially
reasonable time but not within such sixty (60) day period and then fails to diligently
pursue such cure, then the non-defaulting Party may, at its option, terminate this
Agreement and/or pursue its legal or equitable remedies.
19.2.2 Material Breaches -The notice and cure provisions in paragraph 19.2.1 do not apply
27 IEP EXHIBIT 402
Page 28 of34
to defaults identified in this Agreement as Material Breaches. Material Breaches must
be cured as expeditiously as possible following occurrence of the breach or if a
specific cure and/or inability to cure is identified by this Agreement for the specific
Material Breach then that cure shall apply.
19 .3 Prior to the Operation Date and thereafter for the full term of this Agreement, Seller will provide
Idaho Power with the following:
19.3.1 Insurance - Evidence of compliance with the provisions of Appendix G. If Seller
fails to comply, such failure will be a Material Breach.
19.3.2 Engineer's Certifications - Every three (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 State ofldaho, 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 Seller providing the required certificate; and
19.3.3 Licenses I Pennits I Determinations - During the full term of this Agreement, Seller
shall maintain compliance with all permits, licenses and determinations described in
paragraph 4.1.1 of this Agreement In addition, Seller will supply Idaho Power with
copies of any new or additional permits, licenses or determinations. At least every
fifth Contract Year, Seller will update the documentation described in Paragraph 4 .1.1.
If at any time Seller fails to maintain compliance with the permits, licenses and
determinations described in paragraph 4.1.1 or to provide the documentation required
by this paragraph, such failure will be an event of default and may only be cured by
Seller submitting to Idaho Power evidence of compliance from the permitting agency.
ARTICLE XX: GOVERNMENTAL AUI'HORIZATION
20.1 This Agreement is subject to the jurisdiction of those governmental agencies having control over
either Party of this Agreement.
28 IEP EXHIBIT 402
Page 29 of34
ARTICLE XXI: COMMISSION ORDER
21.1 Idaho Power shall file this Agreement for its acceptance or rejection by the Commission and
resolution of the disputed Solar Facility Pricing Schedule as described in paragraph 7 .1. This
Agreement shall only become finally effective upon the Commission's approval of all terms and
provisions hereof without change or condition and declaration that all payments to be made to
Seller hereunder shall be allowed as prudently incurred expenses for ratemaking purposes.
ARTICLE XXII: SUCCESSORS AND ASSIGNS
22.1 This Agreement and all of the terms and provisions hereof shall be binding upon and inure to the
benefit of the respective successors and assigns of the Parties hereto. Neither this Agreement nor
any rights or obligations of either Party hereunder may be assigned, in whole or in part, by
operation of law or otherwise, without the prior written consent of both Parties, which consent
shall not be unreasonably withheld. Notwithstanding the foregoing, any party with which Idaho
Power may consolidate, or into which it may merge, or to which it may convey or transfer
substantially all of its electric utility assets, shall automatically, without further act, and without
need of consent or approval by the Seller, succeed to all ofldaho Power's rights, obligations and
interests under this Agreement. Any purported assignment in derogation of the foregoing shall
be void. This article shall not prevent a financing entity with recorded or secured rights from
exercising all rights and remedies available to it under law or contract. Idaho Power shall have
the right to be notified by the financing entity that it is exercising such rights or remedies.
ARTICLE XXIIl: MODIFICATION
23 .1 No modification to this Agreement shall be valid unless it is in writing and signed by both Parties
and subsequently approved by the Commission.
ARTICLE XXN: TAXES
24.1 Each Party shall pay before delinquency all taxes and other governmental charges which, if failed
to be paid when due, could result in a lien upon the Facility or the Interconnection Facilities.
29 IEP EXHIBIT 402
Page 30 of34
ARTICLE XXV: NOTICES AND AUTHORIZED AGENTS
25.1 Notices-All written notices under this Agreement shall be directed as follows and shall be
considered delivered when faxed, e-mailed and confirmed with deposit in the U.S. Mail, first-
class, postage prepaid, as follows:
To Seller: Original document to:
Name:
Telephone:
Telephone:
E-mail:
E-mail:
Name:
Telephone:
E-mail:
To Idaho Power:
Clark Solar 1, LLC
Attn: Mark van Gulilc
POBox7354
Boise, Idaho 83707
[phone]
[phone]
[e-mail]
[e-mail]
Copy of Document to:
McDevitt & Miller LLP
Attn: Dean J Miller
420 West Bannock
Boise, Idaho 83702
[phone]
[e-mail]
Original document to:
Vice President, Power Supply
Idaho Power Company
POBox70
Boise, Idaho 83707
Email: [e-mail]
Copy of document to:
Cogeneration and Small Power Production
Idaho Power Company
PO Box 70
Boise, Idaho 83707
E-mail: [e-mail]
30 IEP EXHIBIT 402
Page 31 of34
Either Party may change the contact person and/or address information listed above, by providing
written notice from an authorized person representing the Party.
25.2 Authorized Agent(s)
Name Title
Authorized Agents as listed above may be modified by the Seller by requesting and completing
an Authorized Agent modification document provided by Idaho Power. This document at
minimum will include the requested changes and require signature(s) from an authorized party of
the Seller.
ARTICLE XXVI: ADDITIONAL TERMS AND CONDITIONS
26.1 Equal Employment - During performance pursuant to this Agreement, Seller agrees to comply
with all applicable equal employment opportunity, small business, and affirmative action laws
and regulations. All Equal Employment Opportunity and affirmative action laws and regulations
arc hereby incorporated by this reference, including provisions of 38 U.S.C. § 4212, Executive
Order 11246, as amended, and any subsequent executive orders or other laws or regulations
relating to equal opportunity for employment on government contracts. To the extent this
Agreement is covered by Executive Order 11246, the Equal Opportunity Clauses contained in 41
C.F.R. 60-1.4, 41 C.F.R. 60-250.5, and 41 CFR 60-741.5 arc incorporated herein by reference.
26.2 Prior to the Seller executing this Agreement, the Seller shall have:
a) Submitted an interconnection application for this Facility and is in compliance with all
payments and requirements of the interconnection process.
31 IEP EXHIBIT 402
Page 32 of34
b) Acknowledged responsibility for all interconnection costs and any costs associated with
acquiring adequate firm transmission capacity to enable the project to be classified as an
Idaho Power Designated Network Resource. If final interconnection or transmission
studies are not complete at the time the Seller executes this Agreement, the Seller
understands that the Seller's obligations to pay Delay and Termination Damages
associated with the project's failure to achieve the Operation Date by the Scheduled
Operation Date as specified in this Agreement is not relieved by final interconnection or
transmission costs, processes or schedules.
26.3 This Agreement includes the following appendices, which are attached hereto and included by
reference:
Appendix A - Generation Scheduling and Reporting
Appendix B - Facility and Point of Delivery
Appendix C - Engineer's Certifications
Appendix D - Forms of Liquid Security
Appendix E - Solar Facility Energy Prices
Appendix E - Alternative Solar Facility Energy Prices
Appendix G - Insurance Requirements
Appendix H - Solar Energy Production Forecasting
Appendix I - Estimated Hourly Energy Production
ARTICLE XXVII: SEVERABJLITY
27. I The invalidity or unenforoeability of any term or provision of this Agreement shall not affect the
validity or enforceability of any other terms or provisions and this Agreement shall be construed
in all other respects as if the invalid or unenforceable term or provision were omitted.
ARTICLE XXVIIl: COUNTERPARTS
28.1 This Agreement may be executed in two or more counterparts, each of which shall be deemed an
original but all of which together shall constitute one and the same instrument.
ARTICLE XXIX: ENTIRE AGREEMENT
29.1 'Ibis Agreement constitutes the entire Agreement of the Parties concerning the subject matter
hereof and supersedes all prior or contemporaneous oral or written agreements between the
Parties concerning the subject matter hereof.
32 IEP EXHIBIT 402
Page 33 of34
IN WITNESS WHEREOF, The Parties hereto have caused this Agreement to be executed
in their respective names on the dates set forth below:
Idaho Power Company
bCU> B. M,ii#r
LiHl',.GFew
8r. Vise FR!siilmt; Pe'l't er 81:1f'l'ly Exeui,re Vlu fi-11,il&,i � t!/ilel tJ�-11� /J#:cer
By
Clark Solar 1, LLC
Mark van Gulik
Manager
Dated
"Idaho Power"
33
Dated
�/ "Seller''
IEP EXHIBIT 402
Page 34 of 34
� CleanEnergy ? States Alliance
ENVIRONMENTAL RULES
FOR HYDROPOWER IN STATE
RENEWABLE PORTFOLIO STANDARDS
by
Val Stori
Project Director
Clean Energy States Alliance
April 2013
EXHIBIT
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 author'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.
(o CleanEnergy Stoles Alliance Hydropower Environmental Rules in Renewable Portfolio Standards 1
Introduction
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. In addition, a few states are considering strengthening or better defining their
environmental qualifications for hydropower.
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. It 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. In 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. In addition, because of concern over the ecological impacts of large dams, large
hydropower (most frequently defined as greater than 30 megawatts {MW)2), is limited in
1 There are mandatory RPSs in 29 states, plus the District of Columbia and Puerto Rico, as well as voluntary
renewable targets in 8 states. 2 Different states have different definitions of small hydropower. There is no standard definition of "small," but 30
MW is the general upper limit.
r: 0 '\ CleanEnergy � '.I Stoles Alliance Hydropower Environmental Rules in Renewable Portfolio Standards 2
inclusion in state RPSs. In 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.4 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 landfill gas.5
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.6 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 hydropower" as less than 60 MW.
4 See the RPS DSIRE spreadsheet here: http://dsireusa.org/rpsdata/index.dm 5 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://nhaap.ornl.gov/system/files/NHAAP NPD FYll Final Report.pdf
7 National Hydropower Association's policy priorities call for improving efficiencies and modernizing equipment:
http://www.hydro.org/tech-and-policy/policy-priorities/clean-renewable-electricity-standards/
r: Q x CleanEnergy � ') Stoles Alliance Hydropower Environmental Rules in Renewable Portfolio Standards 3
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
hydropower facilities.8
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.9 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." 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.14 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
r: O '\ Clean Energy � ') Stoles Alliance Hydropower Environmental Rules in Renewable Portfolio Standards 4
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.
9 Five states prohibit new dams: IL, MD, Ml, NH, and WA. CT and MA prohibit new dams inner 2.
1° Connecticut is considering replacing its Class I "run-of-river" criterion with Low Impact Hydropower Institute
certification. Ml and MA Tier 2 allow new run-of-river.
11 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. WI does not have a limit for large hydropower (<60 MW) completed after 2011.
u Again, small hydropower is usually defined as 30 MW, but this upper limit is somewhat arbitrary.
13 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:/fwww.mass.gov/eea/docs/doer/renewables/225-cmr-14-00-draft-reg-doer-
021413-tracked-changes.pdf 14 AZ, D.C., HA, IL, and KS do not specify a capacity limit for existing facilities.
its Class I. 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
fulfill 2% of the Class I target in 2014 with an annual increase of 1% up to a maximum of 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.17
Among the states with hydropower environmental regulations in RPSs, the following environ­
mental values are the most commonly protected by states:
• Adequate water flow to protect aquatic life and wildlife
• Fish passage
• Water quality
• 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
15 In March 2013, state lawmakers contemplated a bill that would remove the 100 MW limit on all renewable
energy technologies: http://bangordailynews.com/2013/03/13/politics/state-house/lepage-measure-would­
remove-100-megawatt-ca p-for-all-renewa bles/
16 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/DEEPEnergy.nsf/c6c6d525f7cdd1168525797d0047c5bf/67d62db9c92d7f6885257b32
0066e509/$FILE/DEEP%20RPS%20STUDY.pdf
17 The following states apply some kind of specific environmental restriction on hydropower in RPS: AZ., CA, CT, DE,
ME, MA, NH, NJ, NY, OH, OR, and PA.
r: Q \ Clean Energy � '.I Stales Alliance Hydropower Environmental Rules in Renewable Portfolio Standards 5
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 (4) 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 Impact Hydropower Institute (UHi) for RPS
inclusion.18 UHi is a non-profit organization that seeks to reduce the environmental impacts of
hydropower projects. It offers a voluntary certification program to identify and recognize
hydropower facilities that have minimal environmental impacts. Its 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. In addition, UHi checks state and federal compliance documents and the applicant
must ensure that it is meeting all required federal, state, and local standards. UHi does not
certify pumped storage facilities or new impoundments. In general, these environmental
criteria afford greater environmental protection than current legal requirements. 19 In 2009,
UHi reported 46 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
17% of the state's electricity demand from hydro power. 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.21 The state's policies support
hydropower, both new and old, including through its RPS. While the state does not require UHi
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-
18 OE, MA, OR, and PA require LIHI certification in at least one tier. Utah requires LIHI certification for its voluntary
Renewable Portfolio Goal. 19 LIHI Certification Handbook
http://www.lowimpacthydro.org/assets/files/LIHl%20Handbook0ecember%202011%281%29.pdf
20 Low Impact Hydropower Institute, Certified Facilities. Accessed April 15, 2013.
http://www.lowimpacthydro.org/certified-facilities/ 21 http://www.dec.ny.gov/energy/43242.html
r: Q '\ CleanEnergy � ',I Stoles Alliance Hydropower Environmental Rules in Renewable Portfolio Standards 6
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
unit; (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 Independent 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 UHi 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. 23 The following states prohibit pumped storage: CO, D.C., MD, Ml, MO, OR, PA, DE, and MA.
0) CleanEnergy States Alliance Hydropower Environmental Rules in Renewable Portfolio Standards 7
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Case No. PAC-E-15-03
Exhibit No.1!;' (&O I
Witness: Paul H. Clements
BEFORE THE IDAHO PUBLIC UTlLITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Paul H. Clements
February 2015
Rocky Mountain Power
Exhibit No. 1 Page 1 of 3
Case No. PAC-E-15-03
\Nitness: Paul H. Clements
Location Type Size (MW) Proposed Online Date
Idaho Gas 4.5 08/01/2015
Idaho Solar 40.0 08/01/2016
Idaho Solar 20.0 08/01/2016
Idaho Solar 20.0 08/01/2016
Idaho Solar 50.0 08/01/2016
Idaho Solar 20.0 10/31/2016
Idaho Solar 20.0 10/31/2016
Idaho Solar 21.0 12/31/2016
Idaho Solar 20.0 12/31/2016
Idaho Solar 20.0 12/31/2016
Idaho Solar 20.0 12/31/2016
Idaho Solar 20.0 12/31/2016
Oregon Geothermal 3.5 05/01/2014
Oregon Solar 10.0 12/31/2015
Oregon Solar 0.8 12/31/2015
Oregon Solar 10.0 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 7.5 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 8.0 12/31/2016
Oregon Solar 9.9 12/31/2016
Oregon Solar 9.9 12/31/2016
Oregon Solar 9.9 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 9.9 12/31/2016
Oregon Solar 7.5 12/31/2016
Oregon Solar 10.0 12/31/2016
Oregon Solar 10.0 12/31/2016
Rocky Mountain Power
Exhibit No. 1 Page 2 of 3
Case No. PAC-E-15-03
Wtness: Paut H. Clements
Location Type Size (MW) Proposed Online Date
Oregon Solar 9.9 12/31/2016
Oregon Solar 9.9 12/31/2016
Oregon Solar 45.0 12/31/2016
Oregon Solar 20.0 12/31/2016
Oregon Solar 44.2 01/01/2017
Utah Solar 50.0 08/31/2015
Utah Wind 80.0 10/01/2015
Utah Wind 45.0 11/01/2015
Utah Solar 50.4 12/01/2015
Utah Solar 65.6 12/15/2015
Utah Solar 50.4 12/15/2015
Utah Solar 10.0 12/31/2015
Utah Solar 80.0 12/31/2015
Utah Solar 80.0 12/31/2015
Utah Solar 80.0 12/31/2015
Utah Solar 5.0 12/31/2015
Utah Solar 21.0 01/01/2016
Utah Solar 80.0 01/01/2016
Utah Solar 1.0 04/03/2016
Utah Solar 80.0 06/01/2016
Utah Solar 80.0 06/01/2016
Utah Solar 80.0 06/01/2016
Utah Solar 80.0 06/01/2016
Utah Solar 80.0 06/01/2016
Utah Solar 80.0 06/01/2016
Utah Solar 80.0 10/01/2016
Utah Solar 20.0 10/01/2016
Utah Solar 80.0 11/01/2016
Utah Solar 80.0 11/01/2016
Utah Solar 80.0 11/01/2016
Utah Solar 80.0 11/01/2016
Utah Solar 1.0 12/31/2016
Utah Solar 20.0 12/31/2016
Utah Solar 40.0 12/31/2016
Utah Solar 50.0 12/31/2016
Utah Solar 15.0 12/31/2016
Utah Solar 14.5 12/31/2016
Rocky Mountain Power
Exhibit No. 1 Page 3 of 3
Case No. PAC-E-15-03
llllltness: Paul H. Clements
Location Type Size (MW) Proposed Online Date
Utah Solar 7.5 12/31/2016
Utah Solar 50.0 12/31/2016
Utah Solar 80.0 12/31/2016
Utah Solar 80.0 12/31/2016
Utah Solar 6.0 12/31/2016
Utah Wind 69.0 12/31/2016
Utah Solar 78.2 12/31/2016
Utah Solar 80.0 01/01/2018
Utah Solar 80.0 01/01/2018
Utah Wind 80.0 01/01/2018
Utah Wind 80.0 01/01/2018
Wyoming Wind 80.0 07/31/2015
Wyoming Wind 80.0 12/01/2015
Wyoming Wind 80.0 01/01/2016
Wyoming Wind 60.0 01/01/2016
Wyoming Wind 80.0 12/31/2017
Wyoming Wind 80.0 12/31/2017
Wyoming Wind 80.0 12/31/2017
Wyoming Wind 80.0 12/31/2017
NOTICE OF INTENT NOT TO ACT AND DECLARATORY ORDER
(Issued November 19, 2009)
Background
Docket No. EL09-77-000
129 FERC 161,148
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
110 /
2 JD Wind I, LLC, et al. v. Southwestern Public Service Company, Texas
Commission Docket No. 3442 (May l, 2009) (Texas Commission Order).
3 16 U.S.C. § 824a-3 (2006); 18 C.F.R. Part 292 (2009).
I 16 U.S.C. § 824a-3(h) (2006).
2. JD Wind l, 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 qualifying facilities
1. 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
(PURP A). 1 However, as discussed below, we conclude that the May 1, 2009 decision of
the Public Utility Commission of Texas (Texas Commissionj.i which determined that the
wind-powered generation of JD Wind 1, LLC, JD Wind 2, LLC, JD Wind 3, LLC, JD
Wind 4, LLC, JD Wind 5, 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 PURP A and our
regulations implementing PURP A.3
Before Commissioners: Jon Wellinghoff, Chairman;
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 - 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 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)5 of the
Commission's regulations, which gives QFs the option of selling energy "as available'"
or selling "energy or capacity pursuant to a legally enforceable obligation for the delivery
of energy or capacity over a specified terrn.?" 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.9 In
the complaint before the Texas Commission, JD Wind sought both a legally enforceable
obligation, and rates based on avoided costs calculated at the time the obligation was
incurred.
4 On May 18, 2005, J.D.Wind 1, LLC filed a notice of self-certification in Docket
No. QF05-l 14-000; on September 12, 2007, JD Wind 1, LLC filed a notice of self­
recertification. On May 18, 2005, J .D. Wind 2, LLC filed a notice of self-certification in
Docket No. QF05-1 l 6-000; on September 14, 2007, JD Wind 2, LLC filed a notice of
self-recertification. On April 29, 2005, J.D. Wind 3, LLC filed a notice of self­
certification in Docket No. QF05-l l 5-000; 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 10 MW, except for J.D.Wind 4, LLC which is 79.8 MW.
5 18 C.F.R. § 292.304(d) (2009).
6 Id. § 292.304( d)( l ).
7 Id. § 292.304(d)(2).
8 Id. § 292.304(d)(2)(i).
9 Id. § 292.304(d)(2)(ii).
Docket No. EL09-77-000 - 3 -
3. A Texas Commission 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." 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."!' The
Administrative Law Judge's decision was largely based on a finding of fact that "Wind­
Generated Power is not readily available.v'" The Texas Commission affirmed the
Administrative Law Judge's decision with the exception of the latter 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.'3
4. JO Wind asks the Commission to enforce PURP A. JO Wind states that the Texas
Commission 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 time of creation of a legally
enforceable obligation. JD Wind argues that section 210(h)(2) of PURP A 14 authorizes
the Commission to enforce the requirements of PURP A against a state regulatory
authority, such as the Texas Commission. JD Wind also argues, quoting from the
Commission's Policy Statement Regarding the Commission's Enforcement Role Under
Section 210 of the Public Utilities Regulatory Policies Act of 1978, 15 that the
Commission's enforcement authority extends to situations where state regulatory
authority implementation actions under PURP A "are inconsistent with or contrary to the
Commission's regulations." JD Wind concludes that the Commission should exercise its
16 JD Wind 1, LLC, et al. v. Southwestern Public Service Company, Texas
Commission Docket No. 3442 at 32-38 (March 25, 2009).
11/d.
12 Id. at 40.
13 Texas Commission Order at 1.
14 16 U.S.C. § 824a-3(h)(2) (2006).
15 23 FERC, 61,204 at 61,644 (1983) (1983 Policy Statement).
Docket No. EL09- 77-000 -4-
authority under section 210(h)(2) of PURPA because the Texas Commission'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 determined 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 payment
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 intermittent
resources.
6. Notice of JD Wind's filing was published in the Federal Register, 74 Fed. Reg.
51 14 7 (2009), with interventions and protests due on or before October 22, 2009.
7. The Texas Commission filed a timely notice of intervention and protest. The
Texas Commission argues that an enforcement proceeding pursuant to section 21 O(h) of
PURP A does not lie; instead the Texas Commission suggests JD Wind should pursue a
challenge to the Texas Commission's decision pursuant to section 210(g) of PURPA in
state court. The Texas Commission also suggests that the Commission has no role in the
Texas implementation of PURP A once the Texas Commission has adopted rules to
implement PURP A. The Texas Commission also argues that its decision regarding JD
Wind is limited to the facts of JD Wind, and thus does not warrant a declaratory order of
general applicability. Finally, the Texas Commission argues that its decision is consistent
with PURPA and the Commission's regulations implementing PURPA.
8. Xcel Energy Services, Inc. (Xcel), on behalf of itself and its public utility
operating company affiliate, SPS, filed a timely motion to intervene and protest. Xcel
argues that JD Wind properly belongs in state court, pursuant to section 21 O(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 Commission order in state court. Xcel also argues that JD Wind has
mischaracterized the Texas Commission order. Xcel states that, while Texas Jaw
contemplates that legally enforceable obligations can only be created by QFs delivering
"firm power," the Texas Commission 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 legalJy 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 legalJy 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 satisfy 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 Commission decision is not inconsistent with PURP A or with the
Commission's regulations implementing PURPA. Occidental argues that JD Wind's
arguments that the Texas Commission 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. "16
l 0. The American Wind Energy Association (A WEA) and the Solar Energy Industries
Association (SEIA) filed a motion to intervene, 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 intermittent resource QFs are not
prohibited from selling their output pursuant to legally enforceable obligations based on
forecast avoided costs. A WEA states that it is a national trade association representing a
broad range of entities with a common 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 Commission's regulations and that the Texas Commission does
not have the authority, under PURPA, to act inconsistently with the Commission's
regulations. They argue that the Texas Commission's decision that states that a legally
16 Occidental Motion to Intervene at 25.
Docket No. EL09-77-000 - 6 -
enforceable obligation does not apply to wind generation because it is intermittent, or
"non-firm" in the language of the Texas Commission, prohibits all intermittent resources
from 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.
11. 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 Small 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 Commission's interpretation of when legally enforceable obligations can be
established will negatively affect all intermittent resource QFs in the United States.
I 4. The Texas Renewable Energy Industries Association (Texas Renewables) filed
comments in support of JD Wind's petition. Texas Renewables states that the Texas
Commission decision will adversely affect the development of renewable resource
electric generation in Texas. Reversal of the Texas Commission decision is necessary,
Texas Renewables argues, for potential facilities to obtain project financing, which is
critical to developing new renewable resource generation.
I 5. 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 Commission's decision will cause to the development of renewable
resources. The Wind Coalition argues that the Texas Commission order is inconsistent
with the plain language of both PURPA and the Commission's regulations implementing
PURPA.
Docket No. EL09-77-000 - 7 -
17. JD Wind filed an answer to the protests filed by Xcel, Occidental, the Texas
Commission 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,
18 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(a)(2) (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 them.
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 Commission 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 Commission, is in conflict with section
292.304.( d)( 1) of our regulations.17 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 time 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 small power production." 18 PURP A, in turn,
directs the states to "implement" the rules adopted by the Commission.19 A "state
17 18 C.F.R. § 292.304(d)(l) (2009).
18 16 U.S.C. §§ 824a-3(a)-(b) (2006).
19 16 U.S.C. § 824a-3(f) (2006); accord FERC v. Mississippi, 456 U.S. 742, 751
( 1982); Independent Energy Producers Association v. California Public Utilities
Commission, 36 F.3d 848, 856 (9th Cir. 1994); Cogeneration Coalition of America, Inc.,
61 FERC ,i 61,252, at 61,925-26 (1992); Small Power Production and Cogeneration
(continued ... )
Docket No. 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 effecr to [the Conunission's] rules."20 As a result, a state may take action under
PURP A 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 Commission's regulations.':" Section
210(h)(2)(B) of PURPA22 permits any qualifying small power producer, among others, to
petition the Commission to act under section 210(h)(2)(A) of PURPA23 to enforce the
requirement that a state commission implement the Commission's regulations. The
Commission's enforcement authority under section 210(h)(2)(A) of PURPA is
discretionary. As the Commission pointed out in its 1983 Policl Statement, "the
Commission is not required to undertake enforcement action.t" If the Commission does
not undertake an enforcement action within 60 days of the filing of a petition, under
section 210(h)(2)(A) of PURPA, the petitioner then may bring its own enforcement
action directly against the state regulato�< authority or nonregulated electric utility in the
appropriate United States district court."
22. Here, we give notice that we do not intend to go to court to enforce PURP A 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 Utility Regulatory
Policies Act of 1978, Order No. 69, FERC Stats. & Regs. ,i 30, 128, at 30,864 (1980),
order on reh'g, Order No. 69-A, FERC Stats. & Regs. ,i 30,160 (1980), a.lfd in part and
vacated in part, American Electric Power Service Corporation v. FERC, 675 F.2d 1226
(D.C. Cir. 1982), rev'd in part, American Paper Institute, Inc. v. American Electric
Power Service Corporation, 461 U.S. 402 (1983).
2° FERCv. Mississippi, 456 U.S. 742, 751 (1982);seealso 1983 Policy Statement,
23 FERC ,! 61,304, at 61,643 (1983).
21 1983 Policy Statement, 23 FERC ,i 61,304 at 61,644.
22 16 U.S.C. § 824a-3(h)(2)(8) (2006).
23 16 U.S.C. § 824a-3(h)(2)(A) (2006).
24 1983 Policy Statement, 23 FERC ,i 61,304 at 61,645.
25 16 U.S.C. § 824a-3(h)(2)(B) (2006). The Commission may intervene in such a
district court proceeding as a matter of right. Id.
Docket No. EL09- 77-000 - 9 -
23. Notwithstanding our decision not to go to court to enforce PURP A on behalf of JD
Wind, we find that the Texas Commission'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 PURP A and our regulations implementing PURP A, particularly section
292.304(d) of our regulations.26
24. When Congress enacted PURP A 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 PURP A
was because electric utilities had refused to purchase power from non-utility producers.27
Congress thus required the Commission to prescribe rules that the Commission
"determines necessary to encourage cogeneration and small power production.v'" In
section 210(a) of PURPA,29 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.30
25. The Commission's regulations under PURPA also include a requirement that QFs
have the option to sell not only as available but pursuant to legally enforceable
obligations over specified terms.31 Section 292.304(d)32 provides:
(d) Purchases "as available" or pursuant to a legally enforceable
obligation. Each qualifying facility shall have the option either:
( l) To provide energy as the qualifying 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
26 18 C.F.R. § 292.304(d) (2009).
27 FERC v. Mississippi, 456 U.S. 742, 750 (1982).
28 16 U.S.C. § 824a-3(a) (2006).
29 Id.
36 18 C.F .R. § 292.303 (2009).
31 Id. § 292.304(d)(2).
32ld. § 292.304(d).
Docket No. EL09-77-000 - IO -
(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 qualifying
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 PURP A that utilities purchase energy and
capacity from QFs. The Commission explained:
Paragraph (d)(2) permits a qualifying 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 facilitr. merely by refusing to enter into a
contract with a qualifying facility.[3 ]
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 PURP A-imposed obligation on the electric utility to purchase
from the QF, and a non-contractual, but still legally enforceable, obligation will be
created pursuant to the state's implementation of PURPA.34 Accordingly, a QF, by
33 Order No. 69, FERC Stats. & Regs. ,I 30, 128 at 30,880 ( I 980); accord id.
(noting "the need for qualifying 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").
34 New PURPA Section 2/0(m) Regulations Applicable to Small Power Production
and Cogeneration Facilities, Order No. 688, FERC Stats. & Regs. 131,233, at P 212
(2006), order on reh 's. Order No. 688-A, FERC Stats. & Regs. ,I 31,250, at P 136-3 7
(2007), aff'd sub nom. American Forest and Paper Association v. FERC, 550 F.3d
1179 (D.C. Cir. 2008); see also Midwest Renewable Energy Projects, LLC, 116 FERC
161,017 (2006).
Docket No. EL09-77-000 - 11 -
committing itself to sell to an electric utility, also commits the electric utility to buy from
the QF; these commitments result either in contracts or in non-contractual, but binding,
legally enforceable obligations.
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;35 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)36 is available only to QFs that can deliver "firm" power, and that
the option in section 292.304( d)( I )37 must be chosen by those QFs that cannot deliver
"firm" power. We do not agree. As a starting point, we note that section 292.304(d)
does not draw such a distinction; it does not contain the words "firm" or "non-firm."
Protesters, however, point to the use of the words "as available" in the title, and to the
language of section 292.304( d)( I), as suggesting that section 292.304( d)( 1) is intended to
be applied to all "non-firm" sales. This is contrary to the language of the re�ulation
which provides that "{e]ach qualifying facility shall have the option either:" 8 to choose
the section 292.304( d)( 1) method of sale, or the section 292.304( d)(2) method of sale;
i.e., the QF may choose either: (I) 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 imposed on the utility by the state regulatory authority. No limitation based on
firmness is mentioned. Indeed, in Order No. 69, the Commission explained that an "as
35 See 18 C.F.R. § 292.304(d)(l) (2009).
36Id. § 292.304(d)(2).
37 Id. § 292.304(d)(I ).
38 Id. § 292.304(d) (emphasis added).
Docket No. EL09-77-000 - 12 -
available" basis merely means "without legal obligation.v" 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 latter
option, as JD Wind seeks to do, it then has the option to choose a rate 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, section 292.304(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. "41 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 "non-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.42 The 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 Commission's order, limiting the award of a
legally enforceable obligation to only those QFs that provide "firm" power, is
inconsistent with our regulations implementing PURP A. 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 time that
obligation is incurred.
39 Order No. 69, FERC Stats. & Regs. ,i 30,128 at 30,880.
40 Id. at 30,881-83.
41 See 18 C.F.R. § 292.304(e) (2009).
42 Order No. 69, FERC Stats. & Regs. ,i 30,128, at 30,881-82 (1980). In fact, the
Commission also expressly found that wind generators can provide "firm capacity." Id.
at 30,882.
� . .
Docket No. EL09- 77-000
The Commission orders:
(A) Notice is hereby given that the Commission declines to initiate an
enforcement action under section 210(h)(2){A) of PURPA.
- 13 -
(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.
(Issued February 19, 2010)
ORDER DENYING "REQUESTS FOR REHEARING, RECONSIDERATION OR
CLARIFICATION"
Docket No. EL09- 77-00 l
Before Commissioners: Jon Wellinghoff, Chairman;
Marc Spitzer, Philip D. Moeller,
and John R. Norris.
JD Wind 1, LLC
JD Wind 2, LLC
JD Wind 3, LLC
JD Wind 4, LLC
JD Wind 5 LLC
JD Wind 6, LLC
130 FERC � 61,127
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
I JD Wind 1, LLC, 129 FERC � 61,148 (2009) (November 19 Order).
2 16 U.S.C. § 824a-3(h) (2006).
1. 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 1, LLC, JD Wind 2, LLC, JD Wind 3, LLC, JD Wind 4,
LLC, JD Wind 5, LLC, and JD Wind 6, LLC (collectively, JD Wind).1 In the November
19 Order, the Commission gave notice that it declined to initiate an enforcement action
pursuant to the section 21 O(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 Commissionr' -- which determined that JD Wind's wind­
powered generation is not entitled to a legally enforceable obligation and an avoided cost
3 JD Wind I, LLC v. Southwestern Public Service Co., Texas Commission Docket
No. 3442 (May I, 2009) (Texas Commission Order).
Docket No. EL09- 77-00 l
rate calculated at the time that obligation is incurred -- is inconsistent with the
requirements of PURPA and our regulations implementing PURPA.4
- 2 -
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 PURP A 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 19 Order; we accordingly deny the requests.
Backe;round
3. As discussed more fully in the November 19 Order, JD Wind l, 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 qualifying 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,5 which gives QFs the option of
selling energy "as available'" or selling "energy or capacity pursuant to a legally
enforceable obligation for the delivery of energy or capacity over a specified term."? 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.9 In the complaint before the Texas Commission,
4 16 U.S.C. § 824a-3 (2006); 18 C.F.R. Part 292 (2009).
5 18 C.F.R. § 292.304(d) (2009).
6 Id.§ 292.304(d)(I).
7 Id. § 292.304(d)(2).
8 Id. § 292.304(d)(2)(i).
9 Id. § 292.304(d)(2)(ii).
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 "firm power," and that, in the absence of that showing, "the JD Wind
Companies cannot create a legally enforceable obligation.v'" The Administrative Law
Judge's decision was largely based on a finding of fact that "Wind-Generated Power is
not readily available."11 The Texas Commission affirmed the Administrative Law
Judge's decision with the exception of the latter 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.12
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 19 Order
6. The Commission exercised its discretion and declined to go to court to enforce
PURP A 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 PURP A 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. 13 The Commission specifically pointed to
section 292.304( d), 14 which provides:
(d) Purchases "as available" or pursuant to a legally enforceable
obligation. Each qualifying facility shall have the option either:
10 JD Wind I, LLC, et al. v. Southwestern Public Service Co., Texas Commission
Docket No. 3442 at 32-38 (March 25, 2009).
II Id. at 40.
12 Texas Commission Order at 1.
13 November 19 Order, 129 FERC ,i 61,148 at P 25-29.
14Jd.; 18 C.F.R. § 292.304(d) (2009).
Docket No. EL09-77-001 - 4 -
(1) To provide energy as the qualifying 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 qualifying
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.
7. Noting that section 292.304(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.15 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 obligations. 16
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 "firm" power,
is inconsistent with the Commission's regulations implementing PURPA.17 Under these
regulations, each QF, including each QF owned by JD Wind, has the right to choose to
15 November 19 Order, 129 FERC � 61,148 at P 25, 29; New PURPA
Section 2JO(m) Regulations Applicable to Small Power Production and Cogeneration
Facilities, Order No. 688, FERC Stats. & Regs.� 31,233, at P 212 (2006), order on
reh 's. Order No. 688-A, FERC Stats. & Regs. � 31,250, at P 136-3 7 (2007), aff'd sub
nom. American Forest and Paper Association v. FERC, 550 F.3d 1179 (D.C. Cir. 2008);
see also Midwest Renewable Energy Projects, LLC, 116 FERC � 61,017 (2006).
16 November 19 Order, 129 FERC � 61,148 at P 25, 29.
17 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. 18
Requests for Rehearine;, 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 PURP A.19
Finally Xcel argues that the Commission should have instituted a rulemaking before
re-interpreting its regulations. Xcel also asks the Commission to clarify that its
November 19 Order is "of no legal moment." Xcel further asks the Commission to
clarify 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 clarify that the Commission: (1) 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.
1 1. 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.
is Id.
19 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
Discussion
Procedural Matters
- 6 -
12. Because this proceeding arises under section 21 O(h) of PURP A, formal rehearing
does not lie, either on a mandatory or a discretionary basis." 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.21 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 19 Order
represents a change to its interpretation of section 292.304(d) of its regulations.V Both
also argue, relying primarily on a portion of the legislative history of PURPA,24 that the
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
20 See Southern California Edison Co., 71FERC161,090, at 61,305 (1995);
New York State Electric & Gas Corp., 72 FERC 161,067, at 61,340 (1995).
21 18 C.F.R. § 385.713(d) (2009).
22 See CGE Fulton, l.L. C., 71 FERC 1 61,232, at 61,880-81 ( 1995); Connecticut
light & Power Co., 71FERC161,035, at 61,151 (1995).
23 18 C.F.R. § 292.304(d) (2009).
24 H.R. Rep. No. 95-1750, at 99 (1978).
Docket No. EL09-77-001 - 7 -
obligation (section 292.304(d)(2)).25 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.27 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.28
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 19 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.29 The preamble to its adoption of the regulation
at issue here expressly contemplated that QFs could receive a capacity payrnent.i'' And,
in fact, the Commission recognized the possibility that intermittent QF resources,
including solar and wind resources, which would not be considered "firm" 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
25 18 C.F .R. § 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.
26 18 C.F.R. § 292.304(d)(2)(i) (2009).
27 18 C.F .R. § 292.304( d)(2)(ii) (2009).
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 PURP A for consistency with our regulations; review typically occurs,
as here, when we are presented with a petition for enforcement.
29 November 19 Order, 129 FERC ,i 61, 148 at P 28.
30 id.
Docket No. EL09-77-001 - 8 -
for purchases.v'! 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 qualifying 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. Section 292.304(d)
constitutes part of the Commission's original implementation of PURP A 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 PURP A, including the issue of the consistency of our regulation granting
a QF the option of selling pursuant to a legally enforceable obligation with PURP A, the
issue should have been raised in the context of that rulemaking and the appeal of that
rulemaking.
31 Id. P 28 & n.42. (citing Order No. 69, FERC Stats. & Regs.� 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.� 30, 128 ( 1980), order on reh'g, Order No. 69-A, FERC
Stats. & Regs. 130,160 (1980), aff'd 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, American
Paper Institute, Inc. v. American Electric Power Service Corp., 461 U.S. 402 ( 1983).
-------------�------------------------------
Docket No. EL09-77-00 I - 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 PURP A. Xcel points to the following language to support its argument that
Congress intended that nonfirm power cannot qualify for a legally enforceable obligation:
The conferees expect that the Commission, in judging whether the electric
power supplied by the [ qualifying 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 [ qualifying facility]
by reason of any legally enforcible [sic] oblif?tion of such [ qualifying
facility] to supply firm power to the utility. [3 ]
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. 34
The Commission's regulations, discussed above, addressing both the right to a legally
enforceable obligation as well as, separately, consideration of the firmness 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 a rate 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 19 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
33 H.R. Rep. No. 95-1750, at 99 (1978).
34 November 19 Order, 129 FERC 161, 148 at P 28; see Order No. 69, FERC
Stats. & Regs. 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.t''" The Commission recognized that:
[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.38 Rates based on avoided
costs at the time the obligation is originally incurred are consistent with the requirements
of PURP A, 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.39 However, that the Commission
35 Id. at 30,880.
36 Id. at 30,868.
37 Id. at 30,880.
38 See, e.g., New York State Electric & Gas Corp., 71 FERC 61,027, at 61,115-
16 ( 1995), order denying reconsideration, 72 FERC ,I 61,067 ( 1995), appeal dismissed
sub nom. New York State Electric & Gas Corp. v. FERC, 117 F.3d 1473 (D.C. Cir. 1997).
39 Occidental is also correct that the Commission has twice refused to prematurely
address certain issues between Xcel and JD Wind. See Xcel Energy Services, Inc., 122
FERC ,I 61,048, at P 45 (2008) (the Commission, because it was denying Xcel 's PURP A
(continued ... )
Docket No. EL09-77-001 - 11 -
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 PURP A or the
Commission's regulations. Under PURPA, the Commission has prescribed "such rules
as it determines necessary to encourage cogeneration and small power production." 40
PURPA, in turn, directs the states to "implement" the rules adopted by the Commission.41
When a state commission ignores the requirements of PURPA, as implemented in our
regulations, the QF has the right under PURP A to seek enforcement of its PURP A
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.43 Section 210(h)(2)(B) of PURPA permits any
qualifying small power producer, among others, to petition the Commission to act under
section 21 O(h)(2)(A) of PURP A 44 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 19 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 21 O(m) petition to terminate the mandatory purchase obligation, declined to
address whether a legally enforceable obligation had been established); Xcel Energy
Services, Inc. v. Southwest Power Pool, Inc., 118 FERC ,r 61 ,232, at P 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.
40 16 U.S.C. §§ 824a-3(a)-(b) (2006).
41 16 U.S.C. § 824a-3(t) (2006); accord FERC v. Mississippi, 456 U.S. 742, 751
(1982); Independent Energy Producers Association v. California Public Utilities
Commission, 36 F.3d 848, 856 (9th Cir. 1994); Cogeneration Coalition of America, Inc.,
61 FERC ,I 61,252, at 61,925-26 (1992).
42 November 19 Order, 129 FERC ,r 61, 148 at P 21.
43 I 6 U.S.C. § 824a-3(h)(2)(B) (2006).
44 16 U.S.C. § 824a-3(h)(2)(A) (2006).
Docket No. EL09-77-001 - 12 -
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.45
25. Where, as here, the Commission does not undertake an enforcement action within
60 days of the filing ofa petition, under section 210(h)(2)(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.46 Our
November 19 Order, as well as the instant order, serve as a statement of our position
regarding the right under PURP A of each QF to enter into a legally enforceable
obligation.47
The Commission orders:
Occidental's and Xcel's requests are hereby denied.
By the Commission.
(SEAL)
Kimberly D. Bose,
Secretary.
45 See, e.g., MidAmerican Energy Co., 85 FERC 1 61,4 70 ( 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 1 61,012 ( 1995), reconsideration denied, 71 FERC 1 61,012 (state adder to
avoided cost rate conflicts with PURP A).
46 16 U.S.C. § 824a-3(h)(2)(B) (2006). The Commission may intervene in such a
district court proceeding as a matter of right. Id.
47 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 Energy Services, Inc.,
and Southwestern Public Service Co., 117 FERC 1 61,280, at P 1 (2006).
Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014)
Util. L. Rep. P 14,913
766 F.3d380 United States Court of Appeals,
Fifth Circuit.
facilities must be able to form legally enforceable
obligations.
Reversed and remanded.
EXELON WIND 1, L.L.C., formerly known as JD
Wind 1, L.L.C.; Exelon Wind 2, L.L.C., formerly
known as JD Wind 2, 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.,
Plain tiffs-A ppellees,
v.
Donna L. NELSON, in her 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. 12-51228. I Sept. 8, 2014.
