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A endixC-chnical Appendix
For 2009 Integrated Resource Plan - December 2009
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Idaho Power Company Table of Contents
TABLE OF CONTENTS
Introduction..................................................................................................................................................1
Near- and Long-Term Action Plan ..............................................................................................................2
Portfolio Analysis, Results, and Supporting Documentation .............. ........................................................4
Initial Resource Portfolios. ..... ................... ........................... ......... ............. ... ... ...... ...............................4
Detailed Portfolio Design Sheets. ....... ........... .... ............. ............... ... ............. .................................. ......5
Detailed Resource Portfolio Modeling Assumptions ........... .... .... ................. ......................................15
Resource Portfolio Analysis-Base Case, Resource Portfolio Analysis (2010-2019) .................16
Resource Portfolio Analysis-Base Case, Coal Curailment (2010-2019)........................ ...........17
Resource Portfolio Analysis-$43 CO2, No Coal Curtailment (2010-2019) ...............................18
Resource Portfolio Analysis-Curent Operations, No Carbon, No Coal Curtailment
(2010-2019)...................................................................................................................................19
Resource Portfolio Analysis-Base Case, Coal Curtailment (2020~2029)...................................20
Resource Portfolio Analysis-$43 CO2, No Coal Curtailment (2020-2029) ...............~...............21
Resource Portfolio Analysis-Current Operations, No Carbon, No Coal Curtailment
(2020-2029) ...................................................................................................................................22
Portfolio Incremental Transmission Analysis......................................................................................23
Loss of Load Analysis ........................... .... ..................... ............. ....... .................................................34
Sales and Load Forecast Data....................................................................................................................35
Average Anual Forecast Growth Rates..............................................................................................35
Expected Case Load Forecast ..............................................................................................................36
Monthly Summary ............. ............ .... ............... ................... ..... ........................................... ..........36
Annual Summary ...........................................................................................................................56
70th Percentile Load Forecast...............................................................................................................58
Monthly Summary .........................................................................................................................58
Anual Summary . ........................................................ ...... ... ......................................................... 78
Existing Resource Data..............................................................................................................................80
Hydroelectric and Thermal Plan Data..................................................................................................80
Qualifying Facility Project Data ..........................................................................................................81
Power Purchase Agreement Project Data ...... ................. ...... ........ .... ...................................................82
Fuel Data ....................................... ....................... ................. ............... ......................................................83
Gas and Coal Forecast-Data and Graphs...........................................................................................83
Natural Gas Price Forecast-Comparison to Other Forecasts.............................................................84
Natual Gas Price Forecast-Comparison to Previous Integrated Resource Plans .............................84
2009 Integrated Resource Plan-Appendix C Pagei
Table of Contents Idaho Power Company
Supply-Side Resource Data .......................................................................................................................85
Key Financial and Forecast Assumptions............................................................................................85
Cost Inputs and Operating Assumptions.. ....................................... .... ..... ..... ....... ...... .... ......................87
Levelized Cost of Production.......................................... .....................................................................88
The Comprehensive Aquifer Management Plan (CAMP) Process and Potential to Impact
Power Generation.. ..................... .................... ....................... ............ ... ........................................ ........90
The CAMP Process. ................................ .......... .................... ..... ...... ..............................................90
Potential Impact of CAMP Implementation on Idaho Power........................................................91
Modeled CAMP Scenario ..............................................................................................................92
Brownlee Reservoir Inflow Record .....................................................................................................94
Monthly Wind Energy Distribution.....................................................................................................95
Demand-Side Resource Data .....................................................................................................................96
Cost-Effectiveness ...............................................................................................................................96
Alternate Costs ............ ............................ .......... .................. ....... ...... .... ........ .......... .......... ..............97
Load and Resource Balance.....................................................................................................................l 08
Monthly Average Energy Surplus/Deficiency Data ....... ..... ...... ........................................................108
Monthly Average Energy Surpluses and Deficits with Existing Resources ................................1 08
Monthly Average Energy Surluses and Deficits with 2009 IRP Resources ............................. .119
Peak Hour Load Surplus/Deficiency Data.........................................................................................120
Peak Hour Deficits with Existing Resources. ............... .............. .................................................130
Peak Hour Deficits with 2009 IR Resources .............................................................................131
PDR580 Results.................................................................................................................................132
50th Percentile Water, 50th Percentile Load .................................................................................132
70th Percentile Water, 70th Percentile Load .................................................................................142
90th Percentile Water, 70th Percentile Load .................................................................................152
Oregon Order UM 1056 Planning Criteria .... ....................................... .... ...............................................162
Summary of Northwest Utility Planning Criteria ....................................................................................170
IRP Advisory Council Roster................................................................................................................. .172
Pageii 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Introduction
INTRODUCTION
Appendix C-Technical Appendix contains some of the supporting and explanatory materials used to
develop Idaho Power's 2009 Integrated Resource Plan (IRP). The Technical Appendix begins with a
reprint of the short-term and long-term resource action plans and follows with detailed information
concerning various resource planning issues.
The main document, the IRP, contains a full narrative of the Idaho Power resource planning process.
Additional information regarding the Idaho Power sales forecast is contained in Appendix A-Sales and
Load Forecast, and details on Idaho Power's energy efficiency efforts are explained in Appendix B-
Demand-Side Management 2008 Annual Report. The IR, including the three appendices, was filed with
the Idaho and Oregon public utility commissions in December 2009.
For information or questions concerning the resource plan or the resource planning process, contact
Idaho Power:
Idaho Power-Resource Planning
1221 West Idaho Street
Boise, Idaho 83702
208-388-2483
2009 Integrated Resource Plan-Appendix C Page 1
Action Plan Idaho Power Company
EAR'" AND LONG-TERM ACTION PLAN
Near-Term Action PlanYear Action
2010....... ... .................. ........ .............. ... ... Present and gain acceptance of 2009 IRP with regulatory commissions
File wind contract resulting from the 2012 Wind RFP with the IPUC
File geothermal contract with the IPUC
Irrigation Peak Rewards program increases from 160 MV to 220 MV
FlexPeak Management program increases from 20 MW to 40 MW
Langley Gulch CCCT construction begins
2011 ........................................................ Wind project construction begins
Langley Gulch CCCT construction continues
Irrigation Peak Rewards program increases from 220 MW to 250 MV
FlexPeak Management program increases to from 40 MW to 45 MW
File 2011 IRP with regulatory commissions
2012 ........................................................ Wind project on-line (approximately 150 MW)
Langley Gulch CCCT on-line (300 MW)
Geothermal project on-line (approximately 20 MW)
2013... ... ...... ................................. .... ....... Boardman to Hemingway construction begins
Shoshone Falls Upgrade Project construction begins
File 2013 IRP with regulatory commissions
2014 ........................................................ Shoshone Falls Upgrade Project construction continues
2015.......... .......... ......................... ........... Shoshone Falls Upgrade Project on-line (49 MW)
Boardman to Hemingway completed (250 MV)
File 2015 IRP with regulatory commissions
2016 ........................................................ Geothermal project on-line (approximately 20 MV)
2017............................................. .... '" .... Boardman to Hemingway additional capacity for market purchases (175 MV)
File 2017 IRP with regulatory commissions
2018 ........................................................ No action
2019 ........................................................ File 2019 IRP with regulatory commissions
Alternate Portolio Near-Term Action Plan
Year Action
2010 ........................................................................................................... File 20091RP with regulatory commissions
File wind contract (2012 Wind RFP) with the IPUC
File geothermal contract with IPUC
Irrigation Peak Rewards Program increases to 220 fI
FlexPeak Management program increases to 40 MW
Langley Gulch CCCT construction begins
2011 ...... ... ............................................... ................................................... Wind project construction begins
Langley Gulch CCCT construction
Irrigation Peak Rewards Program increases to 250 fI
FlexPeak Management program increases to 45 fI
File 2011 IRP with regulatory commissions
2012 ......... .................................................................................................. Wind project on line (approximately 150 MW)
Langley Gulch CCCT on-line (300 MW)
Geothermal generation on-line (approximately 20 MW)
Natural gas generation rèource one RFPs
2013 ........................................................................................................... File 20131RP with regulatory commissions
2014 ........................................................................................................... Shoshone Falls upgrade construction
Page 2 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Action PlanYear Action
Natural gas generation resource two RFPs
2015........................................................................................................... Shoshone Falls upgrade on-line (50 MW)
Natural gas generation resource one on-line
File 2015 IRP with regulatory commissions
2016 ........................................................................................................... Geothermal Generation on-line (approximately 20 MW)
2017...... ........................ ... ............................................................ .............. Natural Gas generation resource two on-line
File 2017IRP with commissions
2018 ........................................................................................................... No action
2019 ........................................................................................................... File 20191RP with commissions
Long-Term Action Plan
Year
2020........................................................................................................
2021........................................................................................................
2022........................................................................................................
2023........................................................................................................
2024........................................................................................................
2025........................................................................................................
2026........................................................................................................
2027........................................................................................................
2028........................................................................................................
2029........................................................................................................
Action
Natural gas generation project on-line (approximately 100 MW)
No action
Wind project on-line (approximately 100 MW)
No action
Natural gas generation project on-line (approximately 200 MW)
No action
Natural gas generation project on-line (approximately 200 M-)
Wind project on-line (approximately 400 MW)
Natural gas generation project on-line (approximately 400 M-)
Natural gas generation project on-line (approximately 500 M-)
2009 Integrated Resource Plan-Appendix C Page 3
Portfolio Analysis Idaho Power Company
PORTFOLIO ANALYSIS,
AN SUPPORTING MENTATION
Initial Resource Portolios (2010-2019)
2012
1-1 Solar 1-2 Gas Peaker 1-3 Gas Peaker & B2H'1-4 B2H
Resource MW Resource MW Resource MW Resource MW
Wind*150 Wind*150 Wind*150 Wind*150
CCCT (Langley Gulch)* 300 CCCT (Langley Gulch)* 300 CCCT (Langley Gulch)* 300 CCCT (Langley Gulch)* 300
Geothermal*20 Geothermal*20 Geothermal*20 Geothermal*20
Shoshone Falls 49 Shoshone Falls 49 Shoshone Falls 49 Shoshone Falls 49
SCCT (Large Aero)200 SCCT (Frame Peaker)170 B2H 250 B2H 250
Geothermal*20 Geothermal*20 Geothermal*20 Geothermal*20
Solar PT wISt 100 SCCT (Frame Peaker)170 SCCT (Large Aero)100 B2H 175
Solar PT wISt 100 SCCT (Large Aero)100
Year
2015
2016
2017
2019
1 B2H-Boardman to Hemingway
*Committed Resource
Initial Resource Portolios (2020-2029)
2020
2-1 NuclearlGreen 2-2 GatewayWest 2-31GCC 2-4 Win & Peakers 2-5 Limited Curtilment
Resource MW Resource MW Resource MW Resource MW Resource MW
Solar PT wISt 100 SCCT (Large Aero)100
Wind 100 Wind 100 Wind 100
Solar PT wISt 100 Gateway West 200 Solar PT wISt 100 Wind 100 SCCT (Large Aero)100
Nuclear 270
Geothermal 52 IGCCw/Seq.600 SCCT (Large Aero)200
Solar PT wISt 100 Gateway West 200 Gateway West 100
Wind 100 SCCT (Large Aero)200 SCCT (Large Aero)100
Geothermal 52 Gateway West 400 Solar PT wiSt 100 Wind 400 Wind 200
SCCT (Large Aero)100
Nuclear 400 Gateway West 600 SCCT (Large Aero)400 SCCT (Large Aero)400
Gateway West 250 Solar PT wiSt 100 SCCT (Large Aero)500
Year
2021
2022
2023
2024
2025
2026
2027
2028
2029
Page 4 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
1-1 Solar
Cum.Cum.Cum.Cum. RES
Peak Ener Peak RESMW MWh
0 0 0
0 0 50 438,000
0 0 50 438,000
0 0 68 595,680
7 0 75 657,000
107 200 75 657,000
107 200 93 814,680
135 292 121 1,059,960
135 292 121 1,059,960
163 384 149 1
CR = Coimed Resource Min (91)(188)
NR = New Resource STDEV 289 142
MP = Market Purchase AVG 505 107
Peak-Hour0~N C'"'i.co I"eo cr~~~~~~~~~~,,,,,.,,,,"5 "5 "5 "5 "5 "5 "5 "5 "5 "5....................
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
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(400)
(600)
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2009 Integrated Resource Plan-Appendix C PageS
Portfolio Analysis Idaho Power Company
1~2 Peaker
Cum.Cum.Cum.Cum. RES
Energy Peak RESMW MWh
0 0 0
0 0 50 438,000
0 0 50 438,000
0 0 68 595,680
7 0 75 657,000
95.4 159.8 75 657,000
95.4 159.8 93 814,680
183.8 319.6 93 814,680
183.8 319.6 93 814,680
183.8 319.6 93
Min (91)(188)
STDEV 292 138
AVG 515 99
CR = Corrtted Resource
NR = New Resource
MP = Market Plrchase
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
P~ak-HolJr
0 ..N C'""L(co..............,,,,,,,:5 :5 :5 :5 :5 :5 :5..............
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Page 6 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
1 ~3 Gas Peaker B2H
Cum.Cum.Cum.Cum. RES
RES Ener Peak RESMW MWh
0 0 0
0 0 50 438,000
0 0 50 438,000
0 0 68 595,680
7 0 75 657,000
132 250 75 657,000
132 250 93 814,680
184 344 93 814,680
184 344 93 814,680
236 438 93 814,680
CR = Cormtted Resource Min (91)(188)
NR = New Resource STDEV 294 163
MP = Market Purchase AVG 527 133
Peak-Hour
0 ~N (V ""L(lO I"co en~~~~~~~~~~,,,,,,,,,,"S "S "S "S "S "S "S "S "S "S-,-,-,-,-,-,-,-,-,..
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
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(400)
(600)
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2009 Integrated Resource Plan-Appendix C Page?
Portfolio Analysis Idaho Power Company
14B2H
Cum.Cum.Cum.Cum. RES
RES Peak Ener Peak RESMW MWh
0 0 0
0 0 50 438,000
0 0 50 438,000
0 0 68 595,680
7 0 75 657,000
132 250 75 657,000
132 250 93 814,680
219.5 425 93 814,680
219.5 425 93 814,680
219.5 425 93
CR = Cormed Resource Min (91)(188)
NR = New Resource STDEV 297 180
MP = Market Plrchase AVG 533 148
PeakæHour
0 ..N cr ""LO (0 I'00 ()....................,,,,,,,,,,"S "S "S "S "S "S "S "S "S "S--------------------
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
I I i I.
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Page 8 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portfolio Analysis
Nuclear/Green
Cum.Cum.Cum.Cum. RES
Ener Peak RESMW MWh
28 92 28 245,280
60 97 60 525,600
88 189 88 770,880
358 459 88 770,880
405 506 134.8 1,180,848
433 598 162.8 1,426,128
433 598 162.8 1,426,128
480 645 209.6 1,836,096
860 1045 209.6 1,836,096
985 1295 209.6 .......1,8~§,ge§
Min (93)(380)
STDEV 396 44
AVG 803 707
CR = Comrtted Resource
NR = New Resource
MP = Market Purchase
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
Peak~Hour0..C\M "f LO co ,.e-e-e-e-~N e-e-i:i:i:i:i:C i:i:co co 11 11 11 co 11 11................
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2009 Integrated Resource Plan-Appendix C Page 9
Portfolio Analysis Idaho Power Company
2-2 Gateway West
Cum.Cum.Cum.Cum. RES
Ener Peak RESMW MWh
0 0 0
32 5 32 280,320
132 205 32 280,320
132 205 32 280,320
132 205 32 280,320
232 405 32 280,320
264 410 64 560,640
464 810 64 560,640
764 1410 64 560,640
764 1410 64 ....560,640
CR = Conrled Resource Min (189)(131)
NR = New Resource STDEV 381 506
MP = Market Purchase AVG 682 661
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
Peak-Hour0..N C'"'l!(0 I'co enNNNNNNN":N ":t t t t t t t c t cC\C\C\C\C\C\C\C\C\C\....................
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Page 10 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portfolio Analysis
2-3IGCC
RES
Cum.Cum.Cum.Cum. RES
Ener Peak RESMW MWh
0 0 0
0 0 0
28 92 28 245,280
28 92 28 245,280
556 692 28 245,280
556 692 28 245,280
556 692 28 245,280
584 784 56 490,560
784 1184 56 490,560
812 1276
Min (169)(240)
STDEV 419 491
AVG 781 705
CR " Comrtted Resource
NR = New Resource
MP = Market Purchase
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
Peak-Hour0.-N C'""io c.I'toNNNe-e-e-N N N
C:C:C:i:i:i:C:C:C:lt lt lt lt lt lt lt lt lt------------------
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2009 Integrated Resource Plan-Appendix C Page 11
Portolio Analysis Idaho Power Company
24 Wind Peakers
Cum.Cum.Cum. RES
Peak RESMW MWh
0 0
0 0
5 30 262,800
5 30 262,800
205 30 262,800
305 30 262,800
405 30 262,800
425 158 1,384,080
825 158 1,384,080
Min (345)(599)
STDEV 384 460
AVG 648 504
CR = Comrtted Resource
NR = New Resource
MP = Market Purchase
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
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Page 12
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2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
2.5 limited Coal Curtailment
o~cm-,
Cum.Cum.Cum.Cum. RES
Ener Peak RESMW MWh
0 0 0
32 5 32 280,320
82 105 32 280,320
82 105 32 280,320
82 105 32 280,320
234 485 32 280,320
284 585 32 280,320
348 595 96 840,960
398 695 96 840,960
748 1395 96 840,960
748 1395 96 . .S4Q,960
Min (205)(237)
STDEV 371 510
AVG 647 632
Peak-Hour
C'.,ID (0 I'ex (1~N N ~N ~~c è:è:c è:c cmmmmmmm-,-,-,-,-,-,-,
CR = Comrtted Resource
NR = New Resource
MP = Market Purchase
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
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2009 Integrated Resource Plan-Appendix C Page 13
Portfolio Analysis Idaho Power Company
2-6 No Coal Curtailment
CR = Committed Resource
NR = New Resource
MP = Market Purchase
300
250
200
150
100
50
o
(50)
(100)
(150)
(200)
(250)
(300)
1,400
1,200
1,000
800
600
400
200
o
(200)
(400)
(600)
Min
STDEV
AVG
Peak~Hour0T"C'C'oo I!co I'co m"l C'C'C'"l C'"l C'"l C'
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50
50
80
80
130
130
230
358
358
358
358
84
432
1,029
Cum.
Peak
100
100
105
105
205
205
405
425
425
425
425
(138)
245
550
Cum.
