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<tffiffi*INTEGRATED RESOURCE PLAN
An IDACORP CompanY
LOOKING AHEAD
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in ldaho Power's filings with the
Securities and Exchange Commission.
@ Printed on recycled paper
3Effi*.INTEGRATED RESOURCE PLAN
An IDACORP Company
'r't-'ll,' -i -,.
LOOKING FORWARDIRP
ACKNO\ALEDGEMEI{T
Resource planning is an ongoing process at ldaho Power. Idaho Power
prepares, files, and publishes an lntegrated Resource Plan (lRP) every two
years. ldaho Power expects that the experience gained over the next few
years will likely modify the 20-year resource plan presented in this
document.
ldaho Power invited outside participation to help develop the 2017 lRP.
ldaho Power values the knowledgeable input, comments, and discussion
provided by the lntegrated Resource Plan Advisory Council and other
concerned citizens and customers.
It takes approximately one year for a dedicated team of individuals at
ldaho Power to prepare the lRP. The ldaho Power team is comprised of
individuals that represent many departments within the company. The IRP
team members are responsible for preparing forecasts, working with the
advisory counci! and the public, and performing all the analyses necessary
to prepare the resource plan.
ldaho Power looks fonrvard to continuing the resource planning process
with customers, public-interest groups, regulatory agencies, and other
interested parties. You can learn more about the ldaho Power resource
planning process at idahopower.com.
JUNE .2017
ldaho Power Company Table of Contents
TaeLe oF CoNTENTS
List of Tables ............
....1
List of Appendices
.. vl
vlll
lx
Glossary of Acronyms
l. Summary..
x1
..1
..1
..J
..J
Introduction...............
Public Advisory Process ......
IRP Methodology......
Greenhouse Gas Emissions.
Portfolio Analysis Summary..
Action Plan..........
2. Political, Regulatory, and Operational Issues......
Idaho Strategic Energy Alliance
Idaho Energy Primer
State of Oregon Biennial Energy Plan: 2015--2017
FERC Relicensing
Idaho Water Issues.......
Renewable Integration Costs
Community Solar Pilot Program....
Renewable Energy Certifi cates
Renewable Portfolio Standard
Rule History..............
Clean Power Plan Final RuIe.........
3. Idaho Power Today.......
4
6
........8
........9
o
........9
l0
Energy Imbalance Market...... ........15
.....1 1
.....t2
.....14
.....15
....16
....17
....18
....18
....21
2017 tRP Page i
Table of Contents ldaho Power Company
Customer Load and Growth.....
2016 Energy Sources
Existing Supply-Side Resources ................
Hydroelectric Facilities................
Coal Facilities ...........
Solar Facilities
Power Purchase Agreements................
Wholesale Contracts
Power Market Purchases and Sales..
4. Future Supply-Side Generation and Storage Resources
Generation Resources
Renewable Resources
...........21
...........23
...........23
...........24
Natural Gas Facilities.............
.28
.29
.33
.35
PURPA.....
...........29
...........3 I
...........32
...........33
....35
...........35
Geothermal
.35
.37
...........38
.....38
Natural Gas-Fired Resources
Nuclear Resources .....42
.....42
.....43
.39
.39
.39
.44
.45
Coal Resources.......--.-..---.-..
Storage Resources.
Battery Storage.....
Ice-Based TES
Pumped Hydro Storage
5. Demand-Side Resources ..................
......46
......47
Page ii 2017lRP
ldaho Power Company Table of Contents
DSM Program Overview
Changes from the 2015 IRP..
Program Screening.
Demand Response Performance ...............
Committed Energy Efficiency Forecast....
Brownlee East Path..
Montana-Idaho Path
Borah West Path
Midpoint WestPath
Idaho-Nevada Path
Idaho-Wyoming Path .......
Idaho-Utah Path.
B2H
Project Participants ...........
Permitting Update
.............47
.............47
.............47
............48
............50
Transmission and Distribution Deferral Benefits Associated with Energy
Efficiency.
Committed Demand Response Forecast .
Additional Demand Response..
6. Transmission Planning...............
Past and Present Transmission................
Transmission Planning Process..
Local Transmission Planning...............
Regional Transmission Planning ...............
Interconnection-Wide Transmission Planning
Existing Transmission System.
....53
....53
....53
....55
...55
...56
...56
...57
...57
Idaho-Northwest Path.....
..57
..58
..58
..59
..59
..59
..60
..60
..60
..6t
..62
..62
2017 tRP Page iii
Table of Contents ldaho Power Company
Activities after BLM ROD ..63
.64
.64
.67
.68
69
7l
7t
73
73
74
76
78
79
79
8l
83
84
85
85
86
88
90
93
93
94
97
97
B2H Cost Treatrnent in the IRP...........