Synopsis
Background: Qualifying wind generation facilities under
the Public Utilities Regulatory Policies Act (PURP A)
brought action against the Texas Public Utilities
Commission (PUC), challenging the PUC's requirement
that only qualifying 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:
111 Texas Courts had exclusive jurisdiction over the
facilities' challenges to the Texas PUC's order;
121 federal courts had exclusive jurisdiction over the
facilities' challenges to the Texas PUC's rule; and
111
121
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 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. 16 U.S.C.A. §
824a-3(f).
Cases that cite this headnote
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
West Headnotes {23)
Edward C. Prado, Circuit Judge, filed an opinion
concurring in part and dissenting in part.
IJJ PURPA and Federal Energy Regulatory Commission
(FERC) regulations did not mandate that all qualifying
Westl v Next 2015 Thomson Reuters No claim to 011ginal U S Government Works
Exelon Wind 1, L.L.C. v, Nelson, 766 F.3d 380 (2014)
Util. L. Rep. P 14,913
141
Federal Courts
.,,..Jurisdiction
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 plaintiff has the burden of establishing subject
matter jurisdiction.
Cases that cite this headnote
171 Courts
.-Exclusive 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
PU RP A if two conditions are met: ( 1) the party
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. 16 U.S.C.A.
§ 824a-3(h)(2)(A)-(B).
Cases that cite this headnote
151
161
Federal Courts
Y..Oismissal 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
..,...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.
16 U.S.C.A. §§ 824a-3(f), 824a-3(g).
Cases that cite this headnote
181
191
Courts
Y-Exclusive 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. 16
U.S.C.A. § 824a-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
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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 both the agency and the court. 1131 Administrative Law and Procedure
Deference to agency in general
1101
1111
1121
Cases that cite this headnote
Administrative Law and Procedure
'"'"Permissible 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
court defers to the agency's interpretation if it is
a reasonable interpretation of the 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
Federal Courts
Y"'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
subject-matter jurisdiction.
Cases that cite this headnote
1141
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
..-Exclusive 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 qualifying
facilities could form legally enforceable
obligations would require the Texas PUC to
alter its current rules. 16 U.S.C.A. § 824a-3(f).
Cases that cite this headnote
Judgment
¥""Inferences from judgment
Questions of subject matter jurisdiction that
have been passed on in prior decisions sub
silentio are not entitled to preclusive effect.
Cases that cite this headnote
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Util. L. Rep. P 14,913
1'61 Courts
w-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, § 21 O(f), 16 U.S.C.A. §
824a-3(f).
Cases that cite this headnote
1191 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 qualifying facilities must be
able to form legally enforceable obligations, and
thus the Texas Public Utilities Commission
(PUC) could additionally require that qualifying
facilities produce firm power before permitting
the facilities to enter legally enforceable
obligations. 16 U.S.C.A. § 824a-3(f)(I); 18
C.F.R. § 292.304(d).
Cases that cite this headnote
1171
1181
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 qualifying
facilities. 16 U.S.C.A. § 824a-3{f)(l).
Cases that cite this headnote
Electricity �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. § 824a-3(t)(l).
Cases that cite this headnote
1201
1211
Administrative Law and Procedure
,i,i-Plain, literal, or clear meaning; ambiguity
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.
Cases that cite this headnote
Administrative Law and Procedure
4-Plain, literal, or clear meaning; ambiguity
Administrative Law and Procedure
-Erroneous construction; conflict 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
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(23(
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
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
Qualifying Facilities. Appellees are qualifying 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.
1221 Statutes
9-Supertluousness
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.
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-Appellants.
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, Esq., King & Spalding, L.L.P.,
Washington, DC, for lntervenors-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:
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. Mississippi, 456 U.S. 742, 745, 102
S.Ct. 2126, 72 L.Ed.2d 532 (1982); Power Res. Grp. v.
Pub. Viii. Comm 'n, 422 F.3d 231, 233 (5th Cir.2005)
[hereinafter Power Resource Ill ).1 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
Qualifying Facilities. See 16 U.S.C. §§ 796(17),
824a-3(a); 18 C.F.R. §§ 292.IOl(b)(I), 292.203. While
Congress sought to promote energy generation by
Qualifying 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
Qualifying 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." 16 U.S.C. § 824a-3(a)(2), (b)(l).
111 "State regulatory agencies, such as the PUC, are
directed to adopt rules which comply with FERC's
regulations and implement PURPA." Power Resource /II.
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422 F.3d at 233 (citing 16 U.S.C. § 824a-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 New
York v. United States, 505 U.S. 144, 167-68, 112 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, I 02 S.Ct. 2126. In FERC v. Mississippi, 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.
Id. at 760, I 02 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. Id. 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.'
121 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)(I)
of FERC's Regulation, a Qualifying Facility may only
provide power to the utility on an "as-available" basis,
and must price the power at the "time of delivery." Id. §
292.304(d)( I). Immediately following ( d)( I) is another
subsection of FERC's Regulation, which allows a
Qualifying Facility to sell its power pursuant to a Legally
Enforceable Obligation. Id. § 292.304(d)(2). A Qualifying
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)( I), or it may choose to fix the price
"at the time the obligation is incurred." Id. In other words,
Qualifying 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 Qualifying Facility that generates "firm
power" to enter into a Legally Enforceable Obligation. 16
Tex. Admin. Code § 25.242(c) (PUC Rule 25.242). The
PUC defines "firm power" as "power or power-producing
capacity [from a Qualifying Facility] that is available
pursuant to a legally enforceable obligation for scheduled
availability over a specified term." Id. § 25.242(c)(5). The
PUC defines non-firm power from a Qualifying Facility
as "[p]ower provided under an arrangement that does not
guarantee scheduled availability, but instead provides for
delivery as available." Id. § 25.242(c)(9). In other words,
only those Qualifying Facilities able to forecast when they
will deliver energy to the utility-and capable of
delivering the specified amount of energy at the scheduled
time-are eligible to take advantage of the pricing options
in subsection (d)(2) of FERC's Regulation. *386 By
contrast, Qualifying 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 Qualifying 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.' 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. §
824 l-3(a)(3). 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
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approximately $0.035 per kilowatt-hour to more than
$0.090 per kilowatt-hour for the first nine years of that
twenty-year term. Southwestern 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 ( d)( I).
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 Jaw 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:
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
energy, can also result in
significant 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 Qualifying 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 Qualifying Facility may form a Legally
Enforceable Obligation even if its power is non-firm.'
Exelon voluntarily non-suited its state court appeal of the
PUC Order. In December 2009, Exelon filed 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: (I) the PUC Order did not
implement FERC's Regulation; (2) all Qualifying
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: (I) 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 Southwestem'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
12(b)(I) and 12(b)(6), 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 had jurisdiction 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.
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II.
l·3l l4l l5I 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. In re FEMA
Trailer Formaldehyde Prods. liab. litig.
[Miss.Plaintiffs), 668 F.3d 281, 286 (5th Cir.2012).
Exelon, as the plaintiff, has the burden of establishing
subject matter jurisdiction. Id. If 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
I 006, IO IO (5th Cir.1998).
161 171 PURPA provides for two types of review of a state
utility regulatory authority's actions: implementation and
as-applied challenges. See Power Resource Ill, 422 F.3d
at 234-35. Federal courts have exclusive jurisdiction over
implementation challenges, while state courts have
exclusive jurisdiction over as-applied challenges." 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-3(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." Id. (internal quotation marks
and citations omitted); see also 16 U.S.C. § 824a-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 Ill, 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
tum.
A.
Appellants argue that Exelon raised as-applied challenges
because Exelon only challenged the PUC's application of
PUC Rule 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 Rule 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.
i.
To help elucidate the difference between implementation
and as-applied challenges, we begin by reviewing our
decision in Power Resource JI/, 422 F.3d at 231. There,
the PUC had determined that a Qualifying 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].
PRG then brought suit in federal district court, where it
requested several additional forms of relief, including: ( 1)
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 'n, No. l:03-CV-762-HLH, Dkt. No. I, at
*12 (W.D.Tex. Oct. 10, 2003) (hereinafter Power
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Util. L. Rep. P 14,913
Resource II ). 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 hear ....
[T]he one ultimate and limited
issue before the Court at this time
is whether [PUC] failed to
implement the [Legally
Enforceable Obligation] option
provided by FERC's regulations.
Id (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 Ill, 422 F.3d at 239.
ii.
181 We now tum 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
Rule 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 I, 73 S.W.3d at 361-62. 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 II dismissed
these types of claims for lack of jurisdiction because they
were as-applied challenges. Power Resource II, No.
l:03-CV-762-HLH, Dkt. No. 44, at 17-18. We agree
with the conclusions reached by both the state and federal
district 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 Ill, 422 F.3d at 235 (internal quotation
marks and citations omitted).7
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 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 *391 energy sources, like
solar energy, can also result in
significant 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.20 I 0) (en bane); 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 ag�to an individual petitioner." As a
result, Exelon's challenges to the PUC Order are
as-applied challenges.
iii.
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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.1995) ("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."
191 1•01 We disagree. In City of Arlington, the Supreme
Court afforded Chevron deference to an agency's
interpretation of its own jurisdiction. Id. w Indeed, the
Supreme Court explicitly noted that it granted certiorari
"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 court. City of Arlington 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.
1111 1121 While the Supreme Court has not addressed this
novel argument, our own precedent forecloses it. As
Judge Wisdom noted long ago, "[t]he courts, however,
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 (5th 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.2013) (citing
Henderson ex rel. Henderson v, Shinseki, - U.S.--,
131 S.Ct. 1197, 1202, 179 L.Ed.2d 159 (20 I I); 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, 118 S.Ct. 1003, 140 L.Ed.2d 210
( 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." Id.
1131 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--do 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. Id. (citing Skidmore
v. Swift & Co., 323 U.S. 134, 65 S.Ct. 161, 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.
B.
i.
1141 Exelon's second category of claims challenges PUC
Rule 25.242. Exelon argues that the Rule does not fully
implement FERC's Regulation because PUC Rule 25.242
limits the category of Qualifying 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 Rule 25.242. Exelon did,
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however, raise a more general challenge to PUC Rule
25.242 by asking for a declaration that all Qualifying
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 Ill, 422
F.3d at 237-39. Exelon's claims challenging PUC Rule
25.242 are thus implementation challenges.
1•5I 1161 Occidental asserts that our "drive-by" jurisdictional
ruling in Power Resource Ill 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 Ill is
not such a case. See Hagans v, Lavine, 415 U.S. 528, 533
n. 5, 94 S.Ct. 1372, 39 L.Ed.2d 577 ( 1974). The district
court opinion in Power Resource II devoted substantial
time to the jurisdictional question. We, in tum, devoted a
large portion of our opinion to recounting the district
court's jurisdictional determination before reaching the
merits of the case. See Power Resource Ill, 422 F.3d at
234-37. The appellant in Power Resource Ill 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 at 239. While our decision in Power
Resource Ill certainly could have given more guidance on
its jurisdictional determination, the issue was clearly
before the court. Power Resource Ill 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.3d 274, 283 (5th Cir.2011) ("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, Shala/a, 9
F.3d 11, 13 n. 3 (5th Cir.1993) ( "[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 Ill, we would conclude that the delineation
drawn by the district court in Power Resource II between
implementation and as-applied challenges is a persuasive
reading of PURPA's text, and would follow the same
approach here.
ii.
The PUC insists that we should read PURPA 's
jurisdictional grant more narrowly, *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 bas failed to open its doors to
adjudicate disputes under PURPA when it is
simultaneously hearing similar state lawsuits. While this
reading of PURP A's jurisdictional provisions may be
possible, it is not compelled by the Supreme Court's
decision in FERC v. Mississippi, and would conflict with
our own prior interpretation of the scope of PURPA 's
jurisdictional grant. See Power Resource Ill, 422 F.3d at
235-37. Absent a clear contrary statement from the
Supreme Court or en bane reconsideration, we are bound
by our own precedent. See United States v, Stone, 306
F.3d 241, 243 (5th 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. Mississippi, 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, 102
S.Ct. 2126. As a result, Texas was not forced to pass laws
implementing FERC's regulations. Cf Printz v. United
States, 521 U.S. 898, 933, 117 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
[Qualifying 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 Ill, 422 F.3d
at 236.
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.
Ill.
We now tum lo whether the district court properly
granted summary judgment in favor of Exelon on its
claims that the PUC failed to implement FERC's
Regulation. "We review a district court's ruling on a
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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.2012). "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
party. Matsushita Elec. Indus. Co. v. Zenith Radio, 475
U.S. 574, 587, 106 S.Ct. 1348, 89 L.Ed.2d 538 (1986).
1171 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
[Qualifying Facilities]." Power Resource Ill, 422 F.3d at
236 (citations omitted).
1181 PURPA requires states to implement FERC's
regulations. See *395 16 U.S.C. § 824a-3(f)(t).11 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
FER C's rules." FERC v. Mississippi, 456 U.S. at 751, I 02
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 Qualifying 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." 18
C.F.R. § 292.304(d). We note at the outset that the plain
language of PUC Rule 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 Qualifying 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 tum once again to our
binding precedent in Power Resource Ill, 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 Ill here. We disagree, and explain below
why that case forecloses the position taken in the
dissenting opinion.
A.
1191 In Power Resource Ill, we upheld the PUC's
determination that PRG-which was also a Qualifying
Facility-could 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. PRO-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 Qualifying Facilities that
were unable to meet the rule's requirements. Id. at 238.
We disagreed, and upheld the PUC's 90-day Rule,
explaining that,
*396 PRO has failed to show that PURPA and the
FERC regulations mandate that all [Qualifying
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
Obligations].
If FERC had determined it necessary to set more
specific guidelines concerning [Legally Enforceable
Obligations], 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 Obligation] is left to
the states and their regulatory agencies.
Id. at 238-39 (emphasis added). Power Resource Ill 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 Ill 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 Obligation.
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
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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." Cf Matthew L. Wald,
Texas Is Wired for Wind 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 Ill, the mere fact that
PUC Rule 25.242 prevents some Qualifying 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 Ill, "(t]he *397 plain text of the FERC
regulation ... fails to mandate" that all Qualifying
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 Ill.
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 Regulation
to allow all Qualifying 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, 117 S.Ct.
905, 137 L.Ed.2d 79 ( 1997)." Instead, Exelon argues that
we 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 Ill. rs
1201 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 'I Cable &
Telecomm. Ass 'n v. Brand X Internet Servs., 545 U.S.
967, 982, 125 S.Ct. 2688, 162 L.Ed.2d 820 (2005).16
Power Resource Ill 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 concerning [Legally
Enforceable Obligations], it could
have done so. For example, the
FERC regulations could have
mandated *398 that the [Qualifying
Facilities] must be able to lock in
purchase rates with a [Legally
Enforceable Obligation] 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 Obligation} is left to
the states and their regulatory
agencies.
Power Resource /II, 422 F.3d at 239 (emphasis added).
Our approach does not, as the dissenting opinion argues,
"flip [] Brand X on its head." Dissent at 21. 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.2011 ); Tran v.
Mukasey, 515 F.3d 478, 484 (5th Cir.2008); Sierra Club
v. Envt 'I Prof. 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
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prior decisions also noted ambiguity in the text at issue.
See, e.g., Garfias-Rodriguez v. Holder, 702 F.3d 504, 512
{9th Cir.2012) ("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
Perez-Gonzalez decision."); Hernandez-Carrera v.
Carlson, 547 F.3d 1237, 1245 (10th Cir.2008) ("The
Supreme Court has twice explicitly found the statute to be
ambiguous."); Fernandez v. Keisler, 502 F.3d 337,
347-48 (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 of
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 Energy
Brayton Point, LLC v. Johnson, 443 F.3d 12, 17 ( I st
Cir.2006) ("The short of it is that the Seacoast court,
faced with an opaque statute, settled upon what it sensibly
thought was the best construction of the Clean Water
Act's 'public hearing' language."); levy v. Sterling
Holding cs, 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?, 119 Harv. L.Rev. 1532, 1538 (2006)
(discussing the possible ways to implement Brand X ). In
contrast to these cases, in Power Resource Ill we
determined that the "plain text" of FERC's Regulation
allowed the PUC to limit the situations in which
Qualifying Facilities can form Legally Enforceable
Obligations. Thus, under Brand X. the interpretation put
forward by Exelon would not be entitled to deference
even if counsel had not conceded this point at oral
argument.
*399 1211 E . d, h h. . ven assuming arguen o t at t rs pnor
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 Ill, 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 40 I.
Instead, we are deferring to the PUC's official
interpretation of the Regulation in 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)(I) superfluous." Subsection (d)(I)
of FERC's Regulation allows a Qualifying Facility to
provide power to the utility only on an as-available basis,
and requires the Qualifying Facility to price the power at
the moment of delivery. Id. § 292.304(d)(I). Subsection
(d)(2) gives a Qualifying Facility this exact same option
to sell power to the utility on an as-available basis, and
also provides a Qualifying Facility with a second option
to choose to fix the price "at the time the obligation is
incurred."
1u1 1231 Under the reading advocated by Exelon and
adopted by the district court, every Qualifying Facility
must have the option to form a Legally Enforceable
Obligation, and thus to select between the two pricing
options available under subsection ( d)(2). If every
Qualifying 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 Qualifying 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
supertluous. See Nat 'I Ass 'n of Home Builders, 551 U.S.
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at 668, 127 S.Ct. 2518 ("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) ("If 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 Qualifying 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." 16 U.S.C. § 824a-3(aX2), (bXI).
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 additionaJ power
it must arrange to purchase to meet its requirements
without paying a premium for last-minute purchases.
Because only firm power Qualifying 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 Qualifying Facilities
be able to create Legally Enforceable Obligations at any
time. Power Resource Ill, 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. Id. at 236.
Here, the PUC has reasonably distinguished between
Qualifying 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. he PUC made a reasonable decision that
only those Qualifying 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 of the federal * 40 I 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 21 O of
Title II of the Public Utility Regulatory Policies Act of
1978 ("PURPA"). Pub.L. 95-617, 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 tum provided that "each State
regulatory authority shall ... implement [any] rule
[prescribed by FERC under § 824a-3(a) ]." Id. §
824a-3(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 regulatory
authority for purposes of implementing any
requirement of a [FERC] rule." 16 U.S.C. § 824a-3(g)(I
}-(2) (cross-referencing 16 U.S.C. § 2633); 16 U.S.C. §
2633 ("Any person ... may obtain review of any
determination made under [certain provisions] ... in the
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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. Id. §
824a-3(h)(2)(A). In addition, PURPA entitles electric
utilities and small power producers to petition FERC "to
enforce the requirements of [the state implementation
provision)." Id. § 824a-3(h)(2)(B). 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 regulatory
authority ... to comply with [the implementation]
requirements," and FERC may intervene as of right. Id.
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 qualifying facility'
shall have the option ... to provide energy or capacity
pursuant to a legally enforceable obligation." 18 C.F.R. §
292.304(d)(2). The Public Utility Commission of Texas
("PUC") implemented that regulation by permitting only
some qualifying 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 Order") 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 Wind I. uc. 129FERC161,148(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 qualifying facility
shall have the option to form legally enforceable
obligations. PUC Rule 25.242 deprives qualifying
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.-, 131 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, 131 S.Ct. 871, 878, 178 L.Ed.2d
716 (2011) (same); cf Chevron U.S.A., Inc. v. Natural
Resources Defense Council, Inc., 467 U.S. 837, 842-43,
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
itself] of the traditional means of statutory interpretation,
which include the text itself, its history, and its purpose."
See Bel/um v. PCE Constructors, lnc., 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
I 094 (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 of the 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
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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 qualifying facility shall have the option either:
(I) To provide energy as the qualifying 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 qualifying 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.
18 C.F.R. § 292.304(d).
A. All Qualifying Facilities Are Entitled to Create
Legally Enforceable Obligations.
The key phrase in dispute is "Each qualifying 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 of the FERC
regulation fails to mandate that all Qualifying 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. Mi/berg Weiss Bershad Hynes
& Lerach, 523 U.S. 26, 27, 118 s.o. 956, 140 L.Ed.2d 62
( 1998); see, e.g., Nat 'l Ass 'n of Home Builders v.
Defenders of Wildlife, 551 U.S. 644, 661-62, 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
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
qualifying facility to form a legally enforceable
obligation. The option belongs to each qualifying facility,
which means that it belongs to "every" qualifying 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.200 I))). Every qualifying facility
"ha[s)" the option; not the state regulatory authority.
Thus, the state regulatory authority may not make the
choice for each qualifying 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 qualifying 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 Qualifying facilities
may include wind power producers, see 18 C.F.R. §
292.204(a)-(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 Qualifying 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
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implementation requirements imposed on it by PURPA.
See 16 U.S.C. § 824a-3(t), (h)(2XA). 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 qualifying facility. Since every qualifying facility
may form legally enforceable obligations, the regulation
does not need to specify which qualifying 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 of the 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, I 02 S.Ct. 2126,
72 L.Ed.2d 532 ( 1982). Congress sketched out a bold
solution to that problem-mandatory purchases of energy
by electrical utilities from qualifying facilities, 16 U.S.C.
§ 824a-3(a)-and asked FERC to promulgate rules to that
effect. FERC chose a scheme that turned on making
legally enforceable obligations available for each
qualifying 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
qualifying 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 certainty, 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), (b)(I)). 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, I 04 S.Cl. 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 18 C.F.R. § 292.304(a), (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
[for just and reasonable rates] if it equals avoided costs.").
The idea that the court 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 qualifying 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.
Ill. "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
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actually creates and why, nevertheless, deference to
FERC makes sense.
A. The Court Should Defer to F'ERC's Interpretation
of Its 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 erroneous 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.2013) (quoting Bowles v. Seminole Rock & Sand Co.,
325 U.S. 410, 414, 65 S.Ct. 1215, 89 L.Ed. 1700 (1945));
see also Auer v. Robbins, 519 U.S. 452, 461, I 17 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
internal quotation marks omitted)). Therefore, if 18
C.F.R. § 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. Occupational Safety & Health
Review Comm'n, 499 U.S. 144, 152, 111 S.Ct. 1171, 113
L.Ed.2d 117 (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.' Id.
In Martin, 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 14 7-48, I 11 s.o. 1171 ( citing 29
U.S.C. §§ 651 (b)(3), 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 11 S.Ct. 1171.
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, 111 S.Ct. I 171. 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. In 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. Id. 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 171, and
courts "should defer to the Secretary [to the extent] the
Secretary's interpretation is reasonable," id. at 158, 111
S.Ct. 1171 (emphasis omitted).
Martin 's statute-specific 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 16 U.S.C. § 824a-3(a), (h)(I). In particular, 16
U.S.C. § 824a-3(h) ( "Commission enforcement")
empowered FERC to "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 of right in a petitioner's federal court action even when
FERC did not use its discretionary enforcement power. Id.
State regulatory authorities have no analogous role to
either the Commission or the Secretary in Marlin.
Whereas the Commission in Marlin 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. at 760, 102 S.Ct. 2126; see also 16
U.S.C. § 824a-3(t). In addition, state regulatory
authorities may defend as-applied challenges to their
implementation plans in state court actions, but, under
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federal law, they enjoy neither a special adjudicative or
enforcement power. See 16 U.S.C. § 824a-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 Marlin, 499
U.S. at 152, 111 S.Ct. 1171. 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 "lt]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. lt 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 nullify
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 [18 C.F.R. §§
292.301-14]." 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 "recogni(zed] the work already
begun and ... the variety of local conditions." Id. at
12,231. The Supreme Court ratified that "latitude"
language in FERC v. Mississippi, 456 U.S. at 751, 102
S.Ct. 2 I 26. 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
I 6 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 positron, 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 Ill, 422 F.3d at 236 (quoting N. Am.
Natural Res., Inc. v. Mich. Pub. Serv. Comm 'n. 73
F.Supp.2d 804, 807 (O.Mich.1999)). 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. In Power Resource Ill, for example, the court
acknowledged that PURPA gave an exclusive grant of
authority to FERC over rules on the certification of
qualifying facilities. 422 F.3d at 236 n. 2.; see also lndep.
Energy Prods. Ass 'n, Inc. v. Cal. Pub. Utils. Comm 'n, 36
F.3d 848, 853-54 (9th Cir. I 994) ("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.
\/\ estl- ,Next ;J015111on 5 1 Reuters No cla1111 to 0119111al U S Government Works 20
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Util. L. Rep. P 14,913 --------------------------
..., - L
2. Power Resource Ill
parties to consult. JD Wind /, LLC, 129 FERC 61, 148
(Nov. 19, 2009). There is only a single letter because that
is how authoritative interpretations are often made.
Power Resource Ill does not support the majority's
holding. Two important limitations make that case
inapplicable here. First, Power Resource Ill 's statement
of deference was highly context-specific. This case is
different. Second, that case tells us nothing about which
agency deserves deference where FERC has spoken and
disagrees with a state agency's interpretation of FERC's
regulations.
FERC's grant of discretion to the PUC was necessarily
tied to the particular issue in the case-conditions on the
formation of legally enforceable obligations. Every
indication shows that the Power Resource Ill court was
careful not to overstate the scope of the PUC's discretion.
Its crucial statement of deference, which the majority
recites, accords deference only "with respect to the
approval of purchase contracts between utilities and
QFs."6 The district court thoroughly discredited reliance
on Power Resource Ill in its opinion below:
J. No FERC Interpretation
The majority opines that there is no FERC interpretation
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.g., Decker v.
Nw. Envtl. Def Ctr., - U.S. --, 133 S.Ct. 1326,
1336-37, 185 L.Ed.2d 447(2013) (giving Auer deference
to the EPA's interpretation offered in an amicus brief). In
any case, the FERC interpretation is "before our court"
not only because its Declaratory Order is in the record and
has been briefed by the parties, but also because FERC's
Declaratory Order was the jurisdictional prerequisite for
the case even coming to our court. See Power Resource
Ill, 422 F.3d at 235 ("If FERC does not bring an
enforcement action within 60 days following the date on
which a petition is filed, the utility or qualifying facility
may bring an enforcement action in federal district court."
(quoting 16 U.S.C. 824a-3(h)(2)(B))).
Also note that if the court required that the interpretation
be argued by a party "before our court," we would
actually lack a PUC interpretation, too. Before our court,
the PUC has notably abandoned the interpretation of the
FERC regulation that it made in the district court, instead
relying entirely on the now-repudiated argument that our
court lacks jurisdiction. It would seem a double standard
for the majority to rely on this argument to negate
FERC's interpretation while preserving the PUC's. In Power Resource {Ill}, 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 Order, but minimizes the limits when in time a LEO can be created; no LEO can
effect of that interpretation by characterizing it as a be established more than ninety days before the QF has
"single letter"} sent to Exelon. This misunderstands the power available, or will have power available. After
situation. 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
notice of Exelon's predecessor's filing in the Federal Circuit upheld the rule. [422 F.3d) at 240 .... Unlike the
Register, inviting interventions and protests. See JD Wind firm-power rule, any wind QF can comply with the
I, LLC, et al.; Notice for Petition for Declaratory Order, ninety-day rule; it is simply a matter of timing.
74 Fed.Reg. 51147--02 (Oct. 5, 2009). FERC received Although there are no doubt considerable practical
briefing from the Appellants in that proceeding, and also expenses and difficulties involved, in theory any QF
from a variety of other industry groups, renewable energy can comply with the ninety-day rule through careful
developers, and utilities. See JD Wind/, LLC, 129 FERC planning in advance, such as in what sequence to seek
61,148, at 61,630-32. Many of these intervenors were financing, obtain permitting, and begin different phases
under the impression that FERC's interpretation was not of construction, in relation to when to send LEO
just a one-off missive intended for a single party, but a paperwork to a utility .... By contrast, the firm-power
wide-ranging policy interpretation. *410 See, e.g., id at ,i rule is simply insurmountable for an entire class of
61,631. {"Montana Renewables states that the Texas 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 negatively affect all the wind into the constant, predictable stream of energy
intermittent resource QFs in the United States."). Then, demanded by the firm-power rule. As such, this case
FERC published its interpretation in a public reporter, falls outside the scope of guidance offered by Power
available for all state regulatory authorities and regulated Resource {Ill J.
• ·�Next 2�. t h Jn Re.iter N I I US , - C I v v l a 111 to 01191na Gove, nrnent VVor ks
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3. Bram/ X
In addition, as Power Resource Ill states in a portion
quoted in the majority opinion, "[t]he plain text of the
*412 FERC regulation ... fails to mandate [the]
requirement [that Power Resource Group sought]." 422
F.3d at 239. In other words, Power Resource Ill
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 Ill 's
interpretation of the regulation cannot bar FERC's later
interpretation.
In rejecting Auer deference for FERC's Declaratory
Order, the majority invokes the Brand X doctrine even
though it is inapposite. See Nat 'I Cable & Telecom ms.
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." Id.
at 982, 125 S.Ct. 2688. The majority then asserts that
Power Resource Ill'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 Ill answered a different
question, so even if that case did offer an unambiguous
interpretation of the regulation, that interpretation would
not bind us.
see id. at 236 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 Ill, and it
explains why this case is different.
West Penn {Power Co., 71
F.E.R.C. 61153, 61,495 (May 8,
1995),] and its progeny Jersey
Central Power & light Co., 73
F.E.R.C. 61,092, 61,297 (Oct. 17,
1995), and Metropolitan Edison
Co., 72 F.E.R.C. 61,015, 61,050
(July 6, 1995), support the
proposition that the FERC
regulations grant the states
discretion in setting specific
parameters for LEOs.
Put another way, Power Resource [Ill} reviewed [a]
rule [ J governing when and how a LEO is formed,
whereas the firm-power rule ... determin[es] whether
some types ofQF can ever obtain a LEO.
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
Still, Power Resource Ill is entirely consonant with the against deferring to a later agency construction. Brand X
Martin analysis laid out above. The Power Resource Ill establishes the opposite holding: it ensures that a later
court made its deference determination contingent 011 agency construction of an ambiguous statute or regulation
whether Congress and FERC intended for the state to is entitled to deference in spite of a prior judicial opinion
make an authoritative interpretation and whether the state that interpreted the ambiguous provision a different way.
acted within the scope of that delegation. In particular, Here, the majority in effect punishes FERC for failing to
Power Resource Ill considered the structure of the statute, defend its (purportedly identical) position in a prior case,
Next .It N . ..mg111a1 U S Government Works J..2
Id. at 238. In other words, "FERC has given each state the
authority to decide when a LEO arises in that state." Id. at
239 (emphasis added). Therefore, Power Resource Ill
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 Ill cannot control.
Exelon Wind /, LLC v. Smitherman, 2012 WL
4465607, at *12 (W.D.Tex.2012) (emphasis added).
The difference between that case and this one is one of
kind, not degree.
*411 The next difference between this case and Power
Resource Ill is just as remarkable and legally significant.
In Power Resource Ill, FERC did not offer its
interpretation of its own regulation in response to the
petitioner's request. Power Resource Ill, 422 F.3d at 234
(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 Ill
looked to (and was persuaded by) FERC declaratory
orders in determining whether it was appropriate to grant
discretion to the PUC:
Util. L. Rep. P 14,913
but as Brand X said, "[a]gency inconsistency is not a basis
for declining to analyze the agency's interpretation."
Brand X. 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 (d)(I)
superfluous." Majority op. at 399. The superfluity
argument goes as follows: if (d)(2) 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 qualifying facility would
choose the (d)(I) route. The majority says this reading
makes ( d)( I) superfluous because it is "hard to understand
why" FERC chose this bifurcated scheme for electricity
sales. Id 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
( dX 1) provides a complementary or second-best scheme
for qualifying facilities. Thanks in part to rules like the
one our court affirmed in Power Resource Ill, a legally
enforceable obligation can be harder to form.
Consequently, selling power without a legally enforceable
obligation can save those formation costs. In the event
that a qualifying facility begins producing energy but is
barred for ninety days from forming a legally enforceable
obligation, (d)(I) 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)(I) would not be
superfluous merely because (d)(2) is also an available
option for qualifying facilities.'
S. 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-either challenging or acceding to
Auer deference-have never had the weight that the
majority places on Exelon's concession. In 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. 718 F.3d at 492 n. 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 493; see also Castellanos-Contreras v.
Decatur Hotels, LLC. 622 F.3d 393, 40 I n. 8 (5th
Cir.2010) (en bane) (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: (I) the absence of a FERC
interpretation; (2) an application of Power Resource Ill;
(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
Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014)
01 t: Inomson Reuters Noc a•m to 011911,cil US Govern,nt:!nl Wurk-:,
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, 119 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.Ed.2d 967 (2004) {holding
that the EPA could overrule the state agency's
construction of the term "best available control
Footnotes
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
2
3
4
5
6
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. In order to avoid confusion, we refer to the state court decision as Power Resource I, the
district court decision as Power Resource II, and the subsequent decision by this court on appeal as Power Resource
Ill.
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 Wind Energy: Past, Present, and Future, 4 Envt'I. & Energy l. & Pol'y J. 69, 76-77 (2009)
(quoting Gen. Elect. Energy, Analysis of Wind Generation Impact on ERGOT Ancillary Requirements 7 (2008)); see
also John Shelton, Who, What, How, & Wind: The Texas Energy Market's Future Relationship with Wind Energy and
Whether It Will Be Enough to Meet the State's Needs, 11 Tex. Tech Adm in. l.J. 401, 408-09 (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 at 76 ("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 section 292.304(d)(1) method of sale, or
the section 292.304(d)(2) method of sale;"
In conclusion, 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 FERG 61,148 (Nov. 19, 2009).
PURPA's • 'multi-layered' 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 FERG declines to bring such an action, the party may file a complaint which
VI: es ti Next o· m o K uters No la1111 to or ,g,nal U S Gover 111Y1e11t Works
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 Ill,
422 F.3d at 234-35; see also 16 U.S.C. § 824a-3(h)(2)(A)-(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
8
9
10
11
12
13
Wesd
This result is supported by other courts that have had occasion to interpret PURPA's jurisdictional grant. See
Occidental Chem. Corp. v. La. Pub. Serv. Comm'n, 494 F.Supp.2d 401, 411 (M.D.La.2007) (applying the reasoning
from the federal district court in Power Resource II); Mass. Inst. of Tech. v. Mass. Oep't of Pub. Utils., 941 F.Supp.
233, 238 (D.Mass.1996); Greensboro Lumber Co. v. Ga. Power Co., 643 F.Supp. 1345, 1374 (N.D.Ga.1986), affd,
844 F.2d 1538 (11th Cir.1988).
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 clarify it so that in the future, if somebody came in and could meet that
standard that we're not being preclusive.
COMM. 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: It really does.
COMM. NELSON:-because, you know, along the coast the pattern is totally different and it blows at peak times.
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,
§ 2, 1981 Tex. Gen. Laws 70, 71 (codified at Tex. Utils. Code Ann.§ 35.061).
The Supreme Court's decision in Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., 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. Id. at 842-43, 104 S.Ct. 2778. If
Congress has resolved the question, then the clear intent of Congress binds both the agency and the court. Id. 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 construction of the statute." Id. 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. Rivetkeepet; tnc., 556 U.S. 208, 218, 129 S.Ct. 1498, 173 L.Ed.2d 369 (2009).
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 11.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 Fid. Fed. Sav. & Loan Ass'n v. 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 votx, 505 U.S.
at 166-67, 112 S.Ct. 2408; Nat'/ Collegiate Athletic Ass'n v. Governor of N.J., 730 F.3d 208, 228 (3d Cir.2013), cert.
denied, 2014 U.S. LEXIS 4343, and cert. denied, 2014 U.S. LEXIS 4345, and cert. denied, 2014 U.S. LEXIS 4346
{June 23, 2014).
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 qualifying facility-Power provided under an arrangement that does not guarantee
scheduled availability, but instead provides for delivery as available.
16 Tex. Admin. Code§ 25.242(c)(5), (9).
Nor did our holding in Power Resource Ill 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
PURPA. The dissenting opinion's contrary interpretation would undermine this balance by �ving FERC the final say
Next L I c ri )1 H I r N > I 1 in to ouqinal US Govertun ·nt Work.,
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 concerns expressed by the Supreme Court in FERC v. Mississippi, 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 Ill.
14
15
16
17
18
2
3
4
We ,I
In Auer the Supreme Court applied the same two-step analysis from Chevron and explained that agency
interpretations of their own regulations are entitled to even greater deference. 519 U.S. at 457, 117 S.Ct. 905.
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. In support of this conclusion. the dissenting
opinion relies on a dissent from an en bane opinion of this court, Castellanos-Contreras v, Decatur Hotels, LLC, 622
F.3d 393, 397 (5th Cir.2010) (en bane), and our decision in Elgin Nursing & Rehabilitation Center v. U.S. Dep't of
Health & Human Servs., 718 F.3d 488, 492 (5th Cir.2013). A dissenting opinion is, of course, not binding. Elgin did not
address the issue of whether a party may concede that an interpretation is not entitled to deference. Instead, 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 at 492. We therefore see no reason why we should not accept Exelon's concession here.
While the Supreme Court's decision in Brand X specifically addressed Chevron deference, our sister circuits have
applied this same framework when interpreting regulations. See, e.g., Levy v. Sterling 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.").
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 not 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.
Indeed, 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. §§ 292.20:H>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, lntrastatutory Federalism and
Statutory Interpretation: State Implementation of Federal Law in Health Refonn and Beyond, 121 Yale L.J. 534, 534
(2011 ).
The Martin test parallels the Supreme Court's Chevron "Step Zero" analysis, which asks whether Congress delegated
authority to make interpretations carrying the force of law. See United States v. Mead, 533 U.S. 218, 226-27, 121 S.Ct.
2164, 150 L.Ed.2d 292 (2001); see also 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-may not be a radically different
approach than the one currently in use."); Jacob E. Gersen, Overlapping and Underlapping 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 Martin 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. at 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." Id. at 227, 121 S.Ct. 2164. The analysis, then, is attentive
to the structure and text of each specific statute.
In addition, although Martin 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. § 385.207(a) (interpreting enforcement authority under the Federal Power Act); see 16 U.S.C. §
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
\.Next 11 r tJo I 11 le 0119111c1I U::, i_., lVf 11111H·nl Wor�c. 1"
..
Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380 (2014)
Util. L. Rep. P 14,913
5
6
7
8
that the greater enforcement power necessarily includes the lesser authority to issue declaratory orders.
The "letter" that FERC sent Exelon is also known as a "Declaratory Order"-the preferred nomenclature. See, e.g.,
Indus. Cogenerators v. FERG, 47 F.3d 1231 (D.C.Cir.1995).
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.
The majority acknowledges that this is a satisfactory explanation for (d)(1). See Majority op. at 399 n. 17.
The majority also rejects Auer deference 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. In any case, the
majority does not rely on this constitutional avoidance argument for its deference holding.
End of Document © 2015 Thomson Reuters No claim to original U S Government Works
West! • Next 2015 Thomson f{euters No c1a1111 to or19111al U S Gove, nment Works 27
An IDACORP company
Integrated
Resource
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 dilfer materially can be lound on Idaho Power's lilings with the Securities and
Exchange Commission.
June 2015 An IDACORP Company
ACKNOWLEDGMENT
Resource planning is an ongoing process at Idaho Power. Idaho Power
prepares, files, and publishes an Integrated Resource Plan every two years.
Idaho Power expects that the experience gained over the next few years will
likely m6dify the 20-year resource plan presented in this document.
Idaho Power invited outside eartitipation to help develop the 2015
lntegrateaHesource Plan. Idaho Power values the knowledgeable
input comments, and discussion provided by the Integrated Resource
Pia'\ Advisorv. C uncil and other concerned citizens and customers.
lttakes approxi ately one year for a dedicated team of individuals at Idaho
Power to-prepa,.;erthe Integrated Resource Plan. The Idaho Power team is
comprised of. individuals that represent many different departments within
the company. The Integrated Resource Plan team members are responsible
for preparing forecasts, working with the advisory council and the public,
and performing all the analyses necessary to prepare the resource plan.
Idaho Power looks forward to continuing the resource planning process with
customers, public interest groups, regulatory agencies, and other interested
parties. You can learn more about the Idaho Power resource planning
process at www.idahopower.com.
Integrated
Resource Plan
2015
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 factors that could cause
future results to differ materially can be found in Idaho Power's filings with the Securities and
Exchange Commission.
@ Printed on recycled paper
Idaho Power Company
TABLE OF CONTENTS
Table of Contents
Table of Contents i
List of Tables vi
List of Figures viii
List of Appendices x
Glossary of Acronyms x
I. Summary 1
Introduction I
Proposed Pilot Projects _ 6
Solar PV to Address Distribution Feeder Voltage oss 6
Ice-Based Thermal Energ Storage 6
Community Solar 6
Portfolio Analysis Summary 8
Val my and Jim Bridger Coal Unit Early Retirement and CAA Section I I I (d)
Regulation 8
Uncertainty Related to PURPA Solar 9
Boardman to Hemingway Transmission IO
Selection of the Preferred Portfolio 10
Action Plan I I
Action plan (2015-20 I 8) 1 I
2. Political, Regulatory, and Operational Issues 13
Idaho Energy Plan 13
Idaho Strategic Energy A I liance 14
FERC Relicensing 14
Idaho Water lssucs 16
2015 IRP Page i
Table of Contents Idaho Power Company
Renewable Integration Study 19
Northwest Power Pool Energy Imbalance Market... 20
Renewable Energy Certificates 20
Renewable Portfolio Standard 21
REC Management Plan 22
Federal Energy Legislation CAA Section I I l(d) 22
3. Idaho Power Today 25
Customer Load and Growth 25
2014 Energy Sources 27
Existing Supply-Side Resources 29
Hydroelectric Facilities 30
Coal Facilities 34
Natural Gas Facilities 34
Solar Facilities 35
Power Purchase Agreements .37
Public Utility Regulatory Policies Act.. 38
Wholesale Contracts 40
Market Purchases and-Sales 40
4. Demand-Side Resources 41
lntroduction 41
DSM Program Overview 41
DSM Planning Changes from the 2013 IRP .42
Program Screening 43
DSM Program Performance 43
Energy Efficiency Performance 43
Demand Response Performance 44
Committed Energy Efficiency Forecast .45
Committed Demand Response Resources .48
Page ii 2015 IRP
Idaho 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- ide Generation and Storage Resources 53
Renewable Resources 53
Solar 53
Geothermal 55
Hydroelectric 56
Wind 57
Biomass 57
Conventional Resources 57
Natural Gas-Fired Resources 58
Nuclear Resources 60
Coal Resources 60
Storage Technologies 6 I
Battery Storage 62
Ice-based Thermal Energy Storage 63
Pumped Storage 63
6. Transmission Planning 65
Past and Present Transmission 65
Transmission Planning Process 66
Local Transmission Planning Process 66
Regional Transmission Planning 67
Interconnection-Wide Transmission Planning 67
Existing Transmission System 68
Idaho-Northwest Path 68
Brownlee East Path 69
2015 IRP Page iii
Table of Contents Idaho Power Company
..