RESMW
o
32
32
32
32
32
32
96
96
96
96
Cum. RES
MWh
280,320
280,320
280,320
280,320
280,320
280,320
840,960
840,960
840,960
134-(),eeO
Page 14
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2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portfolio Analysis
Resource Portolio Modeling Assumptions
Time
Period
2010-2019
NTTG
Transmission
Plan3
Coal
Curtailment1
X
Carbon
Adde.-Figure Name
Base Case,
Coal Curtailment
Used in first 10-year
Portolio Selection
Process
Base Case,
Coal Curtailment
2010-2019 $43 C02,
No Coal Curtailment
2010-2019 Current Operations,
No Carbon,
No Coal Curtailment
2020-2029 Base Case,
Coal Curtailment
Used in second 10-Year
Portfolio Selection
Process
2010-2019 X X
X X
X
X X
2020-2029 $43 C02,
No Coal Curtailment
2020-2029 Current Operations,
No Carbon,
No Coal Curtailment
lldaho Power coal plants are curtailed to comply with HR 2454
2$43 per ton added starting in 2012
31ncludes all NTTG projects at estimated capacity estimate ratings
4Transmission paths in the Aurora model are unconstrained to levels of anticipated use by Idaho Power
5Coal curtailed to 2020 targets (partial HR 2454 compliance)
X X
X
OnlylPC
Transmission
Share of B2H4
X
Limited Coal
CurtailmentS
2-5 Only
2009 Integrated Resource Plan-Appendix C Page 15
Portfolio Analysis Idaho Power Company
RESOURCE PORTFOLIO ANALYSIS
Base Case, Coal Curtilment (2010-2019)
1.3
Base Case-Coal Curtailment 1-1 Solar 1.2 Gas (Peaker)(Peaker & B2H)1-4 B2H
Capital Costs 2009 ($ Total)$1,264,351,176 $266,751,176 $249,551,176 $96,951, 176
Capital Costs NPV ($ 20 Year)$621,711,410 $239,909,076 $178,705,464 $107,198,820
Aurora NPV Portfolio Total Cost $1,963,326,421 $2,066,337,264 $2,032,468,672 $2,063,765,789
NPV Total = Aurora + Capital $2,585,037,830 $2,306,246,340 $2,211,174,136 $2,170,964,609
CO2 Excess Emissions (Tons)117,808 288,017 429,833 258,563
RES Excess Green Tags year 2019 684,156 193,596 193,596 193,596
Carbon Allowances Esimates 117,808 288,017 429,833 258,563
Boxer/Kerr Price Cap Proposal NPV $(263,462) $1,467,059 $5,163,204 $1,839,437
2019 Res Position Esimates 684,156 193,596 193,596 193,596
RES NPV $ Estimates Yr 1-10
Expected Value (Cost Reduction)$(46,921,264) $(37,338,255) $(37,338,255) $(37,338,255)
Transmission $13,163,761 $10,977,415 $55,403,269 $94,451,794
Expected Portolio Cost $2,551,016,864 $2,281,352,560 $2,234,402,354 $2,229,917,585
Rank by Least Cost 4 3 2 1Diffrence$321,099,279 $51,434,974 $4,48,769 $
Risk Factors
CO2 $43 (Incremental)$4,802,283 $13,851,809 $23,646,013 $12,957.638
RES NPV $ Estimates Yr 1-10
High Value (Additional to Expected)$(55,685,534) $(41,902,289) $(41,902,289) $(41,902,289)
DSM 50% Realization (Cost Difference)$51,876,928,$38,966,959 $71,495,131 $40.522,318
High Load Growth (Cost Difference)$290,681,839 $288,768,701 $320,277,146 $289,732,784
Gas Price
High NG Prices differential frm Low $(36,516,721) $(40,577,759) $(7,744,434) $(38,094,952)
Transmission B2H
With 3rd-Party Participation NPV ($16,726,745)($46,086,195)
Total Risk Cost $255,158,795 $259,107,422 $349,04,823 $217,129,304
Rank by Least Risk 2 3 4 1
Diffrence $38,029,491 $41,978,118 $131,915,519 $
Portolio Differences w/Cost Risk Adj
High $631,943,608 $352,444,685 $395,431,881 $259,031,593
Page 16 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portfolio Analysis
RESOURCE PORTFOLIO ANALYSIS
Base Case, Coal Curtilment (2010-2019)
Base Case-Coal Curtailment 1-1 Solar 1-2 Gas Peaker 1-3 Gas Peaker & B2H 1-4B2H
Capital Costs 2009 ($ Total)$1,328,502,353 $363,702,353 $346,502,353 $193,902,353
Capital Costs NPV$ 20 Year $621,711,410 $239,909,076 $178,705,464 $107.198,820
Aurora NPV Portolio Total Cost $1,976,455,828 $2.021,669,045 $2,017,973,554 $2,021,858,588
NPVTotal = Aurora + Capital $2,598,167,238 $2,261,578,121 $2,196,679,018 $2,129,057,408
C02 Excess Emissions (Tons)(9,258)57,787 213,135 73,737
RES Exæss Green Tags year 2019 684,156 193,596 193,596 193,596
Carbon Allowances Needed Estimates (9,258)57,787 213,135 73,737
Boxer/Kerry Priæ Cap Proposal NPV $(263,462)$1,467,059 $5,163,204 $1,839,437
2019 Res Position Estimates 684,156 193,596 193,596 193,596RES NPV $ Estimates Yr 1-10
Expected Value (Cost Reduction)$(46,921,264)$(37,338.255) $(37,338,255) $(37,338,255)
Transmission $13,163,761 $10,977,415 $55,403,269 $94,451,794
Expected Portfolio Cost $2,564,146,272 $2,236,684,34 $2,219,907,236 $2,188,010,384
Rank 4 3 2 1
Diference NPV 1-10 Years $376,135,888 $48,673,956 $31,896,852 $
Risk Factors--..~.._-----.~_.-~----~~_..._._-_.__.__.
C02 $43 (Incremental)$(661,560)$3,951,893 $14,327,997 $5.010,136
RES NPV $ Estimates Yr 1-10
High Value (Additional to Expected)$(55,685,534)$(41,902,289) $(41.i:m.289) $(41,902,289)
DSM 50% Realization (Cost Differenæ)$27,500,134 $88,116,160 $85.454,235 $87,129,172
High Load Growth (Cost Differenæ)$267,685,288 $327,202,920 $325,007,765 $327,887,601
Gas Price
High NG Prices differential from Low $(49,646,128)$4,090,460 $6,750,684 $3,812,250
Transmission B2H
No resell IPC Outbound NPV ($16,726,745)($46,086,195)No Third Party Parlcipauon 1-10 Years (Not Inlcuded in totals below)$211,215,269 $201,526,193
11-20 Year Transmission Rev Req ~PC Sells Outbound $47,299,585 $59,148,872
11-20 Year Transmission Rev Req IPC Does Not Sell Outbound $67, 755,614 $115,510,138.56
11-20 Year Trans Rev Req ~PC No Third Part Partidpation $600, 050,525 $600,050,525.21
Portfolio Differences w/Cost Risk Adj
High $621,079,622 $472,035,389 $447,3)0,789 $377,752,964
High w/Transmission $574,993,427 $425,99,195 $401,214,594 $377,752,964
Low $565,394,088 $430,133,100 $405,398,500 $335,850,675
LowwlTransmission $519,307,893 $384,046,905 $359,312,305 $335,850,675
Rank 4 3 2 1
2009 Integrated Resource Plan-Appendix C Page 17
Portfolio Analysis Idaho Power Company
RESOURCE PORTFOLIO ANALYSIS
$43 C02, No Coal Curtailment (2010-2019)
1-3 Gas Peaker
$43 C02-No Coal Curtailment 1-1 Solar 1-2 Gas Peaker &B2H 1-4B2H
Capital Costs 2009 ($ Total)$1,328,502,353 $363,702,353 $346,502,353 $193,902,353
Capital Costs NPV 20-Year $621,711,410 $239,909,076 $178,705,464 $107,198,820
Aurora NPV Portolio Total Cost $3,613,437,405 $3,701,347,429 $3,703,473,275 $3,698,952,139
NPV Total == Aurora + Capital $4,235,148,815 $3,941,256,505 $3,882,178,739 $3,806,150,959
C02 Excess Emissions (Tons)7,758,441 7,705,353 8,323,589 7,584,025
RES Exæss Green Tags year 2019 684,156 193,596 193,596 193,596
2019 Res Position 684,156 193,596 193,596 193,596
RES Net Valuciion Estimates Yr 1-10
Expected Value (Cost Reduction)$(46,921,264) $(37,338,255)$(37,338,255)$(37,338,255)
Transmission B2H Fully Subscribed NPV $13,163,761 $10,977,415 $55,403,269 $94,451,794
Expected Portfolio Cost $4,201,391,311 $3,914,895,665 $3,900,243,754 $3,863,264,498
Rank 4 3 2 1
Diference $338,126,813 $51,631,167 $36,979,255 $
Page 18 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portfolio Analysis
RESOURCE PORTFOLIO ANALYSIS
Current Operations, No Carbon, No Coal Curtailment (2010-2019)
Current Operations, No carbon, No 1-3 Gas Peaker
Curtailment 1-1 Solar 1-2 Gas Peaker &B2H 1-4B2H
Capital Costs 2009 ($ Total)$1,328,502,353 $363,702,353 $346,502,353 $193,902,353
Capital Costs NPV 20-Year $621,711,410 $239,909,076 $178,705,464 $107,198,820
Aurora NPV Portolio Total Cost $1,907,178,616 $2,001,439,129 $2,000,008,019 $2,001,618,009
NPVTotal = Aurora + Capital $2,528,890,26 $2,241,348,205 $2,178,713,483 $2,108,816,829
C02 Excess Emissions (Tons)5,272,549 5,312,589 5,453,587 5,364,722
RES Excess Green Tags year 2019 684,156 193,596 193,596 193,596
Carbon Allowances Needed Estimates 5,272,549 5,312,589 5,453,587 5,364,722
Boxer/KerryPrice Cap Proposal NPV $127,454,073 $128,498,367 $131,857,808 $129,738,767
2019 Res Position 684,156 193,596 193,596 193,596
RES Net Valuation Estimates Yr 1-10
Expected Value (Cost Reduction)$(46,921,264)$(37,338.255)$(37.338,255)$(37,338,255)
Transmission B2H Fully Subscribed NPV $13,163,761 $10,977,415 $55,403,269 $94,451,794
Expected Portfolio Cost $2,622,586,596 $2,343,485,731 $2,328,636,306 $2,295,669,136
Rank 4 3 2 1Difrence$326,917,459 $47,816,595 $32,967,170 $
2009 Integrated Resource Plan-Appendix C Page 19
Portfolio Analysis Idaho Power Company
RESOURCE PORTFOLIO ANALYSIS
Base Case, Coal Curtilment (2026-2029)
2-5 Limited Coal
Base Case-Coal Curtilment 2-1 Nuclear Green 2.2 Gateway West 2-3 IGCC 2-4 Wind & Peakers Curtilment
Capital Costs 2009 ($ Total)$5,834,274,000 $355,600,000 $5,123,200,000 $1,957,200,000 $762,300,000
Capital Costs NPV$ 20 Year $2,267,193,086 $150.871,393 $1,724,352,346 $479,620,560 $241.162,616
Aurora NPV Portolio Total Cost $948,612,021 $1,805.716,731 $1,106.374,123 $1,671,794,651 $1,461.869,774
NPVTotl = Aurora + Capital $3,215,805,108 $1,956,588,124 $2,830,726,469 $2,151,415,212 $1,703,032,390
C02 Excess Emissions (Tons)6.186,401 7,268,164 6,401.005 8,328,556 26.657,888
RES Exæss Green Tags year 2019 1.267,572 (7,864)167,316 815.556 272,436
Carbon Allowances Needed Estimates 6,186,401 7,268.164 6,401,005 8,328,556 26,657.888Boxer/Kerry Price Cap Proposal NPV $(30,674,006) $(8,100,874) $(26,194,772)$14,030,419 $396,574,720
2029 Res Position Estimates 1,267,572 (7.884)167,316 815,556 272,46
RES NPV $ Estimates Yr 1-10
Expected Value (Cost Reduction)$(99,699,468)$(1,485,655) $8,518,747 $(17,665,567)$(6,796,825)
Transmission Estimate NPV $849,733.630 $1,408,824,342 $768,798,180.04 $452,114,922 $207,800,668,18
Expected Portfolio Cost $3,935,165,264 $3,355,825,937 $3,581,848,625 $2,599,894,987 $2,300,610,952Rank by Least Cost 5 3 4 2 1Diferenc$1,634,554,312 $1,055,214,985 $1,281,237,672 $299,284,034 $
Risk Factors
C02 $43 (Inaemental)$296,689,242 $320,631,927 $301,438.004 $344.097,492 $749.714,446
RES NPV $ Estimates Yr 11-20
High Valle (Additional to Expected)$(149,549,202)$(2,228,482) $12,778,121 $(26,498,351 )$(10,195.238)
DSM 50% Realization (Cost Differenæ)$110.191,842 $116,351,682 $113,762,113 $116.777,644 $24,354,437
High Load Growth (Cost Dilferenæ)$465,800,512 $486,161,488 $473,734,605 $486.948,952 $392,322,637
Gas Price
High NG Priæs sensitivity $(83,134,652) $199,963.861 $(96,394,526)$294,198,968 $(97,212.291)
Transmission B2H
Zero 3rd-Part Partcipation NPV
Total Risk Cost $639.997,742 $1.120,880,476 $805,318,318 $1,215.524,706 $1.058,983,991Rank by Least Risk 1 4 2 5 3Diference$$480,82,734 $165,320,575 $575,526,9 $418,986,249
PortfoUo.J)ifferenc:es.w,/Çost .Risk.Adj
High $2,424,101,255 $2,178.323,943 $2.073,777.869 $1,541,307,091 $1,069.179,229High w/Transmission $2,424,101,255 $2,178,323,943 $2,073,777,869 $1,541,307,091 $1,069,179,229
Low $2,573,650,457 $2,180,552,425 $2.060.999.748 $1,567,805.41 $1,079,374,467
Low wfTransmission $2,573,650,457 $2,180,52,425 $2,060,999,748 $1,567,805,441 $1,079,374,467Rank54321
Page 20 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portfolio Analysis
RESOURCE PORTFOLIO ANALYSIS
$43 C02, No Coal CurtaHment (2020-2029)
2-5 Limited Coal
$43 C02 No Coal Curtailment 2-1 Nuclear/Green 2-2 Gateway West 2-3IGCC 2-4 Wind & Peakers Curtailment
Capital Costs 2009 ($ Total)$5,834,274,000 $355,600,000 $5,123,200,000 $1,957,200,000 $762,300,000
Capital Costs NPV $20 Year $2,267,193,086 $150,871,393 $1,724,352,346 $479,620,560 $241,162,616
Aurora NPV Portolio Total Cost $1,684,893,917 $2,689,899,037 $1,878,056,113 $2,646,447,583 $2,689,352,379
NPVTotal = Aurora + Capital $3,952,087,004 $2,840,770,430 $3,602,408,459 $3,126,068,143 $2,930,514,994
CO2 Excess Emissions (Tons)
RES Excess Green Tags year 2019 1,267,572 (7,884)167,316 815,556 272,436
Carbon AllOwances Needed Estimates
BoxerlKerry Price Cap Proposal NPV $(30,674,006)$(8,100,874)$(26,194,772)$14,030,419 $396,574,720
2029 Res Position Estimates 1,267,572 (7,884)167,316 815,556 272,436
RES NPV$ Estimates Yr 1-10
Expected Value (Cost Reduction)$(99,699,468) $(1,485,655)$8,518,747 $(17,665,567) $(6.796.825)
Transmission Estimate NPV $849,733,630 $1,408,824,342 $768,798,180.04 $452,114,922 $207,800,668.18
Expected Portfolio Cost $4,671,447,160 $4,240,008,243 $4,353,530,615 $3,574,547,918 $3,528,093,556
Rank by Least Cost 5 3 4 2 1Diference$1,143,353,603 $711,914,687 $825,437,058 $46,454,362 $
2009 Integrated Resource Plan-Appendix C Page 21
Portfolio Analysis Idaho Power Company
RESOURCE PORTFOLIO ANALYSIS
Current Operations, No Càrbon, No Coal Curtailment (2020-2029)
2-5 Limited Coal
c:urre~tQPlllltiol1sN()carl()N()cuitiill1lint_?:1Nu"lear/Gi:een __2-GatiiYlliy1Nlli;t ?:~IGÇÇ ~..YVri~"liakllri;_ __C:iiiti_mentCapital Costs 2009 ($ Total)$5,834.274,000 $355,600.000 $5,123,200,000 $1,957,200,000 $Capital Costs N PV $20 Year $2,267,193,086 $150.871.393 $1,724,352,346 $479,620,560 $Aurora NPV Portolio Total Cost $664,260,485 $1,331,464,010 $807,979,5æ $1,251,035,806 $
NPVTotal = Aurora + Capital $2,931,453,572 $1,482,335,403 $2,532,331,854 $1,730,656,367 $
C02 Excess Emissions (Tons)41,437,283 42,239,982 41,302,614 42,968,883RES Exæss Green Tags year 2019 1,267.572 (7,884)167,316 815,556
Carbon Allowances Needoo Estimates 41,437,283 42,239,982 41,302,614 42,968,883
BoxerfKeriy Price Cap Proposal NPV $(30,674,006)$(8,100,874)$(26,194,772)$14,030,419 $396,574,720
2029 Res Position Estimates 1,267,572 (7,884)167,316 815,556RES NPV$ Estimates Yr 1-10
Expected Value (Cost Reduction)$(99,699,468)$(1,485,655)$8,518,747 S (17,665,567)$(6,796.825)
Transmission Estimate NPV $849,733,630 $1.408.824,342 $768,798,180.04 $452,114,922 $207,800,668.18
Expected Portfolio Cost $3,650,813,728 $2,881,573,215 $3,283,454,000 $2,179,136,141 $597,578,562Rank by Least Cost 5 3 4 2 1Diference$3,650,813,728 $2,881,573,215 $3,283,454,00 $2,179,136,141 $597,578,562
Page 22 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
2009 Integrated R.esource Plan
Idaho Power Transmission Rate Approximation for2009 IRP Analysis
Portfoio 2-5
Project
Gateway 19% owned by IPCo (300/1600)
300 Wind
1050 Existing Coal
Capital Cost
$ 337,500,000
I nduded in GW
Annual Revenue Requirements
Existing Revenue Requirements.......................................... ........
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s )..................................
New Net Revenue Requirements.................................................
$106,566,650
$(17,510,193)
$89,056,456
$337,500,000
$54,023,495
$143,079,951
System Use (in MW)
Existing System Peak Demand......... ........ .... ...............................
Future additionallPC Network Use
New System Demand-Induding new uses................ .......... ......
5,627
300
5,927
Point-To-Point Transmission Rate
a) Existing Rate-$IkW-yr...........................................................;.... $
b) New Rate without 3rd-Party U se$IkW -yr.................. ................ $
15.83
24.14
Po int-To-Poi nt Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase ~ 100%).................................
Existing uses adjusted at new rate b)................... ................ ........ $
100%
(9,198,010)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assgned to IPC Retail Load Servioo............................................
b) Future - New Projects without additional participation
BPA Load Ratio Share.................................................................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assgned to IPC Retail Load Servioo............................... no..........
Net change
$4,237,114
$7,375,757
$6,742,822
$70,700,764
$6,028,365
$11,250,202
$6,742,822
$119,058,562
$48,357,798
Page 232009 Integrated Resource Plan-Appendix C
Portfolio Analysis Idaho Power Company
2000 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfoio 1-2
Project
Two 170 MW Peakers at Langley
Capital Cost
$ 22,000,000
Annual Revenue Requirements
Existing Revenue Requirements.... ........ .... ...... ........ .... ...... ..........
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s )..................................
New Net Revenue Requirements.................................................
$106,566,650
$(17,510,193)
$89,056,456
$22,000,000
$3,521,532
$92,577,988
System Use (in MW)
Existing System Peak Demand....................................................
Future additionallPC Network Use
New System Demand-Induding new uses................................
5,627
340
5,967
Point-To-Point Transmission Rate
a) Existing Rate-$/kW-yr................................................................ $
b) New Rate without 3rd-Party Use$/kW-yr.................................. $
15.83
15.52
Point- To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase:; 100%).................................