Northwest Seasonal Resource Availability Forecast ...
Gateway West.........
Nevada without North Valmy......
Transmission Assumptions in the IRP Portfolios......
7. Planning Period Forecasts..
Average-Energy Load Forecast .......
Peak-Hour Load Forecast ................
Additional Firm Load.
Generation Forecast for Existing Resources.
Hydroelectric Resources ...............
Coal Resources............
Natural Gas Resources..............
Analysis of IRP Resources.
Resource Costs-IRP Resources
LCOC-IRP Resources
LCOE-IRP Resources
Resource Attributes-IRP Resources ............
IRP Resources and Porffolio Design........
T&D Deferral Benefit Associated with DERs.......
Load and Resource Balance.....
8. Portfolios..
Weather Effects......
Economic Effects
Natural Gas Price Forecast....
Portfolio Design......
Page iv 2017 tRP
ldaho Power Company Table of Contents
Studied Portfolios.
Jim Bridger Scenario I ................
Jim Bridger Scenario 2..............
Jim Bridger Scenario 3................
Jim Bridger Scenario 4................
Portfolio Design with Two Factors......
9. Modeling Analysis and Results
Planning Case Portfolio Analysis
Natural Gas Price Sensitivities..........
Stochastic Risk AnaIysis.............
Portfolio Analysis Results in Factorial Design Format....
Solar Tipping-Point Analysis...
Qualitative Risk Analysis
Qualitative Risks........
Qualitative Benefits
Summary of Qualitative Risks and Benefits.
CAA Section 111(d)
Capacity Planning Margin
Flexible Resource Needs Assessment
Historical Analysis..........
Projected Flexibility Score n 2026.....
Solar Capacity Credit..
LOLE
10. Preferred Portfolio and Action Plan...............
Preferred Portfolio
Action Plan (2017 -2021) ......
Idaho Power and the Utility of the Future
Conclusion
......98
......98
....100
......117
......1 l8
......1 l9
......1 19
103
l0s
107
109
109
tt2
tt4
t2t
129
...122
...123
...t24
...t27
...127
..130
..132
133
.133
.133
135
r36
2017 tRP Page v
Table of Contents ldaho Power Company
Table l.l
Table 1.2
Table 1.3
Table 3.1
Table3.2
Table 3.3
Table 3.4
Table 4.1
Table 5.1
Table 5.2
Table 5.3
Table 6.1
Table6.2
Table 6.3
Table 7.1
Table 7.2
Table 7.3
Table 7.4
P7 resource additions -.-..-....-7
LIST OF TABLES
Factorial design applied to portfolios 7
Action plan..........
Historical capacrty, load, and customer data .22
Existing resources .24
Net metering service customer count as of March 1,2017.. ......................30
Net metering service generation capacity (MVD as of Marchl,2017 ......30
Solar capacity credit values .................37
Demand response programs.. ...............49
Total energy efficiency portfolio forecasted effects (2017-2036)
.51
Total energy efficiency portfolio cost-effectiveness sunmary... ...............52
Transmission import capacity.... ..........60
B2H capacity and permitting cost allocation............ ..............62
Transmission assumptions and requirements..........................69
Load forecast-average monthly energy (aMW)75
Load forecast-peak hour (MW)............77
...92Resource attributes..
July monthly average energy deficits (aMW) by Bridger coal future
with existing and committed supply- and demand-side resources (70th-
percentile water and 70th-percentile load).........
July monthly peak-hour capacity deficits (MW) by Bridger coal future
with existing and committed supply- and demand side resources (90th-
percentile water and 95th-percentile load)
Pl timeline
...96
Table 7.5
Table 8.1
Table 8.2
Table 8.3
Table 8.4
Table 8.5
Table 8.6
Table 8.7
Table 8.8
Table 8.9
Pl resource sunmary........
P2 timeline
P3 timeline
P4 resource sunmary
P5 timeline
..96
..99
101
P2 resource summary .......100
100
.................100
P3 resource summary
P4 timeline
.................. I 0l
.......101
Page vi 2017 tRP
ldaho Power Company Table of Contents
Table 8.10 P5 resource sunmary..
Table 8.1I P6 timeline
Table 8.12 Resource P6 resource sunmary..
Table 8.13 P7 timeline
Table 8.14P7 resource summary..
Table 8.15 P8 timeline
Table 8.16 P8 resource summary..