Idaho-Montana Path 69
Borah West Path 69
Midpoint West Path 69
Idaho-Nevada Path 70
Idaho-Wyoming Path 70
Idaho-Utah Path 70
Boardman to Hemingway 71
Gateway West 73
Gateway West Need Analysis 75
Transmission Assumptions in the IRP Portfolios 76
7. Planning Period Forecasts 79
Load Forecast 79
Econornic Effects 80
Peak-Hour Load Forecast 82
Average-Energy Load Forecast 84
Additional Firm Load 86
Generation Forecast for Existing Resources 87
Hydroelectric Resources 87
Coal Resources 90
Coal Analysis 90
Natural Gas Resources 91
Natural Gas Price Forecast. 91
Resource Cost Analysis 92
Resource Cost Analysis II-Resource Stack 93
Levelizcd Capacity (Fixed) Cost 93
Levelized Cost of Production 94
Supply-Side Resource Costs 97
Page iv 2015 IRP
Idaho Power Company Table of Contents
Load and Resource Balance 99
8. Portfolio Selection 104
Portfolio Design 104
Portfolio Design and Selection 105
Status Quo Portfolio I 06
North Valrny Retirement Year-End 2019 Portfolios 107
North Val my Retirement Year-End 2025 Portfolios 110
North Val my Staggered Retirement Year-End 2019 (Unit 1) and Year-End 2025
(Unit 2) Portfolios 112
Jim Bridger Staggered Retirement Year-End 2023 (Unit I) and Year-End 2032
(Unit 2) Portfolios 113
Jim Bridger Staggered Retirement Year-End 2023 (Unit 1) and Year-End 2028
(Unit 2) Portfolio 114
Jim Bridger Staggered Retirement Year-End 2023 (Unit l ) and Year-End 2032
(Unit 2), North Valmy Retirement Year-End 2025 Portfolio 115
Alternative to Boardman to Hemingway Portfolios 116
North Valmy Staggered Retirement Year-End 2021 (Unit I) and Year-End 2025
(Unit 2) Portfolio 118
Portfolio Design Summary 119
9. Modeling Analysis and Result 12 I
CAA Section 111 ( d) Sensitivi Analysis 122
Null sensitivity (no Gf,..A Section I l l(d)) 122
State-by-State Mass-Based Compliance 123
System-Wide Mass-Based Compliance 123
Emissions intensi y compliance utilizing the EPA 's compliance building blocks 123
Baseline CAA Section I 11 ( d) 124
CAA Section 11 I (d) sensitivity analysis - results 126
Stochastic Risk Analysis 129
Portfolio cost - assessment of year-to-year variability 13 I
Tipping-Point Analysis 132
2015 IRP Page v
Table of Contents Idaho Power Company
Portfolio Emissions 133
Qualitative Risk Analysis 133
Existing Generation 134
New Generation 135
Preferred Portfolio 138
Analysis of Shoshone Falls Upgrade 139
Capacity Planning Margin 139
Flexible Resource Needs /\ssessment. 143
Loss of Load Expectation (LOLE) 14 7
I 0. Preferred Portfolio and Action Plan .....................................................................•................. 149
Preferred Portfolio (2015-2034) 149
Action Plan (2015-2018) 149
LIST OF TABLES
Table I.I
Table 1.2
Table 2.1
Table 3.1
Table 3.2
Table 3.3
Table 4.1
Table 4.2
Table 4.3
Table 5.1
Table 6.1
Page vi
Community solar model comparison 7
Action plan (2015-2018) I I
Phase l measures included in the ESPA CAMP 18
Historical capacity, load, and customer data 26
Existing resources .30
Net metering service customer count and generation capacity as of May I,
2015 .36
Current portfolio of demand response programs .44
Total energy efficiency current portfolio forecasted effects (2015-2034)
(aMW) 47
Total energy efficiency portfolio cost-effectiveness summary .48
Solar capacity credit values 55
Available transmission import capacity 70
2015 IRP
Idaho Power Company Table of Contents
Load forecast-peak hour (MW) 83
Boardman to Hemingway capacity and permitting cost allocation 71
Transmission assumptions 77
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 (70111
percentile water and 70111 percentile load) I 02
December monthly average energy deficits (average MW) by coal future
with existing and committed supply- and demand-side resources (701h
percentile water and 701h percentile load) 102
July monthly peak-hour capacity deficits (MW) by coal future with
existing and committed supply- and demand-side resources (90'h
percentile water and 95111 percentile load) 103
December monthly peak-hour capacity deficits (MW) by coal future with
existing and committed supply- and demand-side resources (90111
percentile water and 95th percentile load) 103
Fixed-cost impacts of coal retirement I 05
Resource portfolio PI 106
Resource portfolio P2(a) I 06
Resource portfolio P2(b) I 07
Resource portfolio P2(c) 107
Resource portfolio 3 108
Resource portfo I io P4( a) I 08
Resource portfolio P4(b) I 09
Resource portfolio P4(c) 110
Resource portfolio PS 110
Resource portfolio P6 11 I
Resource portfolio P6(b) 1 I I
Resource portfolio P6 11 I
Rcsou rce port fo I io P8 I 12
Resource portfolio P9 1 13
Table 7.4
Table 7.6
Table 6.2
Table 6.3
Table 7.1
Table 7.2
Table 7.3
Table 7.5
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 8.11
Table 8.12
Table 8.13
Table 8.14
Table 8.15
2015 IRP Page vii
Table of Contents Idaho Power Company
Table 8.16
Table 8.17
Table 8.18
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 IO. I
Resource portfolio PIO 1 13
Resource portfolio PI I 1 14
Resource portfolio P 12 1 15
Resource portfolio P 13 115
Resource portfolio P 14 1 16
Resource portfolio P 15 117
Resource portfolio P 16 117
Resource portfolio P 17 1 18
Resource portfo I io P 18 1 19
Resource portfolio scenario summary 120
Financial assumptions 122
Proposed target reductions - State-by-state mass-based compliance (IPC
share) 123
Insert caption (portfolios shaded in green were studied in the stochastic
risk analysis) 125
Portfolio Costs by CAA Section L l l(d) Sensitivity($ millions) 127
First peak-hour capacity deficit - effects of removing 141 MW of solar
PURPA 136
Capacity planning margin 14 l
Action plan (20IS-2018) I 50
LIST OF FIGURES
Figure 1.3
Figure 1.4
Figure 2.1
Figure 3.1
Figure 3.2
Page viii
C02 emissions intensity of the largest I 00 utilities .4
C02 emissions of the largest I 00 utilities 5
Brownlee historical and 2015-2034 forecasted April - July inflow 18
Historical capacity, load, and customer data 26
2014 Idaho Power system nameplate by fuel type (MW) (owned resources
plus purchased power) 28
2015 IRP
Idaho Power Company Table of Contents
Figure 3.3 2014 energy by source 28
Figure 3.4 2014 power purchases by fuel type 29
Figure 3.5 PURPA contracts by resource type 38
Figure 4.1 Cumulative energy efficiency savings, 2002-2014 (a MW) .44
Figure 4.2 Demand response peak reduction capacity and I RP targets. 2004-2014
(MW) 45
Figure 6.1 Idaho Power transmission system map 68
Figure 6.2 Boardman to Hemingway routes with Agency Preferred Alternative 73
Figure 6.3 Gateway West Map , 74
Figure 6.4 Midpoint West Historical Utilization "' 76
Figure 7.1 Peak-hour load-growth forecast (MW) 83
Figure 7.2 Average monthly load-growth forecast (aMW) 85
Figure 7.3 Brownlee historical and forecast inflows 89
Figure 7.4 Henry Hub Price Forecast-EIA Annual Energy Outlook 201-1
(nominal dollars) 92
Figure 7.5 30-year levelized capacity (fixed) costs 95
Figure 7.6 30-year levelized cost of production (at stated capacity factors) 96
Figure 7.7 Capacity cost of new supply-side resources, on line 2020 97
Figure 7 .8 Energy cost of new supply-side resources 98
Figure 9.1 Portfolio stochastic analysis 130
Figure 9.2 Exceedance graph of standard deviations 132
Figure 9.3 Tipping point analysis results 133
Figure 9.4 flexibility need (500 MW solar. existing wind, I% likelihood) 143
Figure 9.5 System regulation 144
Figure 9.6 Regulation violations. spring 2012 145
Figure 9 .7 Regulation violations, summer 2012 145
Figure 9.8 Regulation violations. fall 20 I I 146
Figure 9.9 Regulation violations. winter 2011/2012 146
Figure 9.10 LOLE (hours per year) 148
2015 IRP Page ix
Table of Contents
LIST OF APPENDICES
Appendix A-Sales and Load Forecast
Appendix 8-Demand-Side Management 2012 Annual Report
Appendix C-Tcchnical Appendix
GLOSSARY OF ACRONYMS
AC-Alternating Current
A/C-Air Conditioning
A COE-United States Army Corps of Engineers
A FU DC-Allowance for Funds Used During Construction
akW-Avcragc Kilowatt
aM W-A verage Megawatt
Bl.M-Bureau of Land Management
BOR-Bureau of Reclamation
BPA-Bonneville Power Administration
CAA-Clean Air Act of 1970
CAES-Center for Advanced Energy Studies
CAMP-Comprehensive Aqui for Management Plan
CAP-Community Advisory Process
CBM-Capacity Benefit Margin
CCCT-Cornbined-Cycle Combustion Turbine
CCR-Coal Combustion Residuals
cfs-Cubic Feet per Second
Page x
Idaho Power Company
2015 IRP
Idaho Power Company Table of Contents
CHP-Combined Heat and Power
Clatskanie PUO-Clatskanie Peoples Utility District
C02-Carbon Dioxide
CREP-Conservation Reserve Enhancement Program
DC-Direct Current
DOE-Department of Energy
DSM-Demand-Side Management
EEAG-Energy Efficiency Advisory Group
EJA-Energy Information Administration
EPA-Environmental Protection Agency
EPRJ-Electric Power Research Institute
ESA-Endangered Species Act of 1973
ESPA-Eastem Snake River Plain Aquifer
F-Fahrenheit
FCA-Fixed-Cost Adjustm
FCRPS-Federal Columbi River ower System
FEIS-Final Environmental Imp ct Statement
FERC-Federal Energy Regulatory Commission
FPA-Federal Power Act of.1920
FWS-US Fish and ildlife Service
I lg-Mercury
HRSG-Heat Recovery Steam Generator
ID WR-Idaho Department of Water Resources
IGCC-lntegrated Gasification Combined Cycle
!NL-Idaho National Laboratory
2015 IRP Page xi
Table of Contents
IOER-ldaho Office of Energy Resources
!PUC-Idaho Public Utilities Commission
I RP-Integrated Resource Plan
IRPAC-IRP Advisory Council
kV-Kilovolt
kW-Kilowatt
kWh-Kilowatt-hour
lbs-Pounds
LO LE-Loss of Load Expectation
L TP-Local Transmission Plan
m2-square meters
mm-Millimeter
MMBtu-Million British Thermal Units
MSA-Metropolitan Statistical Area
MW-Megawatt
MWh-Megawatt Hour
NEEA-Northwest Energy Efficiency Alliance
NEPA-National Environmental Policy Act of 1969
NERC-North American Electric Reliability Corporation
NTTG-Northern Tier Transmission Group
NPCC-Northwest Power and Conservation Council
NOx-Nitrogen Oxide
NPV-Net Present Value
NWPP-Northwest Power Pool
NREL-National Renewable Energy Laboratory
Page xii
Idaho Power Company
2015 IRP
Idaho 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
PC/\-Power Cost Adjustment
PM&E-Protection, Mitigation, and Enhancement
PGE-Portland General Electric
PPA-Power Purchase Agreement
PURPA-Public Utility Regulatory Policies Act of 1978
PY-Photovoltaic
QF-Qualifying Facility
RC RA-Resource Conservation and Recovery Act of 1976
REC-Renewable Energy Certificat
RES-Renewable Electricity Standard
RFP-Request for Proposal
RH BART-Regonal Haze Best Available Retrofit Technology
RPS-Ren wable Portfolio Standard
SCCT-Simple-Cycle Combustion Turbine
SCR-Selective Catalytic Reduction
S02-Sulfur Dioxide
SRBA-Snake River Basin Adjudication
TEPPC-Transmission Expansion Planning Policy Committee
UAMPS-Utah Associated Municipal Power Systems
USFS-United States Forest Service
2015 IRP Page xiii
Table of Contents
WECC-Western Electricity Coordinating Council
W-Wau
Page xiv
Idaho Power Company
2015 IRP
Idaho Power Company
Introduction
1. SUMMARY
1. Summary
The 2015 integrated Resource Plan (IRP) is Idaho Power's 12'h resource plan prepared to fulfill
the regulatory requirements and guidelines established by the Idaho Public Utilities Commission
()PUC) and the Public Utility Commission of Oregon (OPUC). The Idaho Power resource
planning process has four primary goals:
I. Identify sufficient resources to reliably serve the growing demand for energy within the
Idaho Power service area throughout the 20-year planning period.
2. Ensure the selected resource portfolio balances cost, risk, and environmental concerns.
3. Give equal and balanced treatment to supply-side resources, demand-side measures,
and transmission resources.
4. Involve the public in the planning process in a meaningful way.
The 2015 IRP evaluates the 20-year planning period from 2015 through 2034. During this period
load is forecasted to grow by I .2% per year for average energy demand and 1.5% per year for
peak-hour demand. Total customers are expected to increase to 711,000 by 2034 from 515,000 in
2014. Additional company-owned resources will be needed to meet the increased demands.
Idaho Power owns and operates 17 hydroelectric projects, three natural gas-fired plants, one
diesel-powered plant, and shares ownership in three coal-fired facilities. Hydroelectric
generation is the crown jewel of Idaho Power's generation fleet. The hydroelectric plants are
subject to variable water and weather conditions. Public and regulatory input encouraged Idaho
Power to adopt more conservative planning criteria beginning with the 2002 IRP. Idaho Power
continues to develop more conservative stream flow projections and planning criteria for use in
resource adequacy planning. Idaho Power has an obligation to serve customer loads regardless of
water and weather conditions. Further discussion of Idaho Power's IRP planning criteria can be
found in Chapter 7.
Other resources used in the planning include demand-side management (DSM) and transmission
lines. The goal for DSM programs is to achieve prudent, cost-effective energy efficiency savings
and provide an optimal amount of peak reduction from demand response programs. Idaho Power
also strives to provide customers with tools and information 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 resource planning process also evaluates additional transmission capacity as a
resource alternative to serve retail customers. Transmission 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 Transmission Group (NTTG).
Idaho Power coordinates local transmission planning with the regional forums as well as the
2015 IRP Page 1
1. Summary Idaho Power Company
r \
Federal Energy Regulatory Commission (FERC). Idaho Power is obligated under FERC
regulations lo 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 customers I and Idaho Power retai I
customers.2 Timing of new transmission projects are subject to complex permitting. siting,
regulatory and partner coordination.
Public Advisory Process
Idaho Power has involved representatives of the public in the resource planning process since
the early 1990s. The public forum is known as the IRP Advisory Council The IRP Advisory
Council generally meets monthly during the development of the resource plan, and the meetings
are open to the public. Members of the council include political, environmental, and customer
representatives. as well as representatives of other public-inter st groups. Many members of
the public participate even though they are not members oft e IRP Advisory Council.
Some individuals have participated in Idaho Power's resource planning process for g.,ver
20 years. A list of the 2015 IRP Advisory Council, mbers can be found in Appendix C­
Technical Appendix.
Idaho Power conducted 12 JRP
Advisory Council meetings, including a
resource portfolio design workshop.
Public working group meetings to
address the speci fie topics of energy
efficiency. solar resources, and the
study of coal resources were also held.
In addition, Idaho Power hosted a field
trip to the Swan Falls hydroelectric
project for participants of the lRP
process. Idaho Power personnel leading
the field trip shared in formation on a variety of topics, including high-voltage The IRP Advisory Council visits Swan Falls Dam.
transmission. recreation, avian biology,
archaeology, and Snake River water
supply. Field trip participants were also led on a tour of the Swan Falls hydroelectric power
plant, and the Swan Falls museum.
I Idaho Power has a regulatory obligation to construct and provide transmission service to network or
wholesale customers pursuant to a FERC tariff.
2 Idaho Power has a regulatory obligation to construct and operate its system 10 reliably meet the needs of
native load or retail customers.
Page 2 2015 IRP
Idaho Power Company 1. Summary
Idaho Power believes working with members of the IRP Advisory Council and the public
improves the IRP. Idaho Power and the members of the I RP Advisory Council recognize that
final decisions on the resource plan are made by Idaho Power. However, Idaho Power
encourages IRP Advisory Council members and members of the public to submit comments
expressing their views regarding the 2015 I RP 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 groups and at
educational seminars as requested.
IRP Methodology
/
Preparation of the Idaho Power 2015 IRP began with the forecast of future customer demand.
Existing generation resources, demand-side resources, and transmission import capacity are
combined with customer demand to create a load and resource balance for energy and capacity.
Idaho Power then evaluated new energy efficiency programs, and the expansion of existing
programs to revise any energy and capacity deficits. Finally, Idaho Power designed and analyzed
supply-side and transmission resource portfolios to address the remaining energy and capacity
deficits.
Idaho Power evaluates resources and resource portfolios using a financial analysis. Idaho Power
evaluates the costs and benefits of each resource type. The financial costs include construction,
fuel, operation and maintenance (O&M), necessary transmission upgrades, and anticipated
environmental controls and emission costs. The financial benefits include economic resource
operations, projected marke sales, and the market value of renewable energy certificates (REC).
Idaho Power is part ofdhe larger northwestern and western regional energy markets, and market
prices are an important component of evaluating energy purchases and sales. Idaho Power faces
transmission import constraints and at times of peak customer load must rely on its own
generation resources re ardless o the regional market prices. Likewise, there are times when the
generation connected to the Idaho Power system exceeds customer demand and the transmission
export capacity, and the company must curtail generation on its system.
An additional transmission connection to the Paci fie No rth west has been part of the Idaho Power
preferred resource portfolio since the 2006 IRP. By the 2009 IRP, Idaho Power determined the
approximate configuration and capacity of the transmission line, and since 2009 the addition has
been called the Boardman to Hemingway Transmission Line Project (821-1). Idaho Power again
evaluated the Boardman to I lerningway transmission 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 portfolios over the entire 20-
year planning period in the 2015 IRP. The analyzed portfolios in the 2015 IRP add resources in
2020 at the earliest under certain scenarios, and consequently Idaho Power determined it is
practical to once again consider the 20-year planning period in total.
2015 IRP Page 3
1. Summary
Greenhouse Gas Emissions
Idaho Power Company
Idaho Power owns and operates 17 hydroelectric projects, three natural gas-fired plants, one
diesel powered plant, and shares ownership in three coal-fired facilities. Idaho Power's carbon
dioxide (C02) emission levels have historically been well below the national average for the I 00
largest electric utilities in the United States (US), both in terms of total C02 emissions (tons)
and C02 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 381h lowest emitter
ofC02 per MWh produced and the 361h lowest emitter ofC02 by tons of emissions among the
nation's I 00 largest electricity producers, according to a May 2014 collaborative report using
publicly reported 2012 generation and emissions data.3 Figures 1.3 and l.4 show Idaho Power's
relative position to other utilities in terms of C02 emissions intensity and the overall quantity of
COi emissions. According to the report, out of the I 00 companies named, Idaho Power and Ida­
West Energy together ranked as the 52"d largest power producej based on fo sil fuel, nuclear,
and renewable energy facility total electricity generation.
2.500
2.000
s: � 1.500 ::;; � . Q.
N 0 0 0 .. .,, e 1.000 ::, 0 11.
500
Figure 1.3
- . -·
Idaho Power
38thlowest ---J ·--·-··-·-·
� ...
Utility
C02 emissions intensity of the largest 100 utilities
3M. J. Bradley & Associates.(2014). Benchmarking Air Emissions of the I 00 Largest Electric Power
Producers in the United States.
Page 4 2015 IRP
Idaho Power Company
160,000,000
1. Summary
140,000,000
120.000.000
100,000.000
N 0 o 0 80.000,000 .. c 0 I-
60,000,000
40,000,000
20,000,000
Figure 1.4
........ -.------------------------------
Idaho Power 361h lowest
Utility
C02 emissions of the largest 100 utilities
In September 2009, Idaho Power's Board of Directors approved guidelines to reduce
Idaho Power's resource portfolio average C02 ermssions intensity from 20 IO through 2013 to
IO to 15 percent below the c 1 pan 's 2005 C02 emissions intensity of I, 194 pounds per M Wh.
Because Idaho Power's CO emissions intensity fluctuates with streamtlows and production
levels of existing and ticipated renev able.resources, the company has adopted an average
intensity reduction goal to Be achieved over several years.
Currently, generation and emissions from company-owned resources are included in the C02
intensity calculation. The company's progress toward achieving this intensity reduction goal and
additional information on Idaho Power's C02 emissions are reported on the company's website:
C02 Emissions Intensity Reduction Goal.
Information related to Idaho Power's C02 emissions is also available through the Carbon
Disclosure Project at www.cdproject.net and on the Idaho Power website: Emissions.
In November 2012, the Board of Directors approved the extension of the company's 20 IO to
2013 goal for reducing C02 emission intensity. The goal as restated in 2012 is to achieve C02
emission intensity IO to 15 percent below the 2005 C02 emission intensity from 20 IO to 2015. A
second extension of the goal approved by the Board of Directors in May 2015 sets a target C02
emission intensity of 15 to 20 percent below the 2005 C02 emission intensity for 2016 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 2015 IRP incorporates the cost and long term effects of
carbon regulation by modeling several scenarios based on the Environmental Protection
2015 IRP Page 5
1. Summary Idaho Power Company
Agency's (EPA) proposed Clean Air Act (CAA) Section 111 (d) regulations and the impact the
new rules would have on the company's operations. A more complete discussion of climate
change and the regulation of greenhouse gas emissions is available starting on page 64 of the
IDACORP, lnc., 2014 Form 10-K.
Proposed Pilot Projects
Solar PV to Address Distribution Feeder Voltage Loss
A smal I scale proof of concept photovoltaic and battery system pilot project is being considered
for feeders with low voltage near the end of the feeder. The purpose of the pilot project is to
evaluate its operational performance and its cost effectiveness. The system will be designed to
maintain the feeder voltage within+/- 5% of nominal voltage (ANSI C84.1) and be cost
competitive with other options. During 2015 and 2016 the physical and economic feasibility will
be examined. If feasible, a pilot system will be constructed and monitored. The results of the
work will be reported in the 2017 Integrated Resource Plan.
Ice-Based Thermal Energy Storage
Identify and work with a commercial customer to install thermal ice storage. 11,e initial phase
would involve identifying a customer, designing the 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 effectiveness of the concept.
Community Solar
In the 2009 IRP, Idaho Power proposed a Solar PY pilot project. At the time, a downward trend
in the cost of solar PY was identi fled and that trend has continued over the past few years. In
addition, the energy shape of solar generation has been seen as a much better fit with Idaho
Power's customers needs when compared to other variable and intermittent renewable
resources. For these reasons the company was interested in gaining experience and data related
to solar generation and a small pilot project was proposed.
In August 2010, the IPUC commented in Order No. 32042 (Case No. IPC-E-09-33) on the
proposed solar pi lot project by stating:
Solar power has been identi tied as a resource that shou Id be pursued by the
Company. The recently announced Boise City solar project. we find. will 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 timing and nature of its involvement in
solar research and related projects. First, the solar project referenced in the IPUC order did not
ultimately provide the assessment opportunity envisioned by the Commission, as the developers
chose not to pursue completion of the project. Further.just three months after Order 32042 was
issued, in November 20 IO Idaho Power had 80 MW of PURPA wind contracts pending approval
at the IPUC and the company had received another 570 MW of requests for new contracts. It was
Page 6 2015 IRP
Idaho Power Company 1. Summary
at that time the company filed a joint petition 10 address PURPA policy and pricing issues at the
state level and Case No. GNR-E-10-04 was opened. Finally, just a short time later, Idaho Power
filed an application to modify its net metering service offering and the IPUC opened Case No.
I PC E 12 27. In that case the Corn mission 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 10 postpone the development of any solar research
project or customer-focused program pending the outcome of those cases.
Customer interest in central station and distributed solar generation was the subject of a number
of discussions within the context of the 2015 IRP preparations, among both the IRPAC members
and Idaho Power leadership. Late in the 2015 IRP public process, Idaho Power was approached
by several interested parties and asked to consider sponsoring a community solar project. The
U.S. Department of Energy (DOE) in their document A Guide to Community Shared Solar:
Utility, Private. and Nonprofit Project Development
(http://www.nrel.gov/docs/fy 12osti/54570.pd f) defines "community shared solar" as a solar­
electric system that provides power and/or financial benefit to multiple community members.
The DOE document further states the primary goal of community solar is to increase access to
solar energy and to reduce up-front costs for participants. Secondary goals include: I) improved
economies of scale, 2) optimal project siting. 3) increased public understanding of solar energy,
and 4) local job generation.
Several models have been used to facilitate community shared solar projects including utility
sponsored, special purpose entity and nonprofit. Table 1.1 below from the DOE guide compares
various community solar modeJs:
Table 1.1 Community solar model comparison
Utility Special Purpose Entity (SPE) Nonprofit
Owned By
Financed By
Hosted By
Subscriber Profile
Subscriber Motive
Long-term Strategy
of Sponsor
Examples
2015 IRP
Utility or third party
Utility, grants, customer
subscriptions
Utility or third party
Electric customers of the utility
Offset personal 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 •
University Park Community
Solar, LLC
Clean Energy Collective, LLC
Island Community Solar, LLC
Nonprofit
Memberships, donor
contribuuons, grants
Nonprofit
Donors. members
Return on investment;
philanthropy
Retain for electricity
production for life of
system
Winthrop
Community Solar
Project
Solar for Sakai
Page 7
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
•
1. Summary Idaho Power Company
Several possibilities exist for the structure of a solar pilot project. One option Idaho Power is
interested in pursuing would be to develop a photovoltaic (PY) project at a substation near
existing load. Th is 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 subsidized by allowing participating customers to buy the output on a voluntary
basis from 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. For an 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 electric bills that is
proportional to I) their contribution and 2) how much electricity the solar project produces.
Usually, the utility or some identified third-party owns the solar system itself The participating
customer has no ownership stake in the solar system. Rather, the customer buys rights to the
benefits of the energy produced by the system.
It is important to note that Idaho Power's load and res
any new generation, including solar generation, is neithe needed nor economic to pursue at this
time or during the four-year action plan horizon. However, � regulations governing carbon
emissions mature, additional renewable generatio may be warranted and community shared
solar cou Id be a viable option to help satisfy some.future carbon intensity targets.
Given the quickly changing regulatory, technological and economic landscape, the company will
actively explore the risks and opportunities of, and potential designs for, a community-based
solar project by continuing to work with interested parties. Because there is no identified
resource need in the near-term, a project of this nature would be pursued outside of the
traditional needs-based regulatory tramewor and ould rather focus on meeting changing
customer preferences with regard t where-and how the energy they use is produced.
Portfolio Analysis Summary
A fundamental goal of the TRP process is the identification of a selected, or preferred, resource
portfolio. The preferred portfolio identifies resource options and timing to allow Idaho Power to
continue to reliably serve customer demand balancing cost, risk, and environmental factors over
the 2015-2034 planning period. Several key factors create uncertainty regarding the selection of
a preferred port folio in the 2015 I RP. These factors include consideration of North Val my and
Jim Bridger coal unit early retirement, the EPA's proposed CAA Section 111 (cl) regulation, large
contracted amounts of unbuilt PURPA solar projects, and the timing of the Boardman to
Hemingway Transmission Line Project (B2H).
Va/my and Jim Bridger Coal Unit Early Retirement and CAA Section
111 ( d) Regulation
The 2015 IRP examines the EPA 's proposed CAA Section 111 (d) regulation and the future of
Idaho Power's ownership share of the Jim Bridger and North Val my coal-fired power plants.
With the exception of the Status Quo portfolio, all other portfolios analyzed evaluate alternatives
Page 8 2015 IRP
Idaho Power Company 1. Summary
Lo continued investment in the coal units and/or the impact of reducing generation from fossil­
fueled power plants to comply with uncertain environmental regulations. The optimization of
coal unit shutdown alternatives using computer modeling tools will not be possible until the
proposed CAA Section 11 l(d) regulation is finalized sometime in the second halfof2015. It is
possible to identify trends in the modeling results that indicate a portfolio with an earlier North
Val my unit shutdown coupled with the completion of the Boardman to I lemingway project
performs well on a 20-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 mortgage early. Over the shortened
life of a loan the total payments will be less, but in the near term the monthly payment will be
higher. The same is true when contemplating early retirement of North Valmy or Jim Bridger
units. For example, a North Valmy 2019 early shutdown will cost approximately $95 million
dollars more between 2015 and 2019, but save approximately $181 million in fixed O&M,
capital investment, and finance costs compared to a 203 I and 2034 retirement (in nominal
dollars). Unlike the home mortgage example, a coal unit will have little value at the
decommissioning date and it is likely another resource investment will be required.
Uncertainty Related to PURPA Solar
Power supply planning is complicated by the inability of a utility to 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 sales agreements with all Qualifying Facilities (QF)
that request to sell energy to Idaho Power. Changes in PURPA regulations, resource incentives
and technology can and does continually change the quantity and MWs of projects being
proposed or contracted for under thePURPA program. In addition, even after a PURPA QF
agreement is executed with a proposed project there is still uncertainty if the project will actually
be built. Th is uncertainty of proposed projects and construction of projects under contract resu Its
in increased planning uncertainty to the timing and type of company-owned resources needed.
Current PURPAregulations also do not have any consideration for Idaho Power energy needs or
impacts on system reliability which creates challenging integration issues as well as runs
contrary to the company's desire to develop a reliable system as efficiently and cost effectively
as possible.
The IRP load and resource balance includes 461 MW of solar photovoltaic (PY) from PURPA
projects scheduled to be online by year-end 2016. The energy and peak-hour capacity of these
projects was included in the PURPA forecast at the time the forecast was prepared. The risk of
relying on these signed contracts is exemplified by the fact that 141 MW of the 461 MW were
recently terminated due to inaction by the PURPA developers. The removal of the 141 MW of
solar capacity has the effect of increasing peak-hour capacity deficits by approximately 75 MW.
Because the schedule for completing the JRP would not allow the PURP A generation forecast to
be updated, the removal of the 141 MW of solar PY generation is addressed in a qualitative
manner in the risk analysis section of Chapter 9.
2015 IRP Page 9
1. Summary
Boardman to Hemingway Transmission
Idaho Power Company
Portfolio analysis for the 2015 IRP indicates portfolios with the Boardman to l lerningway
project (B2H) consistently outperform those in which the transmission line is excluded. This
result is consistent with analyses or past IRPs that have shown the B2H project is a valuable
supply-side resource that will allow Idaho Power to meet future system needs. Regional growth
in renewable energy resources such as wind and solar makes 8211 increasingly valuable as it
provides increased system flexibility critical to the reliability of interconnected systems with
high penetration levels of variable and intermittent resources.
Selection of the Preferred Portfolio
As previously noted, portfolios with early North Valrny unit retirements performed well in the
2015 IRP analysis. In fact, analysis shows favorable economics for portfolios having retirement
ofNorth Valmy Unit I as early as 2019. However, these portfolios carry considerable risk
associated with the following factors:
• Uncertainty related to the proposed CAA Section 111 (d) regulation, particularly the
effect of the final rule on operations at existing coal- and natural gas-fired power plants in
the proposed interim compliance period beginning in'2020
• Uncertainty related to retirement planning for a jointly owned power plant, specifically
the cha I lenges associated with arriving at a retirement date that is feasible to both owners
of the plant
• Uncertainty related to PURPA solar, and the effect of further project cancellations on
capacity additions in the early 2020s
• Uncertainty related to the completion date of the B2H project due to permitting issues
and the needs of project partners
• Uncertainty of regulatory acceptance of early coal unit retirement and rate impacts
associated with accelerated cost recovery
Given these risks, the preferred portfolio selected is portfolio P6(b), which includes retirement of
the North Val my plant at year-end 2025 and the completion of the 821-1 project in 2025. The
close linking of these resource actions suggests an earlier completion date of the 821-1 project
could accelerate the decommissioning of the North Valmy plant. Portfolio 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. These
resource additions late in the planning period address projected needs for resources providing
peaking capability and system flexibility. With expected long-term expansion of variable energy
resources, the need for dispatchable resources that provide system flexibility will also increase.
Page 10 2015 IRP
Idaho Power Company
Action Plan
Action plan (2015-2018)
1. Summary
Table 1.2 provides the schedule of action items Idaho Power anticipates over the next four years.
Actions related to the Shoshone Falls project are described in chapters 5 and 9 of the IRP.
Table 1.2 Action plan (2015-2018)
Year Resource
2015-2018 Boardman to Hemingway
2015-2018 Gateway West
2015-2018 Energy Efficiency
2015 Shoshone Falls
2015 Jim Bridger Unit 3
2015-2016 Shoshone Falls
2016 Jim Bridger Unit 4
2016 North Valmy Units 1 and 2
2017 Shoshone Falls
2017 Jim Bridger Units 1 and 2
2019 Shoshone Falls
2015 IRP
Action
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 regarding 50 MW expansion
Complete installation of selective catalytic 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
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 smaller upgrade
Evaluate the installation of SCR technology for Units 1 and 2 at Jim Bridger in
the 2017 IRP
On-Jine date for smaller upgrade during first quarter
Page 11
1. Summary
Page 12
Idaho Power Company
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2015 IRP
Idaho Power Company 2. Political, Regulatory, and Operational Issues
2. POLITICAL, REGULATORY, AND OPERATIONAL ISSUES
Idaho Energy Plan
In 2007, the Idaho Legislature's Interim Committee on Energy, Environment and Technology
prepared. and the Idaho Legislature approved, a new Idaho Energy Plan for the first time in
25 years. With rapid changes in energy resources and policies, the committee recommended the
legislature revisit the Idaho 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 in 2012. The Idaho Office of
Energy Resources (IOER) and the Idaho Strategic Energy Alliance provided assistance to the
Interim Committee during the update of the energy plan.
The 2012 update finds that Idaho citizens and businesses continue to benefit from stable and
secure access to affordable energy, despite the potential eco omic and political vulnerability
caused by Idaho 's reliance on energy imports. Idaho currently lacks significant commercial
natural gas and oil wells and only generates about half the electricity it uses. Yet the state has
abundant hydropower, wind. biomass. and other renewable energy sources.
Ongoing changes in energy generation and consumption pro id an opportunity for economic
growth within the state. While the Idaho Energy Plan acknowledge the risks attributed to
advances in energy generation, transmission, and end-use technologies, it also recognizes
the prospective benefits. With this recognition, the 2012 fdaho Energy Plan emphasizes
five core objectives:
I. Ensure a secure. reliable, and stable energy system for the citizens and businesses
of Idaho.
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
natural resou recs.
4. Promote sustainable economic growth, job creation, and rural economic development.
5. Provide the means for Idaho's energy policies and actions to adapt to
changing circumstances.
Because the IOER was charged with coordinating and cooperating with federal and State
agencies on issues concerning the State's energy requirement, Governor C. L. "Butch" Otter
asked the IOER to coordinate the State of Idaho 's response to the Environmental Protection
Agency's (EP A) Clean Power Plan on behalf or all relevant State agencies.
2015 IRP Page 13
2. Political, Regulatory, and Operational Issues
Idaho Strategic Energy Alliance
Idaho Power Company
Under the umbrella 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
Idaho's energy future. The Alliance is Idaho's primary mechanism to engage in seeking options
for and enabling advanced energy production, energy efficiency, and energy business in the State
of Idaho.
The purpose of the Alliance is to enable the development of a sound energy portfolio for Idaho
that includes diverse energy resources and production methods, that provides the highest value to
the citizens of Idaho, that ensures quality stewardship of environmental resources, and that
functions as an effective, secure, and stable energy system.
Idaho Power representatives serve on both the Alliance b�a1J directors and a
volunteer task forces which work in the following areas: L .
• Energy efficiency and conservation • Forestry
• Wind
• Geothermal
• Hydropower
• Carbon issues
• Baseload resources
•
FERC Relicensing
•
Biofuel
Solar
Transmission
Communication and outreach
Like other utilities that operate non-federal hydroelectric projects on qualified waterways,
Idaho Power obtains licenses from FERC for its hydroelectric projects. The licenses last for 30 to
50 years, depending on the size, complexity, and cost of the project.
Idaho Power tiled a final license application (FLA) for the Swan Falls Hydroelectric Project
(Swan 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 term expiring September I, 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 for the I ICC expired at the end of July 2005. Until the new, multi-year license is issued,
Idaho Power continues to operate the project under an annual license issued by FERC.
Page 14 2015 IRP
Idaho Power Company 2. Political, Regulatory, and Operational Issues
The HCC license application was filed in July 2003 and accepted by FERC for filing in
December 2003. FERC is now processing the application consistent with the requirements of the
Federal Power Act of 1920, as amended (FPA); the National 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 incurred to comply 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 being conducted, it is not
possible to estimate the final total cost.
Relicensing activities include the following:
I. Coordinating the relicensing process
2. Consulting with regulatory agencies, tribes, and interested parties
3. Preparing studies and gathering environmental data on fish, wildlife, recreation,
and archaeological sites
4. Preparing studies and gathering engineering-data on historical flow patterns,
reservoir operation and load shaping, forebay and river sedimentation,
and reservoir contours and volumes
5. Studying and analyzing data
6. Preparing all necessary reports, exhibits, and filings responding to requests for additional
information from FERC
7. Consulting on legal matters
Failure to relicense any of he existing hydroelectric projects at a reasonable cost will create
upward pre sure on the current electric rates of Idaho Power customers. The relicensing process
also has the potential to decrease available capacity and increase the cost of a project's
generation through additional operating constraints and requirements for environmental PM&E
measures imposed.as a condition of relicensing. Idaho Power's goal throughout the relicensing
process is to maintain the low cost of generation at the hydroelectric facilities while
implementing non-power 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 I RP. 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 IRP Page 15
2. Political, Regulatory, and Operational Issues
Idaho Water Issues
Idaho Power Company
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 stream flows, including tributary spring flows and the
regional aquifer system, is crucial for Idaho 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 legal and administrative
water-rights proceedings. Idaho Power's ongoing participation in water-rights issues is intended
to guarantee that sufficient water is available for use at the company's hydroelectric 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
stream now adjudication 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 Idaho Power
and the governor and attorney general
of Idaho in October 1984. Idaho Power
filed claims for all of its hydroelectric
water rights in the SRBA. As a result of
the SRBA the company's water rights
were adjudicated, resulting in the issuance of partial water right decrees. The Final Unified
Decree for the SRBA was signed on August 25, 2014.
In 1984, the Swan Falls Agreement resolved a struggle between the State of Idaho and
Idaho Power over the company's water rights at the Swan Falls Project. The agreement stated
Idaho Power's water rights at its hydroelectric facilities between Milner Dam and Swan Falls
entitled the company to a minimum flow at Swan Falls ofJ,900 cubic feet per second (cfs)
during the irrigation season and 5.600 cfs during the non-irrigation season.
The Swan Falls Agreement 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. Jdaho 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 court to resolve issues
associated with Idaho Power's water rights and the application and effect of the trust provisions
Snake River below Bliss.
Page 16 2015 IRP
Idaho Power Company 2. Political, Regulatory, and Operational Issues
of the Swan Falls Agreement. In addition, Idaho Power asked the court to determine whether the
agreement subordinated the company's hydroelectric water rights to aquifer recharge.
A settlement signed in 2009 reaffirmed the Swan Falls Agreement and resolved the litigation by
clarifying that the water rights held in trust by the state arc subject to subordination to future
upstream beneficial uses, including aquifer recharge. The settlement also committed 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 development and hydroelectric
generation. Both parties are working with water user's and other stakeholders in the development
of water-management measures through the implementation of the Eastern Snake River Plain
Aquifer, Comprehensive Aqui fer Management Plan (ESP/\ CAMP) as approved by the Idaho
Water Resource Board (IWRB), and the 2009 Swan Falls Reaffirmation Agreement.
Given the high degree of interconnection between the ESPA and Snake River, Idaho Power
recognizes the importance of aquifer-management planning in promoting the long-term
sustainability of the Snake River. The company continues to emphasis implementation of the
ESPA CAMP to improve aquifer levels and tributary spring flows to the Snake River. While
some of the Phase I recommendations outlined in Table 2.1 were slow to develop due to limited
initial funding, House Bill 547 signed into law by Governor Oucr in 2014, provides$5 million
annually to the Idaho Water Resource Board for aquifer stabilization projects, with the ESPA
having first priority.
While there have been two practices-recharge and weather modification-that have received
funding and have met or exceeded targets, declining aquifer levels and spring discharge persist.
During the winter of2014-2015 weather and canal maintenance conditions allowed for an
extended winter time recharge season from October 27, 20 I 4 to March 24.2015, resulting in a
volume recharged of72,325 acre-feet. This volume significantly exceeded the combined
recharge of the two previous seas ns, and exceeded the average annual recharge of the previous
five season by 4,500 acre-feet.
Idaho Power initiated and pursued a successful weather modification program in the Snake River
Basin. The company partnered with an existing program in the upper Snake River Basin and,
through the cooperative effort, has greatly expanded the existing weather modification
operational program, along with forecasting and meteorological data support. The company has
an established long-term plan to continue the expansion of this program. In 2014, Idaho Power
expanded its cloud seeding program to the Boise and Wood River basins, in collaboration with
basin water users and the Idaho Water Resource Board. Wood River cloud seeding. along with
the upper Snake activities, will benefit the ESPA CAMP implementation through additional
water supply.
2015 IRP Page 17
2. Political, Regulatory, and Operational Issues Idaho Power Company
Table 2.1 Phase I measures included in the ESPA CAMP
Measure Target (acre-feet)
Groundwater to surface-water conversions.................................. 100,000
Managed aquifer recharge............................................................ 100,000
Demand reduction .
Estimated to Date
(acre-feet)
30,300
78,000*
Surface-water conservation .
Crop mix modification .
Rotating fallowing, dry-year lease, conservation reserve
enhancement program (CREP) .
Weather modification .
"Average annual recharge from 2009 - 2014.
50,000
5,000
40,000
50,000
26,000
0
34,000
250,000
For the 2015 IRP, Idaho Power forecasted flows similar to those in the 2013 IRP; witb declines
in reach gains extending through the end of the IRP planning period. Based on mode�ng under
the 90-percent exceedance forecast, declining flows at Swan Falls drop to 4,030 cfs, which is
slightly higher than the Swan Falls minimum of 3,900 cfs. Figure 2.1 provides the yearly April
through July inflow to Brownlee Reservoir as forecasted for the 2015 IRP.
13
12
11
10
9 I 8
J 7 ; - . I
-H,stoncal --·IRP50'A, - - IRP70% --·IRP90%
Figure 2.1
Page 18
Brownlee historical and 2015-2034 forecasted April - July inflow
2015 IRP
Idaho Power Company 2. Political, Regulatory, and Operational Issues
Water Lease Agreements
Idaho Power views the rental of water for delivery through its hydroelectric system as a
potentially cost-effective power-supply alternative. Water leases that allow the company to
request delivery when the water is needed are especially beneficial. Acquiring water through the
water bank also helps the 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 2014 with Water District 63 in the Boise River basin
to rent 8,000 acre-feet of storage water released in January 2015.
In August 2009, Idaho Power also entered into a five-year (2009-2013) ater-rental agreement
with the Shoshone-Bannock Tribal Water Supply Bank for 45,716 acre-feet of American Falls
storage water. Under the terms of this agreement, the company cap schedule the release of the
water to maximize the value of the generation from the entire system of main stem Snake River
hydroelectric projects.