Existing uses adjusted at nEM rate b)........................................... $
100%
344,857
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ ......................... $
Long-Term PTP Revenue............................................................ $
Legacy Contract Revenue............................. ............................... $
Assigned to IPC Retail Load Service............. .................. ............. $
b) Future
BPA Load Ratio Share........................................ ......................... $
Long-Term PTP Revenue............................................................ $
Legacy Contract Revenue............................. ............................... $
Assigned to IPC Retail Load Service............................................ $
Netchange $
4,237,114
7,375,757
6,742,822
70,700,764
4,154,388
7,230,494
6,742,822
74,450,284
3,749,520
Page 24 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
2000 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfoüo 1-3 with additional 3rd party subscription
Project
B2H 11% Owned by IPCO (250/2300)
Two 100MV Aeros at Langley
Capital Cost
$ 65,217,391
$ 22,000,000
Annual Revenue Requirements
Existing Revenue Requirements..................................................
Existing Revenue Credits.............................................................
Existing Net Revenue Reguirements...........................................
New Project Capital
New Revenue Requirements for Project(s ).. .... ........................ ....
New Net Revenue Requirements.................................................
$106,566,650
$(17,510,193)
$89,056,456
$87,217,391
$13,960,854
$103,017,310
System Use (in MW)
Existing System Peak Demand. .......... ...... .... ....... ...... .... ........ ......
Future additionallPC Network Use
New System Demand-Including new uses.............. ...... ........ ....
5,627
450
6,077
Point-To-Point Transmission Rate
a) Existing Rate-$/kW-yr...... .......................................................... $
b) New Rate without 3rd-Party Use$/kW-yr.................................. $
15.83
16.95
Point-To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase ~ 100%).................................
Existing uses adjusted at ne. rate b)........................................... $
100%
(1,244,978)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share..............................,..................................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Serviæ............................... .............
b) Future - B2H with additional participation
BPA Load Ratio Share.................................................................
Long-Term PTP Revenue........................................... .................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Serviæ............................................
Net change
$4,237,114
$7,375,757
$6,742,822
$70,700,764
$4,462,935
$7,900,174
$6,742,822
$83,911,380
$13,210,615
Page 252009 Integrated Resource Plan-Appendix C
Portfolio Analysis Idaho Power Company
2000 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfoüo 1-3 without additional3rd part subscription
Project
B2H 22% Owned by IPCO (500/2300)
Two 100MW Aeros at Langley
Capital Cost
$ 130,434,783
$ 22,000,000
Annual Revenue Requirement
Existing Revenue Requirements.. ...... .......... ............ ...... ..............
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s )..................................
New Net Revenue Requirements...... ........ ...... ........ ...... .......... .....
$106,566,650
$(17,510,193)
$89,056,456
$152,434,783
$24,400,177
$113,456,633
System Use (in MW)
Existing System Peak Demand....................................................
Future additionallPC Network Use
New System Demand-Induding new uses................................
5,627
450
6,077
Point-To-Point Transmission Rate
a) Existing Rate-$/kW-yr.. .... ...... ............ .... ...... ...... ............ ...... ...... $
b) New Rate without 3rd-Party Use-$/kW-yr.............................. .... $
15.83
18.67
Point-To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase;: 100%).................................
Existing uses adjusted at new rate b). .... ...... ........ .......... .......... .... $
100%
(3,145,545)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ ......................... $
Long-Term PTP Revenue............................................................ $
Legacy Contract Revenue............................. ............................... $
Assigned to IPC Retail Load Service............................... ............. $
b) Future - B2H without additional participation
BPA Load Ratio Share........................................ ......................... $
Long-Term PTP Revenue..................................................... .... ... $
Legacy Contract Revenue............................. ............................... $
Ass9ned to IPC Retail Load Service..................... .......... no.......... $
Netchange $
4,237,114
7,375,757
6,742,822
70,700,764
4,837,378
8,700,743
6,742,822
93,175,690
22,474,926
Page 26 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
2000 Integrated Resource Pian
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfofio 1-4 with additional 3rd party subscription
Project
B2H 19% owned by IPCo (425/2300)
450 Market Purchase
Capital Cost
$ 110,869,565
included in B2H
Annual Revenue Requirements
Existing Revenue Requirements..................................................
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements......................................... ..
New Project Capital
New Revenue Requirements for Project(s )...... .......... ...... ........ ....
New Net Revenue Requirements.................................................
$106,566,650
$(17,510,193)
$89,056,456
$110,869,565
$17,746,849
$106,803,305
System Use (in MW)
Existing System Peak Demand..................... ...............................
Future additionallPC Network Use
New System Demand-Including new uses.............. ...... ........ ....
5,627
425
6,052
Point-To-Point Transmission Rae
a) Existing Rate-$IkW-yr...... .... .... ...... .... .... .......... ...... ........ .... ........ $
b) New Rate without 3rd-Party Use$/kW-yr.................................. $
15.83
17.65
Point-To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase:; 100%).................................
Existing uses adjusted at naN rate b)........................................... $
100%
(2,014,578)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Service............................... .............
b) Future - B2H with additional participation
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to ¡PC Retail Load Service......................................... ..
Net change
$4,237,114
$7,375,757
$6,742,822
$70,700,764
$4,615,289
$8,224,350
$6,742,822
$87,220,844
$16,520,080
Page 272009 Integrated Resource Plan-Appendix C
Portfolio Analysis Idaho Power Company
2000 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfoio 1-4 without additional3rd part subscription
Project
B2H 37% owned by I PCo (850/2300)
450 Market Purchase
Capital COst
$ 221,739,130
included in B2H
Annual Revenue Requirements
Existing Revenue Requirements..................................................
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s)..................................
New Net Revenue Requirements.... ........................ ...... .... ...........
$106,566,650
$(17,510,193)
$89,056,456
$221,739,130
$35,493,697
$124,550,153
System Use (in MW)
Existing System Peak Demand..................... ...............................
Future additionallPC Network Use
New System Demand-Including new uses................................
5,627
425
6,052
Point-To-Point Transmission Rate
a) Existing Rate-$IkW-yr.......... ...... .... .... .......... .......... .... ................ $
b) New Rate without 3rd-Party Use-$IkW-yr.................................. $
15.83
20.58
Point-To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase;; 100%).................................
Existing uses adjusted at neN rate b)........................................... $
100%
(5,258,889)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ ......................... $
Long-Term PTP Revenue............................................................ $
Legacy COntract Revenue............................. ............................... $
Assgned to IPC Retail Load Serviæ................... ............ ............. $
b) Future - B2H without additional participation
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy COntract Revenue............................. ...............................
Assgned to ¡PC Retail Load Serviæ............................................
Net change
4,237,114
7,375,757
6,742,822
70,700,764
$5,254,035
$9,590,940
$6,742,822
$102,962,357
$32,261,593
Page 28 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
2009 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfotio 2-1
Project
Gateway 44% owned by IPCo (1020/2300)
250 East Side Purchase
670 MW Nuclear
300 MW Solar
104 MW Geothermal
Annual Revenue Requirements
Existing Revenue Requirements..................................................
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s)..................................
New Net Revenue Requirements.................................................
Capital Cost
$ 1,316,021,739
included in GW
included in GW
$ 7,500,000
$ 30,000,000
$106,566,650
$(17,510,193)
$89,056,456
$1,353,521,739
$216,657,702
$305,714,159
System Use (in MW)
Existing System Peak Demand... .... ...... .... .... '" ...... ...... .......... ......
Future additionallPC Network Use
New System Demand-Including new uses.. .... .... .... .... ...... ........
5,627
1,424
7,051
Point-To-Point Transmission Rate
a) Existing Rate-$IkW-yr................................................................ $
b) New Rate without 3rd-Party Use-$IkW-yr.................................. $
15.83
43.36
Po int-To-Point Revenue Adjustments (incrementl change to Existing Revenue Credits)
Change in existing uses (increase:; 100%)...................... ...........
Existing uses adjusted at naN rate b)............... ............................ $
100%
(30,458,820)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assgned to IPC Retail Load Serviæ............................... .............
b) Future - New Projects without additional participation
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assgned to ¡PC Retail Load Serviæ.......................................... ..
Net change
$4,237,114
$7,375,757
$6,742,822
$70,700,764
$10,321,179
$20,205,817
$6,742,822
$268,444,341
$197,743,576
Page 292009 Integrated Resource Plan-Appendix C
Portfolio Analysis Idaho Power Company
2009 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfofio 2-2
Project
Gateway 60% owned by IPCo (900/1500)
MSTI47% owed bylPCo (700/1500)
700 MW East Side Purchase (Wyoming)
200 MV Wnd
Capital Cost
$ 1,780,500,000
$ 466,666,667
included in GW
I nduded in GW
Annual Revenue Requirements
Existing Revenue Requirements...... ...... ........ .......... .......... .... ......
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements......................................... ..
New Project Capital
New Revenue Requirements for Project(s)...... .......... ..................
New Net Revenue Requirements.... o. .... .... ...... .... .............. ...... .....
$106,566,650
$(17,510,193)
$89,056,456
$2,247,166,667
$359,703,101
$448,759,557
System Use (in MW)
Existing System Peak Demand..................... ...............................
Future additional IPC Network Use
New System Demand-Induding new uses.... ...... .... ...... .... .... ....
5,627
1,600
7,227
Point-To-Point Transmission Rate
a) Existing Rate-$IkW-yr...... ...... .... .... .... .......... .......... .... .... ...... ...... $
b) New Rate without 3rd-Party Use$IkW-yr.................................. $
15.83
62.10
Point-To-Point Revenue Adjustments (incrementl change to Existing Revenue Credits)
Change in existing uses (increase;: 100%).................................
Existing uses adjusted at nEM rate b). .............. .............. .............. $
100%
(51,188,896)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ ......................... $
Long-Term PTP Revenue............................................................ $
Legacy Contract Revenue............................. ............................... $
Assigned to IPC Retail Load Serviæ............................... ............. $
b) Future - New Projects without additional participation
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Serviæ............................... .............
Net change
4,237,114
7,375,757
6,742,822
70,700,764
$14,527,165
$28,937,873
$6,742,822
$398,551,697
$327,850,933
Page 30 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portolio Analysis
2009 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfoio 2-3
Project
Gateway 40% owned by IPCo (600/1500)
(Aeolus-Hem ingway)
300 MW Solar
400 Large Aero (simco Road)
Capital Cost
$ 1,187,000,000
$ 7,500,000
$ 32,000,000
Annual Revenue Requirements
Existing Revenue Requirements............ ......................................
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s )..................................
New Net Revenue Requirements.... ...... .... .... ...... .... .... ............ .....
$106,566,650
$(17,510,193)
$89,056,456
$1,226,500,000
$196,325,382
$285,381,838
System Use (in MW)
Existing System Peak Demand....................................................
Future additionallPC Network Use
New System Demand-Induding new uses............ ........ ........ ....
5,627
1,300
6,927
Point.To.Point Transmission Rate
a) Existing Rate-$IkW-yr...... .... .............. .......... .... .... ...... .... ...... ...... $
b) New Rate without 3rd-Party Use-$IkW-yr............................ ...... $
15.83
41.20
Point.To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase;: 100%).................................
Existing uses adjusted at neN fate b)........................................... $
100%
(28,070,146)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Service............................... .............
b) Future - New Projects without additional participation
BPA Load Ratio Share.................................................................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Service.......................................... ..
Net change
$4,237,114
$7,375,757
$6,742,822
$70,700,764
$9,829,717
$19,199,644
$6,742,822
$249,609,655
$178,908,891
Page 312009 Integrated Resource Plan-Appendix C
Portolio Analysis Idaho Power Company
2000 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for2009 IRP Analysis
Portfotio 2.4
Project
Gateway 31% owned by IPCo (600/1600)
500 Wird
100 MW East Side Purchase
300 MW Peros at Langley
1100 MW Peros At Simco
Annual Revenue Requirements
Existing Revenue Requirements..................................................
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s)..................................
New Net Revenue Requirements.................................................
Capital Cost
$ 675,000,000
Induded in GW
included in GW
$ 22,000,000
$ 102,000,000
$106,566,650
$(17,510,193)
$89,056,456
$799,000,000
$127,895,622
$216,952,078
System Use (in MW)
Existing System Peak Demand..................... ...............................
Future additionallPC Network Use
New System Demand-Induding new uses...... .... ...... ................
5,627
2,000
7,627
Point-To-Point Transmission Rate
a) Existing Rate-$IkW-yr................................................................ $
b) New Rate without 3rd-Party Use$/kW-yr.................................. $
15.83
28.45
Point.To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase;: 100%).................................
Existing uses adjusted at new rate b)........................................... $
100%
(13,960,338)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................................................
Assigned to IPC Retail Load Service............................... .............
b) Future - New Projects without additional participation
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Service............................... no..........
Net change
$4,237,114
$7,375,757
$6,742,822
$70,700,764
$7,010,667
$13,256,220
$6,742,822
$189,942,369
$119,241,605
Page 32 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Portfolio Analysis
2000 Integrated Resource Plan
Idaho Power Transmission Rate Approximation for 2009 IRP Analysis
Portfofio 2-5
Project
Gateway 19% owned by IPCo (300/1600)
300 Win:
1050 Existing Coal
Capital Cost
$ 337,500,000
Included in GW
Annual Revenue Requirements
Existing Revenue Requirements.. ...... .... .............. .... .......... ..........
Existing Revenue Credits.............................................................
Existing Net Revenue Requirements...........................................
New Project Capital
New Revenue Requirements for Project(s)..................................
New Net Revenue Requirements.... .............. .......... .... .... ........ .....
$106,566,650
$(17,510,193)
$89,056,456
$337,500,000
$54,023,495
$143,079,951
System Use (in MW)
Existing System Peak Demand..................... ...............................
Future additionallPC Network Use
New System Demand-Induding new uses................................
5,627
300
5,927
Point-To-Point Transmission Rate
a) Existing Rate$/kW-yr................................................................ $
b) New Rate without 3rd-Party Use-$/kW-yr.................................. $
15.83
24.14
Point-To-Point Revenue Adjustments (incremental change to Existing Revenue Credits)
Change in existing uses (increase ~ 100%).................. ...............
Existing uses adjusted at naN rate b)........................................... $
100%
(9,198,010)
Network Transmission Revenue Requirements
a) Existing
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Service............................... .............
b) Future - New Projects without additional participation
BPA Load Ratio Share........................................ .........................
Long-Term PTP Revenue............................................................
Legacy Contract Revenue............................. ...............................
Assigned to IPC Retail Load Service............................................
Net change
$4,237,114
$7,375,757
$6,742,822
$70,700,764
$6,028,365
$11,250,202
$6,742,822
$119,058,562
$48,357,798
Page 332009 Integrated Resource Plan-Appendix C
Portfolio Analysis Idaho Power Company
Loss of Load Expectation Summary Data-Preferred Portfolio (1-4 & 2-4)*
Annual
Year Preferred Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2010 0.66 0.00 0.00 0.00 0.00 0.0 0.10 0.43 0.06 0.06 0.00 0.00 0.0
2011 2.17 0.0 0.00 0.00 0.00 0.05 0.14 1.79 0.08 0.08 0.00 0.00 0.01
2012 1.57 0.01 0.00 0.00 0.00 0.02 0.85 0.48 0.11 0.06 0.00 0.00 0.01
2013 1.93 0.00 0.00 0.00 0.00 0.00 0.14 1.53 0.19 0.06 0.00 0.00 0.02
2014 1.91 0.00 0.00 0.00 0.00 0.0 0.26 1.:£0.21 0.06 0.00 0.00 0.02
2015 1.13 0.00 0.00 0.00 0.00 0.0 0.11 0.81 0.11 0.07 0.00 0.00 0.01
2016 1.48 0.00 0.00 0.00 0.00 0.03 0.10 1.15 0.13 0.05 0.00 0.00 0.01
2017 0.57 0.00 0.00 0.00 0.00 0.03 0.05 0.32 0.10 0.06 0.00 0.00 0.0
2018 0.69 0.00 0.00 0.00 0.00 0.02 0.03 0.47 0.09 0.05 0.00 0.00 0.01
2019 0.97 0.00 0.00 0.00 0.00 0.0 0.02 0.77 0.12 0.02 0.00 0.01 0.02
2020 0.71 0.00 0.00 0.00 0.00 0.02 0.02 0.64 0.02 0.01 0.00 0.00 0.00
2021 0.73 0.00 0.00 0.00 0.00 0.00 0.02 0.67 0.02 0.01 0.00 0.00 0.00
2022 1.05 0.00 0.00 0.00 0.00 0.00 0.03 0.97 0.02 0.01 0.00 0.00 0.00
2023 1.58 0.00 0.00 0.00 0.00 0.00 0.09 1.:£0.03 0.10 0.00 0.00 0.00
2024 0.83 0.00 0.00 0.00 0.00 0.00 0.01 0.79 0.00 0.03 0.00 0.00 0.00
2025 0.23 0.00 0.00 0.00 0.00 0.00 0.01 0.21 0.00 0.01 0.00 0.00 0.00
2026 0.14 0.00 0.00 0.00 0.00 0.00 0.07 0.05 0.00 0.02 0.00 0.00 0.00
2027 0.32 0.00 0.00 0.00 0.00 0.00 0.14 0.05 0.00 0.14 0.00 0.00 0.00
2028 3.22 0.00 0.00 0.00 0.00 0.00 0.24 2.89 0.09 0.01 0.00 0.00 0.00
2029 0.10 0.00 0.00 0.00 0.00 0.00 0.00 0.10 0.00 0.00 0.00 0.00 0.00
*With (8M (g 330 MW and 83 MW & 158 MW east-side purchases in 2013/2014 and 83 MW in 2028
Loss of Load Expectation Summary Data-Alternate Portfolio 1-2*
Annual
Year Preferred Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2014 1.91 0.00 0.00 0.00 0.00 0.01 0.26 1.:£0.21 0.06 0.00 0.00 0.02
2015 1.17 0.00 0.00 0.00 0.00 0.00 0.08 0.95 0.07 0.07 0.00 0.00 0.00
2016 1.68 0.00 0.00 0.00 0.00 0.01 0.12 1.34 0.14 0.08 0.00 0.00 0.00
2017 0.65 0.00 0.00 0.00 0.00 0.00 0.04 0.54 0.05 0.02 0.00 0.00 0.00
2018 0.99 0.00 0.00 0.00 0.00 0.00 0.07 0.81 0.07 0.03 0.00 0.00 0.00
2019 1.59 0.00 0.00 0.00 0.00 0.00 0.11 1.32 0.10 0.06 0.00 0.00 0.00
* With (8M (g 330 MW and 83 MW & 158 MWeast-side purchases in 2013/2014
With (8M (g 330 MW and 83 east-side purchases in 2015 and beyond
Loss of Load Expectation Summary Data-Alternate Portfolio 2-5*
Annual
Year Preferred Jan Feb Mar Ap May Jun Jul Aug Sep Oct Nov Dec
2019 0.97 0.00 0.00 0.00 0.00 0.0 0.02 0.77 0.12 0.02 0.00 0.01 0.02
2020 0.85 0.00 0.00 0.00 0.00 0.03 0.05 0.68 0.05 0.03 0.00 0.00 0.01
2021 0.93 0.00 0.00 0.00 0.00 0.04 0.06 0.71 0.07 0.05 0.00 0.00 0.01
2022 0.53 0.00 0.00 0.00 0.00 0.0 0.03 0.42 0.04 0.02 0.00 0.00 0.00
2023 0.75 0.00 0.00 0.00 0.00 0.02 0.08 0.57 0.05 0.03 0.00 0.00 0.00
2024 1.68 0.00 0.00 0.00 0.00 0.02 0.06 1.51 0.06 0.03 0.00 0.00 0.00
2025 1.31 0.00 0.00 0.00 0.00 0.02 0.08 1.00 0.07 0.05 0.00 0.00 0.00
2026 0.70 0.00 0.00 0.00 0.00 0.01 0.04 o.æ 0.03 0.03 0.00 0.00 0.00
2027 0.34 0.00 0.00 0.00 0.00 0.00 0.04 0.28 0.01 0.01 0.00 0.00 0.00
2028 0.95 0.00 0.00 0.00 0.00 0.00 0.03 0.89 0.02 0.01 0.00 0.00 0.00
2029 0.48 0.00 0.00 0.00 0.00 0.00 0.03 0.41 0.0 0.02 0.00 0.00 0.00
*With (8M (g 330 MW and 83 MW purchases in 2020-2029
Page 34 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Sales and Load Forecast
SALES AND LOAD FORECAST DATA
Average Annual Growth Rates (%)
Sales
Residential Sales.................