Table 8.17 P9 timeline
Table 8.18 P9 resource sunmary..
Table 8.19 PlO timeline..
Table 8.20 P10 resource sunmary..
Table 8.21 Pl I timeline
Table 8.22Pll resource sunmary..
Table 8.23Pl2timeline
Table 8.24P12 resource sunmary..
Table 8.25 Factorial design applied to portfolios
Table 9. I Financial assumptions................
Table 9.2 Proposed target reductions for state-by-state mass-based compliance
(Idaho Power share)
Table 9.10 Qualitative benefit analysis....
Table 9.1I Capacity planning margin......
Table 9.12 Hours exceeding flexibility threshold by month..
Table 9.13 Solar capacrty credit values
Table 9.14 Hourly LOLP of 500 iterations for2025
Table 9. I 5 Monthly probabilities............
Table 10.1 P7 Resources.
...........102
...........102
...........102
......r06
......107
......107
......108
......1 10
.103
.103
103
104
r04
104
105
105
106
ll0
123
t32
Table 9.3 2017IRP Portfolios, NPV years 2017-2036 ($ x 1,000) .......
Table 9.4 Portfolio relative costs under nine natural gas price forecasts
Table 9.5 Portfolio rankings under nine natural gas price forecasts... ...113
Table 9.6 AURORA variable + fixed costs (NPV nominal dollars).......
Table 9.7 2017 IRP portfolios, NPV, 2017-2036 ($ x 1,000)
Table 9.8 2017 IRP portfolios, NPV, 2017-2036 ($ x 1,000) ...............118
Table 9.9 Qualitative risk anaIysis...............
....1 I I
....1 l3
...tt7
...1t7
..123
.........t25
.........129
.........130
......... I 3 I
........1 33
2017 tRP Page vii
Table of Contents ldaho Power Company
Table 1 0.2 Action plan (2017 -2021) ....
LIsT oF FIGURES
Estimated Idaho Power COz emissions intensity.............
Estimated Idatro Power COz emissions...........
Historical capacity, load, and customer data..........
2016 energy sources..
PURPA contracts by resource type..........
Cumulative annual growth in energy efficiency.........
Historical annual demand response progftlms
Idaho Power transmission system map ..........
B2H routes with the agency-preferred altemative
Gateway West map
Average monthly load-growth forecast
Peak-hour load-growth forecast (MW)
Brownlee historical and forecast inflows, April through July
Henry Hub natural gas spot price.........
13s
Figure 1.1
Figure 1.2
Figure 3.1
Figure 3.2
Figure 3.3
Figure 5.1
Figure 5.2
Figure 6.1
Figure 6.2
Figure 6.3
Figure 7.1
Figwe7.2
Figure 7.3
Figure 7.4
Figure 7.5
Figure 7.6
Figure 9.1
Figure 9.2
Figure 9.3
Figure 9.4
Figure 9.5
...5
...5
.22
..23
..32
..48
..49
..58
...63
...67
...75
77
..........81
84
Levelized capacity (fixed) costs..........
LCOE (as stated capacity factors).....
Natural gas planning case and eight sensitivities (nominal $).............
Natural gas sampling (Nominal $/\4MBtu)
Customer load sampling (annual MWh).......
Hydro generation sampling (annual MV/h)
Portfolio stochastic analysis, total portfolio cost (2017, NPV,
....87
....89
...114
...1 15
tt2
115
$ millions) ......116
Figure 9.6 Distribution of events with flexibility score 100 MW or greater...... .......128
Figure 9.7 Distribution of events with flexibility score l2 percent of net load
or gteater..t28
Page viii 2017lRP
ldaho Power Company Table of ContenF
LIsT oF APPENDIcES
Appendix A-,Sales and Load Forecast
Appendix B-Demand-Side Management 2016 Annual Report
Appendb C:Technic al Appendix
2017 tRP Page ix
Table of Contents ldaho Power Company
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Page x 2017 tRP
ldaho Power Company Glossary of Acronyms
GIOSSARY oF AcRoNYMS
A/C-Afu Conditioning
AC-Altemating Current
AEG-Applied Energy Group
AEO-Annual Energy Outlook
AFUDC-Allowance for Funds Used During Construction
Agl-Silver Iodide
akW-Average Kilowatt
aMW-Average Megawatt
ATC-Available Transmission Capacity
B2H-Boardman to Hemingway
BLM-Bureau of Land Management
BPA-Bonneville Power Administration
BSER-Best System of Emissions Reduction
CAA-CleanAir Act of 1970
CAISO-Califomia Independent System Operator
CAMP-Comprehensive Aquifer Management Plan
CccT-{ombined-Cycle Combustion Turbine
cfs-{ubic Feet per Second
CHP-{ombined Heat and Power
CHQ-Corporate headquarters