In 2011, the company extended the Shoshone-Bannock lental agreement for two additional
years, 2014 and 2015. The company typically schedule o liverY, of the water between July and
October of each year during the term of the agreement. The S oshone-Bannock agreement was
executed in part to offset the effect of drou ht and changin� ater-use patterns in southern Idaho
and to provide additional generation in summer months when ustomer demand is high. The
company is reviewing the potential to renegotiate the Sfiosh.g_ne-Bannock agreement for future
years.
Idaho Power intends to continue to pursue water-rental opportunities as part of its
regular operations.
Renewable Integration Study
Idaho Power has completed two wind integration studies and one solar integration study since
the mid-2000s. These studies increased the company's understanding of the impacts and costs
associated with integrating variable and intermittent resources without compromising reliability.
The variable and uncertain production from wind and solar resources requires Idaho Power to
provide additional balancing reserves from existing dispatchable generating resources, which
results in lost opportunity costs and corresponding increases in power supply expense.
Idaho Power completed the most recent wind integration study in 2013 which was the basis for a
tariff schedule of wind integration costs proposed to the IPUC by Idaho Power. The Idaho
commission approved the proposal as Schedule 87 in Order No. 33150 in October 2014.
The first Idaho Power solar integration study was completed in 2014 and the subsequent revision
to Schcdu le 87 was approved by the IPUC in Order No. 33227 in February 2015 as part of a
settlement stipulation between Idaho Power and intervening parties. The solar integration
settlement stipulation includes provisions requiring Idaho Power to initiate a second solar
integration study by January 2015 and to complete the second study within 12 months. Idaho
Power has formed a Technical Review Committee (TRC) of renewable energy experts for the
2015 IRP Page 19
2. Political, Regulatory, and Operational Issues Idaho 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 minimum 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 lo the
system.
For the I RP, integration costs for existing wind and solar resources arc common 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 with Schedule 87 for the new
resources. A copy of Schedule 87 is provided in Appendix c: Technical Appendix.
Northwest Power Pool Energy Imbalance Market
Since 2012, the Northwest Power Pool (NWPP) has been evaluating energy markets, sometimes
referred to as a Security Constrained Econo ic Dispatch (SCED . A second phase of the effort
was focused on refining the design eleme ts o a SCED to suit the unique issues present in the
NWPP. A third phase just completed, deve oped a number ofoperational tools to facilitate a
more robust and reliable system operation. The NWPJ> is now moving into a fourth phase to
continue lo refine design elements of a SCED to de e op additional low cost/high value tools to
enhance system operation. Mari)'. instit tional issu remain before a SCED can be implemented
in the Paci fie Northwest.
I.
2.
3. The market would pro ide better real-time pricing for power imbalances that occur in
real-time for wholesale power customers.
Idaho Power support , and will continue to participate in the NWPP discussions; however,
participation by a majority 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
renewable attributes associated with the production of one megawatt-hour of electricity
Page 20 2015 IRP
Idaho Power Company 2. Political, Regulatory, and Operational Issues
generated by a qua Ii fied renewable energy resource, such as a wind turbine, geothermal 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 farm) 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 certified 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 renewable resource is fed into
the electrical grid, and the associated REC can then be used (retired), held (banked), or traded
(sold).
REC prices depend on many factors, including the following:
• The location of the facility producing the RECs
• Whether there is a tight supply/demand situation
• Whether the REC is certified for renewable portfolio standards (RPS) compliance
• The generation type (e.g. wind, solar, geothermal)
• Whether the RECs are bundled with energy or unbundled
When Idaho Power sells RECs, the proceeds are returned to Jdaho Power customers through the
power cost adjustment (PGA) as directed by the IPUC in Order No. 32002 and by the OPUC in
Order No. 11-086. Because the RECs were sold, Idaho Power cannot claim the renewable
attributes associated with those RECs were delivered to retail customers. The new REC owner
has purchased the rights to claim the renewable attributes, or "greenness," of that energy.
Idaho Power customers that choose to purchase renewable energy can do so under Idaho Power's
voluntary Green Power Program. Under this program, every dollar contributed by a customer
brings about the delivery of 118 kWh of renewable energy to the region's power grid, providing
the contrib tin customer associated claims for the renewable energy. The entire amount
designated is use lo purchase green power from renewable projects in the Northwest and to
support Solar 4R Schools. On behalf of program participants, Idaho Power obtains and retires
RECs. For the 2014 Green Power Program, Idaho Power purchased and subsequently retired
19,318 RECs on behalfof Green Power participants.
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 IRP Page 21
2. Political, Regulatory, and Operational Issues Idaho Power Company
facilities will not be included in RPS calculations. However, hydroelectric upgrades on existing
facilities, such as the Shoshone Falls upgrade, will likely be included in RP calculations.
Under the Oregon RPS, Idaho Power is classified as a "smaller utility .. because the company's
Oregon customers represent less than 3 percent of Oregon· s total retai I electric ales. As a
smaller utility, Idaho Power will have to meet a 5- or I 0-pcrcent RPS requirement beginning in
2025.
While the State of Idaho docs not have an RPS, a federal Renewable Energy tandard (RE ) is a
possibility. Idaho Power believes it is prudent to continue acquiring REC associated with
renewable resources to position the company's resource and REC portfolio to minimize the
potential effect on customers if a federal RES is implemented.
REC Management Plan
In December 2009, Idaho Power filed a REC management plan with the IPUC that detailed the
company's plans to continue acquiring long-term rights to RECs in anticipation of a federal RE
but to sell RECs in the near term and return to customers their 95 percent share of the proceeds
as defined under the PCA mechanism. Public comments regarding the plan mirrored the
positions expressed by IRP Advisory Council members, many qf whom filed comments with the
IPUC. In June 20 I 0, the IPUC accepted Idaho Power's REC management plan.
Federal Energy Legislation CAA Section 111 (d)
Idaho Power is subject to a broad range of federal. state, regional, and local environmental laws
and regulations. Current and pending environmental legislation relates to climate change,
greenhouse gas emissions and air quality, mercury (Hg) and other emissions, hazardous wastes,
polych lorinated biphenyls, and endangered and threatened species. The legislation includes the
Clean Air Act of 1970 (CAA), the Clean Water Act of 1972 (CWA); the Resource Conservation
and Recovery Act of 1976 (RCRA); the Toxic Substances Control Act of 1976 (TSCA);
the Comprehensive Environmental Response, Compensation and Liability Act of 1980
(CERCLA); and the ESA.
The utility industry will continue to respond to changes in environmental legislation associated
with utility operations, including emissions regulations associated with the operation of coal- and
natural gas-fired generating faci I ities.
On June 2, 2014, the U.S. Environmental Protection Agency (EPA). under President Obamas
Climate Action Plan, released its long-anticipated proposal to regulate carbon dioxide (C02)
emissions from existing power plants under CAA Section 111 (d) of the Clean Air Act (CAA).
EPA's proposed Clean Power Plan includes ambitious, mandatory C02 reduction targets for each
state, designed to achieve nationwide 30 percent C02 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 C02 per megawatt hour (lbs/MWh) was calculated using four
building blocks:
Page 22 2015 IRP
Idaho Power Company 2. Political, Regulatory, and Operational Issues
I. 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 C02 emitting resources.
4. Building Block 4 - increase end use energy efficiency programs.
A combination of the 4 building blocks were used to calculate an interim goal (average or years
2020-2029) and a final 2030 goal. Each state would then implement the goals through a state
plan, which will need to be approved by the federal EP/\. Each rate-based goal would be legally
binding on each state.
With new comprehensive federal energy legislation, a utility's resource portfolio will continue to
evolve in response to its obligation to serve, market conditions, perceived risks. and regulatory
policy changes. Because the EPA 's proposed rule will not be finalized until sometime after the
completion of the 2015 IRP, the I RP analysis examines several compliance sensititivities that
represent possible outcomes of the final rule. Additional information on those sensitivities is
presented later in Chapter 9.
2015 IRP Page 23
2. Political, Regulatory, and Operational Issues Idaho Power Company
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Page 24 2015 IRP
Idaho Power Company
3. IDAHO POWER TODAY
3. Idaho Power Today
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 Idaho and Oregon.
Firm 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 system
peak-hour record. Construction i downtown Boise.
Average firm load increased from 1,200
aM W in 1990 to 1,739 aMW in 2014 (load calculations exclude the load from the former
special-contract customer Astaris, or FMC). Additional details of Idaho Power's historical load
and customer data arc shown in Figure 3.1 and Table..3.1.
Since 1990, Idaho Power's total nameplate generation has increased from 2,635 MW to
3,594 MW. The 959-MW increase in capacity represents enough generation to serve nearly
175,000 customers at peak times. Table 3.1 shows daho Power's changes in reported nameplate
capacity since 1990.
Idaho Power's newest resource addition is the 318-MW Langley Gulch CCCT. The highly
efficient, natural gas-fired power plant is located in the western Treasure Valley in
Payette County, Idaho. Construction of the plant began in August 20 I 0, and the plant
became commercially available in June 2012.
The data in Table 3.1 suggests each new customer adds approximately 5.5 kW to the peak-hour
load and about 2.5 average kilowatts to the average load. In actuality, residential, commercial.
and irrigation customers generally contribute more to the peak-hour load, whereas industrial
customers contribute more to the 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. Idaho Power has added about 225.000 new customers. The simple peak-hour and
average-energy calculations mentioned earlier suggest the additional 225,000 customers require
approximately 1.237 MW of additional peak-hour capacity and about 560 aM W of energy.
2015 IRP Page 25
3. Idaho Power Today Idaho Power Company
5.500
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
•* <*-' ....;;:_
550,000
500,000
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0 0
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014
-Total Nameplate Generation (MW) -Peak Firm Load (MW) -Average Firm Load (aMW) Customers
Figure 3.1 Historical capacity, load, and customer data
Table 3.1 Historical capacity, load, and customer data
Year Total Nameplate Generation (MW) Peak Finm Load (MW) Average Firm Load (aMW) customers"
1990 2,635 2,052 1,205 290,492
1991 2,635 1,972 1,206 296,584
1992 2,694 2,164 1,281 306,292
1993 2,644 1,935 1,274 316,564
1994 2,661 2,245 1,375 329,094
1995 2,224 1,324 339,450
1996 2,437 1,438 351,261
1997 2,352 1,457 361,838
1998 2,738 2,535 1,491 372,464
1999 2,738 2,675 1,552 383,354
2000 2,738 2,765 1,653 393,095
2001 2,851 2,500 1,576 403,061
2002 2,912 2,963 1,622 414,062
2003 2,912 2,944 1,657 425,599
2004 2,912 2,843 1,671 438,912
2005 3,085 2,961 1,660 456, 104
2006 3,085 3,084 1,745 470,950
2007 3,093 3,193 1,808 480,523
2008 3,276 3,214 1,815 486,048
2009 3,276 3,031 1,742 488,813
2010 3,276 2,930 1,679 491,368
2011 3,276 2,973 1,711 495, 122
2012 3,594 3,245 1,745 500,731
2013 3,594 3,407 1,801 508,051
2014 3,594 3,184 1,739 515,262
1 Year-end residential. commercial, and industrial count plus the maximum number of active irrigation customers
Page 26 2015 IRP
Idaho Power Company 3. Idaho Power Today
Idaho Power anticipates adding approximately 9,800 customers each year throughout the 20-year
planning period. The expected-case load forecast 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 information is presented in Chapter 7 and in Appendix A-Sales and Load Forecast.
The simple peak-hour load-growth calculation indicates Idaho Power would need to add peaking
capacity equivalent lo the 318-M W Langley Gulch CCCT plant every five years throughout the
entire planning period. The peak calculation does not include the expected effects of demand
response programs, and Idaho 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.
The generation costs per kW included in Chapter 7 help put forecast customer growth in
perspective. Load research data indicates the average residential 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 perk W for a natural gas-fired CCCT, such as Idaho Power's Langley
Gulch Power Plant, and peak-hour generation capital costs are abou $800 per kW for a natural
gas-fired SCCT, such as the Danskin and Bennett Mountain projects. These capital cost
estimates are in 2015 dollars and do not include fuel or any other operation and maintenance
expenses.
Based on the capital cost estimates, each new residential customer requires over $1,700 of capital
investment for 1.5 kW of base load generation, plus an additional $4,400 for 5 to 6 kW of peak­
hour capacity, leading to a total generation capital cost of over $6, I 00. Other capital
expenditures for transmission, distribution, customer systems, and other administrative costs are
not included in the $6, I 00 capital generation requirement. A residential customer growth rate of
9,800 new customers per year translates into almost .$60 million of new generation plant capital
each year to serve the baseload and peak energy requirements of the new residential customers.
2014 Energy Sources
Idaho Power's system receives energy from a variety of fuel types and integrates energy from
more than J 00 PURPA projects and three PP As in addition to company-owned generation.
Figure 3.2 belo shows the nameplate capacity of resources delivering to Idaho Power's system
from company-owned resources. PURPA contracts, and long-term PPAs.
2015 IRP Page 27
3. Idaho Power Today Idaho Power Company
Biomass
20 MW
Wind
678 MW 'I.
Waste
35 MW
Coal
1,123 MW
_____ ....,._Landfill Gases
16MW
Natural Gas
777MW
Figure 3.2 2014 Idaho Power system nameplate by fuel type (MW) (owned resources plus
purchased power)
Idaho Power's electricity sources for 2014 are shown in Figure 3.3 below. Idaho Power
generated 77 percent of the total energy requirement In above-average water years,
Idaho Power's low-cost hydroelectric plants are typically the company's largest source or
electricity. Purchased power provides the remainLng.23 percent of the energy requirement and
includes power purchased from PURPA projec , market purchases and power purchased
through I PUC-approved PPA agreemen s, the need for which has been identified in past IRPs.
Market Purchases
1,301,030 MWh
7%
Idaho Power
Generation Coal 5,850,665 MWh
34%
Idaho Power
Generation Gas
1,174,857 MWh
7%
Idaho Power
Generation
Hydro
6,169,847 MWh 36%
Figure 3.3 2014 energy by source
Page 28 2015 IRP
Idaho Power Company 3. Idaho Power Today
In 2014, Idaho Power purchased 4, 148.61 I M Wh of electricity through PURPA contracts,
market purchases, and long-term PPAs, Figure 3.4 provides a percentage break down by type of
fuel for the PPA and PURPA purchases. Market purchases arc 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 prings
Geothermal Project. I lowever, as noted in Chapter 2 .. Renewable Energy Certi ficates."
Idaho 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.
Figure 3.4
Gas
76.713 M\IVh
2%
Market Purchases 1,301,030 M\IVh
31%
Waste
74,878 M\IVh
2°,1,
2014 power purchases by fuel type
Hydro
441, 952 M\IVh
11%
Biomass
101,657 M\IVh
2%
Wind
1 660.874 M\IVh
45%
Existing Supply-Side Resources
To identify the need and timing of future resources, Idaho Power prepares a load and resource
balance that accounts for forecast load growth and generation from all of the company's
existing resources and planned purchases. The load and resource balance worksheets showing
Idaho Power's existing and committed resources for average-energy and peak-hour load are
presented in Appendix C-Technical Appendix. Table 3.2 shows all of Idaho Powers
existing resources, nameplate capacities, and general locations.
2015 IRP Page 29
3. Idaho Power Today Idaho Power Company
Table 3.2 Existing resources
Generator
Nameplate
Capacity (MW) Location
92.3 Upper Snake
75.0 Mid-Snake
585.4 Hells Canyon
82.8 Mid-Snake
12.4 North Fork Payette
2.5 South Central Idaho
391.5 Hells Canyon
13.5 South Central Idaho
60.0 Mid-Snake
59.4 Upper Snake
190.0 Hells Canyon
12.5 Upper Snake
27.2 Mid-Snake
8.8 South Central Idaho
52.9 Mid-Snake
8.3 South Central Idaho
18.0 Mid-Snake
16.5 Mid-Snake
64.2 North Central Oregon
770.5 Southwest Wyoming
283.5 North Central Nevada
318.5 Southwest Idaho
172.8 Southwest Idaho
270.9 Southwest Idaho
5.0 Eastern Idaho
3,594.4
Type
Hydroelectric
Resource
American Falls .
Bliss . .. . .. . . . . .. Hydroelectric
Brownlee........................................................... Hydroelectric
C. J. Strike Hydroelectric
Cascade.............................................................. Hydroelectric
Clear Lake....................................................... .. Hydroelectric
Hells Canyon Hydroelectric
Lower Malad...................................................... Hydroelectnc
Lower Salmon.................................................. .. Hydroelectric
Milner.................................................................. Hydroelectric
Oxbow Hydroelectric
Shoshone Falls Hydroelectric
Swan Falls.......................................................... Hydroelectric
Thousand Springs............................................... Hydroelectric
Twin Falls Hydroelectric
Upper Malad.................................................... . . Hydroelectric
Upper Salmon A.................................................. Hydroelectric
Hydroelectric
Coal
Coal
Natural Gas-CCCT
Natural Gas-SCCT
Natural Gas-SCCT
Salmon Diesel.................................................... Diesel
Total existing nameplate capacity .
The following sections describe Idaho Power's existing supply-side generation resources and
long-term power purchase agreements (PPA).
Hydroelectric Facilities
Idaho Power operates 17 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 equal to approximately 970 aMW. or 8.5 million MWh under median water
conditions.
Page 30 2015 IRP
Idaho Power Company 3. Idaho Power Today
Hells Canyon Complex
The backbone of Idaho Power's hydroelectric system is the Hells Canyon Complex (HCC) in the
I I ells Canyon reach of the Snake River. The HCC consists of Brownlee, Oxbow, and I I ells
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 major portion of Idaho Power's peaking and load­
following capability.
Idaho Power operates the HCC to comply with the existing annual FERC license as well as
voluntary arrangements to accommodate other interests, such as recreational use and
environmental resources. Among the arrangements are the Fall Chinook Program, voluntarily
adopted by Idaho Power in 1991 to protect the spawning and incubation of fall Chinook below
I lells Canyon Dam. The fall Chinook species is currently listed-as threatened under the
Endangered pccies Act (ES/\).
Brownlee Reservoir is the main HCC reservoir-and Idaho Power's only rescrvoir-
with significant active storage. Brownlee Reservoir has I vertical feet of active storage
capacity, which equals approximately one million acre-fee of water. Both Oxbow and
Hells Canyon reservoirs have significantly smaller active storage capacities-approximately
0.5 percent and I percent of Brownlee Reser oir's volume, respec ively.
Brownlee Reservoir is a year-round, multiple-use resource for Idaho Power and the
Pacific Northwest. Although the primary purpose is to provide a stable power source,
Brownlee Reservoir is also used for system flood control, recreation, and the benefit of fish and
wildlife resources.
Brownlee Dam is one of several Pacific Northwest dams coordinated to provide springtime flood
control on the lower Columbia River. Idaho Power operates the reservoir in accordance with
flood-control directions received from the US Army Corps of Engineers (USA CE) as outlined in
Article 42 of the existing FERC license.
After flood-control requirements have been met in late spring, Idaho Power attempts to refill the
reservoir to meet peak summer electricity demands and provide suitable habitat for spawning
bass and crappie. The full reservoir also offers optimal recreational opportunities 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 Reservoir to augment flows in the lower Snake River to help
anadromous fish migrate 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) projects, 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
in the fall as a result of the Fall Chinook Program adopted by Idaho Power in 1991. The constant
2015 IRP Page 31
3. Idaho Power Today Idaho Power Company
now is set at a level to protect fall Chinook spawning nests, or redds. During the fall Chinook
operations, Idaho Power attempts to refill Brownlee Reservoir by the first week of December to
meet wintertime peak-hour loads. The fall Chinook plan spawning nows establish the minimum
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 from the I ICC 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 American falls projects. Although the
upstream projects typically follow run-of-river (ROR) operations, a small amount of peaking and
load-following capability exists at the Lower Salmon, Bliss, and C. J. Strike projects. These three
projects are operated within the FERC license requirements to coincide with daily system peak
demand when load-following capacity is available.
Idaho Power completed a study to identify the effects of load-following operations at the
Lower Salmon and Bliss power plants on the Bliss Rapids snail, a threatened species under the
ESA. The study was part of a 2004 settlement agreement with the U Fish and Wildlife Service
(FWS) to relicense the Upper Salmon, Lower almon. Bliss. and C. J. Strike hydroelectric
projects. During the study, Idaho Power annually alternated operating the Bliss and Lower
Salmon facilities under ROR and load-following operations. Study results indicated that while
load-following operations had the potential to harm individual snails, the operations were not a
threat to the viability or long-term persistence of the species.
A Bliss Rapids Snail Protection Ian developed in consultation with the FWS was completed
in March 20 I 0. The plan ide tifies appropriate protection measures to be implemented by
Idaho Power, includ in� monitoring snail populations in the Snake River and associated springs.
By implementing the prot ction and monitoring measures, the company has been able to operate
the Lower Salmon and B iss proj cs in load-following mode while protecting the stability and
viability of the Bliss Rapids snai. Idaho Power has received a license amendment from FERC
for both projects that allows load-following operations to resume.
Water Lease Agreements
Idaho Power views the rental of water for delivery through its hydroelectric system as a
potentially cost-effective power-supply alternative. Water leases that allow the company to
request delivery when the ater is needed are especially beneficial. Acquiring water through the
water bank also helps the company to improve water-quality and temperature conditions in the
Snake River as part ofongoing 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 for45.716 acre-feet of American Falls storage
water. In 20 I I, the company extended the Shoshone-Bannock rental agreement for two
additional years, 2014 and 2015.
Page 32 2015 IRP
Idaho Power Company 3. Idaho Power Today
Under the terms of the hoshone-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 hoshone­
Bannoek 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.
Cloud Seeding
In 2003, Idaho Power implemented a cloud-seeding program to increase snowpack in the south
and middle forks of the Payette River watershed. In 2008, Idaho Power began expanding its
program by enhancing an existing program operated by a coalition of counties and other
stakeholders in the upper Snake River Basin above Milner Dam. Idaho Power has continued
to work with the stakeholders in the upper Snake River to expand the program and has recently
collaborated with irrigators in the Boise and Wood River Basins to expand the target to include
those watersheds.
Idaho Power seeds clouds by introducing
silver iodide (Agl) into winter storms. Cloud
seeding increases precipitation from passing
winter storm systems. If a storm has the right
combination of abundant supercooled liquid
water vapor and appropriate temperatures
and winds, conditions are optimal for cloud
seeding to increase precipitation.
Idaho Power uses two methods to seed
clouds:
I. Remotely operated ground generators
at high elevations Remote cloud-seeding generator.
2. edified aircraft burning flares containing AgJ
Benefits of either method vary by storm, and the combination of the two methods provides the
most flexibility to success-nilly place Agl into passing storms. Minute water particles within the
clouds freeze on contact with the Agl particles and eventually grow and fall to the ground as
snow.
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/ AG I_ toxicity.pd t). Analyses conducted by Idaho Power
since 2003 indicate the annual snowpack in the Payette River Basin increased between I and
28 percent annually with an annual average of 14 percent. Idaho Power estimates cloud seeding
currently 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
2015 IRP Page 33
3. Idaho Power Today Idaho Power Company
additional runoff from the Payette, Boise, Wood, and Upper Snake projects will total
approximately 1,000,000 acre-feet. Studies conducted by the Desert Research Institute from
2003 to 2005 support the effectiveness of Idaho Power's program.
For the 2014 to 2015 winter season, the program included 23 remote-control led, ground-based
generators and 2 aircraft for operations in the west central mountains (Payette, Boise and Wood
River Basins. The Upper Snake River Basin program included 21 remote-control led. 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 forecasting to guide the coalition's operations.
Coal Facilities
Jim Bridger
Idaho Power owns one-third, or 771 MW (generator nameplate rating), of the Jim Bridger
coal-fired power plant located near Rock Springs, Wyoming. The Jim Bridger plant consists of
four generating units. PacifiCorp has two-thirds ownership and is the operator of the Jim Bridger
facility.
North Valmy
Idaho Power owns 50 percent, or 284 MW (generator nameplate rating), of the North Val my
coal-fired power plant located near Winnemucca, Nevada. The North Valmy plant consists
of two generating units. NV Energy has 50 perc nt ownership and is the operator of the North
Valmy facility.
Boardman
Idaho Power owns 10 percent, or 64.2 MW (generator nameplate rating), of the Boardman
coal-fired power plant Joe te nea Boardman, Oregon. The plant consists of a single generating
unit. Portland General Electric (PGE) has 90 percent ownership and is the operator of the
Boardman facility.
The 2015 JRP assumes ldaho[ower's share of the Boardman plant will not be available after
December 31, 2020. The 2020 date is the result of an agreement reached between the
Oregon Department of Environmental Quality (ODEQ), PGE, and the Environmental Protection
Agency (EPA) related to compliance with Regional Haze Best Available Retrofit Technology
(RH BART) rules on particulate matter, sulfur dioxide (S02), and nitrogen oxide (NOx)
emissions. At the end of 2014, the net-book value of Idaho Power's share of the Boardman
facility was approximately $20.9 million.
Natural Gas Facilities
Langley Gulch
Idaho Power owns and operates the Langley Gulch plant, a nominal 318-M W natural gas-fired
CCCT. The plant consists of one 187-MW Siemens STG-5000F4 combustion turbine and
one 131.5-M W Siemens SST-700/SST-900 reheat steam turbine. The Langley Gulch plant.
Page 34 2015 IRP
Idaho Power Company 3. Idaho Power Today
located south of New Plymouth in Payette County, Idaho, became commercially available in
June 2012.
Dans kin
Idaho Power owns and operates the 271-MW Danskin natural gas-fired. SCCT facility.
The facility consists ofone 179-MW Siemens 50 IF and two 46-MW Siemens-Westinghouse
W25 I BI 2A combustion turbines. The Danskin facility is located northwest of Mountain Home,
Idaho. The two smaller turbines were installed in 200 I. and the larger turbine was installed in
2008. The Danskin units are dispatched when needed to support system load.
Bennett Mountain
Idaho Power owns and operates the Bennett Mountain plant. which consists of a 173-M W
Siemens-Westinghouse 501 F natural gas-fired SCCT located east of the Danskin plant in
Mountain Home, Idaho. The Bennett Mountain plant is also dispatched as needed to support
system load.
Salmon Diesel
Idaho Power owns and operates two diesel generation units located in Salmon, Idaho.
The Salmon units have a combined generator nameplate rating of 5 MW and are operated
during emergency conditions, primarily for voltage and load support.
Solar Facilities
In 1994, a 25-kW solar photovoltaic (PY) array with 90 panels was installed on the rooftop of
Idaho Power's corporate headquarters (CHQ) in Boise, Idaho. The 25-kW solar array is still
operational, and Idaho Power uses the hourly generation data from the solar array for
resource planning.
Idaho Power also uses small PV panels in its daily operations to supply power to equipment used
for monitoring water quality, measuring stream nows, and operating cloud-seeding equipment.
In addition to these solar PY installations, Idaho Power participates in the Solar 4R Schools
Program; o ns a mobile solar trailer that can be used to supply power for concerts,
radio re o es, and other events.
Net Metering Service
Idaho Power's net metering service al lows customers to generate power on their property 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 company's grid.
The majority of net metering customers use solar PY systems. As of May I. 2015, there were
479 solar PY systems interconnected through the company's net metering service with a total
capacity of 3.316 MW. At that time, the company had received completed applications for an
additional 48 net metered solar PY systems representing an incremental capacity of0.498 MW.
For further details regarding customer-owned generation resources interconnected through
the company's net metering service, see Table 3.3.
2015 IRP Page 35
3. Idaho Power Today Idaho 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
Solar PV ....................... 479 48 527 3.316 0.498 3.814
Wind ............................. 70 2 72 0.557 0.010 0.567
Other/hydroelectric ....... 10 10 0.147 0.000 0.0147
Total ............................ 559 50 609 0.508 4.528
Oregon Solar Photovoltaic Pilot Program and Oregon Solar Photovoltaic Capacity
Standard
In 2009, the Oregon Legislature passed Oregon Revised Statute (6RS) 757.365 as amended by
House Bill 3690, which mandated the development of pilot programs for electric utilities
operating in Oregon to demonstrate the use and effectiveness of volumetric incentive rates for
electricity produced by solar PY systems.
As required by the OPUC in Order Nos. I 0-200 and 11-089, Idaho Power established the
Oregon Solar Photovoltaic Pilot Program in 20 I 0, offering volumetric incentive rates to
customers in Oregon. Under the pilot program, Idaho Power acqui ·ed 400 kWac of installed
capacity from solar PY systems with a nameplate capacity of less tli nor equal to IO kW. In July
2010, approximately 200 kW were allocated, ind the remaining 200kW were offered during an
enrollment period in October 2011. However, because-some PV systems were not completed
from the 2011 enrollment, a subsequent offering was held on April I, 2013, for approximately
80 kW.
In 2013, the Oregon Legislature passed llouse Bill 2893, which increased Idaho Power's
required capacity amount by 55 kW. An enrollment period was held in April 2014, and all
capacity was allocated, bringing ldaho Power's total capacity in the program to 455 kW.
Under the Oregon Solar PY Capacity Standard as stated in ORS 757.370, Idaho Power is
required to either own or purchase the generation from a 500-kW utility-scale solar PY facility
by 2020. Under the rules, if the utility scale facility is operational by 2016, the RECs from the
project would be doubled for purposes of complying with the State of Oregon RPS.
Page 36 2015 IRP
Idaho Power Company 3. Idaho Power Today
Power Purchase Agreements
Elkhorn Valley Wind Project, Union County, Oregon
Raft River Geothermal Project
Elkhorn Valley Wind Project
In February 2007, the IPUC approved a PPA
with Telocaset Wind Power Partners, LLC
a subsidiary of Horizon Wind Energy, for IOI
MW of nameplate 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.
In January 2008, the IPUC approved a PPA for
13 MW of nameplate generation from the Raft River Geothermal Power Plant (Unit I) located in
southern Idaho. The Raft River project began commercial operations in October 2007 under a
PURPA contract with Idaho Power that was canceled when the new PPA was approved by the
IPUC. For the first IO years (2008-2017) of the agreement, Idaho Power is entitled to 75 percent
of the RECs from the project for generation that exceeds JO aMW monthly. The Raft River
geothermal project has rarely exceeded the monthly IO aMW of generation since 2009. and
Idaho Power is currently receiving negligible RECs ti om the Raft River geothermal project. For
the second 10 years of the agreement (2018-2027) daho Power is entitled to 51 percent of all
RECs generated by the project.
Neal Hot Springs Geothermal Project
In May 20 I 0, the I PUC approved a"PPA for approximately 22 MW of nameplate generation
from the Neal Hot Springs Geothermal Project located in eastern Oregon. The Neal Hot Springs
project achieved commercial operation in November 2012. Under the PPA. Idaho Power receives
all RECs from the project.
Clatskanie Energy Exchange
In September 2009, Idaho Power and the Clatskanie People's Utility District (Clatskanie PUD)
in Oregon entered into an energy exchange agreement. Under the agreement. Idaho Power
receives the energy as it is generated from the 18-MW power plant at Arrowrock Dam on the
Boise River: in exchange, 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 parties
where the energy value will be determined using the Mid-Columbia market price index. The
Arrowrock project began generating in January 20 I 0, and the agreement term extends through
2015. 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 IRP Page 37
Published Avoided Cost Rates
2015 IRP
Idaho Power Company
Wind
48%
Hydro
12%
Solar
35%
PURPA contracts by resource type
Public Utility Regulatory Policies Act
3. Idaho Power Today
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 small 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 part of the PURPA agreements. Because Idaho Power operates
in Idaho and Oregon, the company must adhere to both the IPUC rules and regulations for all
PURPA facilities located in the state of Idaho and the OPUC rules and regulations for all
PURPJ\ facilities located in the state of Oregon. The rules and regulations are similar but not
identical for the two states. Because Idaho Power cannot accurately predict the level of future
PURPA development, only signed contracts are accounted for in Idaho Power's resource
planning process.
Generation from PURPA contracts has to be forecasted early in the IRP planning process to
update the load and resource balance. The PURPA forecast used in the 2015 IRP was completed
in October 20 14.
Biomass CHP
2%
As of March 31, 2015, Idaho Power had 133 PURPA contracts with independent developers for
approximately 1,302 MW of nameplate capacity. These PURPA contracts are for low-head
hydroelectric projects on various irrigation canals. cogeneration projects at industrial facilities,
wind projects, solar projects, anaerobic digesters, landtilJ gas, wood-burning facilities, and
various other small, renewable-power generation facilities. Of the 133 contracts, I 05 were on­
line as of March 31, 2015, with a cumulative nameplate rating of approximately 781 MW. Figure
3.5 shows the percentage oft e total PURPA capacity of each resource type under contract.
Figure 3.5
A key component of PURPA contracts is the energy price contained within the agreements.
The federal PURPA regulations specify that a utility must pay energy prices based on the
Page 38
Idaho Power Company 3. Idaho Power Today
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 - Wind and solar projects with a nameplate rating of less than I 00 kW and all other
projects less than IO average MW calculated on a monthly basis
• Oregon - A II projects with a nameplate rating of less than IO MW
For all projects that are not eligible for the published avoided cost rate, a unique negotiated
avoided cost is calculated for each project. The basis for this negotiated avoided cost rate is the
commission approved incremental cost IRP avoided cost methodology. In both Idaho and
Oregon the published avoided cost is different based upon the resource type (i.e. wind, solar,
hydro, base load).
REC ownership
• Idaho - Projects that contract with Idaho Power using the published avoided cost rate will
retain all renewable energy certificates (REC) associated with the project. If the PURPA
contract contains negotiated rates, IPUC Order No. 32697, issued December 18, 2012,
stipulates that the RECs will be equally shared between ldaho Power and the
project owner
• Oregon - The project owner retains al I rights to the RECs associated with the project
On January 30, 2015 Idaho Power filed at the Idaho PUC a petition requesting the required
contract term within new Idaho PURPA contracts be revised from 20 years to 2 years. The IPUC
opened case I PC-E-15-0 I to address this matter and a hearing is scheduled for June 29, 2015.
IPUC Order No. 33222, issued February 6, 2015, temporarily revised the contract term from 20
years to 5 years during the processing of the case.
In April 2012, the OPUC issued Order No. 12-146, which opened OPUC Docket UM 1610.
Docket (JM 1610 addresses many of the same PURPA issues identified in the recent Idaho
PURPA cases as well as unique PURPA issues associated with Oregon. Parties have been filing
testimony and comments in the case. The initial hearing was held in Salem, Oregon. on May 23,
2013. Th is case is moving into its second and third phases continuing to review and address
numerous PURPA related issues.
On December 18, 2012, the IPUC issued Order No. 32697. Order No. 32697 included new rules
and regulations in regard to the numerous PURPA issues presented in the various cases that
began in November 20 I 0. Some highlights are as follows:
• The published avoided cost rate is available only for wind and solar projects with a
nameplate rating of less than 100 kW.
• For all other resource types. the eligibility cap remains at IO aMW.
2015 IRP Page 39
3. Idaho Power Today Idaho 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.
• 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 I PUC issued Order No. 32802 concerning the reconsideration or
Case No. GNR-E-11-03. Order No. 32802 affirms many of the commission rulings in
Order No. 32697. PURPA contracting continues to be an issue in Idaho, and approximately
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 wholesale energy contracts (no long-term wholesale
sales contracts and no long-term wholesale purchase contracts). The Elkhorn, Raft River
Geothermal, Neal Hot Springs, and Clatskanie Exchange contracts were described previously in
the Power Purchase Agreements section of the I�P.
Market Purchases and Sales
Idaho Power relies on regional markets to supply a significant portion of energy and capacity
needs during certain times of the year. Idaho Power is especially dependent on the regional
markets during peak-load periods, and the existing transmission system is used to import the
energy purchases. A reliance on regional markets has benefited Idaho Power customers during
times of low prices through the import of low-cost energy. Customers also benefit from sales
revenue associated with surplus energy from economically d ispatchcd resources.
Page 40 2015 IRP
Idaho Power Company 4. Demand-Side Resources
4. DEMAND-SIDE RESOURCES
Introduction
Demand-side resources have been the
first resource choice in every IRP since
2004. No supply-side generation
resource is considered as part of Idaho
Powers plan until all future achievable
potential energy efficiency and demand
response is accounted for and credited
against future loads. In the 2015 I RP
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
CSQHA's new offices received the City of Boise Building
Excellence awards for Best Sustainable Commercial Project
and Best Overall Project for 2014. CSQHA was a participant in
Idaho Power's Building Efficiency program
DSM programs are an essential component of Idaho Power's resource strategy, and its portfolio
of programs consists of demand response, energy efficiency, and market transformation
programs. The three program categories each provide different system benefits. Demand
response programs reduce peakJoads through customer behavior or automations that respond
during periods of extreme loads when all other resources. including market purchases, are at their
maximum capacity. Energy efficiency programs target year-round energy and demand reduction
and are the demand-side alternatives to supply-side base load resources. Market transformation
targets energy savings through engaging and influencing large national and regional
organizations to promote energy efficiency. Idaho Power has collaborated with other regional
utilities and organizations and funded Northwest Energy Efficiency Alliance (NEEA) market
transformation activities since 1997. Energy efficiency. demand response. and market
transformation programs are offered to all four major customer classes: residential. irrigation,
commercial, and industrial. Education programs and services are also offered to customers to
support, promote and encourage efficiency efforts.
Cost-effectiveness analyses, which indicate whether the benefits of these programs exceed the
costs to administer the programs along with the costs incurred by participants. are published
annually. The most recent analysis can be found in the Demand-Side Management 20 I-I Annual
Report Supplement I: Cost Effectiveness. Each program and its component measures in the
existing portfolio of demand-side resources are reviewed for their load impact over the 20-year
IRP planning horizon as part of the IRP process. Additionally. in 2014 Idaho Power contracted
with Applied Energy Group (AEG) to conduct an energy efficiency potential study which
resulted in a forecast of energy savings over the 20-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
2015 IRP Page 41
4. Demand-Side Resources Idaho Power Company
of the energy efficiency forecast arc found in Appendix A-Sales and load Forecast and also in
Appendix C Technical Appendix in the Demand-Side Management section.
DSM Planning Changes from the 2013 IRP
Demand response and market transformation were considered di fTerently in the 2015 I RP than
the previous 2013 plan. ince market transformation was included in the 2014 AEG study.
market transformation savings arc considered as a demand-side resource in the 2015 1 RP
whereas in the past market transformation savings have been excluded from resource planning.
In the 2015 I RP, demand response was treated as both a committed resource based on cost­
effectiveness and as a potential new future resource addition beyond the committed resource
level in select portfolios.
The 2013 I RP load and resource balance analysis demonstrated no capacity deficits in the near
term. As a consequence, Idaho Power temporarily suspended two of its three demand response
programs for summer 2013 under IPUC Case No. IPC-E-12-29 and Tariff Advice No. 13-04
with the OPUC. The suspension of the irrigation and residential demand response programs
wou Id only last the one year because through IPUC Case No. IPC-E-13-14 (Order No. 32923)
and OPUC Case No. UM 1653 (Order No. 13-482), Idaho Power and interested parties reached a
settlement agreement lo continue the company's demand re pon e programs for 2014 and
beyond.
In the 2015 I RP 390 MW of Demand Response capacity is included in every portfolio and up to
an additional 60 MW in some portfolios as needed. In 2014, these programs cost$ I 0.6 million;
had the programs been used for the maximum number of hours, the cost would have been
approximately $13.8 million. These costs represent approximately $6 million dollars in savings
compared to 2012 ($21.2 mill ion) and are significantly less than the annual value of $16.7
million agreed on in the settlement agreement. Another result of the settlement was guidance on
how to operate the programs in years where they may not be short term peak capacity deficits.
To maintain customer engagement as participants in demand response programs, Idaho Power
would conduct a minimum of three events even when the extreme loads, low water, and extreme
temperature assumptions that demand response programs were designed to meet did not occur.
In addition to customer retention, the three events would allow for annual operational evaluation
and increased experience in dispatching the programs to maximize peak reduction. Since demand
response is considered a committed resource to the company and the potential load reduction of
390 MW from demand response was applied to future peak summer loads prior to the selection
of additional resources to meet future 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 e lficicncy 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 (NEEA). Idaho Power has been a
funding member ofNEEA since its inception in 1997.
I listorically, Idaho Power has treated the savings reported by NEEA separate from savings from
company run and administered efficiency programs. While the company has been supporting
Page 42 2015 IRP
Idaho Power Company 4. Demand-Side Resources
market transformation 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. Examples of this would
include residential energy efficient lighting that started out as a NEEA initiative to promote
compact fluorescent technologies and transitioned to utility programs across the Northwest
including Idaho Power. Another reason affecting how market transformation savings were used
in resource planning was related to how savings were attributed to utilities. Until 20 IO NEEA
primarily apportioned savings by how much each regional funder utility contributed to their
various initiatives and there was very little effort put in to geographically pinpoint where the
savings occurred. This made it difficult to count on NEEA savings that may or may not be
actually reducing Idaho Power loads while reducing regional system loads.
Since 20 I 0, NEEA has been working on and continuously improving its ability through
evaluation and increased data collection to verify savings at the service area level of its funders.
This allows Idaho Power to include market transformation savings as part of the company's
efforts to meet IRP energy-savings targets. Another consideration to fully integrate market
transformation into the IRP is that the AEG potential study that determines the energy efficiency
forecast is agnostic to where the savings for any potential measure or technology come from or
who provides them. The forecasted future savings can come from market transformation efforts
done on a regional basis or from a traditional utility administered program.
Program Screening
All DSM programs and measures included in Idaho Power's current portfolio of programs and
the forecast have been screened for cost-effectiveness. Cost-effectiveness analyses of DSM
forecasts for the 2015 IRP are-preserited in more detail in Appendix C-Tec:hnical Appendix.
Appendix Bs-Dernand-Side Management 2014 Annual Report contains a detailed description of
Idaho Power's 2014 current energy efficiency-program portfolio along with historical program
performance (appendices Band Care filed as part of this IRP). A complete review of
Idaho Power's DSM programs, evaluations, and cost-effectiveness can be can be found in the
2014 annual report filing, Deman -Side Management 2014 Annual Report, Supplement I: Cost­
Effectiveness, Supplement 2: Evaluation, which is available on the Idaho Power website at
http://www.idahopower.com/EnergyEfficiency/reports.cfm.
DSM Program Performance
While the IRP planning process primarily looks forward, it is also important to review historical
DSM performance to understand the effects on system load. Accumulated annual savings from
energy efficiency investments grow over time based on measure lives of the efficient equipment
and measures adopted and installed by customers each year. Additionally. past performance of
demand response programs has changed over time as the design and use of the programs have
evolved.
Energy Efficiency Performance
Energy efficiency investments since 2002 have resulted in a cumulative average annual load
reduction of 167 aM W or over 1.4 million MWh of reduced supply-side energy production to
2015 IRP Page 43
4. Demand-Side Resources Idaho Power Company
customers through 2014. Figure 4.1 shows the cumulative annual growth in energy efficiency
effects over the 13-year period from 2002 through 2014 along with the associated I RP targets
that were developed as part of the IRP process since 2004.