Commercial Sales..... ... ... .....
Irrgation Sales.....................
Industrial Sales....................
Additional Firm Sales...........
Firm Sales..........................
System Sales....... .... ... .... ....
Total Sales..................... .....
Loads
Residential Load..................
Commercial Load.................
Irrgation Load......................
Industrial Load.....................
Additional Firm Sales...........
Firm Load Losses....... .........
Firm Load............................
System Load.......................
Total Load...........................
Firm Requirement Load........
Peaks
Firm Peak...........................
System Peak......................
Total Peak...........................
Firm Requirement Peak........
Winter Peak........................
Summer Peak.....................
Customers
Residential Customers.........
Commercial Customers........
Irrgation Customers.............
Industrial Customers............
2010-2015 2010-2020 2010-2029
1.4
1.5
-0.2
3.5
3.4
1.8
1.8
1.8
1.2
1.1
0.0
1.8
1.5
1.2
1.2
1.2
0.6
0.7
-0.5
1.0
2.3
0.7
0.7
0.7
1.4
1.5
-0.2
3.3
3.4
1.5
1.7
1.7
1.7
1.7
1.2
1.1
-0.1
1.7
1.5
1.0
1.1
1.1
1.1
1.1
0.6
0.7
-0.5
1.0
2.3
0.5
0.7
0.7
0.7
0.6
2.1
2.1
2.1
2.1
0.3
2.1
1.8
1.8
1.8
1.8
0.3
1.8
1.5
1.5
1.5
1.5
0.0
1.5
1.6
2.1
1.5
1.3
1.7
2.2
1.4
1.2
1.7
2.1
1.4
1.1
2009 Integrated Resource Plan-Appendix C Page 35
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Sales and Load Forecast Idaho Power Company
$ales Load ForecilstAnnual Sumiary
Biled Sales
ResidentiaL.... ... ..... ........ ....... ..... .... .........
Commeriai............................................
Irrgation...................................................
Incstrial.................................................
Addonal Firm.........................................
Firm Sales
SyStem S¡'les
5.168.469 5,256.321 5.379,801 5.376.155 5.489.259 5.530.778 5,587.128 5,645;662 5;701;444 5.769.695
3.829;818 3,890,483 3,980.186 4.047.917 4.100.296 4,133.788 4;163.623 4.192,537 4.221,347 4.249,770
1;69S,SS 1,708.44 1,595,280 1.663.869 1.677.836 1.683,905 1.682,258 1.683,643 1.86,914 1.689;596
2.196.153 2.41.88 2,567.526 2.589.05 2.599.655 2,61.497 2,611,034 2;616;668 2.622.321 2;628;31
1.428.996 l,61..959 1,621.276 1.687.195 1,689.907 1.669.2$1 1;83.727 1.678.357 1;676.318 1;57;486
14.322.324 14,902.092 15;244.069 15.384.190 15;556.953 16.642.199 15.727.771 15.816.867 15,907.34 15;95.079
14.322.324 14.902.092 15.244.06 15.384.190 15.55.953 15.642.199 15.727.771 15.816.867 15.907.34 15;995.079
0 0 0 0 0 0 0 0 0 0
14,322.324 14.02.092 1$.44.0G 15.384.190 15.566,953 15.642,199 15.727,771 15,816;867 15.07,34 15,995.079
Firm OISysem Sal
Totál Saes
ResidentiaL.. ....... ... ....... ... ........ .......... .....
CommerciaL.............................................
Irrgation...................................................
IndlJtnal.................................................
AdclloriFirm.........................................
Firm Sales
Total Sales
5.174.855 5.264.992
3,83.231 3.897.657 3.997.338 4.053.04 4,104,395 4,137;679 4;179,510 4,196,349 4.225.126 4,253.450
1.98.904 1,708,441 1.695.300 1.683.870 1.677.845 1.683;908 1;682.28 1,683,649 1,685,921 1.689.605
2;211,419 2;57,547 2,569.645 2.689.952 2.60,158 2;605.016 2.611,732 2,616,883 2.62.847 2,628,92
1.28.995 1.604.959 1.621.276 1;687.195 1;689,907 1.689,231 1.683.727 1.678,357 1.676.318 1,657.486
14,349;404 14.933;55 16,28.274 15.398,109 15;56.319 15,650,380 15,765;812 15,824.593 15,916,190 16.03.910
14.349.404 14.933;595 15.28.274 15;398.109 15,56;319 15.650;38 15,765.812 15;a;4'593 15;916;190 16.003.910
0 0 0 0 0 0 0 0 0 0
14.349,404 14,933.595 15.2.274 15.398.109 15;56.319 15;650.380 15.765.812 15.824.593 15,916:190 16;003.910
1.92..G59 1.434.513 1,465.382 1.72.31G 1.48.589 1,496.524 1.507.986 1,13:222 1.21.03 1.531.19G
15,742.063 W.36.10a 16.745.655 1G,70.425 17.52.907 17,146.904 17,273,798 17,337.815 17.437,99 17.535.105
System Slies
Firm Of.SyStem Saes
Loss...........................................,.............
ReqLired Genelilon
.Resid~.............;.,.....;......;.;............591 6 4 61 62
CommeriaL.,................;....,.....................438 455 463 469 472 476 479 482 48
Irrgalòn.....,..........i....._-......,........................194 193 192 192 192 192 192 192 193
Incstnal.""............................................252 293 29 297 297 297 299 299 300
Adcitionil Firm.....,.........................."..,....163 185 193 193 193 192 192 191 189
LOss....;........,.......................,...................159 167 168 170 171 172 173 174 175
Firm Load 1;797 1.905 1.92 1;47 1.957 1;67 1.979 1.991 2.002
Ligl Loa..............................1.635 1.700 1.735 1;752 1.71 1.1l1 1.71l9 1.801 1.1l11 1;821
HellLoad...............................................1;24 2.001 2.042 2.062 2,085 2.096 2.106 20120 2.132 2,143
$yel1 Load 1,97 1;89 1,9l 1.926 1.947 1.957 1,967 1.979 1,91 2.002
Fin Of.SyteI1LOad...........,.........,.,.......0 0 0 0 0 0 0 0 0 0
Tllai Load 1,97 1.1l69 1,06 1.926 1.947 1,957 1.967 1,979 1.991 2.002
Peak Load
19
ElirgElCien (MI)...".. ....... .."...,.. .....17 .33 .93 407 -121 .135 .149
Oer_.Reptrie (Mw)...............,..........0 0 0 0 0 0 0FIrm PelLoa 3;439 3,538 3.819 3.71 3;925 3.978 4.034
Syem Pea (1 Hour)3.439 3.38 3.614 3,703 3;766 3;819 M71 3,925 3,978 4.034
Fin OiSytømPNk.....,...........,............0 0 0 0 0 0 0 0 0 0
Tot~1 Peak loa 3.39 3,531l 3.614 3;03 3.766 3.1l19 3,71 3.925 3,978 4.034
Page 56 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Sales and Load Forecast
Residential...............................................
CommerciaL...........................................
Irrgalio...................................................
IndstriaL...............................................
Additional Fir ........... ........ ....... .... ...... .....
Firm Sales
System Saias
Firm OI.Sysem Sales
Total Sales
Residertl.... ......... ............ .., ...................
Commerci...... ................... ................. ....
Irrgaln...................................................
Industrial..................................................
Additional Firm........................,................
Firm Sal
Syem Sal
Finl OI-Systern Sales
Total Sales
loss.........................................................
Requred Generaton
Sales Load ForecastAlinual Summary
Billèd saes
S.841.011 S.841.418 s,95.447 5.58.
4.76.547 4.293.64 4.313.307 4.334.101 4.3S0.602 4.365.073 4.370.462 4.379.40 4.379.364
1.695,341 1,691,09 1.685.309 1.673.258 1.663.734 1.668.126 1.656,6()1 1.63.78 1:612.185
2.634.391 2.637,943 2,644.19 2.655,893 2.661,588 2:6613,70 2,671.16 2.678.55 2.679,036
1.6S7;426 1.651,857 1,600:315 1.38.050 1,632,964 1.619:435 1;05,$24 1.591),21;7 1,578,77516.104.711;11;.111;90 11;,189.3 11;.191.111 11;,264.271 16,318,279 16:261,893 16,250.219 16,11;.208
16,104.716 16.116.090 16.189.:308 16,245.3~16.191;861 11;.264:271 16,318;279 111;261.893 16.250,2111 16.116,208
0 0 0 0 0 0 0 0 0 0
16.104.116 16,111;;090 16;189.308 16.245,309 16;191,861 11;.264.271 16,3113,279 11;.261.693 16,25.219 16.111;:208
GeneratiilnMill'th Sales
5.858.1367 5.84:921 5,89':281 5
4.292,409 4.291;,753 4,316.405 4,332.205 4,350,97 4.353.$6 4.367,648 4.73;11;4.395.241 4,3s1:98Ø
1:695.31;1.691;08 1,6l,314 1,1;86,373 1.673;278 1,SE3.742 1;661,121 1.6S6;591 1.313.795 1.612.1662.634,96 2.638,631 2,645:'84 2:652.260 2;651;,430 2,662,4G 2,Sl.81l 2,672.4133 2.6713,356 2,679,387
1,657;426 1.651;857 1,1;0.315 1.1;36.705 1,6313,050 1.632,96 1.1;19,435 1;605,524 1,595.267 1.578,77!
16.139.31 11;.123;$9 16,1!l,100 16,243;907 16.230.71;9 16.270,729 11;113.149 11;;21,935 11;,;2,230 16,118,62
16.139.031 16,123.569 16,196.100 16,243,907 16.230..769 16.270,729 16.18,149 16.26,93S 16.211,230 16,118,41;2
0 0 0 0 0 0 0 0 0 0
16.139.031 16:123.569 16,196,100 16.243,907 16.230,769 16.270.729 16,318.149 16,26.935 16.77,230 16,118.462
1,544,406 1,541.15 1.413,045 1.552.690 1.549.724 1.552.855 1.557.457 1,551.223 1.551.30 1.534.338
17,1;83,437 17665,184 17.744.145 17,796.97 11;80,493 17.823.83 17;875,1;01;17,816,158 17,82.0S\17,1;52.801
ResintiaL............,...................,...........
CommeriL..................."......................
Irrigation.......................,......................,,...
IndustL...............................................
Additional Fir.............,.,...................,.....
less...,..............................,......................Fir loa
lighlload................................................
Hea load.,...............................
System Lod
Firm OI.System loa....
Totlìload
667 1;1;7
469 490 493 495 495 497 499 499 50 500
193 193 192 193 190 190 190 189 187 184
300 301 302 303 302 30 305 305 30 306
169 189 188 187 186 ias 185 183 182 180
176 171;177 177 171;177 178 117 177 175
2,013 2.017 2.026 2.032 2.024 2,035 2.041 2.03 2.030 2.015
1.831 1.83 1;83 1.848 1,841 1:851 1;856 1;850 1,84 1,833
2,156 2,11;0 2,169 2.116 2,11;7 2,179 2,185 2,178 2,174 2,158
2,013 2,017 2.026 2.032 2,024 2,035 2,041 2;03 2,030 2.015
0 0 0 0 0 0 0 0 0 0
2;013 2,017 2,026 2.032 2;024 2.035 2.041 2.034 2.030 2;015
90 Percentile
-163 .177 '219 5 +269
0 0 0 0 0
4.091 4.133 4.262 4:430 4.44
4.091 4,133 4.183 4.234 4,21;2 4.312 4.364 4.394 4,43 4.45
0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0
4,091 4,133 4.183 4.234 4.262 4.312 4,31;4,39 4.30 4.45
Energy Efciency (M............................
Deand Response (M.......,..................
Firm Pea load
Syem Pea (1 Hor)
Firm Of.Syem PealL............ ........... .....
Less.............. ..........................................
Total Peak load
2009 Integrated Resource Plan-Appendix C Page 57
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Idaho Power Company Sales and Load Forecast
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Sales and Load Forecast Idaho Power Company
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'-(J Q)roII Q)::a.ro Q)a."o en("Q)!i
Sales and Load Forecast Idaho Power Company
ResidentaL............................................
CommerciaL...........................................
Irrigaion....................".............................
Inc1rial............... ............ ............... .......
Addiional Firm.........................................
Firm Sales
SysemSales
Firm Of-Syem Saies
Total Sales
CommerCial..............................................
Irrigation...................................................
Inc1rlaL.... .... ....... ............ ....... ....... ......
Additiona Fir.........................................
Firm Sales
Sysem Sales
Firm Of-System Sales
Total sales
Loss.........................................................
Reqiired GeneraiOn
ResidentL.. ......... ........ ........ ......... .........
CommerciaL. .... ................. ............ ..... .......
lmgailon...................................................
Inwstriai................................................
Addllona Ar.........................................
Loss.........................................................
Firm Load
2010
5.328.002
3.879.270
1.843.349
2.196.153
1.428.995
14.675,769
Sales And Load Forecast Annual SUmmary
Sileii Sales (MeQaWàl1oursl;70th Percentile2011 2012 20132014 2015
5,18.985 5;545,56 5;544.88 5,61:123 5;705,655
3;941.39 4.03.1)57 4,101.010 4.154.617 4,189.349
1,852.905 U139.741 1.828.330 1.822.27 1.828;36
2,41,884 2.567,526 2,589.054 2.599.655 2.60,497
1.04.959 1.621.276 1,687.195 1.689.907 1.689.231
15.259.872 15,606:163 15.750.577 15.927.598 16.017,097
2016
5,765.013
4.220.439
1.828.719
2.611,034
1.683.727
16,106,932
2017
5.826,541
4,250,624
1.28.104
2,616,668
1.678,357
16.200.2
2018
5,885,328
4.28,729
1.830.375
2.622.321
1.676.318
16.295.071
2019
5.956.603
4,310.468
1.1l34.057
2.628;531
1.57.466
16.387.145
14.675.769 15.259:872 15.606,163 15,750.577 15.927,598 16,017,097 16;06,932 16.200;29 16.295.071 16;387,145o 0 0 0 0 0 0 0 0 0
14.675,769 15.259:872 15;606.163 15.750.577 15.927,59 16,017,097 16;06,932 16,200,29 16.295,071 16,387,145
3.884,769
1.843.364
2.211.19
1,428,995
14,703,056
Generation Month Sales
2011
. 1
3,948.400
1.852,901
2.457.547
1.60.959
15.291.579
!i
4,158.805
1.822.306
2.600,158
1.689,$07
15,935.152
4.106.225
1.28.330
2.569.952
1.87.195
15.764.687
4.193.329
1.828.36
2.605.016
1.689.231
16.025,461
14,703.56 15.291.579 15,64.600 15.764.687 15,935,152 16,025.461
0 0 0 0 0 0
14.703.056 15.291;79 15.64.600 15.764.687 15.935,152 16.025,461
1.431.207 1.473.533 1.504.984 1.512.273 1;29,00$1.537.408
16.134.263 16.765.112 17.148.584 17.276.961 17.46.161 17.562.869
2010 60
44
210
252
163
163
1,842
Lig Load............................."................. 1.676
Hei! Load............................................... 1.972
Sysløm .La 1;842
Firm Ç!.Syem LOad............"................ 0
Tolalload 1.842
Demand Resonse )..........................
Fir Peak Loa
AVeJpe Loall(Av~age Megawat(lIl;7Oth Percenle2011 2012 2013 2014 2015620 633 634 647 652451 451 469 475 479212 209 209 208 20281 293 296 297 297183 185 193 193 193168 171 173 175 176
1.914 1.952 1.972 1.99 2.00
1.741 1.76 1.94 1;814 1,824
2,049 2.091 2.112 2,35 2.147
1.$14 1,952 1.972 1;99 2.00
0 0 I)0 0
1,914 1..952 1.972 1:99 2.00
4.236,696
1.1l26.747
2.611.32
1,683.727
16.146.238
4.254.29
1.828.110
2.616.883
1.678,357
16,208.198
,94
4,284.602
1.830.382
2.622,847
1,676;318
16,30.092
5.
4.314.243
1.34.065
2.628.952
1.657.486
16.396.149
16.46.238 16.208.19816,30.092 16.396.149o 0 0 0
16.146,238 16.208.198 16,304.P92 16.396.149
1.549.452 1;55.05 1,56.06 1,573.950
17.695.690 17.763;233 17.86,177 17,97P.099
2016 2017 2018 2019
659 666 672 681
482 48 469 492
208 209 209 209
297 299 299 300
192 192 191 189
176 178 179 180
2.PLi;2.P8 2.04 2.P51
1,833 1,845 1,856 1.ll6
2,157 2,172 2;184 2;196
2,015 2.028 2,04 2;051
0 P P 0
2.015 2.028 2.P4P 2.051
2010
- 49
o
4.P6
SySI$lPeak(l HolJ)3060 3,56P 3,636 3.72l 3.7a9 3.843 3,895 3;949 4.003 4.060
Firm ().Syem p~k:...,.."."...,...;............0 P 0 0 0 P P 0 0 0
Total Peak Load &.460 3.56P 3;636 3.726 3.78g 3,843 3,895 3,949 4.P03 4.o6l)
Page 78 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Sales and Load Forecast
Residmal...............................................
Commercial..............................................
trrgaion...................................................
IndustriaL.................................................
Add Fin.........................................
Firm Sales
Systm Sales
Finn QISyem Sal
Tota Sales
2020
6.030.952
4.338.582
1.839.802
2.634.391
1,657,426
16,501.53
Sales And Lôad Forecast Aonual Summar
Biled Sales (Megaatoursb7Dt Peretile2021 2022 20232024 2025
6,034.404 6.091.866.139.032 5,092,711 6,160.567
4.356,860 4,378.082 4.395.931 4.401,688 4.419.613
1.35.70 1.629.770 1.6,30.840 1.817.719 1.806,195
:2.1l3.943 :2.64.929 ':2,65.534 2,655;893 :2,661.88
1.51.857 1,650.315 1,1)36.705 1.38.050 1.632.964
16;516.~3 16;594.582 16.655.4:2 16.606.060 16,82.926
2026
6.205,253
4.35,517
1,812,587
2.666,570
1.19,435
16,741.362
2027
6,168.525
4.42.34
1.801.062
2.671.916
1.05.524
16.669.371
2028
6,172.246
4.452.730
1,783,260
2,678.50
1.595,267
16.82,043
2029
6.083,732
4.454,123
1,756.64
2.679.036
1.578,775
16.52,312
4.360,247
1.835.69
2,638.31
1,651.57
16,524,561
4,396.479
1,830.833
2.652.260
1.636.705
16.653,801
Resdental...............................................