Clatskanie PUD-{latskanie People' s Utility District
COz-Carbon Dioxide
COE-United States Army Corps of Engineers
CREP-Conservation Reserve Enhancement Program
CSPP-{ogeneration and Small-Power Producers
CWA-Clean Water Act of 1972
D.C.-Disfrict of Columbia
DC-Direct Current
DER-Distributed Energy Resources
DOE-Department of Energy
DSM-Demand Side Management
EEAG-Energy Efficiency Advisory Group
EGU-Electric Generating Unit
EIA-Energy Information Administration
EIM-Energy Imbalance Market
ElS-Environmental Impact Statement
EPA-Environmental Protection Agency
ESA-Endangered Species Act of 1973
2017 tRP Page xi
Glossary of Acronyms ldaho Power Company
ESPA-Eastem Snake River Plain Aquifer
ESPAM-Enhanced Snake River Plain Aquifer Model
F-Fahrenheit
FCRPS-Federal Columbia River Power System
FERC-Federal Energy Regulatory Commission
FPA-Federal Power Act of 1920
FWS-US Fish and Wildlife Service
GWh-Gigawatt-Hour
GWMA-Ground Water Management Area
HCC-Hells Canyon Complex
HRSG-Heat Recovery Steam Generator
IDWR-Idaho Department of Water Resources
IGCC-Integrated Gasification Combined Cycle
INL-Idaho National Laboratory
IPUC-Idaho Public Utilities Commission
IRP-Inte grated Resource Plan
IRPAC-IRP Advisory Council
IWRB-Idaho Water Resource Board
kV-Kilovolt
kW-Kilowatt
kwh-Kilowatt-Hour
Lcoc-Levelized Cost of Capacity
LCOE-Levelized Cost of Energy
LiDAR-Light Detection and Ranging
LOLE-Loss-of-Load Expectation
LOLP-Loss-of-Load Probability
LTP-Local Transmission Plan
m2-Square Meters
MATl-Montana-Alberta Tie Line
Mou-Memorandum of Understanding
MSA-Metropolitan Statistical Area
MW-Megawatt
MWh-Megawatt-Hour
NEEA-Northwest Energy Efficiency Alliance
NEPA-National Environmental Policy Act of 1969
NERC-North American Electric Reliability Corporation
NOx-Nitrogen Oxide
NPV-Net Present Value
NREL-National Renewable Energy Laboratory
NTTG-Northern Tier Transmission Group
Page xii 2017 tRP
ldaho Power Company Glossary of Acronyms
NWPCC-Northwest Power and Conservation Council
NwPP-Northwest Power Pool
O&M-Operation and Maintenance
OATT---Open Access Transmission Tariff
ODEHregon Department of Environmental Quality
ODOE-Oregon Department of Energy
OEMR-Office of Energy and Mineral Resources
OPUC-Public Utility Commission of Oregon
ORS-Oregon Revised Statue
pAS C-Preliminary Application for S ite Certifi cate
PCA-Power Cost Adjustment
PGE-Portland General Electric
PM&E-Protection, Mitigation, and Enhancement
PPA-Power Purchase Agreement
PURPA-Public Utility Regulatory Policies Act of 1978
PV-Photovoltaic
QA-Quality Assurance
QF-Qualiffing Facility
RAAC-Resource Adequacy Advisory Committee
REC-Renewable Energy Certifi cate
RFP-Request for Proposal
RH BART-Regional Haze Best Available Retrofit Technology
ROD-Record of Decision
ROI-Return on Investment
ROR-Run-of-River
ROW-Right-of-Way
RP S-Renewable Portfolio Standard
SCCT-Simple-Cycle Combustion Turbine
SCR-Selective Catalytic Reduction
SIP-State Implementation Plan
SMR-Small Modular Reactor
SOz-Sulfur Dioxide
SRBA-Snake River Basin Adjudication
SRPM-Snake River Planning Model
T&D-Transmission and Distribution
TEPPc-Transmission Expansion Planning Policy Committee
TES-Thermal Energy Storage
TRC-Total Resource Cost
UAMPS-Utah Associated Municipal Power Systems
US-United States
USBR-Bureau of Reclamation
USFS-United States Forest Service
2017lRP Page xiii
Glossary of Acronyms ldaho Power Company
VRB-Vanadium Redox-Flow Battery
WDEQ-Wyoming Department of Environmental Quality
WECC-Western Electricity Coordinating Council
Page xiv 2017 tRP
ldaho Power Company 1. Summary
1. SuwTMARY
lntroduction
The 2017 Integrated Resource Plan (IRP) is Idaho Power's l3m resource plan prepared to fulfill
the regulatory requirements and guidelines established by the Idaho Public Utilities Commission
(PUC) and the Public Utility Commission of Oregon (OPUC). Idaho Power's resource planning
process has four primary goals:
1. Identiff sufficient resources to reliably serve the growing demand for energy within
Idaho Power's service area throughout the 2D-year planning period.