180 167
160
� -Reported IPC Savings
::E 140 � � - IRP Targets Cl> Cl 120 ni ....
"O c: 100 co
II) Cl c: 80 's co (I)
Cl> .? 60 ; 3 E 40 ::I o
20
2
0 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Figure 4.1 Cumulative energy efficiency savings, 2002-2014 (aMW)
Demand Response Performance
Demand response resources have been part of the demand-side portfolio since the 2004 IRP. The
current demand response portfolio is made up of three distinct programs that work together as
one resource. Each prog_ram targets a different customer class. Table 4.1 lists the three programs
that make up the current demand response portfolio along with the different program
characteristics. The Irrigation Peak Rewards program represents the largest percent of potential
demand reduction. During the 2014 summer season participating irrigation program customers
contributed 78 percent of the total potential demand reduction or 295 MW. More details on Jdaho
Power's deman response programs can be found in appendix 8, Demand-Side Management
20/./-Annual Report.
Table 4.1 Current portfolio of demand response programs
Reduction 2014 Peak Percent of Total 2014
Program Customer Class Technology Performance Peak Performance
A/C Cool Credit residential central A/C 44 12%
Irrigation Peak Rewards irrigation pumps 295 78%
FlexPeak Management commercial, industrial various 40 11%
Total 378
Page 44 2015 IRP
Idaho Power Company 4. Demand-Side Resources
Figure 4.2 shows the historical annual demand response program capacity between 2004 and
2014 along with associated I RP targets between 2004 and 2012. There were no targets for the
years 2013-2014 in the 2013 IRP. The largejump in demand response capacity from 61 MW in
2008 to 218 MW in 2009 was a result of transitioning the majority of the Irrigation Peak
Rewards program to a dispatchable program. The demand response capacity in 2011 and 2012
included 320 and 340 MW of capacity from the Irrigation 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.
500 ..---------------------------------·-·--
450 -------··-·-··-·-··-··-·-·438 - - _
o�---�
-Annual DR Performance/Capacity (MW)
-2006-2012 DR IRP Targets
§' 400
:§.
2: 350 u .. Q.
� 300 +------------------ c 0 .. g 250 -g 0::
'ti 200 +---------------- c .. E � 150+--------------� � .. .. � 100+---------------
6
50
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Figure 4.2 Demand response peak reduction capacity and IRP targets, 2004-2014 (MW)
Committed Energ� Efficiency Forecast
For the 2015 LRP, Applied Energy Group (AEG) was retained to update the previous study from
2012 and provide an updated 20-year comprehensive view of Idaho Power's energy efficiency
potential. The objectives of the 2014 potential study were as follows:
• Incorporate the 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) with in the Idaho Power
service area.
• Assess potential energy savings and peak demand associated with each potential area by
energy efficiency measure or bundled measure and sector.
2015 IRP Page 45
4. Demand-Side Resources Idaho Power Company
• Provide a dynamic model that will support the potential assessment and allov testing of
the sensitivity of all model inputs and assumptions.
• Develop a final report, including summary data tables and graphs reporting incremental
and cumulative potential by year from 2015 through 2034.
Because the potential study's market characterization process bundles industries and building
types into homogenous groupings, Idaho Power's special contract customers were treated outside
of the potential study model. Forecasts for these unique customers. who tend to be very active in
efficiency, were based on the combined customer group 's history of participation along the
near-term pipe I ine of projected projects.
In the AEG study, the energy efficiency potential estimates represent gross savings developed
into three types of potential: technical potential, economic potential, and achievable potential.
Technical and economic potential are both theoretical limits 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, and the elements of building construction.
These levels are described below.
• Technical-Technical potential is defined as the theoretical upper limit of energy
efficiency potential. Technical potentia assumes customers adopt all feasible measures
regardless of cost. At the time of equipment replacement, customers are assumed to select
the most efficient equipment available. In new construction, customers and developers
are also assumed to choose the.most efficient equipment available. Technical potential
also assumes the aqopjion of every other applicable measure available. The retrofit
measures are phased mover a number of years, which is greater for higher-cost measures.
• Economic-Economic potential represents the adoption of all cost-effective energy
efficiency measures. In tbe potential study, the TRC test, which compares lifetime
energy and capacity bene its to the incremental cost of the measure, is applied.
Economic potential assumes customers purchase the most cost-effective option at the
time of equipment failure and also adopt every other cost-effective and
applicable measure.
• Achievable-Achievable potential takes into account market maturity.
customer preferences for energy-efficient technologies. and expected program
participation. Achievable potential establishes a realistic target for the energy efficiency
savings a utility can achieve through its programs. It is determined by applying a series of
annual market adoption factors to the economic potential for each energy efliciency
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 the various industries
and building types within the commercial and industrial customer classes. Saturations of end-use
Page 46 2015 IRP
Idaho Power Company 4. Demand-Side Resources
technologies within customer segments arc assessed to help determine which technologies are
available for efficient upgrades. The next step was screening measures and technologies for
cost-effectiveness, and then assessing the adoption rates of technologies to determine the forecast
of achievable potential. More detailed in formation about cost-effectiveness methodologies and
approaches can be found in Appendix Ce-Techntcal Appendix.
The annual savings potential forecast is provided to Idaho Power in GWh, where it is converted
to hourly and then monthly demand reduction (aM W) to compare with supply-side resources for
the I RP analysis, the savings arc shaped by end use load shapes that spread the forecasted
savings across all hours of the year. The load shapes used to allocate savings by end-use were
provided by AEG as part of the study deliverables. All reported energy efficiency 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 tha would have been
lost as a result of transmitting energy from a supply-side generation resource to the meter level.
Table 4.2 shows the forecasted potential effect of the current portfolio of energy efficiency
programs for 2015 to 2034 in five-year blocks, in terms of cumulative average annual energy
reduction (aMW) by customer class. In 2019, the forecast reduction for 20I5-to-2019 programs
is forecast to be 84.3 aMW; by the mid-point plan year 2024. the cumulative reduction across all
customer classes increases to 169.4 aMW. By the end of the IRP planning horizon in 2034, 300.8
aMW of reduction are forecast to come from the energy efficiency portfolio, with 55 percent of
forecasted reduction coming from programs serving commercial and industrial customers.
Detailed year-by-year forecast values can be found in Appendix C-Technica/ Appendix.
Table 4.2 Total energy efficiency current portfolio forecasted effects (2015-2034) (aMW)
2015 2019 2024 2029 2034
Industrial/Commercial/Special Contracts .............. 8 46 93 138 167
Residential ............................................... , ........... 3 28 55 85 111
Irrigation ................................................................ 11 22 23 23
Total* ................................ " .................................. 12 84 169 246 301
·Totals may not add exactly due to rounding.
Table 4.3 shows the cost-effectiveness summary from the potential study. The table shows the
net present value (N PY) analysis of the 20-ycar forecast of the total resource costs (TRC) and
DSM preliminary alternative costs or program benefits. TRC costs account for both the costs to
administer the programs and the customer's incremental cost to invest in efficiency technologies
and measures offered through the programs. The benefit of the programs is avoided energy,
which is calculated by valuing energy savings against the avoided generation costs of
Idaho Powers existing marginal resources.
2015 IRP Page 47
4. Demand-Side Resources Idaho Power Company
Table 4.3 Total energy efficiency portfolio cost-effectiveness summary
2034 Load Resource Total Benefits TRC: TRC Levelized
Reduction 2034 Peak load Costs ($000s) ($000s) BenefiU Costs
(aMW) Reduction (MW) (20-Year NPV) (20-Year NPV) Cost Ratio (cents/kWh)
Residential 111 175 $425.360 $691.151 1.6 98
Industrial/Commercial/ 167 226 $253.982 $618.633 2.4 33
Special Contract
Irrigation 23 72 $139.190 $222,009 1.6 10.3
Total 301 473 $818,532 $1,531,793 1.9 6.1
The value of avoided energy over the 20-year investment in the energy efficiency measures was
almost twice the TRC when comparing benefits and costs resulting in an overall benefit to cost
ratio of Z. The levelized cost to reduce energy demand by 301 aM..W and peak demand by
473 MW is 6.1 cents per kWh from a TRC perspective.
Once the energy efficiency forecast is complete, the forecasted energy efficiency is included in
the IRP planning horizon and the load and resource balance analysis.Planning assumptions in
the energy efficiency potential forecast include new programs. technology, known changes to
codes and standards, customer adoption behavior, and cost-effectiveness that are explicitly
incorporated into the potential study and reflect differences between the energy efficiency
forecast and the amount of efficiency accounted for in the load forecast. A key difference
between the two views of efficiency is that the load forecast accounts for energy efficiency
effects based on previous years· program performance while the forecast from the potential study
is more prospective in its approach. The amount of energy efficiency not captured by the load
forecast trends is accounted for in the load and resource balance analysis.
Committed Demand Response Resources
Under the current program design and
participation levels, demand response
from al I programs is forecast to provide
390 MW of peak reduction during July
throughout the IRP planning period
with additional program potential
available during June and August. The
committed demand response included
in the IRP has a capacity cost of $33
per annual kW/year.
Non-Cost-Effective DSM
Resource Options
Typical unqation pivot supplied by a pump participating in the AEG provided additional potential Irrigation Peak Rewards demand response program.
study analysis to model additional
achievable potential that would occur if the cost-effectiveness benefit cost ratio requirements of a
Total Resource Cost (TRC) test were changed from the standard requirement of one or greater
Page 48 2015 IRP
Idaho Power Company 4. Demand-Side Resources
down to a value of 0.8. The revised assumptions in the model produced a non-cost-effective
potential of 16 aMW and 24 MW of peak reduction over the 20-year IRP planning horizon. The
20-year present value cost of the additional efficiency was determined to have a levelized cost of
9.1 cents per kWh, which is 3.4 cents higher than the 20-year levelized cost of the achievable
potential within the normal parameters ofTRC 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 portfolios. If Idaho Power were to pay increased incentive amounts to customers then there
would be added available capacity to expand the Irrigation Peak Rewards program in future
years. While the current demand response portfolio cost is $33/kW/Yr, this additional demand
response capacity would cost approximately $51/kW/Yr. This additional demand response
capacity is included in some portfolios beginning in the year 2021, and is included in the
preferred portfolio in 2030.
Energy Efficiency Working Group
On November 4, 2014, the ]PUC issued Orde No. 33161 (Case 1:-Jo. IPC-E-14-04) finding that
Idaho Power's 2013 DSM expenses were prudently incurred. On November 7, 2014. the IPUC
issued Errata to Order No. 33 161, stating that in relation to issues raised in the case:
The Commission agrees that the issues raised by Staff and other parties are
significant and warrant a ore ip-depth e iew. We direct the parties to do so in
the context of the Go,91pany's next Integrated Resource Plan filing.
In response to the Errata, Idaho Power organized an Energy Efficiency Working Group inviting
members of the IRPAC, public pa icipants in the IRP process, and the Energy Efficiency
Advisory Group (eEAG). The Energy Efficiency Working Group held two public meetings in
December 2014.
The first Energy Efficiency Working Croup meeting included a discussion of a broad range of
energy-efficiency and resource planning issues that can be classified into two general categories:
(I) strategies related to energy-efficiency program delivery and (2) treatment of energy
efficiency in the resource planning process. The second Energy Efficiency Working Group
meeting focused on how energy efficiency as a resource should be treated in the IRP. Topics
discussed at the second working group meeting included:
• A comparison presented by AEG of potential studies from other regional utilities
• A comparison presented by I PUC staff of Idaho Power's inclusion of energy efficiency in
the IRP to the inclusion of energy efficiency by other regional utilities
• An Idaho Power-led discussion of the inclusion of transmission and distribution
investment deferral into the benefits in DSM cost-effectiveness analysis.
2015 IRP Page 49
4. Demand-Side Resources Idaho Power Company
Through correspondence with working group participants, Idaho Power expressed the view that
its current treatment of energy efficiency in the resource planning process appropriately balances
the need for responsible and effective resource planning and the desire to pursue all cost­
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 transmission 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 update of this investigation at
the May 7, 2015 IRPAC meeting. In the May 7, 2015 IRPAC meeting, 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 transmission and distribution investments
related to growth, an evaluation of the effectiveness of energy efficiency measures and programs
in deferring transmission and distribution investment, and an estimate of def err vaJue for those
cases having potential for transmission and/or distribution investment deferment.
Idaho Power is also committed to continue to discuss the program delivery issues identified
by working group participants, and by Staff and some interveners in comments filed in
Case No. IPC-E-14-04. The Company plans to use the EEAQ s the forum to provide customers,
regulatory staff, and other interested stakeholders an opportunity to provide advice and
recommendations to Idaho Power in formulating, implementing, and evaluating energy
efficiency and demand response programs and activities.
Conservation Voltage Reduction
The goal of conservation voltage reduction (CVR) is to reduce electrical demand and energy by
minimizing the distrib tion feeder voltage while providing service voltage within the standard
operation range. Idaho Power participated in a northwest CVR pilot and implemented CVR on a
few distribution feeders. In the 2013 IRP, Idaho Power proposed to validate the energy savings
and reduced peak demand of CVR using new technologies and methods of measurement. Idaho
Power included the validation plan (Conservation Voltage Reduction Enhancements Project) in
its 2014 Smart Grid Report. The project scope is to:
• Validate the energy and demand savings associated with CVR at the customer level,
• Quantify the costs and benefits associated with implementing CVR,
• Determine methods for expanding the CVR program to additional feeders,
• Pilot methods for making Idaho Power's CVR program more dynamic, and
• Determine methods for ongoing measurement and validation of the CVR program's
effectiveness.
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 IRP
Idaho 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 of2015.
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 in 2016. Extending CVR measures to other Idaho Power facilities will then be
evaluated.
2015 IRP Page 51
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Idaho Power Company
Page 52 2015 IRP
Idaho Power Company 5. Supply-Side Generation and Storage Resources
5. SUPPLY-SIDE GENERATION AND STORAGE 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 Idaho Power developed the resource
portfolios for the 2015 IRP. Not all supply-side resources described in this section were included
in the preliminary resource portfolios, but every resource described was considered.
The primary source of cost information for the 2015 I RP is a report titled "Lazard's Levelized
Cost of Energy Analysis" 4• Other in formation sources were relied on or con idered on a case­
by-case basis depending on the credibility of the source and the age of the information. For a full
list of all the resources considered, and cost information, please see Figures 7. and 7.6 in
Chapter 7. All cost in formation presented is in 2015 dollars.
Renewable Resources
Renewable resources are the foundation of Idaho Power, and the company has a long history of
renewable resource development and operation. In the 2015 I P, renewable resources were
included in many of the portfolios analyzed as part of meeting the EPA's proposed CAA Section
111 (d) rule. Renewable resources are discussed in general terms in the following sections.
Solar
The primary types of solar technology are utility-scale photovoltaic (PV) and distributed PV. In
general, PV technology absorbs solar energy collected from sun light shining on panels of solar
cells, and a percentage of the solar energy is absorbed into the semiconductor material. The
energy accumulated inside the semiconductor material energizes the electrons and creates an
electric current. The solar cells have one or more electric fields that force electrons to flow in one
direction as a direct current (DC). The DC energy is passed through an inverter, converting it to
alternating current (AC) that can then be used on-site or sent to the grid. Even on cloudy days, a
PY system can still provide 15 percent of the system's rated output.
lnsolation is a measure of solar radiation reaching the earth's surface and is used to evaluate the
solar potential of an area. Typically, insolation is measured in kWh per m2 per day (daily
insolation average over a year). The higher the insolation number, the better the solar power
potential for an area. National Renewable Energy Laboratory (NREL) insolation charts show the
Desert 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 111 (d) rule,
4 http://www.lazard.com/PDF/Levelized%20Cost%20ol1>/o20Energy%20-%20Version%208.0.pdf
2015 IRP Page 53
5. Supply-Side Generation and Storage Resources Idaho Power Company
its flexibility. and its lower overall cost. Solar PV technology has existed for a number of years
but has historically been cost prohibitive. Recent improvements in technology and
manufacturing, 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 report, 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 for fixed panels
is $1 18 per M Wh based on a 21 .5 percent annual capacity factor and $109 per M Wh for PV with
a single-axis tracking system and a 26.8 percent annual capacity factor. In attempting to capture
the decreasing cost of solar, Idaho Power used the 2017 forecast provided by Lazard of$1,250
per kW for PY with a single-axis tracking system.
To account for the decreasing cost trend seen in PV resoure�ver the past few years, the
2015 !RP assumes solar PV costs remain fixed over the 10 year planning period. In comparison,
other resource costs are escalated at 2.2% over the same 20 years. Idaho Power will ontinue to
closely follow the decreasing price trend of solar PY a t is technology continues to become
more cost competitive with more traditional resource al e n tives.
Solar Capacity Credit
Idaho Power reviewed the solar capacity credit calculatibns due to comments received during the
2013 IRP Advisory Council meetings as well as comm�ts eceived after filing the 2013
Integrated Resource Plan. Idaho Power, intere teg_ m mbers of'the !RP Advisory Council, and
interested members of the public formed a study group separate from the IRP Advisory Council
to evaluate solar peak-hour capacity factors. The group formally met in September and October,
and Idaho Power had additional informal meetings and conversations with members of the study
group. Idaho Power updated the solar hotovoltaic peak-hour capacity factors based on guidance
from the members of the solar wo I< group.
Idaho Power simulated solar generation for water years 2011 through 2013 as part of the solar
integration study (data for the period October I, 20 IO through September 30, 2013). Idaho Power
used the simulated solar generation combined with actual load data from the same time period to
estimate the solar peak-hour capacity factors. In essence, the estimation used the system load
data to identify the highest 150 load hours, used the simulated solar generation data to estimate
the time-coincident simulated solar generation, and calculated a weighted average of the solar
peak-hour capacity factor where the frequency of the hour was used as the weight in the
weighted average calculation. The steps of the process arc:
I. Identify the 150 highest load hours from 2011 through 2013 (all are summer hours).
2. Determine the simulated solar generation during each of the 150 highest load hours (solar
generation simulation is from the Idaho Power solar integration study, solar generation
simulated 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 IRP
Idaho 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 from 2:00 pm to 3:00 pm during
the 150 highest load hours).
4. Estimate the 90th percentile exceedance for each clock hour represented in the 150
highest load hours (among the highest 150 load hours, during the clock hour starting at
xx:00, nine times out often, the solar generation was simulated to be at least xx percent
of the maximum possible delivered solar generation).
5. 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 systems and solar
tracking generation.
The solar capacity credit is expressed as a percentage f.installed AC nameplate capacity. The
solar capacity credit is used to determine the amoun Qf peak-hour capacity delivered to the
Idaho Power system from a solar PV plant considered as a new IRP resource option. The solar
capacity credit values used in the 2015 resource plan are reported in Table 5.1.
PV System Description
Geothermal
South Orientation
Southwest Orientation
Tracking
45.5 percent
51.3 percent
Solar capacity credit values Table 5.1
Potential commercial geo hermal generation in the Pacific Northwest includes both flashed
steam and binary-cycle technologies. Based on exploration to date in southern Idaho,
binary-cycle geothermal deve opment is more likely than flashed steam within Idaho Power's
service area. The flashed steam technology requires higher water temperatures. Most optimal
locations for potential geot ermal development are believed to be in the southeastern part of the
state; however, the potential for geothermal generation in southern Idaho remains somewhat
uncertain. The time required 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
fluid temperature is 300°Fahrenheit (F) or greater. Binary-cycle technology is used for lower­
temperature geothermal resources. In a binary-cycle geothermal plant, geothermal water is
pumped to the surface and passed through a heat exchanger where the geothermal energy is
transferred to a low boiling point fluid (the secondary fluid). The secondary fluid is vaporized
and used to drive a turbine/generator. After driving the generator, the secondary fluid is
2015 IRP Page 55
5. Supply-Side Generation and Storage Resources Idaho 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 geothermal reservoir through injection wells.
Cost estimates and operating parameters used for binary-cycle geothermal generation in the
2015 lRP are based on data from independent geothermal developers and cost information from
a power purchase agreement Idaho Power has with U.S. Geothermal, Inc. for the generation from
the Raft River Geothermal Project located in southern Idaho. The capital cost estimate used in
the 2015 IRP for geothermal resources is $4,021 per kW, and the 25-year levelized cost of
production is$ IO I per M Wh based on a 90 percent annual capacity factor.
Hydroelectric
Hydroelectric power is the foundation of Idaho Power's generation fleet. The existing generation
is low cost and does not emit potentially harmful pollutants. Idfho Power believes t�e
development of new large hydroelectric projects is unlikely: because few appropriate sites exist
and because of environmental and permitting issues associated with new, large facilities.
However, small hydroelectric sites have been extensive! developed in southern Idaho on
irrigation canals and other sites, many of which have PURPA. contracts with Idaho Power.
Small Hydroelectric
Because small hydroelectric such as run-of-river and projects requiring small or no
impoundments does not have the same level of environmental and permitting issues as large
hydroelectric projects, the IRPAC expressed an interest in evaluating small hydroelectric in the
2015 IRP. The potential for new, small hydroelectric projects was studied by the Idaho Strategic
Energy Alliance's Hydropower Task Force, and the results released in May 2009 indicate
between 150 MW to 800 MW of new hydroelectric resources could be developed in the state of
Idaho. These figures are based on potential upgrades to existing facilities, undeveloped existing
impoundments and water delivery. systems, and in-stream flow opportunities. The capital cost
estimate used in the IRP for small hydroelectric resources is $3,600 perk W and the 75-year
levelized cost fproduction is $l59 per MWh.
Shoshone Falls Expansion Project
In Augus 2006, Idaho Power tiled a license amendment application with FERC to expand the
Shoshone Falls'Hydroelectric Project (Shoshone Falls project) from 12.5 MW to 61.5 MW.
The project currently has three generator/turbine units with nameplate capacities of 11.5 MW,
0.6 MW, and 0.4 MW. The 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 20 IO the FERC issued a license amendment for 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 2022 to 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 in 2014, and is scheduled to be
Page 56 2015 IRP
Idaho Power Company 5. Supply-Side Generation and Storage Resources
completed in December 2015. Idaho Power continues to analyze costs and benefits of the
generator/turbine expansion segment of the project.
For the 2015 I RP, Idaho Power is considering the Shoshone Fal Is generator/turbine 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 75% 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 size from 1-3 MW each.
The majority of potential wind sites in southern Idaho lie bet een the south central and the most
southeastern part of the state. Areas that receive consistent, sustained winds greater than 15 miles
per hour are prime locations for wind development.
When compared to other renewable options, wind resources are well suited for the Pacific
Northwest and lntermountain regions, evidenced by the 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 resources requires estimates of the expected annual
energy and peak hour capacity. For the 2015 lRP, Jdaho Power used an annual average capacity
factor of28 percent and a capacity factor of 5 percent for peak hour planning. The capital cost
estimate used in the IRP for wind resources is $L,800 per kW and the 25-year levelized cost of
energy is $135 per MWh, which includes a wind integration cost of $15.39 per M Wh.
Biomass
Biomass resource types considered in the 2015 IR'P include wood burning resources and
anaerobic digesters. Wood burning resources typically rely on a steady supply of woody residue
collected from forested areas. Therefore, fuel supply can be an issue for these types of plants as
the radius of the area used to collect fuel is expanded. Several anaerobic digesters have been
built in southern Idaho due to the size of the dairy industry and the quantity of fuel available.
However, these digesters are limited in size and would be difficult to develop on a utility scale.
The capital cost estimate used in the IRP for a 35 MW wood burning biomass project is $2,622
per kW, and $4,761 per kW for a 3 MW anaerobic digester project. The wood burning unit is
expected to have an annual 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 level ized cost of
production is $ I 02 per M Wh for the wood burning unit and $1 19 per M Wh for the 25-year Ii fe.
Conventional Resources
While much attention has been paid to renewable resources over the past few years, conventional
generation resources continue to be needed as well to provide dispatchable capacity which is
critical in maintaining the reliability of an electrical system. These conventional generation
technologies include natural gas-fired resources, nuclear and coal.
2015 IRP Page 57
5. Supply-Side Generation and Storage Resources
Natural Gas-Fired Resources
Idaho Power Company
Natural gas-fired resources burn natural gas in a combustion turbine to generate electricity.
Combined-cycle combustion turbines (CCCT) are typically used for baseload energy. while less­
efficient single-cycle combustion turbines (SCCT) are used to generate electricity during peak
load periods. Additional details on the characteristics of both types of natural gas resources 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 2015 IRP assumes new natural gas resources would
require building additional pipeline capacity. This additional cost is accounted for in portfolios
containing new gas resources and not in the resource stack cost estimate for CCCTs or SCCTs.
Combined-Cycle Combustion Turbines
CCCT plants have been the preferred choice for new commercial power generation in the region.
CCCT technology carries a low initial capital cost compared to other'baseload resources,
has high thermal efficiencies, is highly reliable, offers significant operating flexibility, and emits
fewer emissions when compared to coal, thus requiring fewer pollution controls.
A traditional CCCT plant consists of a gas turbine/generator equipped with a heat recovery steam
generator (HRSG) to capture waste heat from the turbine exhaust. The HRSG uses waste heat
from the combustion turbine to drive a steam-turbine generator to produce additional electricity.
In a CCCT plant, heat that would otherwise be wasted is used to produce additional power
beyond that typically produced by an SCCT. New CCCT plants can be built or existing SCCT
plants can be converted to combined-cycle units by adding an HRSG.
Several CCCT plants, i eluding Idaho Power's Langley Gulch project, are planned in the region
due to recently declining na ral gas prices, the-need for baseload energy, and additional
operating reserves ne ded to integrate wind resources. While there is no current shortage of
natural gas, fueJ supply is a critica component of the long-term operation of a CCCT. The
capital cost estimate used in the IRP for a CCCT resource is $1, 145 per k W, and the 30-year
levelized ost of production at a 70-percent annual capacity factor is $79 per MWh.
Simple-Cycle Combustion Turbines
Simple-cycle, natural gas-turbine technology involves pressurizing air that then heats by burning
gas in fuel cornbustors. The hot, pressurized air expands through the blades of the turbine that
connects by a shaft to the electric generator. Designs range from larger, industrial machines at
80-200 MW to smaller machines derived from aircraft technology. SCCTs have a lower thermal
efficiency than CCCT resources and are not typically economical to operate other than to meet
peak-hour load requirements.
Several natural gas-fired SCCTs have been brought on I ine in the region in recent years.
primarily in response to the regional energy crisis of2000-200 I. High electricity prices
combined with persistent drought conditions during 2000-200 I. as well as continued
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Idaho Power Company 5. Supply-Side Generation and Storage Resources
summertime peak load growth created interest in generation resources with low capital costs and
relatively short construction lead times.
Idaho Power currently has approximately 430 MW of SCCT capacity. As peak summertime
electricity demand continues to grow within Idaho Power's service area, SCCT generating
resources remain a viable option to meet peak load during critical high-demand times when the
transmission system has reached full import capacity. The plants may also be dispatched for
financial reasons during times when regional energy prices arc at their highest.
The 2015 !RP evaluated two different CCT technologies. I) a 47-MW small, aeroderivative
unit and 2) a 170-MW industrial-frame unit. The capital cost estimate used in the IRP for the
small, aeroderivative unit is $1,000 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 IO percent.
Based on the annual capacity factor. the 35-year levelized cost of production is $250 per MWh
for the small, aeroderivative unit and $219 per MWh for the industrial-frame unit. These
levelized costs are close to the same as the higher efficiency of the small aeroderivative unit
offsets the slightly higher capital cost. Ir an CCT resource is identified 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 provided 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 baseframc,
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 configurations with multiple, identical units which allows each unit to run at
its best efficiency point once it is started. As more generation is needed, additional units are
started. This configuration also allows for relatively inexpensive future expansion of the plant
capacity.
For the IRP, Idaho Power modeled a reciprocating engine similar lo the 34SG model
manufactured by Wartsila with a nameplate rating of 18.8 MW. The capital cost estimate used
for a reciprocating engine resource is $500 per kW. and the 40-year levelized cost of production
at a IO percent annual capacity factor is $136 per M Wh.
Combined Heat and Power
Combined Heat and Power (CHP), or cogcncration, typically refers to simultaneous production
of both electricity and useful heat from a single plant. CHP plants are typically located at, or
near, commercial or industrial facilities capable of using the heat generated in the process. These
facilities are sometimes referred to as a steam host. Generation technologies frequently used in
CHP projects are gas turbines or engines with a heat-recovery unit.
The main advantage of CHP is that higher overall efficiencies 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 CHP resources are typically located near load centers, building
2015 IRP Page 59
5. Supply-Side Generation and Storage Resources Idaho Power Company
additional transmission capacity can also often be avoided. In addition, reduced costs for the
steam host provide a competitive advantage that will ultimately help the local economy.
In the evaluation of CI IP resources, it became evident that CHP could be a relatively high-cost
addition to Idaho Power's resource portfolio if the steam host's need for steam forced the
electrical portion of the project to run at times when electricity market prices were below the
dispatch cost of the plant. To find ways to make CHP more economical. Idaho Power is
committed to working 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"
production process. This would be difficult to model for the IRP because each potential CHP
opportunity could be substantially different.
Recognizing the actual cost of a CHP resource may vary depending on the specific facility being
considered, the capital cost estimate used in the IRP for CHP is $2, 123 per kW, and the 40-year
levelized cost of production evaluated at an annual capacit factor 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 to evaluate variou technologies in the IRP. Due to
the Idaho National Laboratory (INL) site in eastern Idaho the IRP Ras typically assumed that an
advanced-design or small modular reactor could be built on the site. For the 2015 IRP. high
capital costs coupled with a great amount of uncertainty in waste disposal issues prevented a
nuclear resource from being included in the portfolio analysis. In addition, the recent earthquake
and tsunami in Japan, and the impact on the Fukushima nuclear plant, created a global concern
over the safety of nuclear power generation. While tQere have been new design and safety
measures implemented. it is difficult to know the nyl impact this disaster will have on the future
of nuclear power generation.
For the 2015 IRP, an 1.100 MW advanced nuclear resource and a 600 MW small modular plant
were analyzed; however. 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 estimate used in the IRP for an advanced nuclear resource is $4,350 per kW, and the 40-year
level ized cost of production. evaluated at an annual capacity factor of 90 percent. is $1 19 per
MWh. For the small modular reactor technology, the capital cost estimate is $5,000 per kW, and
the 40-year levelized cost of production, evaluated at an annual capacity factor of 95 percent. is
$343 per M Wh.
Coal Resources
Conventional coal resources have been a part of Idaho Power's generation portfolio since the
early 1970s. Growing concerns over global warming and climate 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 evaluated in the IRP.
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Idaho Power Company 5. Supply-Side Generation and Storage Resources
IGCC is an evolving coal-based technology designed to substantially reduce C02 emissions. As
the regulation of C02 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 C02 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 a synthetic gas or
"syngas" that can be processed and cleaned to a point that it meets pipeline quality standards. To
produce electricity, the syngas is burned in a conventional combustion turbine that drives a
generator.
The addition of C02-capture equipment decreases the overall efficiency of an IGCC plant by as
much as 15 percent. In addition, once the carbon is captured, it must either be used or stored for
long periods of time. C02 has been injected into existing oil fields to enhance oil recovery;
however, if IGCC technology were widely adopted by utilities for power production, the
quantities of C02 produced would require the development of underground sequestration
methods.
Carbon sequestration involves taking captured C02 and storing i away from the atmosphere by
compressing and pumping it into underground geologic formations. If compression and pumping
costs are charged to the plant, the overall efficiency of the plant is reduced by an additional 15 to
20 percent. Sequestration methods are currently being developed and tested; however,
commercialization of the technology i� not expec ed to happen for some time. The capital cost
estimate used in the IRP for I CC is $3 257 per kW, and the 35-year levelized cost of
production, evaluated at an nnual capacity factor of 85 percent, is $116 per M Wh. The capital
cost estimate used for JG C with carbon sequestration is $6,390 per kW, and the 35-year
levelized cost of production, evaluated at an annual capacity factor of75 percent, is $184 per
MWh.
Storage Technologies
Renewable portfolio standard have spurred the development of renewable resources in the
Pacific Northwest to the point where there is an oversupply of energy. Recently, Mid-C
wholesale market prices for elecrricity are typically one-third to one-ha If lower than just a few
years ago. At the same ti ie, retail rates for electricity continue to grow as utilities have to pass
the cost of building these 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 amp Ii fied. While there are many storage technologies at
various stages of development such as hydrogen storage, compressed air, and flywheels, the
2015 I RP considered and evaluated three speci fie storage technologies: battery storage, ice-based
thermal energy storage, and pumped storage.
2015 IRP Page 61
5. Supply-Side Generation and Storage Resources Idaho Power Company
Battery Storage
Electric Loed CJ
Advantages of the VRB technology
include low cost, long life, and being
easily scalable to utility/grid
applications. Most battery technologies 5 are not a good tit for utility scale Basic illustratio of a flow bat..!_ery.
applications because they cannot be easily or economically scaled to much larger sizes. The
VRB overcomes much of this issue because the capacity of the battery can be increased just by
increasing the size of the tanks that contain the electrolytes, which also helps to keep the cost
relatively low.
Just as there are many types of storage
technologies being researched and
developed, there are numerous types of
battery storage technologies at various
stages of development. The 2015 I RP
focused on one speci fie type of battery
technology, the vanadium redox-flow
battery (VRB). Figure XX is a diagram
showing how the battery functions.
VRB technology also has an advantage in maintenance and replacement costs, as only certain
components need replaced about every IO years, whereas other battery technologies require a
complete replacement of the battery and more frequently depending on how they are used. For
the IRP, the capital cost estimate for the VRB is $3 000 per kW, and the I 0-year levelized cost of
production, evaluated at an annual capacity factor of25 percent, is $240 per MWh.
5 http://strategy.sauder.ubc.ca/antweiler/blog.php?item=2014-09-28.
Page 62 2015 IRP
Idaho Power Company 5. Supply-Side Generation and Storage Resources
Ice-based Thermal Energy Storage
Ice-based thermal energy storage is a
concept developed to take advantage of
the air conditioning needs for mid-sized
to large commercial buildings. The
general concept is to create ice during
low load/low price times (light load
hours) and then to use the ice for air
conditioning needs during the high
load/higher price times (heavy load ii
hours). While this concept does not l
specifically store electricity, it does
shift the time the energy is consumed
with the overall goal of reducing peak it.t�MoNi-s>"'"" il.lna«-ontl'\lrrt) ,.,...._(<>,I
daytime demand. Illustration of an ice-based th,rmal energy storage system.6
One company currently commercializing the ice-based tliermal energy storage technology is Ice
Energy with their Jee Bear Energy Storage System. Requi ements in California to develop energy
storage have allowed several utilities to begin to install and'test-this technology with several of
the installations being 5 MW to 15 MW in size. For the IRP, the capital cost estimate used for
this technology is$ I ,500 per kW, and the 20- ear levelized cost of production, evaluated at an
annual capacity factor of I 0.4 percent, is $224 per MWh.
Pumped Storage
Pumped storage is a type of
hydroelectric power generation used to --- change the "shape" or timing when
electricity is produced The technology
stores energy in the form of water,
pumped from a lower elevation
reservoir to a higher elevation Lower­
cost, off-peak electricity is used to
pump water from 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.
Pumped-storage facility. 7
6 http://www.ice-energy.com/technology/ice-bear-energy-storage-system.
7 http://www.rcnewableenergyworld.com/rea/news/an icle/20 I 0/ I Ozworldwide-puruped-stcrage-act i vity.
2015 IRP Page 63
5. Supply-Side Generation and Storage Resources Idaho 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 sufficient 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 M Wh.
Page 64 2015 IRP
Idaho Power Company
6. TRANSMISSION PLANNING
Past and Present Transmission
6. Transmission Planning
High-voltage transmission lines are vital to
the development of energy resources to serve
Idaho Power customers. Transmission lines
have facilitated the development of southern
Idaho's network of hydroelectric projects that
serve the electric customers of southern Idaho
and eastern Oregon. Regional transmission
lines that stretch from the Pacific Northwest
to the Hells Canyon Complex (HCC) and on
to the Treasure Valley were central to the
development of the HCC projects in the
1950s and 1960s. In the 1970s and 1980s,
transmission lines were instrumental in the
development of partnerships in the three
coal-fired power plants located in neighboring
states that supply approximately one-third of the energy consum d by Idaho Power customers.
Finally, transmission lines allow Idaho Power to economically balance the variability of its
hydroelectric and intermittent resources with access to wholesale e ergy markets.
Idaho Power's regional transmission interconnections improve reliability by providing the
flexibility to move electricity between utilities and also provide economic benefits based on the
ability to share operating reserves. Historically, Idaho Power has been a summer peaking utility,
while most other utilities in the Pacific Northwest experience system peak loads during the
winter. Because of the difference in peak seasons, daho Power purchases energy from the
Mid-Columbia energy trading market to meet peak summer load, and Idaho Power sells excess
energy to Pacific Northwest utilities during the winter and spring. New regional transmission
connections to the Pacific Northwest will benefit the environment and Idaho Power customers
through the-fol lowing:
• The construction of additional peaking resources to serve summer peak load is delayed
or avoided.
• Revenue from off-system 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.
Idaho Power's double-circuit 230-kV transmission line
traversing t!_ells Canyon.
2015 IRP Page 65
6. Transmission Planning Idaho Power Company
• The ability to more efficiently implement advanced market tools such as energy
imbalance markets (EIM) or security constrained economic dispatch ( CED).
Transmission Planning Process
In recent year . FERC has mandated several aspects of the transmission planning process.
FERC Order No. I 000 requires Idaho Power lo participate in transmission planning on a local.
regional, and interregional basis, as described in Attachment K of the Idaho Power Open-Access
Transmission Tari ff (OA'n') and summarized in the following sections.
Local Transmission Planning Process
The expansion planning of Idaho Power's transmission network occurs through a local-area
transmission advisory process and the biennial local transmission planning process.
Local-Area Transmission Advisory Process
Idaho Power develops long-term, local-area transmissio plans with community advisory
committees. The community advisory committees consist of jurisdictional planners; mayors;
council members; commissioners; and large industry, commercial, residential, and environmental
representatives. The plans identify the transmission and substation infrastructure required for the
full development of the area. The plans account for land-use limits and other resources of the
local area. The plans identify the approximate year a project will be placed in service. Local-area
plans have been created for the fol lowing five load cent rs in southern Idaho:
I. Eastern Idaho
2. Magic Valley
3. Wood River Valley
4. Treasure Valley
5. West Central Mountains
Recently, the Treasure Valley Electric Plan was divided into two plans:
I. Western Treasure Valley Electrical Plan-The western plan was completed in 2011 and
encompasses Malheur County in Oregon and Canyon, Gem, Owyhee. Payette and
Washington counties in Idaho.
2. Eastern Treasure Valley Electric Plan-The eastern plan was completed in 2012 and
encompasses all or portions of Ada. Elmore, and Owyhee counties in Idaho.
Biennial Local Transmission Planning Process
The biennial local transmission plan (L TP) identifies the transmission required to interconnect
the load centers. integrate planned generation resources, and incorporate regional transmission
plans. The L TP is a 20-year plan that incorporates the planned supply-side resources identified in
Page 66 2015 IRP
Idaho 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 [BPAJ
customers in eastern Oregon and southern Idaho), Idaho Power's retail customer load,
and third-party transmission customer requirements. By identifying potential resources,
potential resource locations, and load-center growth, the required transmission system capacity
expansions are identified to safely and reliably provide service to customers. The L TP is shared
with the regional transmission planning process.
Regional Transmission Planning
Idaho Power is active in regional transmission planning through the No11J1ern Tier Transmission
Group (NTTG). The NTTG was formed in early 2007 with the overall goal of improving the
operation and expansion of the high-voltage transmission system that delivers power to
consumers in seven western states. In addition to Idaho Power, other members include Deseret
Power Electric Cooperative, No11h Western Energy, Portland General Electric, PacifiCorp
(Rocky Mountain Power and Pacific Power), and the Utah Associated Municipal Po er Systems
(UAMPS). The NTTG relies on a biennial process to develop a regional transmission plan. In
preparing the regional transmission plan, the NTTG uses a public stakeholder process to evaluate
transmission needs resulting from members' load forecasts, LTPs, I RPs, generation
interconnection queues, other proposed resource development, and forecast uses or the
transmission system by wholesale transmission customers.
Interconnection-Wide Transmission Planning
The Western Electricity Coordinating Council's (WECC) Transmission Expansion Planning
Policy Committee (TEPPC) serves as the interconnection-wide transmission planning facilitator
in the western US. Specifically, the TEPPC has three distinct functions:
I. Oversee data management for the western interconnection.
2. Provide policy and management of the planning process.
3. Guide the analyses and modeling for Western Interconnection economic transmission
expansion planning.
In addition to oviding the means to model the transmission implications of various load and
resource scenarios at an interconnection-wide level, the TEPPC coordinates planning between
transmission owners, transmission 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 IRP Page 67
6. Transmission Planning Idaho Power Company
Existing Transmission System
Idaho Power's transmission system traverses from eastern Oregon through southern Idaho to
western Wyoming and is composed of 115-, 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 .
.. ,,.-"'" .. '
�DAHO "FAU..S Gosl'len
I I .. : l I . MtelOl)e;
IP" t
� <, ' AaeraNle l'MN FAU.SJ. ... ,,
; ,:,., ... 0 125 25
.... • ..... PN;'lflC PQMR ,,, �· -, POf:fR @!!UN \ .. HITT1taie
I
legend
C> SUIOl"I ldetlo Pa.« Ut"le$
Plllla -1611'V
- -W.,i -2»V BIOwice Ea:i .... )t$1rV __ ._ _,:,oi.v
--- °"*Litltyl.NS Midpci"t \'Ve-,a .... 23():V __ .. _ •• J<5"V
P,lhC ••• !l)Ot'V
Figure 6.1 Idaho Power transmission system map
The transmission paths identified on the map are described in the following sections, along with
the conditions that result in capacity limitations.
Idaho-Northwest Path
The Idaho-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 Northwest, and the
115-kV interconnection at Harney Substation near Burns, Oregon. The Idaho-Northwest path is
capacity-limited during summer months due to transmission-wheeling obligations for the BPA
eastern Oregon and southern Idaho load and due to energy imports from the Paci fie Northwest to
Page 68 2015 IRP
Idaho Power Company 6. Transmission Planning
serve Idaho Power retail load. If new resources. including market purchases. are located west of
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 Idaho-Northwest Interconnection
shown in Figure 6.1. Brownlee East is comprised of the 230-kV and 138-kV lines cast of the
Hells Canyon Complex and Quartz Substation near Baker City. Oregon. When the Hemingway-
ummer 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 Idaho load and
Idaho Power energy imports from the Pacific Northwest. Capacity limitations on the
Brownlee East path limit the amount of energy Idaho Power can import from the I lells Canyon
Complex as well as off-system purchases from the Pacific Northwest. If new resources,
including market purchases, are located west of the path, additional transmission capacity will be
required to deliver the energy to the Treasure Valley load center.
Idaho-Montana Path
The Idaho-Montana transmission path consists of the Antelope-Anaconda 230-kV and Goshen­
Dillon 161-kV transmission lines. The Idaho-Montana path is also capacity-limited during the
summer months as Idaho Power, BPA, PacifrCorp, and others move energy south from Montana
into Idaho.