Comeral..............................................
Irrigaon...................................................
InduriaL................................................
Adlrtional Finn.........................................
Finn Sales
Sytem Sales
Firm OI-Sysem Saes
Total Sales
Loss.........................................................
Reqiired Generon
Residenlial...............................................
CommerciaL............................................
Irrgaion...................................................
Industrial..................................................
Addional Finn.........................................
Los.........................................................
Firm Load
Ligli Load................................................
Heav Loa..............................................
System Load
Finn OI-Syem Load..............................
ToialLoad
Energ BIciency (M............... .............
Demand Resonse (M)..........................
Firm Peak Load
16.501.53 16,516,933 16,594.582 16.655.042 16,606.060 16,682,926 16,741.362 16,669.371 16,682.043 16.552,312o () 0 0 00 0 0 0 0
15.501,153 16.16,933 16,59,582 16.655.042 16,606.060 16.582,926 16.741.362 16.669,(11 16.682.04 15.55:!312
6.049,707
4,354.84
1.839,826
2,634,963
1,657.426
16,536,770
6,09
4.31,28
1.89.775
2.645,784
1.50.315
16,601.540
2026
6.202,384
4,438.09
1.612,561
2,666.680
1.619.435
16.41,377
4.445,102
U01,051
2.62.463
1.05.524
16,692.548
,052
4,456,843
1.756.627
2.679,387
1,578,715
16,554,68
Avera el
2021
669
498
210
301
189
161
2,067
16,536,770 16,524.581 16.601,54 16,65,801 16.646.300 16.689.534 16,741.77 16,692.548 16,710.395 16,55,683
2020
689
496
209
3()
189
161
2,063
2020
_163
o
4;116
6
500
209
302
168
182
:2.077
1,881
2.214
2,067
1,889
2.224
2.077
1,895
2,232
2.083
1,88
2.223urn
1,99
2.236
2,088
o
2,088
2026
C247
o
4.393
o Oll 0 0 0 0 0 0 0
16.536.770 16,524.561 16.601.540 16.653.801 16.646.300 16.689.534 16,741,377 16.69;548 16,710,395 16,554.683
1.587.760 1.585.325 1,592,238 1,597.369 1.595,017 1;598,504 1.03,588 1.597,831.599,04 1,581.886
18,124,531 18,109,906 18.193,778 18,251.70 18.241.317 18.288;039 18.34.965 18,29,31 18.3090439 18.136,570
1.877
2.209
2.063
o
U63
2021
-177
o
4.160
2009 Integrated Resource Plan-Appendix C
o
2.067
o
2,077
o
2,083
o
2.077
PeákLoad(Megawattsb95lh Percentile2022 2023 2024-191 -205 -219o 0 0
4.210 4.261 4.290
2025
-233
o
4,341
2028 2029
04 70 694
507 507 509 509
207 206 203 201
305 305 305 306
185 183 182 180
183 182 182 181
2,094 2.088 2,084 2,070
1,95 1.899 1,896 1.883
2.243 2.236 2.233 2;217
2.694 2,08 2.08 2,070
0 0 '0 0
2,09 2;088 2;084 2,070
2027
-261
o
4,424
2028
-275
o
4.460
2029
C289
o
4,47S
Syeii,Pèak (1 1î)4.118 4;160 4,210 4.261 4.290 4.341 4.393 4,424 4.460 4;475
FirmOf-SystemPeal...". ..' "..........."..."0 0 0 0 0 0 0 0 0 0
LOSs.,.,.,........"..............,..."..........,....,.,."0 0 0 0 0 0 0 0 0 0
TQlaI Pèak Load 4.118 4,160 4.210 4,261 4.290 4.341 4,393 4.24 4.60 4.475
Page 79
Existing Resource Data Idaho Power Company
EXISTING RESOURCE DATA
Hydroelectric and Thermal Plant Datê
Hyd roelectric Power
Plants
American Falls....................
Bliss....................................
Brownlee.............................
Cascade. .......... ...................
Clear Lake.........................
Hells Canyon...... ......... .......
Lower Salmon........... ..... .....
Malad-Lower.. ........... .........
Malad-Upper.. ..... ....... ........
Milner..................................
Oxbow.................................
Shoshone Falls... ............. ...
Strike,
Swan Falls..........................
Thousand Springs.......... .....
Twin Falls............................
Upper Salmon "A".. ....... ......
Upper Salmon "B". ... ....... ...
Totl Hydro
Thermal, Natural Gas,
and Diesei Power Pia
ri
Boardman (IPC Share).......
Valmy (IPC Share).............
Total Thennal
Nameplate
kVA
102,600
86,250
650,444
13,800
3,125
435,000
70,000
15,500
9,650
62,890
211,112
14,900
90,000
28,600
11,000
56,175
18,000
18,000
1,897,046
kW
92,340
75,000
585,400
12,420
2,500 (1)
391,500
60,00
13,500
8,270
59,448
190,000
12,500 (1)
82,800
27,170
8,800 (1)
52,897
18,000
16,500
1,709,045
Generator Nal1ePI¡lte Rating
Gross kVA Gross kW
811,053 770,501
67,600 64,200
315,000 283,500
1,193,653 1,118,201
Bennett Mountain...... ..........
Evander Andrews Unit #1...
Evander Andrews Unit#2...
Evander Andrews Unit #3...
Total Natural Gas
Salmon Diesel.................. ...
Total IPC Generation
192,000
189,994
51,000
51,000
483,994
6,880
3,581;573
172,800
170,955
45,900
45,900
435,555
5,000
3,267,801
Normal
Rating kW
(4)
92,340
75,000
585,400
12,420
2,420
391,500
60,000
13,500
8,270
59,448
190,000
12,500
82,800
24,170 (3)
6,380 (2)
52,561
18,000
16,500
Net
Dependable
Capabilit
(NDe)
kW(6)
706,
58,600
258,250
1,023,517
164,159
170,955
45,236
45,236
425,586
5,500
Emergency
Rating kW
t5l
108,85
76,470
746,570
14,800
2,420
444,830
64,340
16,520
8,540
61,090
221,410
14,040
90,720
24,170
6,380
53,060
18,930
17,510
(1) A power factor rating ofCl.8 is assumed on for un~s (Clear Lake, Un~ #2 at Shoshone Fans, and Un~s#l and #2
at Thousand Springs) Vrh a totl INA rang of 6,127 INA on 1Mich there is no nameplate kW rang.
(2) The tw smaller units, #1 and #2, bot having nameplate ratings of 1.25 MVA and 1 MI, have been taken out of
service due to reduced tow from the springs and penstock interi.
(3) The Swan Falls unit have bee Iim~ed to 24.170 kW as a resutt of vibraon issues.
(4) The Nonal Rating is defined as the normal kW ouut of the facilit wih all un~s on-line. This rang includes an
equipment limitatins and may be lower than the nameplate rating. To operate at the Noial Rating, appropriate
water condions must exist and the FERC license reuiremets perm~.
(') The Emergency Rating is deiined as the maximum kW output of the facilit v. all units on-line. The Emergency
Rating is based on allowable generator overloads and limite by auxiliary equipment ratings. To operate at the
Emergency Rating, apprpriate water conditns must exist and the FERC license requirements permit.
(8) Net Dependable Capacity (NDC) is defned in the N ERe Generating AvaHabili Data Sysem (GAS) as Gros
Dependable Capacity (GDC) less the unit capacity utilzed for tha units sttio service or auxiliari. GDC is the
Gross Maximum Capacit (GMC) modied for seasonal limitaions over a spcifed perid oftime. The GDC and
MDC (Maximum Dependable Capaciy) used in previous GADS repors are the same in intent and pur¡ose. GMC is
the maximum capacity a unit can sustin over a speci1ied period oftime1Men not restrcted by seasonal or oter derags.
Page 80 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Existing Resource Data
ldahi:()Wèrcory
Quailng FaCilithls
CtlenraiOl and Small Poer ProdctOl Prjectsiiåtll as Qf..1,2i)~
Project
Hydro Projects
BarberDam . ..
Birch Creek...
Falls River. .
HazêltonB
Horseshoe Bend Hydroelectnc
Bìomass Projects
Bettencourt Dry Creek Biofactory
Big Sky West Dairy Digester.
CO-GEN CO.
Hidden Hollow Landfill Gas.
Wind Projects
Bennett CreeKWnd Farm
Glothermal Project
None
Natural Gas 10.00
Natural Gas 10.00
Contrad
On-line Date End Date
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Apr-1989
Nov-19M
014
150
0.36
Nov-2016
Nov-2016
Total Themial Nameplate MWrang 37.00
155
0.52
Jun-1984
Nov-1983
Apr-1986
J.Jn-1983
Aug-1988
May. 1986
Aug-1993
Aug-1987
JuI-1990
Nov-1986
cln-1985
Jun-1990
May.1993
Sep-1995
Biomass 2 25 Aug-2008 Non-firm
Biomass 150 J9n-20û9 Jan-2029
Biomass 9.40 cll-2008 cll-09
Biomass 3.20 Oct-2006 Jul-2009
Total Biomass Nameplate MW ratiri
910
087
0.26
0.93
006
770
760
950
Wnd
Wnd
V¥\nd
Wnd
Wind
Wind
Wind
Wind
WInd
1980 De0-2008 Dec. 2028
1050 Sep-2010 Estimated
1050 Feb 2009 Feb-2029
1890 Feb 2009 Feb 2029
1050 Sep-2005 Sep-2025
12 00 Sep- 2010 Estimated
900 Feb-2006 Feb-2026
1980 Mar-2008 Mar-2028
18.00 Sep2010 Estimated
Tot_i Wind Nameplate MWrari
Nov-1996
Dec-1996
Total Geothemial Nameplate MW rating
Total Nameplate MW
2009 Integrated Resource Plan-Appendix C
Project
Hydro
Hydrú
Hydro
HYdro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Hydro
Cogen 12.00
Natural Gas
Natural Gas
Biomass
Bìomass
Biomass
VInd
VInd
VInd
VInd
VInd
VInd
VInd
VInd
Contract
On-line Date
May-1985
Jun-1989
062
120
End Date
Apr-2005
May-202.4
Apr-20HI
Jul-2020
May-2029
May-2024
Estimated
feb-2017
Jan-2021
Aug-2015
Sep-2018
Mar-2024
Aug-2020
Non firm
Jul-2021
Jul-2018
May-2028
Jul-2020
May-2ú28
Feb-2016
Dec-2020
May-20t8
Aug-2010
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
Estimated
Malad River.
Marco.Ranches
MUd Creek V\æe .
Owyhee Dam CSPP .
Rock Creek #1
Trout-Co
Tunnel
lMite Water Ranch.
Wilson Lake Hydro
140.55
Simplot Pocatello ..
Pocatello Waste
Tamarack CSPP
Vaagen Brothers Lumtier Inc
26.31
Notch Butte Wnd
Oregon Trail Wind
Pilgrim Slage Station Wnd
Salmon Falls Wind
Thousand Spnngs VInd..
T uana Gulch 'Mnd .
252.00
0.00
455,86
021
5.00
1
Jan-1913
Aug-1985
Oct-1984
May-20û5
May-2005
May-1986
Nov-2000
Sep-1983
Apr-1989
Sep-1985
Jun-2006
Aug-1986
Aug-1983
Mey-1996
Jun-1982
Nov-1984
Jan-1985
Jun-20ú4
Dec-1986
Jun-1993
Aug-1985
May-1993
Apr-2024
Oct-2019
Apr-2019
Dec-2014
Feb-2019
Oct-2020
Jun-2023
Non firm
May-2019
Oct-20t8
Mßr-2021
Jun-2018
Aug-2023
May-2021
Aug-202S
Aug-20n
Non firm
Nov-2021
Jun-2020
Jun-2010
Apr-2028
Sep-2030
Jun-2020
Felr2019
Mar-2019
Apr-2020
008 Jun-1985 Jun-2020
2.85 Feb-1985 Feb-2020
0.8 Aug-1986 Jul-2021
7 97 Aug-2007 Aug-2027
279 Apr-1988 Apr-2023
Total Hydr Nameplate MWrating
020
205
022
0.58
0.24
7 DO
016
840
Mar-2006
Sep-2003
Au9-2001
046
500
450
Dec-1985
Jun-1983
Sep-1995
The above iS a summary of the Nameplate rating for the CSPP projects under contract with Idaho Power In the case of CSPP projects, Nameptate rating of the actual generaton units
is not an accurate or reasonable. estimate of the actual energy tMse proiects wUI dellVerto Idaho P_er Histoncal Generation information, røsource specific industr standard cepacity
factors. and other known and measurable op&rating characteristics are accountød for in determinrng a reasonable estimate of the energy tt"se projects will produce. The appiicetion of
this mformation to the portfolio of CSPP projects resUlted in the average annual MW frm CSPP projects bøing 150 MW beginning in 2011 PrOjects listed in this apP&ndlx are included
in the CSPP forecast and were signed and approved contracts as of June 1.200
1950
1950
12.00
10.50
Page 81
Existing Resource Data Idaho Power Company
Idaho Power Company
Power Purchase Agreements
Status as of June 1, 2009
Project
Contract---_......_---_.._- ............................_._........_-~---
MW On-Line Date End Date
Wind Projects
Elkhorn Wind Project .... ..... ................... ..... ..... .... Wind
Total Wind Nameplate MW Rating*
101
101
Dec-2007 Dec-2027
Geothermal Projects
Raft River Unit #1 ............................................... Geothermal
Total Geothermal Nameplate MW Rating*
13
13
Apr-2008 Apr-2033
Total Nameplate MW Rating 114
'The above is a summary of the nameplate ratings for the Power Purchase Agreements under contract with Idaho Power. Nameplate ratings
of the actual generation units is not an accurate or reasonable estimate of the actual energy these projects wil deliver to Idaho Power.
Historical generation information, resource specific industry standard capacity factors, and other known and measurable operating
characteristics are accounted for in determining a reasonable estimate of the energy the projects will produce.
Page 82 2009 Integrated Resource Plan-Appendix C
2009 Integrated Resource Plan-Appendix C Page 83
Fuel Data Idaho Power Company
Natural Gas Price Forecast-Comparison to Other Forecasts
$12 ~---~~------~---~~~~--~-----~-~~~-~~~--~~~---~~~~~~~-~----~-~~---~~---
$11
$10
$9
$8
$7
ii $6::~ $5
$4
$3
$2
$1
$0 i
2009 2011 2013 2015 2017 2019 2021 2023 2025
$12
$11
$10
$9
$8
:: $7
ãí
~ $6
~ $5
$4
$3
$2
$1
$0 j
2009
2027 2029
-20091RP Sumas Delivered '''''''''NWPCC Median East Side -NYMEX -EIA -Global Insight
Natural Gas Price Forecast-Comparison to Previous Integrated Resource Plans
2011 2013 2015 2017 2019 2021 2023 2025 2027 2029
-20001RP -20021RP """""""2004 IRP -20061RP -2009 IRP (Expected)
Page 84 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Supply-Side Resource Data
SUPPLy..SIDE RESOURCE DATA
Key Financial and Forecast Assumptions
Financing Cap Structure and Cost
Composition
Debt..................................................................................
Preferred............................................................................
Common............................................................................
Total......................................................................................
Cost
Debt..................................................................................
Preferred...........................................................................
Common...........................................................................
Averaçie Weiçihted COst......... .... .... ...... .... ..........................
50.54%
0.00%
4946%
100.00%
5.65%
0.00%
1060%
8.10%
Financial Assumptions and Factors
Plant Operating (Book) Life....................................................
Discount Rate (aka WACC)..................................................
Composite Tax Rate...............................................................
Deferred Rate........................................................ .... .............
General O&M Esc Rate............................................. .............
Emission Adder Esc Rate................. ........................ ..............
Annual Prop Tax Rate (% of Invest).......................................
Prop Tax Esc Rate.................................................................
Annual Insuranæ Prern (% of Invest)...................................
Insurance Esc Rate................................................................
AFUDC Rate (Annual)............................................................
Prod Tax Credits Esc Rate............ ...... .... .... .... ........ ...............
30 Years
6.98%
39.10%
35.00%
3.00%
2.50%
0.29%
3.00%
0.31%
2.00%
7.00%
3.00%
Tax Credits (2009 $)
Wind, Geothermal and Closed Loop Biomass.......... ............. $21/MWh first 10 years of operation
Open Loop Biomass, Hydro and In-Stream Generation. ........ $101 MWh first 10 years of operation
Solar Investment Tax Credit (ITC)....................... ................... 30% of depreciable investment
Emissions Limits (pounds per MWh by technology)
(adders are brought into the analysis beginning in 2012)
Small Aeroderavative seCT............................... ...................
Large Aeroderavative SCCT.................. ...............................
Large Frame SCCT...............................................................
Reciprocating Engines...........................................................
CCCT 1x1..............................................................................
CCCT 2x1..............................................................................
Combined Heat and Power (CHP)............................... .........
Distributed Generation-Gas Fired.......................................
Pulverized COal................................................... ................. ..
IGCC......................................................................................
IGCC wI Carbon Sequestration........ .....................................
Biomass-Landfil Gas...... .............. .............. ........ ................
Biomass-Aneorobic D içiesters.............................................
GHG
1,190
1,071
1,119
1,071
809
809
809
1,071
1,886
1,797
309
o
o
Nox
0.12000
0.10800
0.11280
0.10800
0.08160
0.08160
0.08160
0.10800
0.44160
021036
0.42560
1.70000
1.70000
Mercury
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0.00002
0.00002
0.00002
0.00000
0.00000
Emission Adder Rates
(adders are brought into the analysis beginning in 2012)
GHG................. $40 per ton (2009 $)
NOX.................. $2,600 per ton during May-September
Mercury............. $1 ,443/0z in years 2012-2017; $1 ,731/0z in year 2018 and beyond
2009 Integrated Resource Plan-Appendix C Page 85
Supply-Side Resource Data Idaho Power Company
Fuel Forecast Base Case (Nominal, $ per MMBtu)
Year
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
Gas
3.96
5.93
6.97
7.23
7.47
7.64
7.69
7.74
7.99
8.19
8.40
8.69
8.93
9.08
9.55
9.78
9.98
10.17
10.31
10.43
10.52
10.55
10.73
10.84
10.96
11.07
11.19
11.30
11.42
11.53
Generic
1.83
2.23
2.26
2.30
2.34
2.43
2.49
2.46
2.50
2.55
2.63
2.72
2.81
2.90
3.00
3.10
3.20
3.30
3.41
3.53
3.65
3.77
3.69
3.77
3.85
3.93
4.01
~.09
4.16
4.24
Nuclear
0.65
0.65
0.66
0.66
0.67
0.67
0.67
0.68
0.68
0.69
0.69
0.69
0.70
0.70
0.71
0.71
0.72
0.72
0.72
0.73
0.73
0.74
0.74
0.75
0.75
0.75
0.76
0.76
0.77
0.77
Page 86 2009 Integrated Resource Plan-Appendix C
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Supply-Side Resource Data Idaho Power Company
The Comprehensive Aquifer Management Plan (CAMP) Process
and Potential to Impact Power Generation
The CAMP Process
The Eastern Snake Plain Aquifer (ESPA) serves nearly one milion acres of ground water irrgated land,
cities, industries, and thousands of domestic wells. Above American Falls, the ESPA supports spring
discharge that provides natural flow for irrgated lands in the Magic Valley. The ESPA has experienced
serious declines that began in the late 1970s and appear to be ongoing. Those declines have impacted
spring discharge to the Snake River, including springs that provide irrigation water and flows of cold
water that support fish hatcheries from Twin Falls to Hagerman. Flow from the ESP A also provides a
significant portion of the flow in the Snake River at King Hil and below.