2. Ensure the selected resource portfolio balances cost, risk, and environmental concems.
3. Give equal and balanced treatment to supply-side resources, demand-side measures,
and transmission resources.
4. Involve the public in the planning process in a meaningful way
The20lT IRP evaluates the 2O-year planning period from2017 through 2036. During this
period, load is forecasted to grow by 0.9 percent per year for average energy demand and
1.4 percent per year for peak-hour demand. Total customers are expected to increase to 756,000
by 2036 from 534,000 in 2016. Additional company-owned resources will be needed to meet
these increased demands. I
Idaho Power owns and operates 17 hydroelectric projects, 3 natural gas-fired plants,
I diesel-powered plant, and shares ownership in 3 coal-fired facilities. Hydroelectric generation
is a large part of Idaho Power's generation fleet; however, hydroelectric plants are subject to
variable water and weather conditions. Public and regulatory input encouraged Idaho Power to
adopt more conservative planning criteria beginning with the 2002 IRP. In response to this input,
Idaho Power continues to develop more conservative streamflow projections and planning
criteria for use in resource adequacy planning. Idaho Power has an obligation to serve customer
loads regardless of water and weather conditions. Further discussion of Idaho Power's IRP
planning criteria can be found in Chapter 7.
I Recent company disclosures forecast load growth during the 2016 to2035 planning period at I percent for average
energy demand and 1.4 percent for peak-hour demand.
2017 tRP Page 1
'1. Summary ldaho Power Company
Other resources relied on for planning include demand-side management (DSM)
and transmission resources. The goal of DSM programs is to achieve prudent, cost-effective
energy efficiency savings and provide an optimal amount of peak reduction from demand
response programs. Idatro Power also strives to provide customers with tools and information
to help them manage their own energy usage. The company achieves these objectives through
the implementation and carefrrl management of incentive programs and through outreach
and education.
Idaho Power's resource planning process also includes evaluating additional transmission
capacity as a resource alternative to serve retail customers. Transmission projects are often
regional resources, and their planning is conducted by regional industry groups, such as the
Westem Electricity Coordinating Council (WECC) and the Northem Tier Transmission Group
(NTTG). Idaho Power coordinates local transmission planning with regional forums, as well as
the Federal Energy Regulatory Commission (FERC). Idaho Power is obligated under FERC
regulations to plan and expand its local transmission system to provide requested firm
transmission service to third parties and to construct and place in service sufficient transmission
capacity to reliably deliver energy and capacity to network customers2 and Idaho Power retail
customers.3 The timing of new transmission projects is subject to complex permitting, siting,
and regulatory requirements and coordination with co-participants.
IRPs address Idaho Power's long-term resource needs. Idaho Power plans for near-term energy
and capacity needs in accordance with the Energt Risk Management Policy and Energt Risk
Management Standards. The risk management standards were collaboratively developed in 2002
between Idaho Power, IPUC staff, and interested customers (IPUC Case No. IPC-E-0l-16).
The Energt Risk Management Policy and Energ,, Risk Management Standards specifies an
l8-month load and resource review period, and Idaho Power assesses the resulting operations
plan monthly.
2 Idaho Power has a regulatory obligation to construct and provide transmission service to network or wholesale
customers pursuant to a FERC tariff.
3 Idaho Power has a regulatory obligation to construct and operate its system to reliably meet the needs of native
load or retail customers.
Page2 2017 tRP
ldaho Power Company 1. Summary
Public Advisory Process
Idaho Power has involved representatives
of the public in the resource planning
process since the early 1990s. The public
forum is known as the IRP Advisory
Council (IRPAC). The IRPAC meets most
months during the development of the
resource plan, and the meetings are open to
the public. Members of the council include
regulatory, political, environmental,
and customer representatives, as well as
representatives of other public-interest
groups. Many members of the public also tRpAc meering, May 2017
participate even though they are not
members of the IRPAC. Some individuals have participated in Idaho Power's resource planning
process for over 20 years. A list of the 2017 IRPAC members can be found inAppendix C-
Technical Appendix.