Borah West Path
The Borah West transmission 'path is internal to the Idaho Power system. The path is comprised
of345-kV, 230-kV, and 138-kV transmission lines west of the Borah substation located near
American.Falls, Idaho. Idaho Power's one-third share of energy from the Jim Bridger plant flows
over this path, as well as east-side hydroelectric energy and energy imports from Montana.
Wyoming, and Utah. PacifrCorps two-thirds share of energy from the Jim Bridger plant also
nows across this path to load centers in the Pacific Northwest. The Borah West path is
capacity-limited during summer months due to transmission-wheeling obligations coinciding
with high eastern thermal 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 thermal 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 transmission
lines west of Midpoint Substation located near Jerome. Idaho. The Midpoint West path is
2015 IRP Page 69
6. Transmission Planning Idaho Power Company
capacity-limited due to east-side Idaho Power resources. PURP/\ resources, and energy imports.
Similar to the Borah West path, the heaviest path nows arc likely to exist during the fall
and winter when significant wind and thermal generation is present east or the path.
Additional transmission capacity will likely be required if new resources or market
purchases are located east of the Midpoint West path.
kieno-Nevede Path
The Idaho-Nevada transmission path is comprised of the 345-kV Midpoint-Humboldt 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 I 00 percent
of the northbound capacity, while NV Energy is allocated I 00 percent of the southbound
capacity. The available import, or northbound, capacity on the transmission path is fully
subscribed with Idaho Power's share of the No11h Val my generation plant.
ldah�Wyoming Path
The Idaho-Wyoming path, referred to as Bridger West, is comprised of three 345-kV
transmission lines between the Jim Bridger generation plant and southeastern Idaho.
Idaho Power owns 774 MW of the 2,400-MW east-to-west capacity. PacifiCorp owns the
remaining capacity. The Bridger West path effectively feeds into the Borah West path when
power is moving east to west from Jim Bridger; consequently, the import capability of the
Bridger West path is limited by Borah West path capacity constraints.
kieno-Uten Path
The Idaho-Utah path, referred to as ath C, is comprised of345-, 230-, 161-, and 138-kV
transmission lines between.southeastern Idaho and northern Utah. PacifiCorp is the path
owner and operator of all of the transmission lines. The path effectively feeds into Idaho Power's
Borah West path when power is moving from east to west; consequently, the import capability of
Path C is limited by Borah West path capacity limitations.
Table 6.1 Available transmission import capacity
Transmission Path Import Direction Capacity (MW) ATC (MW) ..
1,200 0
262 0
383 0
1,915 0
1,027 0
2,557 0
2,400 60
1,250 o-:
Total Transmission Capacity'
Idaho-Northwest... West to East
Idaho-Nevada.............................................. South to North
Idaho-Montana................ North to South
Brownlee East.............................................. West to East
Midpoint West.............................................. East to West
Borah West.................................................. East to West
Idaho-Wyoming (Bridger West) East to West
Idaho-Utah (Path C) .. . South to North
'Total transmission capacity and ATC as of April 1. 2015
Page 70 2015 IRP
Idaho Power Company 6. Transmission Planning
"The ATC of a specific path may change based on changes in the transmission service and generation interconnection request queue (i.e., the end or a transmission service. granting of transmission service. or cancelation of generation projects that have
granted future transmission capacity)
···1daho Power estimated value. actual ATC managed by PacifiCorp.
Boardman to Hemingway
Idaho Power's IRP process has identified a transmission line to the Pacific Northwest electric
market dating back to 2006. At that time, a line interconnecting at the McNary Substation to
the greater Boise area was included in I RP portfolios. Since its initial identification, 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 identified in 2006 has evolved
into what is currently the Boardman to Hemingway project. The project involves permitting,
constructing, operating, and maintaining a new. single-circuit 500-kY transmission line
approximately 300 miles long between northeast Oregon and southwest Idaho. The new line will
provide many benefits, including the following:
• Greater access to the Paci fie Northwest electric market to serve homes, farms,
and businesses in Idaho Power's service area
• Improved system reliability and reduced capacity limitations on the regional transmission
system as demands on the system continue to grow
• Assurance or Idaho Power's ability to meet customers' existing and future energy needs
in Idaho and Oregon
• Flexibility to integrate renewable resources, respond to pending carbon legislation and
more efficiently implement advanced market tools
The Boardman to Hemingway project was identified as part of the preferred resource portfolio in
Idaho Powers 2009, 2011 and 2013 IRP·s.
In January 2012. Idaho Power entered into a joint funding agreement with PacifiCorp and BPA
to pursue permitting of the project. The agreement designates Idaho Power as the permitting
project manager for the Boardman to I lemingway project. Table 6.2 shows each party's
Boardman to Hemingway capacity and permitting cost allocation.
Table 6.2 Boardman to Hemingway capacity and permitting cost allocation
Idaho Power BPA PacifiCorp
Capacity (MW) west to east .............. 350 400 300
200 winter/500 summer 550 winter/250 summer
Capacity (MW) east to west ............... 85 97 818
Permitting cost allocation .................. 21% 24% 55%
Additionally, a Memorandum of Understanding (MOU) was executed between Idaho Power,
BPA, and PacifiCorp to explore opportunities for BPA to establish eastern Idaho load service
2015 IRP Page 71
6. Transmission Planning Idaho Power Company
from the Hemingway Substation. BPA identified six solutions-including two Boardman to
Hemingway options-to meet its load-service obligations in southeast Idaho. On October 2,
2012. BPA publically announced the preferred solution to be the Boardman to
Hemingway project.
The permitting phase of the 821-1 project is subject to review and approval by the BLM, the U.S
Forest Service, and the Oregon Department of Energy. The federal permitting 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
Hemingway project. On December 19, 2014, BLM published the Draft Environmental Impact
Statement (Draft EIS). Figure 6.2 shows the proposed transmission line routes included in the
Draft EIS with the agency preferred route. Jdaho Power expects the BLM to issue a Final EJS in
2016.
In late February 2013, Idaho Power submitted the preliminary Application for Site Certificate
(pASC) to the Oregon Department of Energy (ODOE) a art of the state siting process. Idaho
Power intends to submit an Amended pASC in late 20 or 2016.
In light of the permitting delays and siting impediments that have occurred and may occur,
Idaho Power is unable to accurately determine an approximate in-service date for the line,
but expects the in-service date would be in 2 21 or beyond.
Additional project information is available at t\ttp://www.boardmantohemingway.com.
Page 72 2015 IRP
Idaho Power Company 6. Transmission Planning
N,-�i, ,t,�M.-fl� '-" ... WttllfltlrlM_ .. .._ ..,.....,.. •• ,,..... °""*. ........ ...., ....... NIIWYot ..... lNlllilllieillHtlc.t ....
20 0 9 Milos --- 0 5 10
-s. ... eo.-,.,
- c-,ry Dounclory eu,.-v or Land ,...,.,�"1
8u,Mu of Ft.clln .. tion
Dop.lrtrnon.t ol Ooto�
fflOICCt ffAIYft!I ..... ....,,.s ... - & P,opoMO SvbMMiOn
£t.,.n,tw,g3ubt.t.l ...... 1
Proposed Action
and Alternatives
Boudman lo Hemingway
5004tV Tr1naml11lon Uno Projtct
Orego�1ho
pecemoer 2014
Figure 6.2 Boardman to Hemingway routes with Agency Preferred Alternative
Gateway West
The Gateway 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
permitting project manager for Gateway West, with Idaho 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 preferred route. Idaho Power has a one-third interest in the
2015 IRP Page 73
6. Transmission Planning Idaho Power Company
segments between Midpoint and I lemingway, Cedar I lill and I lemingway, and Cedar I lill and
Mid point. Further, Idaho Power has sole interest in the segment between Borah and Midpoint
(segment 6), which is an existing transmission line operated at 345-kV, but constructed at
500-kV.
......... t ..... , ... ,. -.-. .. ..--.:,w=:=-- -=--=-,.,,,,.., ..
Figure 6.3
-�=-- -- ..... . . . �
.r-
Gateway West Map
The Gateway West project will provide many benefits to Idaho Power customers, including the
following:
I. Relieving Idaho Power's constrained transmission system between the Magic Valley area
(Midpoint) and the Treasure Valley area (Hemingway). Transmission connecting the
Magic Valley and Treasure Valley is part of Idaho Power's "core" transmission system,
connecting two major Idaho Power load pockets.
2. Provide the option to locate future generation resources east of the Treasure Valley.
3. Provide future load service capacity to the Magic Valley from the Cedar Hill Substation.
4. Transmission capability is needed to meet the transmission needs of the future, including
transmission needs associated with intermittent resources.
Phase I of Gateway West is expected to provide up to 1,500 MW of additional transfer capacity
between Midpoint and Hemingway. The fully completed project would provide a total of3,000
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
Page 74 2015 IRP
Idaho 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 l-lill to Hemingway). The BLM is
currently 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 information about the Gateway West project can be found at
http://www.gatewaywestproject.com.
Gateway West Need Analysis
Idaho Power has two internal transmission paths between the Magic Valley and Treasure Valley:
• Boise East
• Midpoint West
The Boise East transmission path consists of230 kv, 138 kV and 69 kV transmission lines
connecting the Mountain Home area to the Boise/Nampa/Caldwell area. This transmission path
is currently under study due to large amounts of solar generation proposed to be sited in and
around the Mountain Home area. Gateway West will increase the capability of the Boise East
path.
The Midpoint West transmission path consists of230 kV and 138 kV transmission lines
connecting the Magic Valley area to the Mountain Home area. The Midpoint West transmission
path has a rating of 1,027 MW which will increase to 1,710 MW following two initiatives
currently under way:
I. Idaho Power will expand the Midpoint West rating from 1,027 MW to 1,300 MW
through incremental upgrades to existing transmission assets (230 kV and below). These
upgrades are expected to be in service by the end of 2015.
2. Idaho Power has made arrangements to acquire an ownership share of the PacifiCorp­
owned Midpoint-1 lemingway 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 of2015.
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 IRP Page 75
6. Transmission Planning Idaho Power Company
1800
1600
1400
1200
1000
800
600
400
200
0
2009 2010 2011 2012 2013 2014 2015 2016
--Midpoint West Rating -Midpoint West Utilization
1. Large increases to the use of Midpoint West occurred In 2010 (PURPA Wind). 201'1 (PURPA Wind), and 2015 (third party
transmission service). Use Is also projected to Increase in 2016 with the interconnect'ion of 100 MW of solar in eastern Idaho.
Figure 6.4 Midpoint West Historical Utilization
The Midpoint West path will continue to be constrained following the upgrades described above.
As the Boise East and Midpoi t est paths become further utilized, Idaho Power will continue
to invest in new transmission facilities to reinforce the transmission system. Gateway West is the
planned upgrade that will increase the capability of the Midpoint West path.
Transmission Assumptions in the IRP Portfolios
akes resource location
assumptio to determine the
transmi si n requirements s part of
the IRP de elopment process.
Regardless of the location, supply-side
resources included in the resource stack
typically require local transmission
improvements for int 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 requirements for
incremental resources are summarized
in Table 6.3.
Page 76
The Hemingway Substation in southern Idaho is a major hub for
power running through Idaho Power's transmission system.
2015 IRP
Idaho Power Company 6. Transmission Planning
Table 6.3 Transmission assumptions
Resource Type
Resource Levels
(incremental
Geographic Area amounts) Additional Transmission Requirements
Boardman to
Hemingway Line
Gas turbine
(SCCT)
Gas Turbine
(CCCT)
Combined heat
and power (CHP)
Geothermal
Reciprocating
Engines
Photovoltaic (PV)
Pumped Storage
Hydro
Hemingway Substation 500 MW (summer)/
200 MW (winter)
Elmore County 170 MW
Elmore County 300MW
Canyon County 45MW
Cassia County 30MW
Distributed 18MW
Elmore/Owyhee 10MW
County
Above Brownlee 300MW
Reservoir
New 230-kV line from Hemingway into the
Treasure Valley.
New 230kV substation and new 230kV line
into the Treasure Valley.
New 230kV substation and new 230kV line
into the Treasure Valley.
New 138kV substation and new 138kV line to
existing 138kV system.
New 138kV line from resource to existing
138kV substation.
No new transmission. New distribution
upgrades assumed for each engine location.
New 138kV substation and new 138kV line to
existing 138-kV system.
New-230-kV line from Oxbow to Treasure
Valley, oew 138-kV tap from site to existing
138-kV s stem.
The assumptions about the geographic area where particular supply-side resources are developed
determine the transmission upgrades required.
2015 IRP Page 77
6. Transmission Planning Idaho Power Company
Page 78 2015 IRP
Idaho Power Company 7. Planning Period Forecasts
7. PLANNING PERIOD FORECASTS
The IRP process requires Idaho Power
to prepare numerous forecasts and
estimates that can be grouped into four
main categories:
I . Load forecasts
2. Generation forecast for
existing resources
3. Natural gas price forecast
4. Resource cost estimates
Forecasting load growth is essential for Idaho Power to meet
future needs of customers. The load and generation forecasts­
including supply-side resources, DSM.
and transmission import capability-are used to estimate surplus and deficit positions in the load
and resource balance. The identified deficits are used to develop resource portfolios evaluated
using financial tools and forecasts. The following sections provide details on the forecasts
prepared as part of the 2015 IRP.
Load Forecast
Historically, Idaho Power has been a summer peaking utility with peak loads driven by irrigation
pumps and air conditioning NC) in the months of June, July, and August. For a number of
years, the growth rate of the summertime peak-hour load has exceeded the growth of the average
monthly load. However, bot 1 measures are important in planning future resources and are part of
the load forecast prepared for the 2015 I RP.
The expected-case (median) load forecasts for peak-hour and average energy represent
Idaho Bo er's most probable outcome for load growth during the planning period.
However, t e actual path of-future retail electricity sales will not precisely follow the path
suggested by the expected case forecast. Therefore, Idaho Power prepared two additional load
forecasts that address the load variability associated with abnormal weather. The 701h-percentile
and 90111-percentile load 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 Idaho Power's service area using an in­
house economic database. Specific demographic projections are also developed for the service
area from national and local census data. National economic drivers from Moody's Analytics are
2015 IRP Page 79
7. Planning Period Forecasts Idaho Power Company
also used in developing the 2015 I RP load forecast. The forecasts of households, population,
employment, 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 temperatures and median precipitation,
which means there is a SO-percent chance loads will be higher or lower than the expected-case
load forecast due to colder-than-median or hotter-than-median temperatures 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 forecasts for
70111-percentile and 90111-percentile weather. Seventieth percentile weather means that in 7 out
of IO years, load is expected to be less than forecast, and in 3 out of IO years, load is expected
to exceed the forecast. Ninetieth percentile load has a similar definition with a I-in-IO likelihood
the load wi 11 be greater than the forecast.
Weather conditions are the primary factor affecting the load forecast on a monthly or seasonal
time horizon. Over the longer-term horizon, economic, demographic conditions, and changing
technologies in fluence the load forecast.
Economic Effects
The national recession that began in 2008 affected the local economy and energy use in the
Idaho Power service area. The severity of the recession resulted in a decline in new customer
growth. Idaho Power added less than 2,500 new residential customers in 20 I I. Recently,
the number of new residential customers added each year has increased to over 6,500.
Likewise, overall system sales declined by 3.8 percent in 2009, followed by a 0.9-percent decline
in 20 IO and a slight decline in 2011. The 2009 through 20 I I time period was the first time
overall energy use had declined since the energy crisis of2000 to 200 I. In 2012, 2013, and 2014
system electricity sales increased by 1.7 percent, 0.5 percent, and 1.0 percent, respectively. The
sales increases were due to economic recovery in the service area and higher irrigation sales.
The population in Idaho Power's service area, due to migration to Idaho from other states,
is expected to increase throughout the planning period, and the population increase is included
in the load forecast models. 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 may
encourage some manufacturers to consider moving operations to Idaho.
The number of households in Idaho is projected to grow at an annual average rate of 1.2 percent
during the 20-year forecast period. Growth in the number of households within individual
counties in Idaho Power's service area differs from statewide household growth patterns.
Service-area household projections are derived from applying Idaho Power's share to
county-speci fie household forecasts. Growth 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 IRP
Idaho 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 1.6 percent annually from 428.000 at the end
of2014 to nearly 591,000 by the end of the planning period in 2034.
The expected-case load forecast represents the most probable projection of load growth during
the planning period. The forecast for system load growth is determined by summing the load
forecasts for individual classes of service, as described in Appendix A Soles and Load Forecast.
For example, the expected annual average system load growth of 1.2 percent (over the period
2015 through 2034) is comprised of a residential load growth of 1.3 percent, a commercial load
growth of 1.0 percent, an irrigation load growth of 0.5 percent, an industrial load growth of
2.0 percent, and an additional firm load growth of0.6 percent.
The 2015 IRP average annual system load forecast reflects the continued improvement in the
service area economy. While economic conditions during the development of the 2013 IRP were
positive, they were less optimistic than the actual performance experienced in the interim period
leading up to the 2015 IRP. The improved economic and demographic 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 extent, service area economy caused load growth
to stall through 2011. However, in 2012, the recovery was evident, with strength exhibited in
most all economic time series. Retail electricity price projections for the 2015 I RP are lower
relative to the 2013 I RP, serving to increase the-forecast of average loads, especially in the
second IO years of the forecast period.
Significant factors and considerations that influenced the outcome of the 2015 I RP load forecast
include the fol lowing:
• The load forecast used for the 2015 I RP reflects a near-term recovery in the service-area
economy followin{ a severe recession in 2008 and 2009 that kept sales from growing
through 2011. The collapse in the housing sector in 2008 and 2009 dramatically slowed
the growth of new households and, consequently, the number of residential customers
being added to Idaho Power's service area. However, since 2011, residential and
commercial customer growth along with housing and industrial activity. have shown
signs of a meaningful and sustainable recovery. By 2017, customer additions are forecast
to apl'roach the growth that occurred prior to the housing bubble (2000-2004).
• The electricity price forecast used to prepare the sales and load forecast in the 2015 I RP
reflects the additional plant investment and variable costs of integrating the resources
identified in the 2013 IRP preferred portfolio. including the expected costs of carbon
emissions assumed for the 2013 I RP. When compared to the electricity price forecast
used to prepare the 2013 IRP sales and load forecast, the 2015 I RP price forecast yields
lower future prices. The retail prices are most evident in the second IO years of the
planning period and impact the sales forecast positively. a consequence of the inverse
relationship between electricity prices and electricity demand.
• 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.
2015 IRP Page 81
7. Planning Period Forecasts Idaho Power Company
\
typically with an unknown magnitude of the energy and peak-demand requirements.
The current sales and load forecast reflects only those commercial or industrial customers
that have made a sufficient and significant investment indicating a commitment of the
highest probability of locating in the service area. Therefore, the large numbers of
businesses that have contacted Idaho Power and hown interest but have not made
sufficient commitments are not included in the current sales and load forecast.
• Conservation impacts, including DSM energy efficiency programs and codes and
standards, are considered and integrated into the sales forecast. Impacts of demand
response programs ( on peak) are accounted for 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 forecast is higher than the 2013 I RP forecast throughout the
entire forecast period, due to the significant growth in the dairy industry, higlier
commodity prices and changing crop planting patterns. Following the dairy industry
growth, there has been a trend towards more water-intensive crops, primarily alfalfa and
corn. Farmers have also taken advantage of the commodities market by planting
increasing levels of acreage. Additionally, the conversion of flood/furrow irrigation to
sprinkler irrigation, primarily related to farmers trying to reduce labor costs, explains
most of the increased energy consumption in recent years.
• Updated loss factors were determined by Idaho Power's Customer Operations Planning
department. The annual average energy loss coefficients are mu ltiplied by the calendar­
month load, yielding the system load, including losses. A system loss study of the year
2012 was completed in May 2014. 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 aMW to the load forecast, annually.
Peak-Hour Load Forecast
The system peak-hour load forecast includes the sum of the individual coincident peak demands
of residential, commercial. industrial, and irrigation customers, as well as special contracts.
Idaho Power uses the 95111-percentile forecast as the basis for peak-hour planning in the IRP.
The 95111-percentiJe forecast is based on the 951h-pcrcentile average peak-day temperature to
forecast monthly peak-hour load.
Idaho Power's system peak-hour load record-3.407 MW-was recorded on July 2, 2013,
at 4:00 p.m. The previous summer peak demand record was 3,245 MW and occurred on July 12,
2012, at 4:00 p.m. Summertime peak-hour load growth accelerated in the previous decade as
AIC became standard in nearly all new residential home construction and new commercial
buildings. System peak demand slowed considerably in 2009, 20 I 0, and 2011, the consequences
of a severe recession that brought new home and new business construction to a standstill.
Demand response programs operating in the summertime have also had a significant effect on
reducing peak demand. The 2015 I RP 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 IRP
Idaho 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 7.1 and Table 7.1 summarize three forecast outcomes of Idaho Power's estimated annual
system peak load-median. 90111-percentile, and 95111-percentile. The 95111-percentile forecast uses
the 95111-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.
5,100
4,700
4,300
3,900
3,500
3,100
2,700
2,300
1,900
1,500
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
Actual less Astaris --Actual -50lh Percentile -90th Percentile --95th Percentile
Figure 7.1
Table 7.1
Peak-hour load-growth forecast (MW)
Load forecast-peak hour (MW)
Year
2016 ..
2017 .
2018 ..
2019 .
2020 .
2021 .
2022 .
2023 .
2024 .
2015 IRP
3,401
3,463
3,514
3,562
3,615
3,670
3,725
3,780
3,839
901h Percentile 951h Percentile
3,184 3,184
3,537 3,576
3,630 3,669
3,696 3,736
3,752 3,793
3,805 3,847
3,862 3,905
3,922 3,965
3,981 4,026
4,041 4,086
4,105 4, 151
Page 83
2014 (Actual)................................................................ 3, 184
2015................................................. 3,313
Median
7. Planning Period Forecasts Idaho Power Company
Table7.1
Year
Load forecast-peak hour (MW) (continued)
Median 901h Percentile 951h Percentile
4,168 4,215
4,231 4,278
4,293 4,341
4,355 4,404
4,419 4,469
4,481 4,531
4,540 4,592
4,599 4,651
4,659 4,713
4,719 4,773
1.5% 1.5%
2025............................................................................. 3,897
2026............................................................................. 3,956
2027 4,013
2028............................................................................. 4,071
2029............................................................................. 4,130
2030.. 4,187
2031 4,242
2032. 4,296
2033............................................................................. 4,352
2034 4,407
Growth rate (2015-2034)............................................ 1.5%
The median or expected case peak-hour load forecast predicts that peak-hour load will grow
from 3,313 MW in 2015 to 4,407 MW in 2034-an average annual compound growth rate of
1.5 percent. The projected average annual compound growth rate of the 95111-percentile peak
forecast is also 1.5 percent. In the 95111-percentile forecast, summer peak-hour load is expected to
increase from 3,576 MW in 2015 to 4,773 MW in 2034. Historical peak-hour loads, as well as
the three forecast scenarios, are shown in Figure 7.1.
Idaho Power's winter peak-hour load ·ecord was 2,528 MW, recorded on December I 0, 2009,
at 8:00 a.m. Historical winte').'eak-houli load is much more variable than summertime peak-hour
load. The winter peak variability is due o peak-day temperature variability in winter months,
which is far greater than ti e variability of peak-day temperatures in summer months.
Average-Energy Loa(! Forecast
Potential monthly average-energy use by customers in Idaho Power's service area is defined by
three load forecasts that reflect loa uncertainty resulting from differing weather-related
assumptions. Figure 7.2 and Table 7.2 show the results of the three forecasts used in the 2015
IRP reported as annual system load growth over the planning period. There is approximately a
SO-percent probability Idaho Power's load will exceed the expected-case forecast, a 30-percent
probability of load exceeding the 70th-percentile forecast, and a I 0-percent probability of
exceeding the 90th-percentile forecast. The projected 20 year average compound annual growth
rate in each of the forecasts is 1.2 percent.
Idaho Power uses the 70th-percentile forecast as the basis for monthly average-energy planning
in the IRP. The 70th-percentile forecast is based on 70th-percentile weather to forecast average
monthly load, 70th-percentile water to forecast hydroelectric generation, and 95th-percentile
average peak-day temperature to forecast monthly peak-hour load.
Page 84 2015 IRP
Idaho Power Company
2,500 -- --
7. Planning Period Forecasts
2,200
1,900
1,600
1,300
1,000
700
1979 1984 1989 1994 1999 2004 2009 2014 2019 2024 2029 2034
-WA less Astaris --Weather Adjusted --Expected Case -70th Percentile --90th Percentile
Figure 7.2 Average monthly load-growth forecast (aMW)
2015 IRP Page 85
7. Planning Period Forecasts Idaho Power Company
Table 7.2 Load forecast-average monthly energy (aMW)
701h Percentile 901h Percentile
1,829 1,900
1,878 1,950
1,908 1,981
1,928 2,002
1,946 2,021
1,964 2,040
1,987 2,064
2,011 2,088
2,035 2,113
2,059 2,139
2,085 2,165
2, 110 2,190
2,134 2,215
2,156 2,238
2, 183 2,266
2,206 2,290
2,228 2,312
2,246 2,331
2,271 2,356
2,292 2,378
1.2% 1.2%
Median Year
2015............................................................................. 1,786
2016............................................................................. 1,835
2017............................................................................. 1,864
2018............................................................................. 1,883
2019 1,900
2020............................................................................. 1,918
2021............................................................................. 1,941
2022 1,964
2023............................................................................. 1,988
2024 2,012
2025............................................................................. 2,037
2026 2,061
2027 2,085
2028 2,107
2029 2,133
2030............................................................................. 2,156
2031............................................................................. 2,177
2032............................................................................. 2,195
2,219
2,240
Additional Firm Load
The additional firm-load category consists of Idaho Power's largest customers. Idaho Power's
tariff requires the company serve requests for electric service greater than 20 MW under a
special-contract schedule negotiated between Idaho Power and each large-power customer.
The contract and tariff schedule are approved by the appropriate commission. /\ special contract
allows a customer-specific cost-of-service analysis and unique operating characteristics to be
accounted for in the agreement. A special contract also allows Idaho Power to provide
requested service consistent with system capability and reliability. Idaho 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 arc
described briefly as follows.
Micron Technology
Micron Technology represents Idaho 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 facility in Boise and performs a variety of other activities,
Page 86 2015 IRP
Idaho 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 Fertilizer plant is the largest producer of phosphate fertilizer in the western US.
The future electricity usage at the plant is expected to grow slowly through 2016 and then stay
flat throughout the remainder of the planning period.
Idaho National Laboratory
The DOE provided an energy-consumption and peak-demand forecast through 2034 for
the lNL. The forecast cal Is for loads to slowly rise through 2021, rise dramatically through 2024,
and stay near that higher level throughout the remainder of the forecast period.
Generation Forecast for Existing Resources
To identify the need and timing of future
resources, Idaho Power prepares a load and
resource balance that accounts for forecast
load growth and generation from al I of the
company's existing resources and planned
purchases. Updated load and resource balance
worksheets showing Idaho Power's existing
and committed resources for average-energy
and peak-hour load are shown in Appendix C­
Technicaf Appendix. The following sections
provide a description ofldaho Power's'
hydroelectric, thermal, and transmission
resources and how they are accounted for in
the load and resource balance.
Hydroelectric Resources
Swan Falls Dam.
For the 2015 lRP, Idaho Power continues the practice or using 701h-perccnli le forecast
streamflow conditions for the Snake River Basin as the basis for the projections of monthly
average hydroelectric generation. The 701h percentile means basin strcarnflows arc expected to
exceed the planning criteria 70 percent of the time and are expected to be worse than the
planning criteria 30 percent of the time.
Likewise, for peak-hour resource adequacy, Idaho Power continues to assume 90111-percentile
stream flow conditions to project peak-hour hydroelectric generation. The 90111 percentile means
stream flows are expected to exceed the planning criteria 90 percent of the time and to be worse
than the planning criteria only IO 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 IRP Page 87
7. Planning Period Forecasts Idaho Power Company
use more conservative water planning criteria as a method of encouraging the acquisition of
su [ficient firm resources to reduce reliance on market purchases. However, Idaho Power
continues to prepare hydroelectric generation forecasts for 50111-percentile (median)
stream flow conditions because the median stream flow 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 ( RPM) is used to determine surface-water flows, and the Enhanced Snake
Plain Aquifer Model (ES PAM) is used to determine the effect of various aquifer management
practices on Snake River reach gains. The two models arc used in combination to produce
a normalized hydrologic record for the Snake River Basin from 1928 through 2009.
The record is normalized to account for specified conditions relating to Snake River reach
gains, water-management facilities, irrigation facilities, and operations. The 501h-, 701h-,
and 901h-percentile stream flow forecasts are derived from the normalized hydrologic
record. Further discussion of flow modeling for the 2015 IRP is included in Appendix C­
Technical Appendix.
A review of Snake River Basin stream flow trends suggests that.pg sistent decline documented in
the Eastern Snake River Plain Aquifer (ESPA) is mirrored by downward trends in total surface­
water outflow from the river basin. The ESPA Comprehensive Aquifer Management Plan
(CAMP) includes demand reduction and weather-modification m asures that will add new water
to the basin water budget. Idaho Power believes the positive effect of the new water associated
with the CAMP measures is likely to be temporary. The current wafer-use practices driving the
steady decline over recent years are expected to continue resulting in declining basin outflows
assumed to persist well into the 2030s. The declining basin outflows for this IRP are assumed to
continue through the planning period.
A water-management practice affecting
Snake River stream flows involves the release
of water to augment flows during salmon
outmigration. Various federal agencies
involved in salmon migration studies have, in
recent years, supported efforts to shift delivery
of flow augmentation water from the
Upper Snake River and Boise River basins
from the traditional months of July and August
to the spring months of April, May, and June.
The objective of the stream flow 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-now 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 importance of July as a resource-constrained month, Idaho Power continues to incorporate
the shifted delivery of flow augmentation water from the Upper Snake River and Boise River
Page 88 2015 IRP
Idaho Power Company 7. Planning Period Forecasts
basins for the 2015 IRP. Augmentation water delivered from the Payette River Basin is assumed
to remain in July and August.
Monthly average generation for Idaho Power's hydroelectric resources is calculated with a
generation model developed internally by Idaho Power. The generation model treats the projects
upstream of the I ICC as ROR plants. The generation model mathematically manages reservoir
storage in the I ICC to meet the remaining system load while adhering to the operating
constraints on the level of Brownlee Reservoir and outflows from the I lells Canyon project.
For peak-hour analysis, a review of historical operations was performed to yield 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 stream flow condition for any given year is the volume of
inflow to Brownlee Reservoir during the April-to-July runoff period. Figure 7.3 shows
historical April-to-July Brownlee inflow as well as forecas Brownlee inflow for the so",
701h, and 90111 percentiles. The historical record demonstrates the variability of inflows to
Brownlee Reservoir. The forecast inflows do not reflect the historical variability but do include
reductions related to declining base flows in the Snake River. As oted previously in this section,
these declines are assumed to continue through the planning-period.
13 '"J
()
2
3
4 -t----
8
9
11
12
10
0
1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
--'!-Historical -50lh Percentile -70th Percentile -90th Percentile
Figure 7.3 Brownlee historical and forecast inflows
2015 IRP Page 89
7. Planning Period Forecasts Idaho Power Company
Idaho Power recognizes the need to remain apprised of scientific advancements concerning
climate change on the regional and global scale. Idaho Power believes there is too much
uncertainty to predict the scale and timing of hydro logic effects due to climate change.
Therefore, no adjustments related to climate change have been made in the 2015 IRP.
A discussion of climate change, including expectations of possible effects 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 market prices, and moderate
customer load. With respect to peak-hour output, the coal-fired projects are forecast to generate
at the full-rated, maximum dependable capacity, minus 6 percent to account for forced outages.
A summary of the expected coal price forecast is included in Appendix C-Technical Appendix.
Major plant modifications or changes in plant operations required to maintain compliance with
air quality standards are projected for the Jim Bridger units in 2015, 2016, 2021, and 2022 due to
the Regional Haze final rulemaking.
The 2015 IRP assumes Idaho Power's share of the Boardman plant will not be available for coal­
fired operations after December 31, 2020. This date is the result of an agreement reached
between the ODEQ and PGE related to compliance with Regional Haze rules on particulate
matter, S02, and NOx emissions.
Coal Analysis
Idaho Power prepared an initial co� tudy as pa of the 2011 IRP Update and the report was
filed with the !PUC and OP Ci 'February 2013. The 2011 study evaluated several investment
alternatives including converting '\.al units to bum natural gas, installation of selective catalytic
reduction (SCR) or selective non-catalytic reduction (SNCR), and scrubber additions. In the end,
the study recommended inst lation QjSCR on Jim Bridger Units 3 and 4 in 2015 and 2016
respectively. Since the comp I tion of that initial Coal Study, the Company has continued to
monitor the costs and benefits associated with the SCR investments for Jim Bridger Units 3 and
4 to ensure that those investments remain cost-effective. An update to the economic analysis of
the Bridger 3 and 4 SCR investments that supports the continued installation of the SC Rs for
those units is presented in Appendix C -Technical Appendix of the 2015 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 from the 2011 study. The Company will evaluate
investment alternatives for SCRs at Jim Bridger I and 2 no later than the 2017 IRP.
Idaho Power seeks to balance the impacts of carbon regulation with the economic impact to
customers, as well as customer needs for reliable service. For the 2015 IRP, the Company
applied a more dynamic economic analysis of the existing coal units as compared to prior IRPs.
Page 90 2015 IRP
Idaho Power Company 7. Planning Period Forecasts
The 2015 I RP evaluated numerous portfolios which included coal unit shutdowns on various
dates. The Company believes the termination of operations al its coal-fired plants in the very
near future would lead to increased risk of higher costs for customers in the near-term without a
commensurate long-term economic benefit. The Company is mindful 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 to achieve longer term savings.
Idaho Power has been in discussions with the joint owner of the North Val my 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
factors in the utilities' discussions and decision processes.
Idaho Power currently benefits from the diversity of its generation resources, and that diversity
helps mitigate the power supply cost risk borne by customers as the Company transitions to the
new energy landscape.
Natural Gas Resources
Idaho Power owns and operates four natural gas-fired, SCCTs and one natural gas-fired, CCCT.
The SCCT units are typically operated during peak load events in summer and winter months.
The monthly average-energy forecast for the SCCTs is based on J e assumption that the
generators are operated at full capacity for heavy-load hours during January, June, July, August,
and December and produce approximately 230 aM W of gas-fired generation for the five months.
With respect to peak-hour output, the SCCTs are assumed capable of producing an on-demand
peak capacity of 416 MW. While the peak d ispatchable capacity is assumed achievable for all
months, it is most critical to system reliability during summer and winter peak-load months.
Idaho Power's CCCT, Langley Gulch, became commercially available in June 2012. Because of
its higher efficiency rating, Langley Gulch is expected to be dispatched more frequently and for
longer runtimes than the existing SCCTs. Langley Gulch is forecast to contribute approximately
165 aMW with an on-demand peaking capacity of3 I 8 MW.
Natural Gas Price Forecast
Future natural gas price assumptions significantly influence the financial results of the
operational modeling used to evaluate and rank resource portfolios. For the 2015 IRP, Idaho
Power is using the US Energy Information Administration (EIA) natural gas price forecast. Idaho
Power also used the E(A as the source for the natural gas price forecast for the 2013 I RP, and
continues to use the ElA forecast for Idaho-jurisdiction avoided cost calculation purposes. The
natural gas price forecast was discussed during the first 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 market.
The Annual Energy Outlook 2014 Reference case, published by the EIA in April 2014, is the
source for the natural gas price forecast for the 2015 I RP. For the 2015 I RP, Idaho Power uses
nominal prices as published by the EIA as inputs to analysis performed. A chart showing forecast
2015 IRP Page 91
7. Planning Period Forecasts Idaho Power Company
Henry I lub natural gas prices is presented in Figure 7.4. The low and high case natural gas price
forecasts used for the 2015 I RP and shown on the chart correspond respectively to the high
resource (high availability) and low resource (low availability) cases reported by the EIA in the
A EO 2014. Idaho Power applies a Sumas basis and transportation cost to the Henry I lub 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.
$13
$12
$11
$10 'S ai c $9 � ·e S8 ;;; ;; c $7 e 0 .:. • S6 u � .. S5 .. C) e � $4 :. z
S3
$2
$1
--­ �-----
so 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 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 Henry Hub Price Forecast-EIA Annual Energy Outlook 2014 (nominal dollars)
Resource Cost Analysis
A comparative cost analysis of a variety of supply-side and demand-side resources was
conducted as part or resource screening for the 2015 I RP. As described previously. cost inputs
and operating data used to develop the resource cost analysis arc derived from the September
2014 Lazard report, Ldaho Power engineering studies and operating experience, or consultation
with specific resource developers. Resource costs are presented as follows:
• Levelized Capacity (fixed) Costs-Levelized fixed cost per kW of installed (nameplate)
capacity per month
• Level ized Cost of Production (at stated capacity factors)-Total level ized cost per M Wh
of expected plant output or energy saved, given assumed capacity factors and other
operating assumptions
Page 92 2015 IRP
Idaho Power Company 7. Planning Period Forecasts
The capital cost of solar photovoltaic resources has been the subject of considerable I RP
Advisory Council discussion over recent IRPs. As widely reported, solar photovoltaic costs have
declined markedly over recent years, presenting unique challenges in determining appropriate
costs for solar resources. For the 2015 IRP, Idaho Power utilized the Lazard report's projected
2017 capital cost of $1,250 per kW for utility-scale single-axis tracking solar photovoltaic
resources. To further capture reported trends in solar photovoltaic capital costs, the 2015 IRP
capital cost of$1,250 per kW was not escalated according to the IRP's assumed level of
inflation, as the capital costs for other considered resources were.
For the 2015 I RP, Idaho Power is including in resource cost calculations the assumption that
potential IRP resources have varying economic life. Financial analysis for the 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 include capital costs, O&M costs,
fuel costs, and other applicable adders and credits. The initial capital investment and associated
cost of capital of supply-side resources include engineering development costs, generating and
ancillary equipment purchase costs, installation costs, applicable balance of plant construction
costs, and the costs for a transmission interconnection to Idaho Power's network system.
The capital costs also include allowance for funds used during construction (AFUDC)
(capitalized interest). The O&M portion of each resource's levelized cost includes general
estimates for property taxes and property insurance premiums. The value of RECs is not
included in the levelized cost estimates but is accounted for when analyzing the total cost of
each resource portfolio.
The levelized costs for each of-the demand-side resource options include annual
administrative and marketing costs of the program, an annual incentive, and annual participant
costs. The demand-side resource costs do not reflect the financial effects resulting from the load
reduction programs.
Specific resource cost inputs, fuel forecasts, key financing assumptions, and other operating
parameters ar shown in Appendix C-Technical Appendix.
Resource Cost Analysis II-Resource Stack
Levelized Capacity (Fixed) Cost
The annual fixed-revenue requirements in nominal dollars for each resource were summed
and levelized over the assumed economic life and are presented in terms of dollars per kW of
plant nameplate capacity per month. Included in these levelized fixed costs are the initial
resource investment and associated cost of capital, and fixed O&M estimates. As noted earlier,
resources are considered to have varying economic life, and the financial analysis to determine
annual depreciation of capital costs is based on an apportioning of the capital costs over the
entire economic life. Figure 7.5 provides a combined ranking of all the various resource options
in order of lowest to highest levelizcd fixed cost per kW per month. The ranking shows that
natural gas peaking resources and demand response are the lowest capacity cost alternatives. The
natural gas peaking resources have high operating costs, but operating costs are not as important
2015 IRP Page 93
7. Planning Period Forecasts Idaho Power Company
for resources intended for use only during a limited number of hours per year to meet peak-hour
demand.
Levelized Cost of Production
Certain resource alternatives carry low fixed 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 measurement represents the estimated
annual cost (revenue requirements) per MWh in nominal dollars for a resource based on an
expected level of energy output (capacity factor) over the economic Ii fe of the resource.
The nominal, levelized cost of production assuming the expected capacit factors for each
resource type is shown in Figure 7.6. Included in these costs are the cost of capital, non-fuel
O&M, fuel, and emissions adders; however, no value for RECs was assumed in this analysis.
The 821-1 transmission line is the lowest cost resource for meeting baseload requirements.
When evaluating a levelized cost for a project and comparing it to the levelized cos of another
project, it is important to use consistent assumptions for the computation of each number.
The levelized cost of production metric represents the annual cost of production over the life of a
resource converted into an equivalent annual annuity. This is similar to the calculation used to
determine a car payment; only, in this case, the car payment w uld also include the cost of
gasoline to operate the car and the cost of maintaining the car over its useful Ii fe.
An important input into the levelized cost of production calculation for a generation resource is
the assumed level of annual capacity use over the lite of the resource, referred to as the capacity
factor. A capacity factor of 50 percent wou Id suggest a resource would be expected to produce
output at full capacity 50 percent of the hours during the year. Therefore, at a higher capacity
factor, the levelized cost would be less because the plant would generate more MWh over
which to spread the fixed costs. Conversely, lower capacity-factor assumptions reduce the MWh,
and the levelized cost would be higher.
For portfolio cost analysis, fixed resource costs are annualized over the assumed economic life
for each resource and are applied only to the years of production within the IRP planning period,
thereby accounting for end effects.
Page 94 2015 IRP
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Idaho 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 Lazard's Levelized Cost of Energy
Analysis-Version 8.0 as the primary source for supply-side resource costs. Lazard, a leading
independent financial advisory and asset management firm, issued the levelized cost report in
September 2014. Idaho Power engineering studies and plant operating experience were also
utilized. Costs for select resources not provided by the Lazard report and for which Idaho Power
has limited engineering and operating experience were determined through consultation with
specific resource developers.
x Reciprocating Engines
+ Ice TES
eB2H
.i.SCCT
•CCCT
•CHP
• Pumped-Slornge Hydro
• Small Hydro
OResidenlial PV
UtilrtyPV
.i.Wind
:KV Flow Battery
•Geolhermal x.
100%
•
• ...
80% 60%
Capacity. Low Capltal Cost
Lower Righi � High Peak-Hour
2015 IRP
•
40%
2013 IRP
0 1--------- ----- ---------·--·--··----- ..
$7,000
$6,000
$5,000 r e iii $4.000 0 o
?:' u .. 0. $3.000 .. o ...
$2.000
$1.000
so
0% 20%
The 2015 I RP forecasts load growth in the Idaho Power service area and identi fies supply-side
resources and demand-side measures necessary to meet the future energy needs of customers.
The 2015 I RP has identified periods of future system deficiencies. New resource costs are
levelized estimates (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) for a new resource
with a 2020 on line date plotted against peak-hour capacity for variou supply-side resources
considered in the 2015 IRP. The online date of2020 is used because, depending on the coal
retirement scenario, the earliest date for new resources in the 2j) 5 IRP is 2020. The use of the
2020 on line date also allows projected 2015-2016 capital cost declines in utility-scale
photovoltaic solar to be captured in the plotted data.