Declining spring discharge has created numerous water shortages resulting in water calls pitting senior
spring and surface water users against junior ground water appropriators. Many of those water calls are
stil pending or have been only partially resolved through orders from the director of the Idaho
Department of Water Resources (IDWR). Continued declines in spring flows are likely to exacerbate
these ongoing conflcts over water use on the Eastern Snake River Plain (ESRP).
The 2007 Idaho Legislature tasked the Idaho Water Resource Board (IWRB) with developing an ESP A
Comprehensive Aquifer Management Plan (CAMP). The charge ofthe legislature was to "establish
public policy as a settlement framework for future management ofthe ESPA." To meet legislative goals,
the IWRB established a 15-member committee representing various water user groups and other parties
interested in the management of the ESP A. The goal of the committee was to develop an aquifer
management plan to "sustain the economic viability and social and environmental health of the Easter
Snake Plain by adaptively managing a balance between water use and supplies."
Table CAMp.1. Phase I Measures Included in the CAMP
Measure
Ground Water to Surface Water Conversions ......... ... ....... ...... ....... ..... ................. ............... ..... ...... ....
Managed Aquifer Recharge................................................................................................................
Demand Reduction
Surface Water Conservation ........................................................................................................
Crop Mix Modification...................................................................................................................
Rotating Fallowing, Dry-Year Lease, CREP ................................................................................
Weather Modification .... ................. ..... ..... ............ ........... ....... .......... ....... ......... ... ... ..... .... ...... ..............
Target (Acft)
100,000
100,000
50,000
5,000
40,000
50,000
The committee met monthly starting in May 2007 continuing through September 2008. The CAMP
committee first established a goal of producing an annual 600,000 acre-feet adjustment in the water
budget of the ESRP. This water balance adjustment was adopted as the long-term hydrologic target;
however, committee members recognized this adjustment would be achieved only after many years of
implementation. The committee adopted an interim plan called Phase I that targets an annual water
budget change of 200,000-300,000 acre-feet/year. The committee's goal is to have Phase I fully
implemented in 10 years. Table CAMP-l shows the measures anticipated under Phase 1. The Phase I
plan includes the implementation of a variety of measures to change the overall water budget of
the ESRP.
Page 90 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Supply-Side Resource Data
CAMP was submitted to the 2009 Idaho Legislature for approval. Upon legislative approval of the plan,
the IWRB began a process of selecting an implementation committee. The charge of that committee wil
be to "assist the Board in the prioritization, development, implementation, and monitoring and
evaluation of management actions." The implementation committee wil also develop a mechanism to
fund measures implemented under CAMP. The successful implementation of any CAMP-recommended
measure is dependent upon securing a long-term funding source. As such, the specific practices, their
extent or location is unkown at this time. Additionally, some practices are likely to change as the
feasibility and impact of specific practices is evaluated over the next five years. The legislative approval
of CAMP was only the first step in implementing management practices on the ESP A.
Idaho Power recognizes the potential for declining spring flow below Milner Dam to impact generation
capabilities. Idaho Power also recognizes the potential for management practices recommended and
implemented through CAMP to impact generation capabilities. Those impacts could be either positive or
negative. As such, Idaho Power has been an active member of the CAMP committee. Idaho Power was
represented at every CAMP committee meeting, and the company representatives participated in several
sub-committees. Idaho Power also developed the appropriate modeling techniques to assess the potential
impacts of CAMP on river flows and spring discharge. The results of the modeling was provided to the
CAMP committee and used during the decision-making process. Idaho Power has also suggested
management alternatives and has agreed to provide technical and material support for a pilot weather
modification program in the upper Snake River basin.
CAMP committee members recognize that the failure of proposed management practices to increase
aquifer levels or improve spring discharge to the Snake River could result in continued legal action
against junior ground water appropriators. Implementation of CAMP was not to supplant the need for
litigation but to manage the aquifer such that water calls would be lessened. Ground water appropriators
could be subjected to increased mitigation requirements or potential curtailment if CAMP fails to
produce desired results.
Potential Impact of CAMP Implementation on Idaho Power
The implementation of CAMP practices impact hydropower generation in three different ways.
1) Managed recharge can increase spring discharge below Milner Dam, but those increases can
occur only if water is diverted above Milner Dam and directed onto the ESRP and recharged to
the aquifer. Conversions of ground water supplied irrgated land to surface supplied can also
improve spring flow, but would require diversions of water from the Snake River above
Milner Dam as well. Diversion for managed recharge and conversion projects have the potential
to reduce the volume of water passing through numerous Idaho Power projects. Those diversions
may have a negative impact to hydropower production on those facilities located between
Milner Dam and King Hil. Additionally, while most of the water diverted for these projects
comes back to the river as spring discharge, up to 10% of the water remains in the aquifer as
long-term storage. These practices essentially shift water from one compartent, sudace water,
to another compartent, ground water. The net effect on the overall water budget is zero, but the
diversions from the Snake River can have negative impacts to hydropower production.
2) Weather modification and practices that reduce consumptive use of ground water can increase
water flowing through those generation facilities located on the Snake River above King Hil.
These measures actually change the water budget by reducing consumptive demand or by
increasing water supply in the basin. They can increase spring flow or trbutary flow into the
2009 Integrated Resource Plan-Appendix C Page 91
Supply-Side Resource Data Idaho Power Company
Snake River, but, unlike managed recharge or conversion projects, they require no diversions
from the Snake River. These projects increase flows in the Snake River and could potentially
benefit power generation.
3) Practices described in 1) and 2) are likely to be implemented in some combination. The relative
extent of those practices wil ultimately determine whether the impact is positive or negative for
hydropower production. Diversions and increases in spring discharge may eventually balance,
but the first five to ten years of implementation may produce a net negative effect on hydropower
production.
The actual impact to hydropower production resulting from the implementation of the CAMP plan is
uncertain. The availability of funding could drastically alter the implementation of the CAMP Phase I
plan and long-standing water calls may eventually trmp any plan proffered. Changing economic
conditions may also alter decisions made by agrcultue producers and their participation in current
mitigation plans and other programs, such as the Conservation Reserve Enhancement Program (CREP).
In evaluating the potential impacts of CAMP on hydropower production, the Phase I targets provide a
basis for modeling and evaluation.
Modeled CAMP Scenario
Idaho Power developed modeling capabilities to help determine the potential impacts of CAMP on
spring discharge and flows in the Snake River. Idaho Power modeled several different scenarios for the
CAMP committee. The modeling incorporates the Enhanced Snake Plain Aquifer Model (ESP AM) and
the Snake River Planning Modeling (SRPM). The modeling also incorporates information on canal
capacities and sets limits for managed recharge, system conversions, and demand reduction activities.
The modeling also includes estimates on increased water from weather-modification activities.
The scenario modeled for the IRP was the Phase I implementation plan proposed in CAMP.
The parameters entered into the model were done to tr and match the goals of the Phase I plan.
Table CAMP-2 compares the results ofthe Phase I CAMP with the modeled results. The modeled
scenario provides close approximation of the planned Phase I and allows for the examination of the
impacts of CAMP on spring discharge and flows in the Snake River.
Table CAMP-2. CAMP Phase I Goals and Results of Modeling
Action
Ground to Surface Water Conversions
Managed Recharge
Demand Reduction
Weather Modification
CAMP Goal (Average thousand
acre-feet/year)
100
100
95*
50
Modeled (Average thousand
acre-feet/year)
81
140**
45
50
"Some demand reduction includes the purchase of subordination agreements from spring owners that cannot be modeled, but would have no
impact on spring flows or Snake River Flows.
""This recharge also includes approximately 20 KAF/yr recharge on the Wood River system.
The SRPM uses a variety of data inputs to determine water availability for irrgation diversions as well
as providing information on reservoir storage and river flows. The model allows for present conditioning
of historic data. In other words, it applies today's level of development (irrigation diversions and
storage), reach gains, and diversions to historic water availability. The model is curently calibrated to
Page 92 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Supply-Side Resource Data
run from 1928 through 2005. This mode of operation allows for the comparison of a base case scenario
to a variety of management scenarios. This provides a perspective on the degree to which different
management scenarios may impact reservoir storage and river flows.
Table CAMP-3. Average Difference Between the CAMP Scenario and the Base Case Scenario for Flow at
King Hil
July (acre-feet)
7,700
December (acre-feet)
10,900
Yearly (acre-feet)
66,600
A comparison was made for the months of July and December and total yearly flows for the base case
scenario and the CAMP scenario. July and December were selected because they are critical months for
power generation. The comparison of modeled data was for the King Hil gage on the Snake River
(Table CAMP-3). The average flows for July increased 7,670 acre-feet/month, and December flows
increased 10,880 acre-feet/month. The yearly average flows increased by 66,580 acre-feet/year, which is
about 1 % of the yearly average flow at the King Hil gage. These small increases reflect the nature of
changes in the water budget for the upper Snake Basin as proposed through CAMP. The CAMP Phase I
plan contains only 95,000 acft in new or additional water to the system. CAMP may increase spring
discharge trbutary to the Snake River, but those increases are dependent upon large diversion from the
Snake River for managed recharge or system conversions. The overall increase in Snake River flow is
dependent upon a reduction in consumptive use of water or increases related to water modification
activities.
2009 Integrated Resource Plan-Appendix C Page 93
Supply-Side Resource Data Idaho Power Company
Brownlee Reservoir Inflow Recordlllilion Acre-Fe.t)
Record Used for 2009 IRP Modeling of Idaho Power Hydr()power System
CY
1928
1929
1930
1931
1932
1933
1934
1935
1936
1937
1938
1939
1940
1941
1942
1943
1944
1945
1946
1947
1948
1949
1950
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
Brownlee April-July
Inflow Volume (MAF)
6.8
3.5
2.8
2.3
4.8
4.3
2.4
3.0
5.1
3.0
7.1
3.9
4.3
3.8
5.0
9.3
3.4
4.9
6.9
5.3
5.9
5.4
6.6
6.6
10.4
6.1
5.6
3.5
7.9
7.9
7.5
3.9
4.3
3.2
4.9
4.7
5.8
8.5
3.6
Brownlee Annual
Inflow Volume (IIAF)
14.8
9.3
8.3
7.2
10.2
9.4
7.5
7.9
10.4
8.5
13.8
10.0
10.8
10.2
11.2
19.0
9.6
11.7
15.5
12.5
126
12.5
14.8
16.2
19.3
13.7
12.6
9.9
17.6
16.2
15.2
10.4
10.8
8.7
11.1
11.6
13.1
20.0
9.9
CY
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
Brownlee April-uly
Inflow Volume (MAF)
4.9
3.5
6.9
6.3
10.4
7.8
4.0
9.7
8.2
7.3
2.2
5.2
4.0
6.1
4.4
94
10.0
11.4
5.5
8.4
30
2.7
4.4
3.1
2.9
2.0
6.3
2.8
6.9
8.3
10.1
8.6
7.9
4.6
2.6
3.5
3.7
3.2
3.6
Brownlee Annual
Inflow Volume (MAF)
113
10.8
15.4
14.9
22.9
20.2
11.3
20.1
17.6
16.3
7.8
11.9
10.8
13.2
11.5
21.2
23.6
24.4
13.5
20.6
9.2
7.9
10.7
8.6
8.2
6.8
13.0
8.5
14.2
19.1
24.0
17.6
17.8
12.1
7.8
8.8
9.2
8.8
8.8
Note: Based on Idaho Department of Water Resources computed Snake River Basin record for 1928-2005.
Page 94 2009 Integrated Resource Plan-Appendix.C
Idaho Power Company Supply-Side Resource Data
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2009 Integrated Resource Plan-Appendix C Page 95
Demand-Side Resource Data Idaho Power Company
DEMAND-SIDE RESOURCE DATA
Cost..Effectiveness
Most of Idaho Power's energy efficiency programs are preliminarily identified through the integrated
resource planning process. A change for the 2009 Integrated Resource Plan IR is that a majority of
the anticipated new energy effciency future commitments come through additional measures added into
existing programs as opposed to new program offerings.
Idaho Power considers cost-effectiveness to be the primary screening tool prior to demand-side
management (DSM) program implementation. Idaho Power primarily uses the Total Resource Cost
(TRC) test and the Utility Cost (UC) test to develop benefit cost (B/C) ratios to determine the
cost-effectiveness of DSM programs.
In the IRP process, specific programs or potential energy savings are screened by sector to determine if
the levelized cost of the potential programs is less than supply-side resource alternatives. If the DSM
programs are shown to be less costly than supply-side resources as measured by the levelized cost,
the potential program is included in the resource plan. Generally, the hourly shaped energy savings are
used to compare DSM programs with other supply-side and transmission alternatives.
Prior to the actual implementation of energy efficiency or demand response programs, Idaho Power
creates cost-effectiveness models to assess whether a specific potential program design wil be
cost-effective from the perspective of Idaho Power and its customers. Incorporated into the
cost-effectiveness models are inputs from various sources in order to use the most current and reliable
information available. Idaho Power uses a cost-effectiveness model to perform sensitivity analyses in
order to determine the appropriate program design. The remaining inputs used in the cost-effectiveness
models are obtained from the IR process.
When possible, Idaho Power uses actual data and experiences from other companies in the region,
or throughout the countr, to help identify specific program parameters. The regional program review is
typically accomplished through discussions with other utilities' program managers and research staff.
Idaho Power also uses electrc industry research organizations, such as E Source, Edison Electrcal
Institute (EEl), Consortium for Energy Efficiency (CEE), American Council for an Energy Effcient
Economy (ACEEE), Advanced Load Control Alliance (ALCA), Association of Energy Service
Professionals (AESP), Energy Insights, and others, to identify similar programs and expected results.
For other assumptions, including estimated costs, savings, and net-to-gross ratio estimates, Idaho Power
relies on sources, such as the Northwest Power and Conservation Council (NPCC), the Regional
Technical Forum (RTF), Northwest Energy Effciency Allance (NEEA), E Source, the Database for
Energy Effciency Resources (DEER), the Energy Trust of Oregon (ETO), Bonneville Power
Administration (BP A), third-party consultants, and other regional utilities.
The financial assumptions used in the analysis are consistent with the 2009 IRP, including the discount
rate and inflation rate. The IR is also the source of the DSM alternative costs, which is the value of
energy savings and demand reduction resulting from the DSM programs. The DSM alternative costs
vary by season and time-of-day. The DSM alternative energy costs are based on either projected fuel
costs of a natural gas peaking unit or forward market prices as determined by the AURORAxmp!I
Electric Market ModeL. The avoided capital cost is based on a 170 MW natual gas-fired, simple-cycle
combustion tubine.
Page 96 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Demand-Side Resource Data
Idaho Power relies on the Electrc Power Research Institute End Use Technical Assessment Guide
(TAG) and the California Standard Practice Manual for the cost-effectiveness methodology. As defined
in the TAG and California Standard Practice Manual, the TRC and UC tests are most similar to
supply-side tests and provide a useful basis to compare demand-side and supply-side resources.
Idaho Power determines cost-effectiveness on a program basis and on a measure-by-measure basis
where applicable. To be consistent with the IR, demand response program B/C ratios for the residential
A/C Cool Credit, Irigation Peak Rewards, and the commercial and industrial FlexPeak program are
calculated over a 20-year period. In order for a program to be considered cost-effective, the program
must have B/C ratios greater than one for both the TRC and UC tests.
Idaho Power may choose to launch a pilot or limited-scale program to evaluate estimates or assumptions
in the cost-effectiveness modeL. Pilot programs are designed to measure actual program experiences,
including program expenses, savings, and participation. Following implementation of a program,
the cost-effectiveness models are reviewed as data from actual program activity becomes available.
The program design may be reexamined after program implementation.
Alternate Costs
The prices of avoided energy throughout the 20-year planning period were simulated using the Preferred
Portfolio module within the AuroraAxmp modeL. The Preferred Portfolio module takes into
consideration the energy capacity and resource costs of the current preferred mix of IRP resources
along with regional transmission resources in the Western Electricity Coordinating Council (WECC)
region to project forward electric market prices. The forward prices are placed into five homogenous
pricing categories that follow the pattern of heavy and light load pricing throughout each year of
the planning period. The resulting categories are:
· Summer On-Peak (SONP)-A verage of Idaho Power variable energy and operating costs of a
170 MW simple-cycle combustion turbine, which is the marginal resource for peak hour load
deficits durng summertime heavy load hours
· Summer Mid-Peak (SMP)-Average of heavy load prices from June through August
· Summer OffPeak (SOFP)-Average of light load prices from June through August
· Non-Summer Mid-Peak (NSMP)-Average of heavy load prices in January through May and
September through December
· Non-Summer OffPeak (NSOFP)~Average oflight load prices in January through May and
September through December
The SONP is treated differently than the other four pricing periods. During the SONP, additional
purchases from the regional power market are not an option due to currently existing transmission
constraints. The marginal resource Idaho Power is tring to avoid with DSM efforts for SONP hours is
the constrction of simple-cycle combustion turbine. The estimated levelized capacity cost of building
a new simple-cycle combustion turbine is approximately $63/kW over a 30-year expected plant life.
For demand response or direct load control DSM programs operating during the summer peak,
the $63/kW becomes the cost threshold for program cost-effectiveness.
2009 Integrated Resource Plan-Appendix C Page 97
Demand-Side Resource Data Idaho Power Company
The avoided capacity value is spread across the annual SONP hours to value the energy efficiency
savings occurrng during the hours. The total SONP vary between 512 to 528 hours depending on
the calendar. Table DSM-llists the financial assumptions used for the cost effectiveness analysis and
new program screening.
Table DSM-2 shows the results of averaging forward energy prices over the 20-year planning period
that were used to screen new energy effciency and demand response programs for cost-effectiveness.
The cost-effectiveness analysis for measures that have a life longer than 20 years, which is typical for
weatherization and building shell measures, prices are escalated at three percent.
Tables DSM-3 and DSM-4 show the distribution of the three summer and two non-summer pricing
periods across the hours and days of the week and for holidays.
Tables DSM-5 through DSM-7 show the forecast impact of energy efficiency by customer class for
existing programs, new energy effciency commitments, and the total combined impact.
Table DSM-8 shows the annual forecast of utility costs or the costs to administer the new programs and
measures to meet the forecast new energy efficiency amounts.
Table DSM-9 shows the 20-year flow of resource costs that combines the program participant costs with
the costs to administer the program.
Table DSM-l 0 outlines the 20-year flow of avoided generation and the benefits attributed to energy
effciency programs.
Table DSM-ll summarizes the cost-effectiveness analysis for new programs and measures through
the 20-year IRP planning period.
Table DSM-12 shows the annual forecast impact from all demand response programs.
Tables DSM-13 through DSM-15 show the 20-year flow of utility costs, total resource costs, and value
of avoided generation for demand response programs, similar to those presented for new energy
efficiency programs.
Table DSM-16 summarizes the cost~effectiveness for demand response programs and the forecast
impact through the IRP planning horizon.
Table DSM.1. IRP Financials
DSM Analysis Assumptions
Avoided Capacity Costs
Simple-Cycle Combined Turbine...................................... ................................................................
Financial Assumptions
Weighted Average Cost of Capital (2008 Year Ending After Tax) ....................................................
Financial Escalation Factor...............................................................................................................