For the 2017 IRP, Idaho Power conducted eight IRPAC meetings, including a workshop
designed to explore the potential for distributed energy resources to defer grid investment.
Idaho Power believes working with members of the IRPAC and the public improves the IRP.
Idaho Power and the members of the IRPAC recognize that final decisions on the resource plan
are made by Idaho Power. However, Idaho Power encourages IRPAC members and members of
the public to submit comments expressing their views regarding the2017 IRP and the resource
planning process in general.
IRP Methodology
A primary goal of the IRP is to ensure Idaho Power's system has sufficient resources to reliably
serve customer demand over the 20-year planning period. A tool critical to assessing resource
sufficiency is the load and resource balance, which compares projected customer demand with
system resources available for meeting demand. An ef[ective IRP methodology identifies
deficiencies in the 2}-year load and resource balance and analyzes options for satisffing the
identified resource deficiencies. The practical implication of successful integrated resource
planning is that system operators of the future are equipped with a system having sufficient
resources to maintain reliable electrical service to Idaho Power's customers.
Resource sufficiency is assessed for energy and capacity. Existing supply-side resources include
generation resources and transmission import capacity from regional wholesale electric markets.
Existing demand response resources are included in the capacity resource sufficiency assessment
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2017 tRP Page 3
1. Summary ldaho Power Company
as well. Idaho Power then includes the IRP target amount of cost-effective and achievable energy
effrciency, which reflects expansion of existing energy-savings potential.
Based on identified resource deficiencies over the planning period, Idaho Power conducts a
financial analysis of various resources and all portfolios to quantitatively evaluate the individual
resources and resulting portfolios designed to remediate any energy or capacity deficiency over
the planning period. Within the financial analysis, Idaho Power evaluates the costs and benefits
of each resource type. The financial costs include construction, fuel, operation and maintenance
(O&M), transmission upgrades associated with interconnecting new resource options,
and anticipated environmental controls. The financial benefits include economic resource
operations, projected market sales, and the market value of renewable energy certificates (REC)
for REC-eligible resources.
The Idaho Power balancing area is pan of the larger western interconnect. Idaho Power must
balance loads and generation perNorth American Electric Reliability Corporation (NERC)
system reliability standards. During times of acute oversupply, Idaho Power must rely on
available system resources to regain intra-hour balance and must sometimes curtail intermittent
resources like wind and solar. Power markets are available via transmission lines to purchase or
sell power inter-hour to balance the system.
An additional transmission connection to the Pacific Northwest has been part of Idaho Poweros
preferred resource portfolio since the 2006 IRP. By the 2009 IRP, Idaho Power determined the
approximate configuration and capacity of the transmission line, and since 2009 the addition has
been called the Boardman to Hemingway (B2H) Transmission Line Project. Idaho Power again
evaluated the B2H transmission line in the 20l7IRP to ensure the transmission addition remains
a prudent resource acquisition.
Greenhouse Gas Emissions
Idaho Power's carbon dioxide (COz) emission levels have historically been well below the
national average for the 100 largest electric utilities in the United States (US), both in terms of
COz emissions intensity (pounds per megawatt-hour [MWh] generation) and total COz emissions
(tons) @igure l.l and Figure 1.2).
Page 4 2017 tRP
ldaho Power Company 1. Summary
1,500
1,300
1 ,100
9m
7m
500
1 998 2012 2014 2016
Figure 1.1
10,000,000
9,000,000
8,000,000
7,000,000
6,000,000
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
01998 2000 2@2 2@4 2006 2m8 2010 2012 2014 2016
Figure 1.2 Estimated ldaho Power COz emissions
In September 2009,Idaho Power's Board of Directors approved guidelines to reduce
Idaho Power's resource portfolio average COz emissions intensity from 2010 through 2013 to
l0 to l5 percent below the company's 2005 COz emissions intensity of 1,194 pounds per MWh.
Because Idaho Power's COz emissions intensity fluctuates with streamflows and production
levels of existing and anticipated renewable resources, the company has adopted an average
intensity reduction goal to be achieved over several years.
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Estimated ldaho Power COz emissions intensity
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2017 tRP Page 5
1. Summary ldaho Power Company
Generation and emissions from company-owned resources are included in the COz emissions
intensity calculation. The company's progress toward achieving this intensity reduction goal and
additional information on Idalro Power's COz emissions are reported on the company's website.4
Information related to Idatro Power's COz emissions, voluntarily reported annually, is also
available through the Carbon Disclosure Project at cdp.net.