Peak-Hour Capacily (�,)
at90'h Exceedance
Figure 7.7 Capacity cost of new supply-side resources, on line 2020
Resources in the lower right portion of Figure 7.7 are considered to provide peak-hour capacity
at a relatively low capital cost. Among the resources in the lower right portion, the 82H
transmission line and various natural-gas fired generating resources provide the highest peak-
2015 IRP Page 97
7. Planning Period Forecasts Idaho 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 for utility-scale photovoltaic solar.
The marked decline in photovoltaic solar capital costs has been extensively reported over recent
years. The shift in peak-hour capacity is based on analysis performed for the 2015 IRP indicating
peak-hour capacity slightly in excess of 50% 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 part or
the total resource cost. In preparing the I RP, Idaho Power also considers the value each resource
provides in conjunction with the existing resources in the company's generation portfolio.
upply-side resources have different operating characteristics, making some bcucr suited for
meeting capacity needs, while others are better for providing energy.
Figure 7 .8 shows the levelized cost of energy in dollars per megawatt-hour (MWh) for various
new supply-side resources considered in the 2015 IRP, where costs considered include those
related to building and operating the resource for a 20-year period. The data used to create
Figure 7 .8 allows for resource alternatives to be compared based on the capacity cost and the
total levelized cost of production.
•
1,;"
2015 IRP
----<Ii.,. 2013 IRP _ .: ,,,' ... ,,-
Residential PV
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•Wind
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•Small Hydro
x Reciprocating Engines
• Pumped.Storage Hydro
�CHP
• Geothermal
>- V Flow Battery
•CCCT
DUtilrtyPV
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--·-1
j
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so so $50 $100 $150
$7.000
$6.000
$5.000
[ � .; $4.000 0 u � u .. $3,000 Q. .. u
$2.000
Cost of Production ($/MWh)
Figure 7.8 Energy cost of new supply-side resources
Resources in the lower left portion of Figure 7 .8 produce (or deliver) energy at low levelized cost
and have relatively low capital cost. The 821-1 transmission line is among those resources having
low levelized costs and low capital costs. Figures 7.7 and 7.8 respectively demonstrate that the
Boardman to Hemingway transmission line is attractive as a capacity resource (i.e .. one needed
relatively infrequently) and energy resource (i.e., one needed for frequent energy delivery).
Page 98 2015 IRP
Idaho Power Company 7. Planning Period Forecasts
In contrast, a simple-cycle combustion turbine (SCCT) has competitive costs with respect to the
relatively infrequent delivery of capacity (Figure 1.1 ), but is much less competitive when
required to deliver energy (Figure 7.8). The dashed line 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 2015 I RP is presented in Chapter 7.
Load and Resource Balance
Idaho Power has adopted the practice of assuming drier-than-median water conditions and
higher-than-median load conditions in its resource planning process. Targeting a balanced
position between load and resources while using the conservative water and load conditions is
considered comparable to requiring a capacity margin in excess of load while using median load
and water conditions. Both approaches arc designed to result in a system having a sufficient
generating reserve capacity to meet daily operating reserve requ ircments.
To identify the need and timing of future resources, Idaho Power prepares the load and
resource balance, which accounts for generation from all the company's existing resources and
planned purchases. Due to the uncertainty of the CAA Section 11 l(d) rule, many different
assumptions can be made for the future of Idaho Power's coal resources. To address these
different coal futures, Idaho Power has analyzed nine load and resource balance scenarios.
• Status Quo: The first scenario assumes Idaho Power makes no changes in the operations
of its coal fleet. This scenario is very similar to the load and resource balance provided in
the 2013 I RP and is designed to provide a basis for comparison.
• Maintain Coal Capacity: The second scenario assumes Idaho Power will maintain its
coal fleet, but reduce emissions output in compliance with proposed the CAA Section
111 (d) rule by limiting or capping the amount generators can run.
• Retire Valmy CoaJ Plant: A third set of scenarios assumes varying timing dates for the
retirement of Units I and 2 of the Val my coal plant. There are four scenarios that reflect
possible retirement dates for Units I and 2 of Val my:
• Retire Units I and2bytheendof2019
• Retire Units I and 2 by the end of2025
• Retire Unit I by the end of2019 and Unit 2 by the end of2025
• Retire Unit I by the end of202 I and Unit 2 by the end of 2025
• Retire Units land 2 of Bridger Coal Plant: Two sets of scenarios assume differing
retirement dates for Units I and 2 of the Bridger coal plant. There are a total of four units
at Bridger and Units 3 and 4 are not being considered for retirement.
• Retire Unit I by the end of2023 and Unit 2 by the end of2028
• Retire Unit I by the end of 2023 and Unit 2 by the end of 2032
2015 IRP Page 99
7. Planning Period Forecasts Idaho Power Company
• Retire Valmy Coal Plant and Units I and 2 of Bridger Coal Plant: A final scenario
assumes the retirement of Units I and 2 of Val my coal plant by the end of 2025,
retirement of Unit I of Bridger coal plant by the end of2023 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 deficits arc determined using 70111-percentile water and
70'h-percentile average load conditions, coupled with Idaho Power's ability to import energy
from firm market purchases using a reserved network capacity.
Peak-hour load deficits are determined using 901h-percentile water and 95th_percentile peak-hour
load conditions. The hydrologic and peak-hour load criteria are the major factor in determining
peak-hour load deficits. Peak-hour load planning criteria are more stringent than average-energy
criteria because Idaho Power's ability to import additional energy is typically limited during
peak-hour load periods.
All load and resource balances, irrespective of the coal future under consideration, include:
• Existing demand reduction due to the demand response programs and the forecast effect
of existing energy efficiency programs.
• Existing power purchase agreements with Elkhorn Valley Wind, Raft River Geothermal,
and Neal I lot prings. Idaho Power's agreement with Elkhorn Valley Wind expires at the
end of 2027. The other agreements do not expire within the planning period.
• Firm Pacific Northwest import capability. This does not include the import capacity from
the Boardman to Hemingway transmission line or the Gateway West transmission line.
• Expected generation from all Idaho Power-owned resources. Boardman coal plant has a
planned retirement date of 2020.
Page 100 2015 IRP
At times of peak summer load. Idaho Power is using all available transmission capacity (A TC)
from the Paci fie Northwest. If Idaho Power was to face a significant outage at one of its main
generation facilities or a transmission interruption on one of the main import paths, the company
• Existing PURPA projects and contracts completed by October 31, 2014 including 461
MW of solar projects under contract but not yet operational. (Contracts for four solar
projects totaling 14 l MW of installed capacity were terminated on Apri I 6, 2015. The
relatively late termination date precludes the removal of these projects from load and
resource balance analysis for the 2015 IRP.) Idaho Power assumes all PURPA contracts,
with the exception of wind 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 of627 MW of wind under contract. Wind
contracts begin to expire in October 2025 and total wind under contract drops to 130 MW
at the end of the planning period.
Idaho Power Company 7. Planning Period Forecasts
wou Id fai I 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 infrequent, 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 or
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 or July has historically been the month during which Idaho
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 energy demand occurs
during the winter in the month of December. Tables 7.3 and 7.4 provide for the months of July
and December the monthly average energy deficits for each of the coal futures considered in the
2015 I RP. Darker shading in the tables corresponds with larger deficits Surplus positions are not
specified in the tables. Because no deficits exist prior to 2020 the tables include data for only the
period 2020-34.
2015 IRP Page 101
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8. Portfolio Selection
Portfolio Design
8. PORTFOLIO SELECTION
Idaho Power Company
In the 2015 IRP, ldaho Power continued the 2013 lRP"s practice of analyzing a range of coal
retirement portfolios. 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 JRP (Case No. IPC-E-13-15, Order No. 32980). The 23 portfolios
analyzed for the 2015 IRP can be grouped into the following ten categories:
I. Status quo porifolio-A single resource portfolio with no additional retirement of coal­
fired generating units other than Boardman in 2020 and without output constraints related
to the proposed CAA Section 111 (d) regulation. The Status Quo portfolio relies on the
Boardman to Hemingway transmission line and reciprocating gas engines to meet future
resource needs.
All other portfolios considered in the 2015 lRP assume compliance with CAA Section
I I I (d) based on various assumptions regarding what the final rule will contain.
2. Maintain coal capacity porifolios-A set of three portfolios with no retirement of coal
capacity during the IRP planning period with the exception of the planned 2020 year-end
Boardman shutdown.
3. North Va/my retirement.year-end 2019 portfolios-A set of five portfolios with
retirement of both N Val my units at year-end 2019.
4. North Va/my retirement year-end 2025 portfolios-A set of three portfolios with
retirement of both North Valmy units at year-end 2025.
5. North Va/my staggered retirement year-end 2019 {Unit I) and year-end 2025 (Unit 2)
portfolio -A set of two portfolios with retirement of North Val my Unit I at year-end
2019 and Unit 2 at year-end 2025.
6. North Va/my staggered retirement year-end 2021 (Unit 1) and year-end 2025 (Unit 2)
portfolio-A single portfolio with retirement of North Valmy Unit I at year-end 2021
and Unit 2'at year-end 2025.
7. Jim Bridger staggered retirement year-end 2023 (Unit I) and year-end 2032 (Unit 2)
portfolios-A set of two portfolios with retirement of Jim Bridger Unit I at year-end
2023 and Unit 2 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 in 2022 and
Unit 2 in 2021. All portfolios for the 2015 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 I) and year-end 2028 (Unit 2)
portfolio-A single portfolio with retirement of Jim Bridger Unit I at year-end 2023 and
Unit 2 at year-end 2028. The early retirement of this portfolio is assumed to allow the
Page 104 2015 IRP
Idaho Power Company 8. Portfolio Selection
avoidance of installation of selective catalytic reduction for Unit I in 2022 and Unit 2 in
2021.
9. Jim Bridger staggered retirement year-end 2023 (Unit I) and year-end 2032 (Unit 2).
North Va/my retirement year-end 2025 portfolio=re single portfolio with retirement of
Jim Bridger Unit I at year-end 2023 and Unit 2 at year-end 2028, and retirement of both
North Valrny units at year-end 2025. The early Jim Bridger retirement in this portfolio is
assumed to allow the avoidance of installation of selective catalytic reduction for Unit I
in 2022 and Unit 2 in 2021.
I 0. Alternative Lo Boardman to Hemingway portfolios=--tv set of four portfol ios in which the
Boardman to Hemingway transmission line is replaced by alternative resources. Except
for this set of portfolios, al I other 2015 I RP port folios have the Boardman to Hemingway
transmission I ine.
The coal retirement portfolios include the additional cost of recovering the remaining investment
in the coal units prior to retirement. In addition, resource retirement includes the accelerated
decommissioning costs when estimating the resource portfolio 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.
Table 8.1 Fixed-cost impacts of coal retirement
Fixed-Cost Description
Accelerated Recovery of Depreciation Expense on Remainfng Investments
Utility Rate of Return Applied Over a Shorter Life
Accelerated Recovery of Decommissioning and Demolition Costs (Net of Salvage)
Avoidance of Future Incremental Capital (Including Avoidance of Environmental
Retrofit Investments)
Avoidance of Future Fixed Operating Expenses
Portfolio Design and Selection
Cost Impact
Cost
Savings
Cost
Savings
Savings
Idaho Power analyzed 23 resource portfolios for the 2015 IRP. All portfolios arc designed to
balance forecast load with available or additional resources to eliminate energy and capacity
deficits according to the IRP planning criteria described in Chapter 7. Energy and capacity
deficits for the considered coal retirement futures are also provided in Chapter 7. Portfolios were
designed in collaboration with the IRP Advisory Council and public participants in the IRP
process.
2015 IRP Page 105
8. Portfolio Selection
Status Quo Portfolio
Idaho Power Company
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.
P1-82H, reciprocating engines, no coal capacity retirement, no CAA Section
111 ( d) restrictions
Table 8.2
Date
2025
2034
Resource portfolio P1
Resource
Boardman to Hemingway
Reciprocating engines
Installed Capacity
500 MW transfer capaci(y Apr-Sep
200 MW transfer capacity Oct-Mar
36MW
Total retired capacity
Total added capacity
Net peak-hour capacity
Peak-Hour Capacity
500MW
36MW
(OMW)
536 MW
536MW
Resource additions of the set of portfolios with coal capacity maintained, excepting the planned
Boardman shutdown, arc driven by capacity deficits beginning in July 2025 and reaching 523
MW by July 2034. The portfolios of this set differ fr m portfolio Pl only in the assumed onlinc
date for B2H, ranging from 2021 to 2025. The portfolios are designated as resource portfolios
P2(a), P2(b), and P2(c).
P2(a)-82H online 2025, reciprocating engines, no coal capacity retirement
Table 8.3
Date
2025
2034
Page 106
Resource portfolio P2(a)
Resource
Boardman to Hemingway
Reciprocating engines
Installed Capacity
500 MW transfer capacity Apr-Sep
200 MW transfer capacity Oct-Mar
36MW
Total retired capacity
Total added capacity
Net peak-hour capacity
Peak-Hour Capacity
500MW
36MW
(OMW)
536MW
536MW
2015 IRP
Idaho Power Company 8. Portfolio Selection
P2(b)-82H online 2023, reciprocating engines, no coal capacity retirement
Table 8.4
Date
2023
2034
Resource portfolio P2(b)
Resource
Boardman to Hemingway
Reciprocating engines
Installed Capacity
500 WfoN transfer capacity Apr-Sep
200 WfoN transfer capacity Oct-Mar
36MW
Peak-Hour Capacity
500 WfoN
36MW
Total retired capacity
Total added capacity
Net peak-hour capacity
(OMW)
536MW
536MW
P2(c)-82H online 2021, reciprocating engines, no coal capacity retirement
Table 8.5
Date
Resource portfolio P2(c)
Resource Installed Capacity Peak-Hour Capacity
2021
2034
Boardman to Hemingway
Reciprocating engines
Total retired capacity
Total added capacity
(OMW)
536 MW
536MW
500 MW transfer capacity Apr-Sep 500 MW
200 WfoN transfer capacity Oct-Mar
36MW 36 MW
North Va/my Retirement Ye r-End 2019 Portfolios
Resource additions for portfolios with North Valmy retirement in 2019 are driven by capacity
deficits beginning in July 2020 and reaching 786 MW by July 2034. These resource portfolios
arc designated as P3, P4(a), P4(b) P4(c), and PS. The P4 portfolios differ primarily in assumed
online date for 82H, ranging from 2021 to 2025.
2015 IRP Page 107
P3-North Valmy retirement 2019, ice-based thermal energy storage, utility-scale
PV 1-axis, 82H online 2025, EE accrue by 2034 to 16 MW (average energy) and 24
MW (peak-hour capacity)
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. In 2033, 75 MW of additional utility-scale single-axis photovoltaic solar is added. PJ also
adds energy efficiency beyond the amount identified as cost effective in the DSM potential study
included in all portfolios. The extra energy efficiency ramps gradually during the IRP planning
period, reaching 16 MW of average energy and 24 MW of peak-hour capacity by 2034.
8. Portfolio Selection
Table 8.6 Resource portfolio P3
Date Resource
2019 Retire North Valmy (both units)
2020 Ice-based thermal energy storage
2021 Ice-based thermal energy storage
2021 Utility-scale solar PV 1-axis
2023 Utility-scale solar PV 1-axis
2025 Boardman to Hemingway
2033 Utility-scale solar PV 1-axis
2034 Reciprocating engines
2020-34 Energy efficiency•
Idaho Power Company
Peak-Hour
Installed Capacity Capacity
(262 MW) (262 MW)
25MW 25MW
35MW 35MW
150 MW 77MW
180MW 92MW
500 MW transfer capacity Apr-Sep 500MW
200 MW transfer capacity Oct-Mar
75MW 38MW
36MW 36MW
N/A 24._MW
Total retired capacity (262 MW)
Total added capacity 827 MW
Net peak-hour capacity 550MW
'Note: Extra energy efficiency beyond cost-effective amount determined by DSM potential study.
P4(a)- North Valmy retirement 2019, battery storage, reciprocating engines, B2H
online 2025
The resource portfolio P4(a) adds 60 MW of Vanadium redox flow battery storage and 198 MW
of reciprocating engines in the early 2020s prior to the B2H transmission line in 2025. The 60
MW of battery storage is replaced in 2030-31 with new battery storage, followed by the addition
of 54 MW of reciprocating.engines in 2033.
Table 8.7 Resource portfolio P4(a)
Peak-Hour
Date Resource Installed Capacity Capacity
2019 Retije North Valmy (t>Oth units) (262 MW) (262 MW)
2020 V �dox flow battery storage 25MW 25MW
2021 V redox flow battery storage 35MW 35MW
2021 Reciprocating engines 90MW 90MW
2023 Reciprocating engines 108MW 108MW
2025 Boardman to Hemingway 500 MW transfer capacity Apr-Sep 500MW
200 MW transfer capacity Oct-Mar
2030 2020 battery storage end of life (25 MW) (25 MW)
2030 V redox flow battery storage (replace) 25MW 25MW
2030 2021 battery storage end of life (35 MW) (35 MW)
2031 V redox flow battery storage (replace) 35MW 35MW
2033 Reciprocating engines 54MW 54MW
Total retired capacity (322 MW)
Total added capacity 872MW
Net peak-hour capacity 550MW
Page 108 2015 IRP
Idaho Power Company 8. Portfolio Selection
P4(b)- North Valmy retirement 2019, 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 in 2020-21, and the B2H transmission line in 2023. The 60 MW of battery
storage is replaced in 2030-31 with additional battery storage, followed by the addition of 162
MW of reciprocating engines in 2032-34.
Table 8.8 Resource portfolio P4(b)
Peak-Hour
Date Resource Installed Capacity Capacity
2019 Retire North Valmy (both units) (262 MW) (262 MW)
2020 V redox flow battery storage 25MW
2021 V redox flow battery storage 35MW
2021 Reciprocating engines 90MW
2023 Boardman to Hemingway 500 WN\J
2030 2020 battery storage end of life (25MW)
2030 V redox flow battery storage {replace) 25MW
2030 2021 battery storage end of life �35 MW) (35MW)
2031 V redox flow battery storage (replace) 35MW 35MW
2032 Reciprocating engines 54MW 54MW
2033 Reciprocating engines 72MW 72MW
2034 Reciprocating engines 36MW 36MW
Tota retired capacity (322 MW)
Total added capacity 872MW
Net peak-hour capacity 550MW
P4(c)- North Valmy retirement 2019, battery storage, reciprocating engines, 82H
online 2021
Portfolio P4(c) adds 25 MW of Vanadium redox flow battery storage in 2020 and the B2H
transmission line in 2021. The portfolio also includes35 MW of Vanadium red ox flow battery
storage added in 2029, with 25 MW of battery storage replacement in 2030. Reciprocating
engines totaling 252 MW are added in the early 2030s.
2015 IRP Page 109
8. Portfolio Selection Idaho Power Company
Table 8.9
Date
2019
2020
2021
2029
2030
2030
2030
2031
2033
Resource portfolio P4(c)
Resource
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
Installed Capacity
(262 rvf,/1/)
25MW
500 rvwv transfer capacity Apr-Sep
200 rvwv transfer capacity Oct-Mar
35MW
36MW
(25 MW)
25MW
108 MW
108MW
Total retired capacity
Total added capacity
Net peak-hour capacity
Peak-Hour Capacity
(262 MW)
25MW
500MW
35 MW
36 MW
(25 MW)
25MW
108 MW
108 MW
(287 MW)
837 rvwv
550 rvwv
PS- North Valmy retirement 2019, CCCT, B2H online 2025
Resource portfolio PS adds a 300 MW combined-cycle combustion turbine in 2020 and the l32H
transmission line in 2025.
Table 8.10
Date
2019
2020
2025
Resource portfolio P5
Resource
Retire North Valm,'. (both units)
Combined-cycle combustion turbine
Boardman to Hemingway
Installed Capacity Peak-Hour Capacity
(262 tvWV) (262 MW)
300 rvfoN 300 MW
500 rvwv transfer capacity Apr-Sep 500 MW
200 MW transfer capacity Oct-Mar
Total retired capacity
Total added capacity
Net peak-hour capacity
(262 tvWV)
800MW
538MW
North Va/my Retirement Year-End 2025 Portfolios
Portfolios with North Valmy retirement in 2025 experience capacity deficits beginning in July
2025 and reaching 786 MW by July 2034. These resource portfolios are designated as P6. P6(b).
and P7.
PG-North Valmy retirement 2025, B2H online 2025, CCCT
Resource portfolio P6 adds the 82H transmission line in 2025 prior to retiring North Valmy at
year-end 2025. A 300 MW combined-cycle combustion turbine is added in 2030.
Page 110 2015 IRP
Idaho Power Company 8. Portfolio Selection
Table 8.11
Date
2025
2025
2030
Resource portfolio PS
Resource
Boardman to Hemingway
Retire North Valmy (both units)
Combined-cycle combustion turbine
Installed Capacity Peak-Hour Capacity
500 MW transfer capacity Apr-Sep 500 MW
200 MW transfer capacity Oct-Mar
(262 MW) (262 MW)
300 MW 300 MW
Total retired capacity (262 MW)
Total added capacity
Net peak-hour capacity
800MW
538 MW
P6(b)-North Valmy retirement 2025, B2H online 2025, demand response, ice­
based thermal energy storage, CCCT
Resource portfolio P6(b) is a variation of P6 in which the inclusion in 2030 of60 W of
demand response and 20 MW of ice-based thermal energy storage allows the 300 MW
combined-cycle combustion turbine to be deferred by one year to 2031. The 60 MW of demand
response is above and beyond the 390 MW of summer demand response included as an existing
resource in all portfolios.
Table 8.12
Date
2025
2025
2030
2030
2031
Resource portfolio P6(b)
Resource
Boardman to Hemingway
Retire North Valmy (both units)
Demand response
Ice-based thermal energy storage
Combined-cycle combustion turbine
Installed Capacity
500 MW transfer capacity Apr-Sep
200 MW transfer capacity Oct-Mar
(262 MW)
60MW
20MW
300MW
Total retired capacity
Total added capacity
Net peak-hour capacity
Peak-Hour Capacity
500MW
(262 MW)
60MW
20MW
300MW
(262 MW)
880MW
618 MW
P7-North Valmy retirement 2025, B2H online 2025, pumped-storage hydro
The resource portfolio P7 adds the B2H transmission line in 2025 prior to retiring North Valmy
at year-end 2025. A 300 MW pumped-storage hydro project is added in 2030.
Table 8.13
Date
2025
2025
2030
Resource portfolio PG
Resource
Boardman to Hemingway
Retire North Valmy (both units)
Pumped-storage hydro
Installed Capacity Peak-Hour Capacity
500 MW transfer capacity Apr-Sep 500 MW
200 MW transfer capacity Oct-Mar
(262 MW) (262 MW)
300 MW 300 MW
Total retired capacity (262 MW)
2015 IRP
Total added capacity
Net peak-hour capacity
800MW
538MW
Page 111
8. Portfolio Selection Idaho Power Company
North Va/my Staggered Retirement Year-End 2019 (Unit 1) and Year­
End 2025 (Unit 2) Portfolios
Resource add itions of portfolios with North Val my retirement in 2019 (Unit I) and 2025 (Un it 2)
arc driven by capacity deficits beginning in July 2021 and reaching 786 MW by July 2034. The
portfolios of this set arc designated as P8 and P9.
PB-North Valmy retirement 2019 (Unit 1) and 2025 (Unit 2), ice-based thermal
energy storage, utility-scale PV 1-axis, 82H online 2025, small hydro,
reciprocating engines, EE accrue by 2034 to 16 MW (average energy) and 24 MW
(peak-hour capacity)
Resource portfolio P8 adds 60 MW of ice-based thermal energy storage and 70 MW of utility­
scale single-axis photovoltaic solar in 2021-24 and the 82H transmission line in 2025. P3 adds
45 MW of canal hydro in 2031 and 126 MW of reciprocating engines in 2032-33. Equivalent to
resource portfolio P3, portfolio P8 also adds energy efficiency beyond the amount identified as
cost effective in the DSM potential study. The extra energy efficiency ramps gradually during
the IRP planning period, reaching 16 MW of average energy and 24 MW of peak-hour capacity
by 2034.
Table 8.14 Resource portfolio PS
Date Resource Installed Capacity Peak-Hour Capacity
2019 Retire North Valmy (Unit 1) (126 wrN) (126 wrN)
2021 Ice-based thermal energy storage 15 wrN 15 wrN
2023 Ice-based thermal energy storage 30MW 30 wrN
2024 Utility-scale solar PV 1-axis 70 wrN 36 wrN
2024 Ice-based thermal energy storage 15MW 15 wrN
2025 Boardman to Hemingway 500 wrN transfer capacity Apr-Sep 500MW
200 wrN transfer capacity Oct-Mar
2025 Retire North Valmy (Unit 2) (136 MW) (136 MW)
2031 Canal hydro 45MW 45MW
2032 Reciprocating engines 72MW 72 wrN
2033 Reciprocating engines 54MW 54MW
2020-34 Energy efficiency' N/A 24MW
Total retired capacity (262 MW)
Total added capacity 791 MW
Net peak-hour capacity 529MW
'Note: Extra energy efficiency beyond cost-effective amount determined by DSM potential study.
P9- North Valmy retirement 2019 (Unit 1) and 2025 (Unit 2), demand response,
reciprocating engines, 82H online 2025, SCCT
The resource portfolio P9 adds 60 MW of demand response in 2021-24. The 60 MW of demand
response is above and beyond the 390 MW of summer demand response included as an existing
resource in all portfolios. P9 also adds 54 MW of reciprocating engines in 2024. The B2H
Page 112 2015 IRP
Idaho Power Company 8. Portfolio Selection
transmission line is added in 2025, followed by 18 MW of reciprocating engines in 2031 and a
170 MW simple-cycle combustion turbine in 2032.
Table 8.15 Resource portfolio P9
Date Resource Installed Capacity Peak-Hour Capacity
2019 Retire North Valmy (Unit 1) (126 MW) (126 MW)
2021 Demand response 15MW 15 MW
2023 Demand response 30MW 30 MW
2024 Reciprocating engines 54MW 54 MW
2024 Demand response 15 MW 15 MW
2025 Boardman to Hemingway 500 MW transfer capacity Apr-sec 500 MW
200 MW transfer capacity Oct-Mar
2025 Retire North Valmy (Unit 2) (136 MW) (136 MW)
2031 Reciprocating engines 18MW 18MW
2032 Simple-cycle combustion turbine 170 MW 170MW
Total retired capacity (262 MN)
Total added capacity 802MN
Net peak-hour capacity 540MN
Jim Bridger Staggered Retirement Year-End 2023 (Unit 1) and Year­
End 2032 (Unit 2) Portfolios
The resource additions to portfolios-with Jim Bridger retirement in 2023 (Unit 1) and 2032 (Unit
2) are driven by peak-hour capacity deficits beginning in July 2024 and reaching 874 MW by
July 2034. These resourc portfolios a e designated as PIO and PI I.
P10-Jim Bridger retiremen 2023 (Unit 1) and 2032 (Unit 2), SCCT, B2H online
2025, CCCT
The resource portfolio PIO adds a 17\MW SCCT in 2024 and the 82H transmission line in
2025. P 10 adds a 300 MW co\.bined,rcycle combustion turbine in 2033.
Table 8.16 Resource portfqlio P10
Date Resource Installed Capacity Peak-Hour Capacity
2023 Retire Jim Bridger (Unit 1) (177 MW) (177 MN)
2024 Simple-cycle combustion turbine 170MW 170MW
2025 Boardman to Hemingway 500 MW transfer capacity Apr-Sep 500MW
200 MW transfer capacity Oct-Mar
2032 Retire Jim Bridger (Unit 2) (176 MW) (176 MN)
2033 Combined-cycle combustion turbine 300MW 300MN
Total retired capacity (353 MW)
Total added capacity 970MW
Net peak-hour capacity 617 MW
2015 IRP Page 113
8. Portfolio Selection Idaho Power Company
P11-Jim Bridger retirement 2023 (Unit 1) and 2032 (Unit 2), SCCT, B2H online
2025, CCCT
The resource portfolio Pl I adds 60 MW of ice-based thermal energy storage and 155 MW of
utility-scale single-axis photovoltaic solar in 2024 and the 8211 transmission line in 2025. P 11
also adds 180 MW of reciprocating engines and a 45 MW combined heat and power facility in
2033. Like portfolio P3 and P8, P 11 also adds energy efficiency beyond the amount identified as
cost effective in the DSM potential study. The extra energy efficiency ramps gradually during
the I RP planning period, reaching 16 MW of average energy and 24 MW of peak-hour capacity
by 2034.
Table 8.17
Date
2023
2024
2024
2025
2032
2032
2033
2033
2034
2020-34
Resource portfolio P11
Resource
Retire Jim Bridger (Unit 1)
Ice-based thermal energy storage
Utility-scale solar PV t-axis
Boardman to Hemingway
Reciprocating engines
Retire Jim Bridger (Unit 2)
CHP
Reciprocating engines
Reciprocating engines
Energy efficiency"
Installed Capacity
(177 MW)
60MW
155 MW
500 MW transfer capacity Apr-Sep
200 MW transfer capacity Oct-Mar
108 MW
(176 MW)
45MW
36MW
36MW
NIA
Tota1 retired capacity
Total added capacity
Net peak-hour capacity
Peak-Hour Capacity
(17'7 MW)
60MW
80MW
500MW
108MW
(176 MW)
45MW
36MW
36MW
24 MW
(353 MW)
889MW
536MW
·Note: Extra energy efficiency beyo cost-effective amount determined by DSM potential study.
Jim Bridger Staggered Retirement Year-End 2023 (Unit 1) and Year­
End 2028 (Unit 2) Portfolio
The resource.additions of the portfolio with Jim Bridger retirement in 2023 (Unit I) and 2028
(Unit 2) are driven by capacity deficits beginning in July 2024 and reaching 874 MW by July
2034. This resource portfolio is designated as P12.
P12- Jim Bridger retirement 2023 (Unit 1) and 2028 (Unit 2), SCCT, B2H on line
2025, CCCT
The resource portfolio Pl2 adds a 170 MW simple-cycle combustion turbine in 2024 and the
B2H transmission line in 2025. P 12 also adds a 300 MW combined-cycle combustion turbine in
2029.
Page 114 2015 IRP
Idaho Power Company 8. Portfolio Selection
Table 8.18 Resource portfolio P12
Date Resource Installed Capacity Peak-Hour Capacity
970MW
617 MW
Total added capacity
Net peak-hour capacity
( 177 rvlW) ( 177 rv!W)
170 MW 170 MW
500 rvlW transfer capacity Apr-Sep 500 MW
200 rvlW transfer capacity Oct-Mar
(176 rvlW) (176 MW)
300 rvlW 300 MW
Retire Jim Bridger (Unit 2)
Combined-cycle combustion turbine
Retire Jim Bridger (Unit 1)
Simple-cycle combustion turbine
Boardman to Hemingway
2023
2024
2025
2028
2029
Jim Bridger Staggered Retirement Year-lind2023 (Unit 1) and Year­
End 2032 (Unit 2), North Va/my RetireQ!ent Year-End 2025 Portfolio
The resource additions of the portfolio with Jim Bridger retirement in 2023 (Unit I) and 2032
(Unit 2), and North Valmy retirement in 2025, are driven 6 capacity deficits beginning in July
2024 and reaching 1,137 MW by July 2034. is.resource portfolio is designated as Pl 3.
Resource portfolio Pt3 Table 8.19
P13- Jim Bridger retirement 2023 (Unit 1) and 2032 (Unit 2), North Valmy
retirement 2025, SCCT, B2H online 2025, CCC:r
Resource portfolio P 13 adds a 170 MW simple-cycle combustion turbine in 2024 and the 821-1
transmission line in 2025. P13 also adds a 300 M combined-cycle combustion turbine in 2029,
and a second combined-cycle combustion turbine in Q033.
Date Resource Installed Capacity Peak-Hour Capacity
2023
2024
2025
2025
2029
2032
2033
Retire Jim Bridger (Unit 1)
Simple-cycle combustion turbine
Boardman to Hemingway
Retire North Valmy (both units)
Combined-cycle combustion turbine
Retire Jim Bridger (Unit 2)
Combined-cycle combustion turbine
(177 rvlW)
170 rvlW
500 MW transfer capacity Apr-Sep
200 MW transfer capacity Oct-Mar
(262 MW)
300 rvlW
(176 MW)
300MW
(177 MW)
170MW
500 rvlW
(262 MW)
300MW
(176 MW)
300MW
Total retired capacity
Total added capacity
Net peak-hour capacity
(615 rvlW)
1,270 MW
655MW
2015 IRP Page 115
8. Portfolio Selection
Alternative to Boardman to Hemingway Portfolios
Idaho Power Company
This set of four portfolios replaces the Boardman to Hemingway transmission line with
alternatives. Each Boardman to Hemingway alternative portfolio assumes a different coal
retirement future. Resource portfolio P 14 assumes coal capacity is maintained. Resource
portfolio PIS assumes North Valmy retirement in 2019. Resource portfolio P16 assumes
staggered retirement of North Val my Unit I and Unit 2 respectively in 2019 and 2025. Resource
portfolio Pl 7 assumes staggered retirement of Jim Bridger Unit I and Unit 2 respectively in
2023 and 2032.
P14-lce-based thermal energy storage, reciprocating engines, CCCT, SCCT, no
coal capacity retirement
Resource portfolio PI 4 adds 60 MW of ice-based thermal energy storage in 2025-26, 18 MW of
reciprocating engines in 2026, a 300 MW combined-cycle combustion turbine in 2027, and a I 70
MW simple-cycle combustion turbine in 2032.
Table 8.20
Date
Resource portfolio P14
Resource Installed Capacity Peak-Hour Capacity
2025
2026
2026
2027
2032
Ice-based thermal energy storage
Ice-based thermal energy storage
Reciprocating engines
Combined-cycle combustion turbine
Simple-cycle combustion turbine
15 MW
45MW
18 MW
300MW
170MW
15 MW
45MW
18 MW
300 MW
170 MW
Total retired capacity
Total added capacity
Net peak-hour capacity
(0 MW)
548 MW
548MW
P15-North Valmy retirement 2019, battery storage, reciprocating engines, SCCT,
CCCT
Resource portfolio P 15 adds 60 MW of Vanadium redox flow battery storage in 2020-2021 and
252 MW o reciprocating engines in 2020-25. PI 5 also adds a 170 MW simple-cycle combustion
turbine and a 300 MW combined-cycle combustion turbine in the second halfof the 2020s, 60
MW of battery sto age replacement and 36 MW of reciprocating engines in 2034.
Page 116 2015 IRP
•
Idaho Power Company
Table 8.21 Resource portfolio P15
Date Resource Installed Capacity
2019 Retire North Valmy (both units) (262 MW)
2020 V redox flow battery storage 25MW
2021 V redox flow battery storage 35MW
2021 Reciprocating engines 90MW
2023 Reciprocating engines 108 MW
2025 Reciprocating engines 54 MW
2026 Simple-cycle combustion turbine 170 MW
2029 Combined-cycle combustion turbine 300 MW
2030 2020 battery storage end of life (25 MW)
2030 V redox flow battery storage (replace) 25 MW
2031 2021 battery storage end of life (35MW)
2031 V redox flow battery storage (replace) 35MW
2034 Reciprocating engines 36MW
Total retired capacity
Total added capacity
Net peak-hour capacity
8. Portfolio Selection
Peak-Hour Capacity
(262 MW)
25MW
35MW
90MW
108MW
54 MW
170MW
300MW
(25MW)
25MW
(35 MW)
35MW
36MW
(322 MW)
878 MW
556 MW
P16-North Valmy retirement 2019 (Unit 1) and 2025 (Unit 2), demand response,
reciprocating engines, CCCT, SCCT
The Resource portfolio P16 adds 60 MW of demand response and 90 MW of reciprocating
engines in 2021-25. The 60 MW of demand response is beyond the 390 MW of summer demand
response included as an existing resource in all portfolios. P 16 also adds a 300 MW combined­
cycle combustion turbine and a 170 MW simple-cycle combustion turbine in the second half of
the 2020s. In the early 2030s, 18 MW of reciprocating engines and a 170 MW simple-cycle
combustion turbine are added.
Table 8.22 Resource portfolio P16
Date Resource Installed Capacity Peak-Hour Capacity
2019 Retire North Valmy (Unit 1) (126 MW) (126 MW)
2021 Demand response 15MW 15 MW
2023 Demand response 30MW 30MW
2024 Demand response 15MW 15MW
2024 Reciprocating engines 54MW 54MW
2025 Reciprocating engines 36MW 36MW
2025 Retire North Valmy (Unit 2) (136 MW) (136 MW)
2026 Combined-cycle combustion turbine 300MW 300MW
2029 Simple-cycle combustion turbine 170 MW 170 MW
2031 Reciprocating engines 18 MW 18MW
2032 Simple-cycle combustion turbine 170 MW 170MW
Total retired capacity (262 MW)
Total added capacity 808MW
Net peak-hour capacity 546MW
2015 IRP Page 117
8. Portfolio Selection Idaho Power Company
P17- Jim Bridger retirement 2023 (Unit 1) and 2032 (Unit 2), ice-based thermal
energy storage, PV, CHP, geothermal, CCCT, SCCT
Resource portfolio Pl7 adds a variety of resources, including 250 MW of utility-scale, single­
axis, solar PV. 162 MW of reciprocating engines, 45 MW ofCHP, 30 MW of geothermal, and
60 MW of ice-based thermal energy storage in 2024-29. In the 2030s, P 18 adds a 300 MW
combined-cycle combustion turbine and a 170 MW simple-cycle combustion turbine.
Table 8.23 Resource portfolio P17
Date Resource
2023 Retire Jim Bridger (Unit 1)
2024 Ice-based thermal energy storage
2024 Utility-scale solar PV 1-axis
2025 CHP
2026 Reciprocating engines
2027 Geothermal
2027 Utility-scale solar PV 1-axis
2028 Reciprocating engines
2029 Reciprocating engines
2030 Combined-cycle combustion turbine
2032 Retire Jim Bridger (Unit 2)
2033 Simple-cycle combustion turbine
Installed Capacity
(177 MW)
60MW
175 MW
54MW
54MW
300MW
(176 MW)
170 MW
Tota11'etired capacity
Tota added capacity
Net peak-hour capacity
Peak-Hour
Capacity
(177 MW)
60MW
90MW
45MW
54MW
30MW
38MW
54MW
54MW
300MW
(176 MW)
170 MW
(353 MW)
895 MW
542 MW
North Va/my Staggered Retirement Year-End 2021 (Unit 1) and Year­
End 2025 (Unit 2) Portfolio
After the April 2015 I RP Advisory Council meeting, Jdaho Power received from Advisory
Council member David Hawk (Oil and Gas Industry Advisor), in partnership with Advisory
Council member Ben Olio (Idaho Conservation League), a submittal requesting the analysis of a
portfolio with retirement ofNorth Valmy Unit I in 2021. New resources specified by the
submittal included 82H, demand response, combined heat and power, small hydro, geothermal.
and residential photovoltaic solar. Idaho Power developed a resource portfolio using these
specifications. adding retirement of North Valmy Unit 2 in 2025. With retirement of North
Valmy Unit I in 2021 and Unit 2 in 2025, capacity deficits begin in July 2022 and reach 786
MW by July 2034. The resulting resource portfolio, designed to meet these deficits and the
submitted request for speci tic resource actions, is designated as resource portfolio P 18.
Page 118 2015 IRP
Idaho Power Company 8. Portfolio Selection
P18-North Val my retirement 2021 (Unit 1) and 2025 (Unit 2), residential PV solar,
demand response, CHP, B2H online 2025, geothermal, small hydro, reciprocating
engines
Resource portfolio P 18 adds 20 MW of residential photovoltaic solar, 60 MW of demand
response, a 45 MW combined heat and power facility in 2022-24 and the B2H transmission line
in 2025. The 60 MW of demand response is above and beyond the 390 MW of summer demand
response included as an existing resource in all portfolios. P 18 adds 3 MW of residential
photovoltaic solar per year in 2031-34, 40 MW of geothermal in 2031, 45 MW of combined heat
and power in 2032, 60 MW of small hydro in 2033, and 18 MW of reciprocating engines in
2034.
Table 8.24 Resource portfolio P18
Date Resource Installed Capacity Peak-Hour Capacity
2021 Retire North Valmy (Unit 1) (126 MI/V) (126 MI/V)
2022 Residential PV solar 5MW 2MW
2022 Demand response 10MW 10MW
2023 Residential PV solar 5MW 2MW
2023 Demand response 30MW 30MW
2024 Residential PV solar 10 MI/V 3 MI/V
2024 Demand response 20 MI/V 20 MI/V
2024 CHP 45MW 45 MI/V
2025 Boardman to Hemingway 500 MI/V transfer capacity Apr-Sep 500 MI/V
200 MI/V transfer capacity Oct-Mar
2025 Retire North Valmy (U u 2) (136 MI/V) (136 MI/V)
2031 '10 MW 3MW
2031 Geothermal 40 MI/V 40 MI/V
2032 10MW 3MW
2032 CHP 45MW 45MW
2033 Residential PV solar 10MW 3MW
2033 Small hydro 60MW 60MW
2034 Residential PV solar 10MW 3MW
2034 Reciprocating engines 18MW 18MW
Total retired capacity (262 MI/V)
Total added capacity 766 MI/V
Net peak-hour capacity 504 MW
Portfolio Design Summary
The 23 portfolios analyzed for the 2015 I RP consider a range of alternatives with regard to early
coal retirement and the Boardman to Hemingway transmission line. The following table provides
a summary of the 2015 IRP portfolio scenarios on the basis of early coal retirement and the
Boardman to I lemingway transmission line.
2015 IRP Page 119
8. Portfolio Selection Idaho Power Company
Table 8.25
Coal
Resource portfolio scenario summary
B2H Alternative to B2H
No coal capacity retirement
Early retirement - North Valmy
Early retirement- Jim Bridger
Early retirement - North Valmy and Jim Bridger
4
11
3
2
Page 120 2015 IRP
Idaho Power Company 9. Modeling Analysis and Results
9. MODELING ANALYSIS AND RESULTS
Idaho Power evaluated the costs of each resource portfolio over the full 20-year planning
horizon. The resource portfolio cost is the expected cost to serve customer load using all
resources in the portfolio. Portfolio costs are expressed in terms 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 includes
annualized capital costs for new portfolio resources, including transmission interconnection costs
for new generating facilities, and fixed operations and maintenance (O&M) costs and return on
investment. Capital costs for new resources are annualized over the resource's estimated
economic life. Annualized capital costs beyond the IRP planning window (2015-2034) are not
included in portfolio costs.
Coal retirement portfolios include costs for accelerated recovery of remaining depreciation
expense and accelerated recovery of decommissioning and demolition costs (net of salvage). The
costs of coal retirement portfolios are countered by savings from avoiding future coal plant
capital upgrades, including environmental retrofit upgrades, and from avoiding future fixed
operating expenses and return on investment.for the retired coal unit(s).
Idaho Power uses the AURORAxmp® (AURORA) electric market model as the primary tool for
modeling resource operations and determining operating costs for the 20-year planning horizon.
AURORA modeling results provide detailed estimates of wholesale market energy pricing and
resource operation and emissions data.
The AURORA software applies economic principles and dispatch simulation to model the
relationships between generation, transmission, and demand to forecast market prices.