Transmission Losses
Non-summer Secondary Losses
Summer Peak Loss............. .............................................................................................................
$63/kW
6.98%
3.00%
10.90%
13.00%
Page 98 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Demand-Side Resource Data
Table DSM.2. DSM Alternate Costs by Pricin Period
Year
2010 $61.23 $45.22 $33.70 $46.50 $34.94
2011 $71.70 $53.51 $40.04 $55.00 $42.05
2012 $98.56 $83.99 $73.25 $84.85 $72.70
2013 $103.52 $85.83 $76.66 $84.95 $73.38
2014 $105.93 $88.03 $78.54 $87.74 $75.23
2015 $107.21 $90.65 $80.59 $91.35 $77.69
2016 $108.48 $93.77 $82.08 $93.03 $79.60
2017 $111.77 $95.65 $84.94 $95.19 $82.20
2018 $114.49 $97.48 $86.37 $97.66 $84.64
2019 $117.51 $100.97 $88.40 $99.54 $86.87
2020 $121.19 $102.07 $89.30 $101.54 $89.17
2021 $124.46 $104.48 $91.76 $104.64 $91.87
2022 $126.83 $108.43 $95.56 $109.05 $95.67
2023 $132.46 $111.36 $98.73 $111.23 $98.70
2024 $135.69 $113.45 $100.73 $114.15 $101.27
2025 $138.67 $117.06 $104.45 $117.50 $104.31
2026 $141.54 $120.25 $107.38 $121.00 $107.28
2027 $144.00 $122.37 $109.98 $123.58 $110.04
2028 $146.24 $126.81 $113.72 $126.09 $112.90
1Estimated variable operations and management costs of a 170 MW capacity simple-cycle combined turbine.
2009 Integrated Resource Plan-Appendix C Page 99
Demand-Side Resource Data Idaho Power Company
Table DSM-3. DSM Alternate Cost Summer Pricing Periods (June 1 to August 31)
Hour Sunday Monday Tuesday Wednesday Thursday Friday Saturday
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Holiday
Page 100 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Demand-Side Resource Data
Table DSM.4. DSM Alternate Costs Non-Summer Pricing Periods (September 1 to May 31)
Hour Sunday Monday Tuesday Wednesday Thursday Friday Saturday
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Holiday
2009 Integrated Resource Plan-Appendix C Page 101
Demand-Side Resource Data Idaho Power Company
Table DSM-5. DSM Existing Energy Efficiency Forecast 2010-2029 (aMW with transmission losses)
Year Industrial Commercial Irrigation Residential Total
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
4.9
9.7
14.2
18.6
23.0
27.5
31.9
36.3
40.8
45.2
49.6
54.1
58.5
62.9
67.4
71.8
76.2
80.6
85.1
89.5
5.3
11.0
17.2
23.4
29.7
35.9
42.1
48.4
54.6
60.8
67.0
73.3
79.5
85.7
92.0
98.2
104.4
110.6
116.9
123.1
2.7
4.5
6.0
7.5
9.0
10.3
11.5
12.8
14.0
15.3
16.5
17.8
19.0
20.3
21.6
22.8
24.1
25.3
26.6
27.8
1.3
2.5
3.7
4.7
5.6
6.2
6.9
7.5
8.2
8.9
9.5
10.2
10.8
11.5
12.2
12.8
13.5
14.1
14.8
15.4
14.2
27.8
41.1
54.2
67.3
79.8
92.4
105.0
117.6
130.1
142.7
155.3
167.9
180.4
193.0
205.6
218.2
230.7
243.3
255.9
Table DSM.6.
Year
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
New 20091RP Energy Efficiency Resources 2010-2029 (aMW with transmission losses)Residential Commercial Industrial Total0.9 0.9 1.0 2.82.1 1.8 3.1 7.03.4 2.9 6.1 12.44.9 4.0 9.3 18.26.4 5.3 12.7 24.48.0 6.6 16.2 30.89.6 8.0 19.9 37.511.3 9.5 23.5 44.312.9 11.1 27.3 51.314.6 12.8 31.0 58.416.3 14.5 34.9 65.717.7 16.4 38.8 72.919.2 18.3 42.7 80.220.7 20.2 46.7 87.622.2 22.3 50.8 95.323.7 24.4 54.9 103.025.3 26.7 59.0 110.926.9 29.0 63.2 119.028.5 31.3 67.4 127.228.5 31.3 67.4 127.2
Page 102 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Demand-Side Resource Data
Table DSM-7.Total Energy Efficiency Forecasted Impact Existing and New 2010-2029
(aMW with transmission losses)
Year Industrial Commercial Irrigation Residential Total
2010 5.5 5.6 1.1 3.3 15.5
2011 12.9 12.8 2.5 6.6 34.8
2012 20.3 20.1 3.7 9.5 53.5
2013 27.9 27.5 4.7 12.4 72.5
2014 35.7 35.0 5.6 15.4 91.7
2015 43.7 42.5 6.2 18.2 110.7
2016 51.8 50.2 6.9 21.1 129.9
2017 59.9 57.9 7.5 24.0 149.3
2018 68.0 65.7 8.2 26.9 168.9
2019 76.2 73.6 8.9 29.9 188.6
2020 84.5 81.6 9.5 32.8 208.4
2021 92.8 89.6 10.2 35.5 228.2
2022 101.2 97.7 10.8 38.2 248.0
2023 109.6 106.0 11.5 41.0 268.1
2024 118.1 114.2 12.2 43.7 288.3
2025 126.6 122.6 12.8 46.5 308.6
2026 135.2 131.1 13.5 49.4 329.1
2027 143.8 139.6 14.1 52.2 349.7
2028 152.5 148.2 14.8 55.1 370.5
2029 156.9 154.4 15.4 56.3 383.1
Table DSM-8.New Energy Efficiency Utilty Costs 2010-2029
Year Residential Commercial Industrial Total All Sectors
2010 $2,185,803 $859,845 $1,297,023 $4,342,671
2011 $3,060,477 $969,777 $3,319,561 $7,349,814
2012 $3,508,588 $1,067,687 $4,314,247 $8,890,522
2013 $3,811,045 $1,158,161 $4,446,834 $9,416,040
2014 $4,058,383 $1,243,199 $4,658,622 $9,960,205
2015 $4,267,066 $1,325,522 $4,841,031 $10,433,618
2016 $4,406,327 $1,405,619 $4,871,784 $10,683,730
2017 $4,546,267 $1,484,206 $4,939,369 $10,969,841
2018 $4,672,279 $1,561,790 $5,011,687 $11,245,755
2019 $4,768,785 $1,638,743 $5,080,622 $11,488,151
2020 $4,867,634 $1,715,345 $5,146,344 $11,729,324
2021 $4,481,009 $1,791,806 $5,195,678 $11,468,493
2022 $4,584,723 $1,868,290 $5,269,358 $11,722,371
2023 $4,690,963 $1,944,923 $5,330,311 $11,966,196
2024 $4,799,793 $2,021,803 $5,376,699 $12,198,295
2025 $4,911,279 $2,099,010 $5,438,122 $12,448,410
2026 $5,025,489 $2,176,602 $5,496,960 $12,699,051
2027 $5,142,493 $2,254,627 $5,536,118 $12,933,238
2028 $5,262,362 $2,333,121 $5,594,501 $13,189,985
2029 $0 $0 $0 $0
20-Year NPV $42,646,505 $15,206,640 $46,583,003 $104,436,148
2009 Integrated Resource Plan-Appendix C Page 103
Demand-Side Resource Data Idaho Power Company
Table DSM.9. New Energy Efficiency Total Resource Costs 2010-2029
Year Residential Commercial Industrial
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
20.YearNPV
$2,357,175
$3,639,396
$4,212,132
$4,594,083
$4,904,362
$5,166,365
$5,339,158
$5,512,736
$5,668,296
$5,785,396
$5,905,291
$5,395,175
$5,520,874
$5,649,585
$5,781,384
$5,916,347
$6,054,554
$6,196,088
$6,341,030
$0
$51,412,498
$3,636,527
$4,162,005
$4,635,110
$5,075,432
$5,492,750
$5,896,996
$6,291,431
$6,679,287
$7,062,878
$7,443,906
$7,823,649
$8,203,079
$8,582,945
$8,963,830
$9,346,187
$9,730,368
$10,116,647
$10,505,234
$10,896,288
$0
$68,482,366
$1,711,236
$4,382,424
$5,698,932
$5,877,320
$6,160,444
$6,404,797
$6,448,457
$6,540,755
$6,639,234
$6,733,149
$6,822,723
$6,890,478
$6,990,439
$7,073,439
$7,137,028
$7,220,494
$7,300,456
$7,354,203
$7,433,417
$0
$61,693,447
Total All Sectors
$7,704,938
$12,183,825
$14,546,174
$15,546,835
$16,557,556
$17,468,157
$18,079,045
$18,732,777
$19,370,408
$19,962,451
$20,551,663
$20,488,732
$21,094,258
$21,686,855
$22,264,599
$22,867,209
$23,471,657
$24,055,525
$24,670,736
$0
$181,588,312
Table DSM-10. New Energy Efficiency Resource Avoided Energy Costs 2010-2029
Year Residential Commercial Industrial
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
20-YearNPV
$3,709,589
$6,188,004
$8,371,989
$9,735,242
$10,921,698
$12,019,828
$12,895,163
$13,807,371
$14,673,960
$15,459,304
$16,257,717
$17,119,736
$18,070,545
$18,998,401
$19,943,721
$20,959,811
$22,003,968
$23,035,571
$24,124,351
$24,876,318
$142,492,125
$5,626,728
$6,805,914
$7,983,345
$8,899,982
$9,823,463
$10,765,480
$11,721,993
$12,710,756
$13,730,128
$14,790,279
$15,899,087
$17,068,181
$18,292,292
$19,550,317
$20,866,846
$22,253,164
$23,702,308
$25,219,078
$26,825,849
$26,875,246
$143,365,937
$6,044,209
$16,575,769
$22,875,049
$24,155,131
$25,955,488
$27,660,310
$28,532,458
$29,672,368
$30,880,008
$32,112,014
$33,376,505
$34,601,987
$36,035,764
$37,398,739
$38,707,298
$40,189,732
$41,703,823
$43,124,470
$44,782,746
$44,782,746
$301,075,029
Total All Sectors
$15,380,526
$29,569,686
$39,230,383
$42,790,356
$46,700,648
$50,445,619
$53,149,614
$56,190,494
$59,284,096
$62,361,597
$65,533,308
$68,789,905
$72,398,601
$75,947,457
$79,517,864
$83,402,707
$87,410,099
$91,379,118
$95,732,947
$96,534,310
$586,933,090
Page 104 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Demand-Side Resource Data
Table DSM.11. New Energy Efficiency Cost Effectiveness Summary
Impact 20-Year NPV Costs Utilty Costs Total Resource Costs
2029
Load 20- Year Energy Benefit/Cost Levelized ¡Benefit/Cost Levelized
(aMW)(kWh)Utilty Resource Avoided Energy Ratio ($/kWh)Ratio ($/kWh)
Residential 29 1,096,775,152 $42,646,505 $51,412,498 $142,492,125 3.3 $0.039 2.8 $0.047
Commercial 31 1,042,951,839 $15,206,640 $68,482,366 $143,365,937 9.4 $0.015 2.1 $0.066
Industrial 67 2,391,084,888 $46,583,003 $61,693,447 $301,075,029 6.5 $0.019 4.9 $0.026
Total 127 4,530,811,879 $104,436,148 $181,588,312 $586,933,090 5.6 $0.023 3.2 $0.04
Table DSM.12. Total Existing and New Demand Response Forecasted Impacts 2010-2029
(MW with transmission losses)
Year Residential Irrigation Commercial Total
2010 50.6 220.0 39.6 310.2
2011 50.6 250.0 45.2 345.8
2012 50.6 260.0 56.5 367.1
2013 50.6 260.0 56.5 367.1
2014 50.6 260.0 56.5 367.1
2015 50.6 260.0 56.5 367.1
2016 50.6 260.0 56.5 367.1
2017 50.6 260.0 56.5 367.1
2018 50.6 260.0 56.5 367.1
2019 50.6 260.0 56.5 367.1
2020 50.6 260.0 56.5 367.1
2021 50.6 260.0 56.5 367.1
2022 50.6 260.0 56.5 367.1
2023 50.6 260.0 56.5 367.1
2024 50.6 260.0 56.5 367.1
2025 50.6 260.0 56.5 367.1
2026 50.6 260.0 56.5 367.1
2027 50.6 260.0 56.5 367.1
2028 50.6 260.0 56.5 367.1
2029 50.6 260.0 56.5 367.1
2009 Integrated Resource Plan-Appendix C Page 105
Demand-Side Resource Data Idaho Power Company
Table DSM.13. Demand Response Utilty Costs 2010-2029
Year Residential Commercial/Industrial Irrigation Total All Sectors
2010 $3,520,710 $2,081,025 $10,799,032 $16,400,767
2011 $1,352,143 $2,760,783 $11,038,020 $15,150,946
2012 $1,396,152 $3,415,100 $11,223,562 $16,034,815
2013 $1,371,927 $3,448,853 $11,247,225 $16,068,005
2014 $1,417,031 $3,482,066 $11,274,667 $16,173,763
2015 $1,760,923 $3,489,626 $11,306,566 $16,557,115
2016 $1,817,247 $3,498,355 $11,343,682 $16,659,284
2017 $1,813,491 $3,507,347 $11,368,382 $16,689,220
2018 $1,872,482 $3,516,609 $11,456,834 $16,845,925
2019 $1,869,268 $3,526,148 $11,434,099 $16,829,515
2020 $1,967,417 $3,535,973 $11,451,335 $16,954,725
2021 $2,000,416 $3,546,093 $11,482,018 $17,028,527
2022 $2,105,980 $3,556,517 $11,528,664 $17,191,161
2023 $2,141,187 $3,567,254 $11,565,121 $17,273,562
2024 $2,252,091 $3,578,312 $11,593,138 $17,423,542
2025 $2,289,700 $3,589,703 $11,636,912 $17,516,315
2026 $2,407,865 $3,601,435 $11,676,627 $17,685,927
2027 $2,446,881 $3,613,519 $11,705,625 $17,766,024
2028 $2,572,782 $3,625,966 $11,840,660 $18,039,408
2029 $2,614,977 $3,638,786 $11,840,660 $18,094,423
20-Year NPV $21,020,406 $35,339,272 $120,389,467 $176,749,144
Table DSM-14. Demand Response Total Resource Costs 2010-2029
Year Residential CommerciallIndustrial Irrigation Total All Sectors
2010 $3,520,710 $2,081,025 $10,799,032 $16,400,767
2011 $1,352,143 $2,760,783 $11,038,020 $15,150,946
2012 $1,396,152 $3,415,100 $11,223,562 $16,034,815
2013 $1,371,927 $3,448,853 $11,247,225 $16,068,005
2014 $1,417,031 $3,482,066 $11,274,667 $16,173,763
2015 $1,760,923 $3,489,626 $11,306,566 $16,557,115
2016 $1,817,247 $3,498,355 $11,343,682 $16,659,284
2017 $1,813,491 $3,507,347 $11,368,382 $16,689,220
2018 $1,872,482 $3,516,609 $11,456,834 $16,845,925
2019 $1,869,268 $3,526,148 $11,434,099 $16,829,515
2020 $1,967,417 $3,535,973 $11,451,335 $16,954,725
2021 $2,000,416 $3,546,093 $11,482,018 $17,028,527
2022 $2,105,980 $3,556,517 $11,528,664 $17,191,161
2023 $2,141,187 $3,567,254 $11,565,121 $17,273,562
2024 $2,252,091 $3,578,312 $11,593,138 $17,423,542
2025 $2,289,700 $3,589,703 $11,636,912 $17,516,315
2026 $2,407,865 $3,601,435 $11,676,627 $17,685,927
2027 $2,446,881 $3,613,519 $11,705,625 $17,766,024
2028 $2,572,782 $3,625,966 $11,840,660 $18,039,408
2029 $2,614,977 $3,638,786 $11,840,660 $18,094,423
20-YearNPV $21,020,406 $35,339,272 $120,389,467 $176,749,144
Page 106 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Demand-Side Resource Data
Table DSM.15. Demand Response Avoided Capacity Costs 2010-2029
Year Residential Commercial/Industrial Irrigation
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
20-YearNPV
$3,108,304
$3,117,340
$3,140,508
$3,144,787
$3,146,863
$3,147,966
$3,149,066
$3,151,905
$3,154,249
$3,156,852
$3,160,032
$3,162,847
$3,164,891
$3,169,750
$3,172,541
$3,175,111
$3,177,585
$3,179,706
$3,181,640
$3,185,424
$33,417,991
Total All Sectors
$22,107,531
$23,285,110
$24,439,140
$24,511,824
$24,547,086
$24,565,828
$24,584,503
$24,632,727
$24,672,538
$24,716,752
$24,770,776
$24,818,592
$24,853,315
$24,935,844
$24,983,242
$25,026,896
$25,068,919
$25,104,953
$25,137,798
$25,156,455
$258,639,09
$2,636,945
$3,042,059
$3,893,616
$3,910,432
$3,918,590
$3,922,926
$3,927,247
$3,938,404
$3,947,614
$3,957,844
$3,970,342
$3,981,405
$3,989,438
$4,008,532
$4,019,498
$4,029,598
$4,039,320
$4,047,657
$4,055,256
$4,070,128
$39,982,107
$16,262,282
$17,125,711
$17,405,016
$17,456,605
$17,481,633
$17,494,936
$17,508,191
$17,542,418
$17,570,675
$17,602,057
$17 ,640,402
$17,674,340
$17,698,985
$17,757,562
$17,791,203
$17,822,188
$17,852,014
$17,877,590
$17,900,902
$17,900,902
$185,238,997
Table DSM.16. Demand Response Cost.Effectiveness Summary
Impact 20-Year NPV Costs Total Resource Costs
2029 Load 2Q-Year Energy Avoided BenefiUCost Levelized
(aMW)(kWh)Utility Resource Energy Ratio ($/kWh)
Residential 51 555,495 $21,020,406 $21,020,406 $33,417,991 1.6 $38
Commercial/Industrial 56 573,775 $35,339,272 $35,339,272 $39,982,107 1.1 $62
Irrigation 260 2,748,954 $120,389,467 $120,389,467 $185,238,997 1.5 $44
Total 367 3,878,225 $176,749,144 $176,749,144 $258,639,094 1.5 $46
2009 Integrated Resource Plan-Appendix C Page 107
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Monthly Average Energy Surpluses and Deficits with Existing Resources
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Monthly Average Energy Surpluses and Deficits with .ExistingResources
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Page 118 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Load and Resource Balance
lvonthlyAverage Energy SurplusesåhdDefjc:its with 2009 IRP Resources
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Load and Resource Balance Idaho Power Company
Peak Hour Deficits with Existing Resources
(50th Percentile Water and 90th Percentile Load)
20102011 201220132014201520162017 2018 2019 2020 2021 2022 2lJ23 2024 2025 2026 2027 2lJ28 2029
Peak Hour Deficits with Existing Resources
(70th Percentile Water and 95th Percentile Load)
2010 2011 2012 2013 2lJ14 2015 2016 2017 2018 2019 20202021 2022 2023 2lJ24 2025 2026 2027 2028 2029
Peak Hour Deficits with Existing Resources
(90thPercentilè Water ånd 95th Percentile Load)
2010 2011 2lJ12 201320142015201620172018201920202021 2022202320242025202620272028 2029
Page 130 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Load and Resource Balance
Peak Hour Deficits with 2009 IRP Resources
(50th Percentile Water and 90th Percentile Load)
20102011 201220132014201520162017201820192020 2021 2022202 204 2025 20 2027 2028 2029
Peak Hour Deficits with 2009 IRP Resources
(70th Percentile Water and 95th Percentile load)
20102011 201220132014201520162017 2018 2019 2020 2021 202220232024 2025 2026 2027 2028 2029
Peak Hour Deficits with Existing Resources
(90th Percentile Water and 95th Percentile Load)
2012 2013 2014 201520162017 2018 2019 2020 201 2022 203 2024 2025 2026 207 20 2029
2009 Integrated Resource Plan-Appendix C Page 131
Load and Resource Balance Idaho Power Company
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Oregon Order UM 1056 Planning Criteria Idaho Power Company
OREGON ORDER UM 1056 PLANNING CRITERIA
BEFORE THE PUBLIC UTILITY COMMISSION
In the Matter of
PUBLIC
OREGON
COMMSSION OF
Investigation Into Integrated Resource
Pl.anning.