In November 2012, the Board of Directors approved an extension of the company's 2010 to 2013
goal for reducing COz emissions intensity. The goal as restated in20l2 was to achieve aCOz
emissions intensity l0 to l5 percent below the 2005 COz emissions intensrty from 2010 to 2015.
That goal was met.
In May 2017, the Board of Directors approved the current COz emissions intensity goal,
which extends the target COz emissions intensity of 15 to 20 percent below the 2005 COz
emissions intensity through 2020. As of the end of 2016, the company's COz emissions intensity
was 858 pounds per MWh, 28 percent below the 2005 COz emissions intensity.
The portfolio analysis performed for the 2017 IRP assumes all resource portfolios comply with
state-by-state mass-based emission limits detailed in the Clean Power Plan Final Rule filed in the
Federal Register in October 2015. Further discussion of these COz emission constraints is
provided in Chapter 9. Projected COz emissions for each analyzed resource portfolio are
provided in Appendix C-Technical Appendix.
Portfolio Analysis Summary
Idaho Power designed the portfolio analysis for the 2017 IRP to inform the IRP's action plan
with respect to two key resource actions: l) selective catalytic reduction (SCR) investments
required for Jim Bridger units 1 ard2by 2022 and202l, respectively, and 2)theB2H
transmission line. To achieve this objective, portfolios were formulated such that the effects of
these two resource actions, or factors, could be isolated. This portfolio design approximates a
controlled experiment using a factorial experimental design. This design is an effective statistical
technique for studying differences between two (or more) factors, each factor having more than
one possible level. An outline of the factorial design specifically in the context of the 2017 IRP is
as follows:
Factor 1: Treatment of Jim Bridger units I and2
o Level 1: Invest in SCRs and operate through 2036
o Level2: Retire Unit I in2028 and Unit 2in2024 (without investing in SCRs)
o Level3: Retire Unit I n2032 and Unit 2in2028 (without investing in SCRs)
o Level 4: Retire Unit I in2022 and Unit 2 in202l (without investing in SCRs)
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a idahopower.com/AboutUs/Sustainability/CO2Emissions/co2lntensity.cfrn
Page 6 2017lRP
ldaho Power Company
o Factor 2: Primary portfolio element(s)
o Level l:B2H
. Level 2: Solar PV/natural gas-fired generation
. Level 3: Natural gas-fired generation
Table 1.1 provides a matrix of the factorial design with the portfolios corresponding to each
factorial combination.
Table'1.1 Factorial design appliedto portfolios
Primary Portfolio Element(s)
Treatment of Jim Bridger Units 1 and 2 82H Solar PV/Natural Gas Natural Gas
1. Summary
lnvest in SCR
Retire Unit 1 in 2028 and Unit 2 in 2024
Retire Unit 1in2032 and Unit 2in2028
Retire Unit 1in2022 and Unit 2in2021
P1
P4
P7
P10
P2
P5
P8
P11
P3
P6
P9
P12
The IRP emphasizes that the validity of the factorial design relies on by-column and by-row
uniformity; that is, all portfolios within a given row in the above table must uniformly reflect the
same SCR investment scenario, and similarly all portfolios within a given column must
uniformly reflect the same primary portfolio element(s). This uniformity is critical to yielding
meaningful inferences from the factorial design.
The 12 resource portfolios formulated were analyzed under planning-case conditions for natural
gas price, hydroelectric production, and system load. The analysis also included a range of eight
natural gas sensitivities and a stochastic risk analysis. The stochastic risk analysis modeled
100 iterations (or futures) on the selected stochastic risk variables: natural gas price,
hydroelectric production, and system load. These analyses are described in more detail in
Chapter 9. The top performing portfolio from the quantitative portfolio analysis is portfolio 7
(P7). Table 1.1 demonstrates P7 is a portfolio with B2H as the primary element and assumes
retirement of Jim Bridger units 1 and2 in2032 and2028, respectively. The resource additions
with dates for P7 are provided in Table 1.2.
Table 1.2 P7 resource additions
Date Resource lnstalled Capacity
2026 B2H
2031
2032
2033
2035
2036
Reciprocating engines
Reciprocating engines
Combined-cycle combustion turbine (1xl)
Reciprocating engines
Reciprocating engines
500 megawatts (MW) transfer capacity Apr-Sep,
200 MW transfer capacity Oct-Mar
36 MW
36 MW
3OO MW
54 MW
54 MW
2017 tRP PageT
1. Summary ldaho Power Company
The qualitative risk analysis supports the selection of P7, finding thatPT does not carry greater
exposure to qualitative risk factors than other portfolios. In fact, P7 has unique qualitative
benefits associated with Idaho Power's participation in an energy imbalance market (EIM)
and with expanded penetrations of intermittent renewable energy sources. P7 is also consistent
with Idaho Power's goals related to responsibly transitioning away from coal-fired
generating capacity.