The operation of existing and future-resources is based on forecasts of key fundamental
elements, such as demand, fuel prices, hydroelectric conditions, and operating characteristics of
new resources. Various mathematical algorithms are used in unit dispatch, unit commitment.
and regional pool pricing logic. The algorithms simulate the regional electrical system to
determine how utility generation and transmission resources operate to serve load.
Multiple electricity markets, zones, and hubs can be modeled using AURORA. Idaho Power
models the entire WECC when evaluating the various resource portfolios for the IRP. A database
of WECC data is maintained and regularly updated by the software vendor EPIS, Inc. Prior to
starting the IRP analysis, Idaho 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 model that is
more deterministic in character and provides a more specific operational view of the WECC.
Portfolio costs are calculated as the net present value (NPV) of the 20-year stream of annualized
costs, fixed and variable, for each portfolio. The full set of financial variables used in the
2015 IRP Page 121
9. Modeling Analysis and Results Idaho Power Company
analysis is shown in Table 9.1. Each resource portfolio 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)................................................................................. 6.74%
Composite tax rate.................................................................................................. 39.10%
Deferred rate....................................................................................................... 35.00%
General O&M escalation rate............................................................................................................... 2.20%
Annual property tax escalation rate (% of investment) . 0.29%
Property tax escalation rate 3.00%
Annual insurance premium(% of investment)..................................................................................... 0.31%
Insurance escalation rate........................................................................................ 2 OOo/o
AFUDC rate (annual)........................................................................................................................... 7.75°/o
CAA Section 111 (d) Sensitivity Analysis
Idaho Power developed multiple sensitivities for the EPA 's proposed rule for regulating C02
emissions from existing generating sources under CAA Section 111 (d). The multiple sensitivities
are a reflection of the considerable uncertainty related to the stipulations of the finalized rule
scheduled to be issued in Summer 2015. Each sensitivity, with the exception of a null sensitivity
in which no restrictions are assumed, is based on a set of assumptions on compliance stipulations
for the final rule. Analyzing multiple sensitivities alJows the estimation of a range of possible
cost impacts from CAA Section 111 (d). The cost sensitivity analysis could provide information
to state-level agencies tasked with development of state plans for CAA Section I I I (d)
implementation.
The analyzed CAA Section J 11 (d) sensitivities are described by four categories:
• Nul sensitivity (no CAA Section 111 (d))
• State-by-state mass-based compliance
• System-wide mass-based compliance
• Emissions intensity compliance utilizing the EPA 's compliance building blocks.
Null sensitivity (no CAA Section 111(d))
Idaho Power analyzes a null sensitivity to provide a comparison with portfolios complying with
regulations on C02 emissions for existing power plants. The only portfolio analyzed under the
null sensitivity is the status quo portfolio (PI). which maintains coal capacity and meets planning
period deficits with 82H in 2025 and 36 MW of reciprocating engines in 2034.
Page 122 2015 IRP
Idaho Power Company
State-by-State Mass-Based Compliance
9. Modeling Analysis and Results
Under state-by-state mass-based compliance. CAA Section 111 (d)'s proposed state-specific
target reductions are the basis for compliance. The proposed rule's treatment of Langley Gulch is
uncertain as it was brought on line midway through EPA 's 2012 baseline year. Consequently
Langley Gulch is assumed to be constrained at one of three possible annual capacity factors:
30% (837,018 MWh), 55% (1,534,533 MWh). or 70% (1,953,042 MWh). The proposed target
reductions are defined in Table 9.2.
Table 9.2 Proposed target reductions - State-by-state mass-based compliance (IPC share)
Affected Source
Jim Bridger
North Valmy
Boardman
2020-2029 Target MWh
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)
2030- Target MWh
3,675,608 MWh
(19.1% below 2012 MWh)
533,343 MWh
(34.5% below 2012 MWh)
137,029 MWh
(48.1 % below 2012 MWh)
Langley Gulch Target 30%, 55%, or 70% annual capacity factor 2020-2034
System-Wide Mass-Based Compliance
Under system-wide mass-based compliance, CAA Section 11 I (d) compliance is based on
adherence to C02 limits imposed at an individual utility system level. The assumed Idaho Power
system-level limits were derived to be consistent with EPA 's proposed state-specific target
reductions. Under this approach, system-wide emissions, which include emissions from Langley
Gulch and Idaho Power's share of Jim Bridger and North Valmy, are constrained to 6,332,020
tons ofC02 for 2020-2029 and to 5,925,874 tons of C02 for 2030 and beyond. Compared to
2012 system-wide emissions, these constraint levels are lower by 20% (2020-2029 constraint)
and 25% (2030 and beyond constraint).
Emissions 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 compliance. Key lo the building block approach for achieving compliance are
the reduction ofC02 emissions through re-dispatch of affected sources, and the development of
renewable energy and energy efficiency resources leading to a reduction in emissions intensity.
Idaho Power makes the following assumptions in utilizing the EPA 's building blocks as the basis
for CAA Section 111 (d) compliance:
• Boardman coal plant is reduced to a zero production level and retired by year-end 2020
• North Valmy 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 retirement Idaho Power's share of North
2015 IRP Page 123
9. Modeling Analysis and Results Idaho Power Company
Val my is assumed to have an annual production constraint equal to its 2012 production
level (IPC share= 814,264 MWh)
• Jim Bridger coal plant is reduced to a production level 53,320 M Wh less than its 2012
production level of 4.541,712 MWh (IPC share); the redispatch of Jim Bridger is to a
new 95 MW combined-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 of30% (837,018 MWh), 55% (1,534,533 MWh), or 70%
(1.953.042 MWh)
• Renewable energy and energy efficiency resources are developed in Idaho to the EPA's
proposed target levels
Baseline CAA Section 111(d)
Among the sensitivities developed for the 2015 IRP, Idaho Power selected a baseline sensitivity
for initial portfolio cost analysis. The baseline CAA Section 11 l(d) portfolio cost analysis
assumes state-by-state mass-based compliance with Langley Gulch constrained at a 30% annual
capacity factor. The selection of these assumptions for the bas line analysis is not a reflection of
Idaho Power's preference for CAA Sectio� 11 (d). Nor is it a indication of the company's view
of the most probable CAA Section 111 (d) utcome. Rather, it is selected to provide information
in comparing costs between portfolios. The baseline cos identify portfolios for further analysis
under other CAA ection 111 (d) sensitivities and for lie stochastic risk analysis. The resu Its of
the baseline CAA Section 11 l(d) sensitivity analyses are provided in Table 9.3.
Page 124 2015 IRP
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9. Modeling Analysis and Results Idaho Power Company
Notes:
1 All portfolios assume CAA Section 111 (d} implementation except for Portfolio P1.
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 the new portfolio resources and compliance v.1th CAA Section 111 (d) (when
applicable). The reservation charge for new & existing NG plants is calculated m AURORA.
3 Fixed costs of existing resources are excluded except as needed in accounting for coal retirement portfolios.
• Denotes portfolios that were studied in the stochastic risk analysis
The selection of portfolios for further analysis indicated in the table above is based on the results
of the baseline CAA Section 11 l(d) analyses as well as discussions held at IRP Advisory
Council meetings in which participants voiced a desire to further analyze a relatively broad
spectrum of portfolio types (e.g., portfolios with and without 82H).
CAA Section 111(d) sensitivity analysis - results
The analysis of portfolio costs under the different CAA Section 111 (d) sensitivities indicates that
portfolio relative performance does not change significantly across the sensitivities; low cost
portfolios under the baseline CAA ection 111 (d) sensiti ity tend to have low costs under the
other sensitivities. Cost impacts of CAA Section 111 (d) are greatest when individual coal plant
dispatch decisions are mandated under a state-by-state approach. 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 basis for CAA Section) l(d) compliance and
Langley Gulch is assumed to be able to run up to a capacity factor of 70 percent (approximately
1.95 million MWh annually). Under the building block approach, Idaho Power also assumes that
North Valmy can be operated at 2012 production levels (annually) until retirement, and Jim
Bridger can be operated at annual production levels 53,320 MWh less than 2012 production
levels. For reference, portfolio Pl costs under the null sensitivity are $4,417 million. Table 9.4
provides the results of the CAA Section 111 (d) sensitivity analysis.
Page 126 2015 IRP
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Idaho Power Company
Stochastic Risk Analysis
9. Modeling Analysis and Results
The stochastic analysis assesses the effect on portfolio costs when select variables take on values
different from their planning case levels. Stochastic variables are selected on the basis of the
degree to which there is uncertainty regarding their forecasts, and to the degree they can affect
the analysis results (i.c., portfolio costs).
Idaho Power identified the following three variables for the stochastic analysis:
I. Natural gas price-Natural gas prices follows a log-normal distribu ion centered on the
planning case forecast. Natural gas prices are serial correlated, and the serial correlation
is based on the historic year-to-year correlation from 1990 through 2014. The serial
correlation factor is 0.65.
2. Customer load-Customer load follows a normal distribution and is correlated with
Pacific Northwest regional load. Idaho Power worked with the Northwest Po er and
Conservation Counci I (NWPCC) as part of research conducted for the 2013 IRP to
estimate the correlation between Idaho Power customer load and regional customer load.
The correlation factor is 0.50.
3. Hydroelectric variability--Hydroelectric variability follows a normal distribution.
Idaho Power-owned hydroelectric generation is correlated with the Paci tic Northwest
regional hydroelectric generation, and the correlation factor is 0.70. This correlation was
derived using historical stream now data from 1928 through 2009.
The three selected stochastic variables are key drivers of variability in year-to-year power supply
costs, and thus provide suitable stochastic shocks to allow differentiated results for analysis.
Stochastic analysis was performed under the system-wide mass-based limits on C02 emissions.
This assumption was selected because all eleven portfolios can comply with CAA Section 111 (d)
under this compliance approach. Moreover, the objective of the stochastic analysis is to
determine the cost impact when portfolios arc stochastically shocked. The purpose of the
analysis is to understand the range of portfolio costs across the full extent of stochastic shocks
(i.e., across the full set of stochastic iterations), and how the ranges for portfolios differ.
Idaho Power created a set of I 00 iterations based on the three stochastic variables. Idaho Power
then calculated the portfolio cost for eleven portfolios, where the eleven portfolios were selected
based on results of initial cost analysis under the baseline CAA Section 111 (d) sensitivity or to
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
20-year planning period. Figure 9.1 shows the stochastic analysis results.
2015 IRP Page 129
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Idaho Power Company 9. Modeling Analysis and Results
In Figure 9.1, the horizontal axis is the portfolio 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 for the
I 00 stochastic iterations. The figure ii lustratcs portfolio costs at the 5% and 95% 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 50% excecdance level.
Figure 9.1 illustrates portfolio P9. a North Yalmy early retirement portfolio with 82H, is least
cost for the full set of I 00 iterations. Portfolios are relatively clustered across the top nine least
cost portfolios, with 82H alternative portfolios P 16 and P 17 somewhat set apart with higher
costs.
While not easily discerned, there is some crossing of the portfolio-speci fie I ines in Figure 9. I.
Significant crossing of lines in the exceedance graph is an indication of substantial portfolio
disparity; portfolio cost performance in this case is markedly different across the set of stochastic
iterations. As an example, a portfolio consisting of exclusively 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 resourced iversity of Idaho Power" s existing portfolio and the portfolios of new
resources considered in the IRP; under no set of stochastic futures is a portfolio a clear and
runaway cost winner, only to be countered by a different set of futures for which it's just as
clearly a losing portfolio susceptible to significantly higher co ts than other portfolios.
Portfolio cost - assessment of year-to-year variability
At the request of participants in the IRP Advisory Council process, Idaho Power has expanded
the stochastic analysis or the 2015 IRP to include an assessment of year-to-year portfolio cost
variability. This assessment of year-to-year variability allows portfolios to be compared on the
basis of their susceptibility to large year-to-year price swings. Idaho Power assesses the year-to­
year variability by use of the standard deviation metric. For each stochastic iteration, the standard
deviation of the 20-year stream of AURORA-determined variable costs (converted to base 2015
dollars) is calculated. Thus, each of the eleven portfolios for which stochastic analysis is
performed has I 00 different standard deviation measures corresponding to the I 00 different
stochastic iterations. Portfolios susceptible to large year-to-year price swings tend to have larger
standard deviations.
An exceedance graph of the standard deviations for each of the eleven portfolios is shown as
Figure 9.2. The exceedance graph indicates that portfolio P3, which adds just over 400 MW of
utility-scale photovoltaic solar, is least susceptible to large year-to-year swings. Portfolio P 16,
which adds more than 700 MW of natural gas-fired generating capacity, is most susceptible to
large year-to-year swings.
2015 IRP Page 131
9. Modeling Analysis and Results
100%
Idaho Power Company
70%
10%
0% -
20M 30M 40M 50M 60M 70M SOM 90M 100M
-P2a
-P3
-P6b
PS
-P9
-PIO
-P11
-P13
-P16
-P17
-P18
110M 120M
Figure 9.2
Standard Deviation (2015 $ millions)
Exceedance graph of standard deviations
Tipping-Point Analysis
To test the sensitivity of total portfolio cost to capita cost estimates, Idaho Power conducted a
tipping point analysis for portfolio P3, which has a nigh penetration of utility-scale single-axis
photovoltaic solar, and portfolio P7, which has 00 MW of pumped-storage hydro. In the tipping
point analysis, the change in total portfolio cost is determined as a function of change in capital
cost. The capital cost of the solar resource is varied for portfolio P3, and the capital cost of
pumped-storage hydro is varied for portfolio P7. The percent change in capital cost is relative to
planning case capital costs estimates, where the solar resource under planning case is estimated
at $1,250/k (for capacity constructed in 2017 or later) and pumped-storage hydro is estimated
at $5,000/kW. A graph of the tipping point analysis results is provided in Figure 9.3. As an
example, the graph illustrates that a change in utility-scale single-axis photovoltaic solar of -30%
results in an estimated decrease in total portfolio costs for portfolio PJ of $50 million (NPV).
Page 132 2015 IRP
Idaho Power Company 9. Modeling Analysis and Results
S225M
S200M
S175M
S150M .;. ., S125M e � S100M 1 $75M .; 0 $50M u .!:! S25M 0 t: SM 0 0.. ·S25M ;; 0 ·S50M ... .s -S75M .. Cl ·S100M c .. s: -$125M u
-S150M
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-50% -40% -30% -20% -10% 0% 10% 20% 30% 40% 50%
Example. 30% reduction ,n
SOLAR PV costs leads 10 aboul $50 molllon reduction ,n
P3costs
�Portfolio
P3. only varying capital cost
for single axis SOLAR PV
-Portfoho P7· only varying capital cost
for PUMPED HYDRO STORAGE I
Figure 9.3
Change In Capital Cost ("lo)
Tipping point analysis results
Portfolio Emissions
For the 2015 !RP, Idaho Power analyzed the total portfolio emissions for the 20-ycar planning
period by the following four emission types:
I. C02-A greenhouse gas associated with climate change
2. NOx-Contributes to regional haze
3. S02-Contributes to acid rain formation
4. Hg-A toxic element found in coal deposits
Total emissions by type were calculated using AURORA emissions modeling. The total
emissions for each portfolio include emissions from new resources in addition to emissions from
Idaho Power's existing resources. With the exception of portfolios retiring Jim Bridger Units I
and 2 without installation ofNOx-controlling environmental retrofits, all portfolios comply with
environmental regulatio s. Illustrations of the four emission types for the eleven portfolios on
which CAA Section 111 (d) sensitivity and stochastic analysis were performed are provided in
the Appendix C-Technical Appendix.
Qualitative Risk Analysis
The qualitative risks associated with the portfolios are more difficult to assess. The goal is to
select a portfolio that is likely to withstand unforeseen 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 IRP Page 133
9. Modeling Analysis and Results Idaho Power Company
risks within the portfolios and describes Idaho Power's interpretation of the risk profiles
associated with each resource and acknowledges that the portfolios may contain unique and
differing risks.
Existing Generation
Hydro-Water Supply Risk
The long-term sustainability of the Snake River Basin stream flows is important for Idaho Power
to sustain hydro generation as a resource to meet future demand. Several assumptions related to
the management of stream flows were made in developing the twenty-year stream flow forecasts
for the IRP. These assumptions include:
• The implementation of aquifer management practices on the eastern Snake River Plain
including aquifer recharge, system conversions, and the Conservation Reserve
Enhancement Program (CREP)
• Future irrigation demand and return flows
• Declines in reach gains tributary to the Snake River
• The expansion of weather modification (i.e., cloud seeding) efforts.
The assumptions used in developing the twenty year streamflow forecast are carefully planned
and based on the current knowledge of Idaho Power staff in consultation with other stakeholders.
Those assumptions are also subject to the limitations of the current models used in developing
the twenty-year stream flow forecast for the 2015 TRP.
Additional risks to future hydro generation not included in the development of the twenty-year
streamflow outlook consist of:
• Changes in the timing and demand for irrigation water due to climate variability
• C anges to the sources of flow augmentation water and the potential for overestimation
of tl w augmentation availability in low water years
• Long-term changes in the timing of flood control releases at Brownlee Reservoir in
response to earlier snowmelt
• The potential for underestimation of the decline in reach gains within the Snake River
Basin
• Changes to funding or ability to achieve forecasted levels of aquifer management on the
ESPA.
Relicensing Risk
Working within the constraints of the original FERC licenses. the I lclls Canyon Complex has
historically provided operational flexibility which has benefited Idaho Power's customers. The
Page 134 2015 IRP
Idaho Power Company 9. Modeling Analysis and Results
operational flexibility of the Hells Canyon Complex is increasingly critical to the successful
integration of variable energy resources. 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 Powers
ability to optimally manage the Hells Canyon Complex, making the integration of variable
energy resources more challenging and ultimately increasing power supply costs.
Fossil fuel-fired power generation and proposed EPA CAA Section 111(d) rule
risks
In 2014, the EPA released, under CAA Section 11 l(d), a proposed rule for addressing
greenhouse gas emissions from existing fossil fuel-fired electric generating units. The EPA's
proposal requires that states meet their goal by 2030, with interim goafs from 2020 to 2029. The
EPA has stated that it expects to finalize the rulemaking by summer 2015. State., implementation
plans would be due by June 20, 2016, subject to extension for portions of the plan to June 30,
2017 for state plans or June 20, 2018 for multi-state plans, under certain circumstances. Since
this is a proposed rule, it is subject to interpretation and change. Thei;,.e is considerable
uncertainty on the stipulations of the final rule, and the resulting impact on fossil fuel-fired
generation on Idaho Power's system and throughout the region.
Regulatory risk
Idaho Power is a regulated utility with an obligation to serve custom er load in its service area
and therefore is subject to regulatory risk. Idaho Power expects tha future resource additions and
removals will be approved for inclusion in rate bas apd that it will be allowed to earn a fair rate
of return on investments related to resource actiont.: f the I RP portfolios. Idaho Power includes
public involvement in the !RP process through an I.J{.P Advisory Council and by opening the IRP
Advisory Council meetings to the public. The open public process allows a public discussion of
the IRP and establishes a foundation of customer understanding and support for resource
additions and removals when the plan is submitted for approval. The open public process reduces
the regulatory risk associated with developing a resource plan.
NOx Compliance alternatives risk
Portfolios with early retirement of Jim Bridger Units I and 2 assume these units are permitted to
operate until retirement without installation of selective catalytic reduction (SCR) retrofits
necessary for compliance with EPA regional haze regulations. All other portfolios assume the
SCR retrofits are installed on schedule in 2021 for Unit 2 and 2022 for Unit I. The permitting
associated with the Jim Bridger early retirement compliance alternatives is highly speculative at
this point. /\n inability to successfully achieve permitting consistent with the assumptions of
these compliance alternatives would likely have significant effect on the costs and feasibility of
portfolios with early retirement of Jim Bridger Units I and 2.
New Generation
Resource Commitment Risk
Idaho Power faces risk in the timing of, and commitment to, new resources. There are a number
of factors that influence the actual timing of resource planning including the pace of PURPA
2015 IRP Page 135
9. Modeling Analysis and Results Idaho Power Company
resource development, siting issues, partnership in fluences, 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 part 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 alter the resource adequacy picture. Idaho
Power's practice is to include PURPA projects that arc operational or under signed contract.
ince the 2015 I RP process began in late summer 2014, Idaho Power has signed contracts for
461 MW of solar PURPA projects, and has received inquiries for an additional 885 MW.
ince including the 461 MW of solar contracts as part of committed system resources in the 2015
IRP. contracts for four solar PURPA projects totaling 141 MW have been terminated, leaving
320 MW still under contract. Table 9.5 illustrates the effect of removing the 141 MW of solar
PURPA projects with terminated contracts on the 2015 IRP first deficit year.
Table 9.5 First peak-hour capacity deficit - effects of removing 141 MW of solar PURPA
Scenario
Status quo
Maintain coal capacity
Valmy retire units 1 and 2 year-end 2019
Valmy retire units 1 and 2 year-end 2025
Valmy retire unit 1 year-end 2019 and unit 2 ye i'r-end 2025
Valmy retire unit 1 year-end 2021 and unit 2 year-end 2025
Bridger retire unit 1 year-end 2023 and unit 2 year-end 2028
Bridger retire unit 1 year-end 2023 and nit 2 year-end 2032
Bridger retire unit 1 year-end 2023 and uni 2 year-end 2032,
Valmy retire units 1 and 2 year-end 2025
1•1 deficit without
151 deficit 2015 IRP 141 MW solar PURPA
July 2025 July 2024
July 2025 July 2024
July 2020 July 2020
July 2025 July 2024
July 2021 July 2021
July 2022 July 2022
July 2024 July 2024
July 2024 July 2024
July 2024 July 2024
As 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 deficiencies, and
ultimately may require ldaho Power to construct system resources earlier than expected and with
larger capacities.
While uncertainty related to potential over-forecasting of PURPA development is a critical risk
element from the perspective of resource adequacy, PURPA development also carries the
potential for under-forecasting. The potential for under-forecasting is evidenced by the October
13. 2014 filing of signed contracts for401 MW of solar PURPA projects, out ofthe 461 MW in
total; over the course of a day, the PURPA forecast grew by 401 MW. While under-forecasting
does not jeopardize system 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 2015 IRP
Idaho 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 I RP 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 8211
transmission line. Environmental requirements related to siting of the transmission line have the
potential to bring about project delays and increased permitting costs. The completion date of the
project is subject to these siting, permitting, and regulatory approval requirements. The needs of
the partners, PacifiCorp and BPA, also impact the in-service date.
Regional Resource Adequacy
Regional resource adequacy is part of the regional transmission planning process. In July 2013,
the Northwest Power and Conservation Council (NWPCC) approved a charter for the.Resource
Adequacy Advisory Committee (RAAC). The Rt\Avs purpose is to assess power supply
adequacy in the Northwest. Idaho Power has participated in the RAAC since its inception, and
also participated in the NWPCC's Resource Adequacy Forum, which preceded the RAAC.
The NWPCC has adopted an adequacy standard used by the RA Casa metric for assessing
resource adequacy. The purpose of the resource adequacy standard is to provide an early warning
should resource development fail to keep pace with demand growth. The analytical information
generated with each resource adequacy assessment assists the regional utilities when preparing
their individual IRPs. The statistic used to assess compliance with the adequacy standard is the
likelihood of supply shortage, which is commonly known as the loss of load probability (LOLP).
Under the adequacy standard, the LOLP is held to a maximum level of 5 percent.
The RAAC has issued d aft report on· an assessment of LOLP for the 2020 and 2021 operating
years. The LOLP for the 2020 operating year is just under the 5 percent adequacy standard level.
For the 2021 operating year tie OLP increases to a little over 8 percent. The draft RAAC report
indicates tha t e increased LO P for the 2021 operating year is the resu It of planned retirements
of coal-fired generating capacity at Centralia, Washington and the Boardman power plant. The
RAAOiadequacy assessme t otes t�t the 2021 LOLP would be brought to below the 5 percent
level by adding resources providing the equivalent of I, 150 MW of d ispatchable generation. The
RAAC also notes that the LOLP analysis for both operating years does not include planned new
generating resources in the region, because these resources, while planned, have yet to be sited or
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 Paci fie Northwest in addressing their opposing seasonal capacity deficits.
2015 IRP Page 137
9. Modeling Analysis and Results Idaho Power Company
The Idaho Power resource planning process is consistent with the NWPCC resource 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 B2H arc
the lowest cost portfolios.
DSM implementation
While Idaho 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 from the estimated amounts if customer participation rates arc not achieved.
New technologies
Many of the portfolios include technologies that Idaho Power has limited experience in
developing, building, or operating. This lack of direct experience increases the risk associated
with the development of these resources including:
• Price Risk: Cost estimates for solar are based on a 2014 Lazard report. While this report
provides an objective, third party estimate of resource costs, {here is risk that trends in
solar pricing may not be properly captured by the Lazard report.
• Siting Risk: Several of the technologies involve differen risks associated with the type of
resource being developed:
• Fuel types such as gas may encounter pub1ic and political pressure against a project
being located near load centers or being constructed at all.
• Technologies such as Cl IP and ice-based TES would require a large commercial or
industrial customer to partner with Idaho.Power.
Geothermal, pumped storage, and canal drop hydro require the facility to be sited at the source of
the motive force. These projects are often located in remote locations far from load centers which
increase the development and transmission costs associated with the resource.
Preferred Portfolio
On the basis of the 2015 IRP's quantitative and qualitative analysis, the preferred portfolio
selected by Idaho Power is portfolio P6(b). P6(b) balances the cost, risk and environmental
concerns identified in this IRP. The retirement of the No11h Yalmy plant and the completion of
B2H in 2025 balances the risks of CAA Section 111 (d), increases in unplanned intermittent and
variable generation, and is shown to be cost competitive. Portfolio 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. These
resource additions late in the planning period address projected needs for resources providing
peaking capability and system flexibility. With expected long-term expansion of variable energy
resources, the need for dispatchable resources that provide system flexibility will also increase.
Page 138 2015 IRP
Idaho Power Company
Analysis of Shoshone Falls Upgrade
9. Modeling Analysis and Results
For the 2015 IRP, Idaho Power analyzed the benefits and costs of the 50 MW expansion of the
Shoshone Falls power plant. The incremental electrical generation the plant v ould produce with
the expansion is on average approximately 200 GWh annually. Using the AUROA model, an
analysis was performed to determine the value this incremental hydro generation would provide
to the system. The incremental generation is assumed to be eligible for Renewable Energy
Certificates (REC) and the value of these certificates is included in the benefit calculation. The
cost of the project was updated using 2015 IRP assumptions.
The analysis indicates that the incremental energy produced from the expansion is projected to
yield over the 20-year planning period a benefit to the preferred portfolio of approximately $13.8
million on an NPY basis under planning case assumptions for natural gas price, customer load,
and hydroelectric generation. However, as noted in Chapter 5, nearly 75% of the incremental
energy in an average year is produced during the six-month period from January through June,
with substantially less production during the months of July through September. Thus, while the
analysis indicates some economic benefit from the incremental energy, the 50 MW hoshonc
Falls expansion cannot be linked to an !RP-determined resource need as it provides little to no
capacity or energy during peak summer load months.
As a result, Idaho Power will explore construction of a smaller-sized upgrade to more cost
effectively replace the aging 0.6 MW and 0.4 MW units at Shoshone Falls. The smaller upgrade
will allow energy benefits to be realized through a much higher annual capacity factor and fulfill
I icensc requirements associated with beneficial use of stream flow at the project location.
Conceptual-level analysis indicates an upgrade having capacity ranging in size from 1.7 MW to
4.0 MW is well suited for the hydraulic characteristics of the existing facilities. Cost analysis
conducted as part of the conceptual-level study indicates energy from the smaller upgrade can be
produced at a 40-year levelized cost of approximately $50-$55 per MWh for the 4.0 MW
upgrade and $60-$65 per MWh for'the 1.7 MW upgrade. As indicated in the Action Plan in
Chapter I 0, Idaho Power will continue study of the smaller upgrade options. and seek an
amendment of the current FER license to allow for construction of a smaller-sized capacity
upgrade to commence in 2017.
Capacity Planning Margin
Idaho Power discussed planning criteria with state utility commissions and the public in the
early 2000s before adopting the present planning criteria. Idaho Power's future resource
requirements are not based directly on the need to meet a specified reserve margin.
The company's long-term 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 I RP, Idaho Power calculated the capacity planning margin
resulting from the resource development identified in portfolio P6(b). the preferred resource
portfolio. When calculating the planning margin. the total resources available to meet demand
consist of the additional resources available under the preferred portfolio plus the generation
2015 IRP Page 139
9. Modeling Analysis and Results Idaho Power Company
from existing and committed resources assuming expected-case (50111-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 (50111-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.
Idaho Power maintains 330 MW of transmission import capacity above the forecast peak load to
cover the worst single planning contingency. The worst single planning contingency is defined as
an unexpected loss equal to Idaho Power's share of two units at the Jim Bridger coal facility or
loss of Langley Gulch. The reserve level of330 MW translates into a reserve margin of over IO
percent, and the reserved transmission capacity allows Idaho Power to import energy during an
emergency via the NWPP. A 330-MW reserve margin also results in the attainment of a loss-of­
load expectation (LOLE) of roughly 1 day in IO years, a standard industry measurement.
Capacity planning margin calculations for July of' each year through the planning period are
shown in Table 9.6.
Page 140 2015 IRP
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Idaho Power Company
Flexible Resource Needs Assessment
9. Modeling Analysis and Results
Idaho Power analyzed the need for flexible resource as directed by the Oregon PUC in Order 12-
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 overcome the generation shortfall). Idaho Power determined that
there are likely to be insufficient down-regulation resources available at certain times of the year.
Specifically, down-regulation deficiencies occur during periods ofovcrsupply when all of the
Idaho Power generation resources arc reduced to safe operating levels, yet company generation
plus the intermittent generation exceeds customer load.
Idaho Power analyzed the flexible resource needs using the data developed for the solar
integration study. The data consist of actual load, actual wind, and simulated PV solar generation
for 500 MW of solar plant at six geographic locations throughout Idaho Power's service area.
The data were developed at five-minute intervals over three water years from October 20 IO
through September 2013.
The first step in the analysis was to estimate the flexible resource requirement. Idaho Power
calculated the flexible need requirement in 5-, I 0-, 15-, 30-, 45-, and 60-minute intervals from
the dataset and the results are presented in Figure 9.7 below. The one-percent likelihood shown
in Figure 9.4 is the total likelihood; the one-percent likelihood is composed of one-half percent
up plus a one-half percent down.
20%
15% "O IV 10% 0 ...J - 5% Cl.) z 0% - 0 - -5% c: Cl.) o -10% � Cl.) a, -15%
-20%
0 10 20 30 40 50 60 70
Figure 9.4
Minutes
- - - · Load Net (Wind, Solar) -- Load
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.
2015 IRP Page 143
9. Modeling Analysis and Results Idaho Power Company
Idaho Power used a resource dispatch simulation of the Idaho Power system to forecast available
system flexibility after adding 500 MW of PY solar to the generation mix. The purpose of the
simulation is to assess both the regulation requirement and supply. The simulation was
performed using a one-hour time step. Up-regulation and down-regulation quantities were
assessed to determine 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 (April 2012
historical data with the addition of500 MW of PY solar on the system).
1000
800
600
400
200
0
-200
-400
-600
-800
-- Reg Up Avail
--RegUpReq
-- Reg Up Violation
-- Reg Down Violation
-- Reg Down Req
-- Reg Down Avail
-1000
3/31/2012 4/5/2012 4/10/2012 4/15/2012 4/20/2012 4/25/2012 4/30/2012
Figure 9.5 System regulation
Figure 9.5 shows the five quantities:
I. Up-regulation available
2. Up-regulation requirement
3. Regulation violation (both up and down)
4. Down-regulation requirement
5. Down-regulation avai I able
Figure 9.9 below is simplified to focus on the regulation violation by removing the lines showing
the regulation requirement and the regulation available.
Page 144 2015 IRP
Idaho Power Company
1000
800
600
400
200
s 0 'r v ij ij v
�
i ::;
-200
-400
-600
-800
9. Modeling Analysis and Results
-- Reg Up Violation
-- Reg Down Violation
-1000 l ·---
3/31/2012 4/512012 4/10/2012 4/15/2012 4/20/2012 4/25/2012 4/30/2012
Figure 9.6 Regulation violations, spring 2012
Figure 9.6 shows significant down-regulation violations during certain hours of the spring. The
down-regulation violations occur during periods of oversupply when all of the Idaho Power
generation resources are reduced to safe operating levels, yet company generation plus the
intermittent generation exceeds customer load. There are no up-regulation violations during the
April study period.
-- Reg Up Avail
--RegUpReq
-- Reg Up Violation
-- Reg Down Violation
-- Reg Down Req
-- Reg Down Avail
600
200
400
0
-200
-400
-600
-800
1000
800
Idaho Power analyzed the other. three seasons of the year and determined that regulation is
primarily an issue during the-spring. The graphs for summer, fall, and winter are shown in
figures 9.7 through 9.9 be ow:
i
-1000 L
7/10/2012 7/15/2012 7/20/2012 7/25/2012 7/30/2012 8/4/2012 819/2012
Figure 9.7 Regulation violations, summer 2012
2015 IRP Page 145
9. Modeling Analysis and Results Idaho Power Company
1000
800
600
400
200
0
-200
-400
-600
-800
-- Reg Up Avail
--Reg UpReq
--Reg Up Violation
-- Reg Down Violation
-- Reg Down Req
-- Reg Down Avail
-1000
10/10/2011 10/15/2011 10/20/2011 10/25/2011 10/30/2011 11/4/2011 11/9/2011
Figure 9.8 Regulation violations, fall 2011
As shown in the graphs, the regulation violation I ine 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 Idaho Power system is operating at the regulation
limits. The simulations show that it is more likely for the Idaho Power system to face down­
regulation I imits than up-regulation limits.
-1000
12/15/2011 12/20/2011 12/25/2011 12/30/2011
-- Reg Up Avail
--RegUpReq
-- Reg Up Violation
-- Reg Down Violation
-- Reg Down Req
-- Reg Down Avail
1/14/2012 1/9/2012 1/4/2012
Regulation violations, winter 2011/2012
400
800
200
0
600
-800
-600
-400
-200
1000
Figure 9.9
Page 146 2015 IRP
Idaho Power Company 9. Modeling Analysis and Results
Idaho Power is currently conducting a second solar integration study. Idaho Power anticipates
that additional regulation analysis will occur as part 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 Idaho Power and other utilities in the region. Idaho Power is currently
investigating different methods to address potential down-regulation violations.
Loss of Load Expectation (LOLE)
Idaho Power used a spreadsheet model8 to calculate the LOLE for the eleven portfolios studied
in the stochastic risk analysis in the 2015 IRP. The assessment assumes critical water conditions
at the existing hydroelectric facilities and the planned additions for the selected portfolios. J\s
mentioned in the Capacity Planning Margin section, Idaho Power uses a capacity benefit margin
(CBM) of 330 MW in transmission planning to provide the necessary reserves for unit
contingencies. The CBM is reserved in the transmission system and is sold on a non firm basis
until forced unit outages require the use of the rransmission capacity. The 2015 IRP analysis
assumes CBM transmission capacity is available to meet deficits due to forced outages.
The model uses the I RP forecasted hourly load profile, generator and purchase outage rates
(EFORd), and generation and transmission capacities to compu a LOLE for each hour of the 20
year planning period. Demand response programs were modeled as a reduction in the hourly load
for the IO peak days in a given year, although existing programs llow use up to 15 days. The IO
day assumption was chosen as a conservative reflection ofreality where it is assumed some days
will be left in reserve for unexpected extreme weathe . Ice TES resources were modeled as a
reduction to hourly load during afternoon/evening Hours in summer months and an increase in
hourly load during night hours in summer months. 'The LOLE analysis is performed monthly to
permit capacity de-rates for maintenance or a lack.of fuel (water). Resource capacities are
assumed to be constant for all hours each month with the exception of demand response and ice
TES as explained above, as well as solar photovoltaic resources. Photovoltaic resources are
modeled with a capacity that varies by hour for each month according to changing daylight hours
and sun position.
The typical metric used in the utility industry to assess probability-based resource reliability is a
LOLE of J day in IO years. Idaho Power chose to calculate a LOLE on an hourly basis to
evaluate the reliability at a more granular level. The I -day-in-I 0-years metric is roughly
equivalent to 0.5 to I hour per year.
The results of the LOLE probability analysis are shown in Figure 9.10. Several portfolios result
in a LOLE greater than 2 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 13 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 Billintons Power System Reliability Evaluation, chapters 2 and 3. 1970.
2015 IKP Page 147
9. Modeling Analysis and Results Idaho Power Company
2033 2031 2029 2027 2025 2021 2019 2017
050
000!.:=�::::::.it::=:::11::::=::�:::!�������---ll�;f;����=-�������
2015
Figure 9.10
Page 148 2015 IRP
Idaho Power Company 10. Action Plan
10. PREFERRED PORTFOLIO AND ACTION PLAN
Preferred Portfolio (2015-2034)
Analysis for the 2015 I RP consistently indicates favorable economics associated with two
significant resource actions: the 8211 transmission line and the early retirement of the North
Valrny power plant. IRP analysis suggests a strong connection between these resource actions,
both of which are characterized by uncertain timetables. Specifically, an acceleration in the
completion of the 821-1 line can be expected to provide the system reliability and access to
markets allowing for a corresponding acceleration in the early retirement of North Valmy.
The B2H transmission line and early North Valmy retirement are two key major resource actions
of portfolio P6(b), the 2015 IRP's preferred resource portfolio. Portfolio P6(b) contains both
actions in the year 2025, with the completion of the transmission line preceding the end-of-year
coal plant retirement. Portfolio P6(b) contains no other resource actions through the end of the
2020s, adding 60 MW of demand response and 20 MW of ice-based thermal energy in 2030, and
a 300 MW combined-cycle combustion turbine in 2031.
The absence of resource needs in portfolio P6(b) prior to the 2025 retirement of North Val my is
noteworthy. The resource sufficiency through the early 2020s shields portfolio P6(b) from risk
exposure associated with the following factors:
I. Uncertainty related to planned, but yet-to-be-built PU.RP solar; further project
cancellations beyond those already observed will have greater impact on portfolios
requiring capacity additions in the early 2020s.
2. Uncertainty related to EPA 's proposed regulation of C02 emissions from existing power
plants under CAA Section 111 (d), particularly the effect of the final rule on operations at
coal- and natural gas-fired power plants in the proposed interim compliance period
beginning in 2020.
3. Uncertainty related to the completion date of the B2H line due to permitting issues and
the needs of project partners.
4. Uncertainty related to retirement planning for a jointly owned power plant (North
Valmy), specifically the challenges associated with arriving at a mutually feasible
retirement date.
Uncertainty is a common part oflong term integrated resource planning. Even with the increased
uncertainty surrounding the 2015 IRP the analysis indicates completion of the B2H line and early
retirement of the North Valrny power plant are prudent actions. The timing of the actions can be
appropriately adjusted as conditions related to the four factors I isted above become actionable.
Action Plan (2015-2018)
The action plan for the 2015-2018 period includes items specifically related to the preferred
portfolio P6(b) and other items irrespective of portfolio selected. The P6(b) action items include
2015 IRP Page 149
10. Action Plan Idaho Power Company
T I
continued permitting and planning for the B2H transmission line, and investigation of North
Val my retirement in collaboration with plant co-owner NV Energy. The pursuit of these items
over the action plan period is critical to the successful and timely implementation of the
preferred portfolio.
The Gateway West transmission line remains a key future resource to Idaho Power and the
region promoting continued grid reliability in a time of expanding variable energy resources.
Thus, the plan includes continued permitting and planning associated with the Gateway West
project.
CAA Section 111 (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 111 (d) moves towards finalization and
implementation. As stipulations of the final rule become clearer and as implementation
planning is developed, Idaho Power will assess the impacts ot:CAA Section 11 l(d) on the
preferred portfolio.
The action plan also includes the following items:
• Continued pursuit of cost-effective energy efficiency, W,Orking with stakeholder groups
such as the Energy-Efficiency Advisory Group and regional groups such as the
Northwest Energy Efficiency Alliance
• Filing to amend the FERC license to adjust the 50 MW Shoshone Falls hydroelectric
project expansion, and efforts ·elated to the study and construction a smaller upgrade of
the project with a scheduled online date in the first quarter of 2019
• Completion of selective catalytic reduction (SCR) retrofits for Jim Bridger Units 3 and 4
• Begin economic evaluation of SCR retrofits for Jim Bridger Units I and 2 (SCR
installation required for Unit I in 2022 and for Unit 2 in 2021)
Table I 0.1 provides actions with dates for the 2015-2018 period.
Table 10.1 Action plan (2015-2018)
Year Resource
2015-2018 Boardman to Hemingway
2015-2018 Gateway West
2015-2018 Energy Efficiency
2015 Shoshone Falls
2015 Jim Bridger Unit 3
2015-2016 Shoshone Falls
2016 Jim Bridger Unit 4
Page 150
Action
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 catalytic 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
2015 IRP
Idaho Power Company 10. Action Plan
2016 North Valmy Units 1 and 2 Continue to work with NV Energy to synchronize depreciation dates and
determine if a date can be established to cease coal-fired operations
2017 Shoshone Falls Commence construction of a smaller upgrade
2017 Jim Bridger Units 1 and 2 Evaluate the installation of SCR technology for Units 1 and 2 at Jim Bridger in
the 2017 IRP
2019 Shoshone Falls 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, Idaho Power expects to continue participating in the regional
power market and enter into mid-term and long-term PPAs. However, in 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.
Conclusion
TI1e 2015 IRP analysis indicates favorable
results for the 82H transmission line and the
early retirement of the North Valmy power
plant. The analysis also suggests linkage
between the 82H line and the early retirement of
North Yalmy. Acceleration in the completion of
the transmission line could bring about a
corresponding acceleration in scheduling for
North Yalmy retirement.
Idaho Power has treated th B2H transmission
line as an uncommitted reso ce in,every TRP View of the Hemingway Substation.
beginning with the 2006 IRR. Fo every IRP,
including the 2015 IRP, the B2fl ine has been a top performing resource alternative. The
consistency of these analyses indicates that it is time for Idaho Power. the transmission line
partners. and the various regulatory and governmental agencies to complete a final permitting
and construction schedule for the Boardman to Hemingway transmission line.
Idaho Power strongly supports public involvement in the planning process. Idaho Power thanks
the IRP Advisory Council members and the public for their contributions to the 2015 I RP.
The IRP Advisory Council discussed many technical aspects of the 2015 resource plan along
with a significant number of political and societal topics at the meetings, portfolio design
workshop, and field trip to an Idaho Power facility. Idaho Powers resource plan is better
because of the contributions from the IRP Advisory Council members and the public.
2015 IRP Page 151
Idaho Power prepares an IRP every two years, and the next plan will be filed in 2017. As
described in this plan, the corning years are characterized by considerable uncertainty associated
with energy-related issues on the state, regional, and national levels. Idaho Power anticipates that
as uncertainty related to these issues clears the 2015 IRP preferred portfolio and action plan may
be adjusted in the next IRP filed in 2017, or sooner if directed by the IPUC or OPUC.
10. Action Plan Idaho Power Company
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Page 152 2015 IRP