OF OREGON
UM 1056
)
)
)
)
)
)
)
ORDER
DISPOSITION: APPENDIX TO ORDER NO, 07~002 CORRCTED
In Order No. 07-002, we adopted guidelines to govern the Integrated Resource
Planning (IRP)process. In setting forth those guidelines in an appendix, we inavertently
omitted Guidelìne 1 (d), which we discussed and adopted in the body onhe order on pages 1
and 8. Accordingly, Appendix A to Order No. 07~002 is replacedwiththeattaC1ied appendix
to this order, which includes all the adopted guideHnes. The reinainderofthe order is
unchaged.
SO ORDERED.
Made, entered, and effective
ideration of this order purua to ORS 756.561. A
n must be fied vvith the Commission \vith 60 days of
request must comply with the reuirements in OAR 860-014-0095. also be served on ea pa to the procedin as
provided by OAR 860013~0070(2). A par may appeal this orde by filing a petition for
review with the Court of Appeals in compliane with ORS i 83.480- 183.484.
Page 162 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Oregon Order UM 1056 Planning Criteria
ORDER NO. 07-047
Adopted.IRP Guidelùies
Guideline 1: Substative Requirements
a. All resources must be evaluated on a consistent and
comparable basis.
o All known resources for meeting the utility's load should be
considered, including supply-side options which focus on
the generation, purchase and transmission of power - or
gas purchases. transportation, and storage - and demand-
side options whichfocus on conservation and demand
response.
o Utilities should compare diferent resource fuel types,
technologies. lead times, in-service dates. durations and
locations in portfolio risk modeling.
o Consistent assumptions and methods should be usedfor
evluation of all resources.
o The after-tax marginal weighted-average cost of capital
(WACC) should be used to discount all future resource
costs.
b. Risk and uncertainty must be considered
o At a minimum, utilites should address the following
sources of ri sk and uncertdinty:
1. Electric utilties: load requirements. hydroelectric
generation. plant forced outages, fuel prices, electricity
prices, and costs to comply with any regulation of
greenhouse gas emissions.
2. Natural gas utilities: demand (peak, swing and base-
load), commodity supply and price, transportation
availabilty and price, and costs to comply with any
regulation of greenhouse gas emissions.
o Utilities should identif in their plans any additonal
sources of risk and uncertainty.
c. The primary goal must be the selection of a portfolio of
resources with the best combination of expected costs and
APPENDIX A
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2009 Integrated Resource Plan-Appendix C Page 163
Oregon Order UM 1056 Planning Criteria Idaho Power Company
ORDER NO. 07-047
associated risks and uncertainties for the utility and itscustomers. J .
o The planning horizon for analyzing resource choices
should be at least 20 years and account for end efcts.
Utilities should consider all costs with a reasonable
likelihood of being included in rates over the long term,
which exends beyond the planning horizon and the life of
the resource.
o Utilities should use present value of revenue requirement
(PVRR) as the ke cost metric. The plan should include
analysis of current and estimated future costs for all long-
lived resources such as power plants, gas storage facilities,
and pipelines, as well as all short-lived resources such as
gas supply and short-term power purchases.
o To address risk, the plan should include, at a minimum:
1. Two measures ofPVRR risk: one that measures the
variability of costs and one that measures the severity
of bad outcomes.
2. Discussion of the proposed use and impact on costs and
risks of physical and financial hedging.
o The utility should explain in its plan how its resource
choices appropriately balance cost and risk.
d. The plan must be consistent with the long-run public interest as
exressed in Oregon and fèderal energy policies.
Guìdeline.2 :ProceduralRequirements.
a. The public. which includes other utilities, should be allowed
signifcant involvement in the preparation of the IRP.
1nvolvement includes opportunities to contribute iriormation
and ideas, as well as to receive information. Parties must have
an opportunity to maJæ relevant inquiries of the utilty
formulating the plan. Disputes about whether information
requests are relevant or unreasonably burdensome, or whether
a utilty is being properly responsive, may be submitted to the
Commission for resolution.
1 We sometimes refer to ths portfolio as the "best cost/risk portolio."
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Idaho Power Company Oregon Order UM 1056 Planning Criteria
ORDER NO. 07-047
b. While confidential information must be protected, the utilty
should make public, in its plan, any non-confidential
information that is relevant to its resource evaluation and
action plan. Confdential information may be protected
through use of a protective order, through aggregation or
shielding of data, or through any other mechanism approved
by the Commission.
c. The utility must provide a draf IRP for public review and
comment prior to filing a final plan with the Commission.
Gnblelie;J: Plan Eiling, Review, and UpdatéS.
a. A utility mustfìle an IRP within two years of its previous IRP
acknowledgmetit order. If the utility does not intend to take
any signifcantre:source action for at least two years after its
next JRP i:; due, the utility ¡nay request an extension of its filingdate from the Commission.
b. The utilitYlniistpresent the results of its filed plan tathe
Commission cit a public rneetingprior to the deaçlline/or
writtenpublic cOmment.
c. Commission staf and parties should complete their comments
and recommendations within six months of IRP filing.
d. The Commission wil consider comments and recommendations
on a utility's plan at a public meeting before issuing an order
on acknowledgment. The Commission may provde the utility
an opportunity to revise the plan before issuing an
acknowledgment order.
e. The Commission may provide direction to a utility regarding
any additional analyses or actions that the utility should
undertake in its next IRP.
f Each utility must submit an annual update on its most recently
ack:nowledged plan. The update is due on or befòre the
acknowledgment order anniversary date. Once a utilty
anticipates a significant deviation from its acknowledged IRP,
it must file an update with the Commission, unless the utilty is
within six months offiling its next IRP. The utility must
summarize the update at a Commission public meeting. The
utility may request acknowledgment of changes in proposed
actions identified in an update.
APPENDIX A
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2009 Integrated Resource Plan-Appendix C Page 165
Oregon Order UM 1056 Planning Criteria Idaho Power Company
ORDER NO. 07-047
g. Unless the utility requests acknowledgement of changes in
proposed actions, the annual update is an informational filing
that:
o Describes what actions the utility has taken to
implement the plan;
o Provides an assessment of what has changed since the
acknowledgment order that affects the action plan,
including changes in such factors as load, expiration of
resource contracts, supply-side and demand-side
resource acquisitons, resource costs. and transmission
availability; and
o Justifes any deviations from the CKknowledged action
plan
Guideline 4: Plan Components.
At a minimum. the plan must include the following elements:
a. An explanation of how theu,tility met each o.fthe substantive
and procedural requirements;
b. Analysis of high and low load growth scenarios in additon to
stochastic load risk analysis with an exlanation of major
assumptions;
c. For electric utilities. a determination of the levels of peaking
capacity and energy capabilty expectedfor each year of the
plan. given existing resources; identifcation of capacity and
energy needed to bridge the gap between expected loads and
resources; modeling of all existing transmission rights, as well
asfuture transmission additions associated with the resource
portolios tested:
d. For natural gas utilities, a determination of the peaking, swing
and base-load gas supply and associated transportation and
storage expected for each year o.fthe plan, given exsting
resources; and identification CJ gas supplies (peak, swing and
base-load), transportation and storage needed to bridge the
gap between exected loads and resources;
e. Identification and estimated costs of all supply-side and
demand-side resource options, taking into account anticipated
advances in technology;
APPENDIX A
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Idaho Power Company Oregon Order UM 1056 Planning Criteria
ORDER NO. 07.047
.f Analysis of measures the utility intends to take to provide
reliable servce, including cost-risk tradeoffs;
g. Identification of key assumptions about the fùture( e.g., fúel
prices and environmental compliance costs) and alternative
scenarios considered;
h. Construction of a representative set of resource portfolios to
test various operating characteristics, resource types, filels and
sources, technologies, lead times, in-service dates, durations
and general locations - system-wide or delivered to a spec~fic
portion of the system;
i. Evaluation of the performance of the candidate portfolios over
the range ofidentifedris/(s emel uncertainties;
1- Results of testing and rankorderingofthe portfolios by cost
and risk metric, and interpretation of those results;
It Analysis of the unCertainties associätedwith eachportfolio
eValuated;
1. Selection of a portfolio that represents the best combination of
ç()st andris/(for tha utilityaYid its çustomers;
m. Jdenttfication and exlanation of any inconsistencies of the
selected portfolio with any state and federal energy policies
that may ajct a utilty's plan and any barriers to
implementation: and
n. An action plan with resource activites the utility intends to
undertake over the next two to four years to acquire the
identifed resources, regardless of whether the activity was
acknowledged in a previous IRP, with the key attributes of
each resource specifed as in portfolio testing.
Guideline 5: Trasmission.
Portfolio analysis should include costs to the utility for the fùel
transportation and electric transmission required for each
resource being considered. In addition, utilities should consider
fuel transportation and electric transmissionfacilities as resource
options, taking into account their value for makng additional
purchases and sales, accessing less costly resources in remote
APPENDIX A
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2009 Integrated Resource Plan-Appendix C Page 167
Oregon Order UM 1056 Planning Criteria Idaho Power Company
ORDER NO. 07-047
locations, acquiring alternative fuel supplies, and improving
reliability.
Guideline 6: Conservation.
a. Each utility should ensure that a conservation potential study is
conducted periodically for its entire service territory.
b. To the extentthat.a utilitycontf"ols the level offundingfor
cpi1servation prpgrams in its servicelerritory, the utility should
include in its action plan all best cost/riskportfolio conservation
resources for meeting projected resource needs, specifil1gannual
savings targets.
c. To the extent that an outside party administers conservation programs
in a utility's service territory at a level offunding that is beyond the
utility's control, the utility should:
o Determine the amount.ofconservatidn resources in the best
costlriskportfolio without regard to any limits onfundil1gaf
conservation programs; and
o 1dentijj; the preferred portfolio and action plan consistent with
the outside party's projection afconservation acquisiton.
Guideline 7 : Demand Response.
Plans should evaluate demand response resources, including
voluntary rate programs, on par with other options for meeting
energ)~ capacity, and transmission needs (for electric utilties) or
gas supply and transportation needs (for natural gas utilties).
Guideline 8: Envinmenta Costs.
Utilities should include, in their base-case analyses, the regulatory
compliance costs they expect for carbon dioxide (COz), nitrogen
oxides, sulfur oxides, and mercury emissions. Utilties should
analye the range of potential CO2 regulatory costs in Order
No. 93-695, .from zero to $40 (1990$). In addition, utilities should
perform sensitivity analysis on a range of reasonably possible cost
adders for nitrogen oxides, sulfur oxdes, and mercury, if
applicable.
GuideUne9: Diect Access Loads.
An electric utility's load-resource balance should exclude
customer loads that are effectively commited to service by an
alternative electricity supplier.
APPENDIX A
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Idaho Power Company Oregon Order UM 1056 Planning Criteria
ORDER NO. 07-047
Guidelinel0: Multi-state Utities.
Multi-state utilties should plan their generation and transmission
systems. or gas supply and delivery, on an integrated-system basis
that achieves a best cost/risk portfolio for all their retail
customers.
Guideline 11: Reliabilty.
Electric utilities shoulâ çinalyze reliCib#itywithin the. risk modeling
of the actual portfolios being considered. Loss oflOådprobability.
expected planning reserve margin. and expected and worst-case
unserved energy should be determined byyear for top-performing
portfolios. Naturalgtis ittiliies should analyze. on an integrtited
nasis, gas supply, transportation, and storage. along withdemanel-
side resources, to reliably meet peak, SWing, ¡;el base-load systemrequirements. Electric and natural gas utilty plans should
demonstrate thatthe utilty's chosenportfolio achieves its stated
reliability, costand risk objectives.
Guideline It: Distributed Generation.
Electric utilties should evaluate distributed generation
technologies on par with other supply-side resources and should
consider, and quantif' where possible. the additonal benefts of
distri buted generation.
Guid~line 13: Resourc~AcquisitioJL
a. An electric utility should, in its IRP:
o IdentifjJ its proposed acquisition strateg)/for each resource in its
action plan.
o Assess the advantages and disadvantages of owning a resource
instead ofpurchasingpowetjrom another patty.
o Identif. any Benchmark Resources it plans to consider in
competiive bidding.
b. Natural gas utilities should either describe in the IRP their bidding
practices for gas supply and transportation, or provide a description
of those practices following IRP acknowledgment.
APPENDIX A
PAGE70F7
2009 Integrated Resource Plan-Appendix C Page 169
Summary of Northwest Utility Planning Criteria Idaho Power Company
UMMARY OF NORTHWEST UTILITY PLANNING CRITERIA
Utility
Avista Corporation
Bonnevile Power
Administration
Planning Criteria
Peak Load- The maximum one-hour obligation, including operating reserves, On the
expected average coldest day in January and the average hottest day in August.1
Peak Resource Capability-The maximum one-hour generation capability of company
resources, including net contract contribution, at the time of the one-hour system
peak, and excluding resources that are on maintenance during peak load periods.1
Planning Reserve-Set at a level equal to 15 percent planning reserve margin during
the company's peak load hour.1
Confidence Interval-Ninety percent confidence interval based on the monthly
variability of load and the 10th percentile of monthly historical hydro energy. This
results in a 10 percent chance of load exceeding the planning criteria for each month.
In other words, there is a 10 percent chance that the company would need to
purchase energy from the market in any given month.1
Load Forecast-Based upon normal weather conditions.
Hydro Conditions-Firm hydro energy and capacity estimates based on 1937 critical
water conditions.2
Hydro Energy-Based on current generation capability under average monthly river
discharge. Uses operating year (OY) 1937 water conditions (the 12-month period from
August 1936 through July 1937) to estimate the firm hydro energy capability in low
water conditions.2
Federal Firm Energy Surplus Analysis-Defined as the amount of generation that can
be produced in excess of firm loads using 1937 critical water conditions.2
Hydroelectric Capacity-The monthly instantaneous capacity of hydroelectric projects
is defined as the full-gate-flow maximum generation at mid-month reservoir elevation
using 1929 through 1998 historical water conditions.2
Hydro Conditions-70th percentile hydro conditions based upon historical data from
1928 through 2005.3 .
Load Forecast-Based upon 50th percentile weather conditions. 3
Monthly Average Energy-Based on 70th percentile water and 70th percentile
average load conditions.3
Catacity-Based on monthly peak-hour Northwest transmission deficit assuming
90t percentile water, 70th percentile average load and 95th percentile peak-hour load
conditions.3
Utilzes a fully probabilstic model-Prospective plans are tested against 20 years of
future conditions. The test process uses random simulations of the principal sources
of uncertainty, including hydro conditions, regional electric loads, fuel prices, CO2
control requirements, import and export markets, resource availability, and other
factors. The Council's analytical process creates a two-dimensional mathematical
surface defined by portolio cost and portolio risk. A subset of resource portolios
along the mathematical cost-risk frontier are selected for further consideration.
The preferred portolio is selected from the set of finalist portolios using qualitative
criteria.4
Integrated Resource Plan, Avista August 2009, Chapter 2.
2 2009 Pacific Northwest Loads and Resources Study, Bonnevile Power Administration, July 2009, Sections 2 & 4.
3 2009 Integrated Resource Plan, Idaho Power Company, December 2009.
4 Draft Sixth Northwest Power Plan, Northwest Power and Conservation Council, September 2009.
Idaho Power Company
Northwest Power and
Conservation Council
Page 170 2009 Integrated Resource Plan-Appendix C
Idaho Power Company Summary of Northwest Utility Planning Criteria
Utilty
PacifiCorp
Planning Criteria
Thermal-Maximum dependable capacity for peak-hour assessment. Energy
assessments used maximum dependable capacity de-rated for forced outages and
maintenance.5
Hydro Conditions-Critical water conditions. For peak hour assessment, decision
support software is used to shape critical hydro energy to estimate maximum
capability sustainable for one hour.5
Loads-Average energy requirements based upon normal weather conditions.5
Planning Reserve-Planning reserve margin of 12 percent assumed for energy and
peak-hour assessments.5
Hydro Conditions-Normal hydro conditions.Portland General
Electric Company
(PGE)
Loads-PGE identifies annual energy needs under a reference case (i.e., expected or
most likely) and high-load and low-load forecasts, assuming normal weather
conditions.6
Capacity-PGE evaluates peaking needs by comparing the annual one-hour
maximum load inclusive of 12 percent reserves (6 percent operating margin, 6 percent
planning margin), calculated on a 1-in-2 or average basis, to the capability of
energy-producing resources. Reports both the winter and the summer peak loads.6
Puget Sound Energy Loads-For capacity, power demand was estimated at normal winter minimum
temperature (230 F) plus a 15 percent planning margin. Five different economic
growth scenarios were modeled in the resource plan.?
Hydro-For capacity resource need, hydro projects assumed at full capacity output.?
Thermal-For capacity resource need, thermal projects assumed at full capacity
output.?
5 2008 Integrated Resource Plan, PacifiCorp, May 28, 2009, Chapter 5.
6 PGE 2009 Integrated Resource Plan, Portland General Electric, November 2009, Chapter 3.
7 Integrated Resource Plan, Puget Sound Energy, July 2009, Chapters 5 & 8.
2009 Integrated Resource Plan-Appendix C Page 171
Summary of Northwest Utility Planning Criteria Idaho Power Company
IRP ADVISORY COUNCIL ROSTER
Customer Representatives
AARP.............................................................
Agricultural Representative ......... ............. .....
Boise State University....................................
Heinz Frozen Foods .......................................
Idaho Retailers...............................................
Industrial Customers of Idaho Power ............
INL.................................................................
Micron............................................................
Simplot...........................................................
Public Interest Representatives
Idaho Conservation League...........................
Idaho Department of Commerce....................
Idaho Office of Energy Resources ....... ..........
Idaho State House of Representatives............
Idaho State Senate..........................................
Northwest Power and Conservation CounciL.
Snake River Alliance ....... ........ ......................
Twin Falls Canal Company...........................
Maribeth Connell
Sid Erwin
John Gardner/Todd Haynes
Steve Munn
Pam Eaton
David Hawk
Tom Moriarty
John Velikoff
Don Sturtevant
Betsy Bridge
Don Dietrich/Lane Packwood
Paul Kjellander
Representative Fred Wood
Senator Russ Fulcher
Jim Yost/Shirley Lindstrom
Ken Miller
Vince Alberdi, Retired General Manager
Regulatory Commission Representatives
Idaho PUC...................................................'" Rick Sterling
Oregon PUC................................................... Kelcey Brown
Consultant/F aci litator
The Cadmus Group, Inc. ................................ Brian Hedman
Page 172 2009 Integrated Resource Plan-Appendix C