Action Plan
Table 1.3 provides the schedule of action items Idaho Power anticipates over the next four years
Further discussion surrounding the action plan is provided in Chapter 10.
Tabte 1.3 Action plans
Year Resource Action Action Number
2017-2018 EtM
2017-2018
2017-20',t9
Loss-of-load and solar
contribution to peak
North Valmy Unit 1
2017-2021 Jim Bridger units 1
and2
2017-2020 B2H
2018-20266 B2H
2017-2021 Boardman
2017-2021 Gateway West
Continue planning for western EIM participation beginning in
April2018.
lnvestigate solar PV contribution to peak and loss-of-load
probability analysis.
Plan and coordinate with NV Energy ldaho Powe/s exit
from coal-fired operations by year-end 2019. Assess import
dependability from northern Nevada.
Plan and negotiate with PacifiCorp and regulators to achieve
early retirement dates of year-end 20281or Unit 2 and
year-end 2032 for Unit 1.
Conduct ongoing permitting, planning studies,
and regulatory filings.
Conduct preliminary construction activities, acquire long-lead
materials, and construct the B2H project.
Continue to coordinate with PGE to achieve cessation of
coal-fired operations by year-end 2020 and the subsequent
decommission and demolition of the unit.
Conduct ongoing permitting, planning studies,
and regulatory filings.
Continue the pursuit of cost-effective energy efficiency.
Continue stakeholder involvement in CAA Section 111(d)
proceedings, or alternative regulations affecting
carbon emissions.
Plan and coordinate with NV Energy ldaho Power's exit
from coal-fired operations by year-end 2025.
1
2
3
4
5
6
7
I
2017-2021
2017-2021
Energy efficiency
Carbon emission
regulations
I
10
2017-2021 North Valmy Unit 2 11
5 The B2H short-term action plan is 2017 to2026. All other action plan items are for 2017 to202l.
6 B2H in-service date of 2024 or later, subject to coordination of activities with project co-participants.
Page 8 2017 IRP
ldaho Power Company 2. Political, Regulatory, and Operational lssues
2. PoltncAL, REGULAToRv, AND OpenrroNAL lssues
ldaho Strategic Energy Alliance
Under the umbrella of the Idatro Governor's Offrce of Energy and Mineral Resources (OEMR),
the Idaho Strategic Energy Alliance allows various stakeholders to represent and participate in
developing energy plans and strategies for Idaho's energy future. The Idaho Strategic Energy
Alliance is Idaho's primary mechanism for advancing energy production, energy efficiency,
and energy business in Idaho.
The purpose of the Idaho Strategic Energy Alliance is to develop a sound energy portfolio for
Idaho that includes diverse energy resources and production methods; the highest value to the
citizens of Idaho; quality stewardship of environmental resources; and an effective, secure,
and stable energy system.
Idaho Power representatives serve on both the Idaho Strategic Energy Alliance Board of
Directors and several volunteer task forces on the following topics:
. Energy efficiency and conservation
o Wind
o Geothermal
o Hydropower
. Carbon issues
o Baseload resources
o Economic/financial development
Forestry
Biogas
Biofuel
Solar
Transmission
Communication and outreach
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o Energy storage
ldaho Energy Primer
In20l6, the Idaho Strategic Energy Alliance prepared the20l6ldaho Energy Primer (Primer).
The Primer is a resource to help citizens of Idaho better understand the contemporary energy
landscape in the state and to make informed decisions about Idaho's energy future.
The Primer provides information about energy resources, production, distribution, and use in the
state. Having reliable, affordable, and sustainable energy for individuals, families, and businesses
while protecting the environment is critical to achieving sustainable economic growth and
maintaining our quality of life.
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2. Political, Regulatory, and Operational lssues ldaho Power Company
The 2016 Idatro Energy Primer finds that, despite Idaho's reliance on imported energy,
Idaho citizens and businesses continue to benefit from stable and secure access to affordable
energy. In a year with average hydroelectric generation, about 65 percent of Idaho's electricity is
generated in Idaho. The other 35 percent comes primarily from coal-fired power plants located in
neighboring states. Idaho has the fifttr lowest carbon dioxide output of any state because of its
abundant hydropower, wind, biomass, and other renewable energy sources.
State of Oregon Biennial Energy Plan: 2015-2017
The Oregon Department of Energy (ODOE) completes a Biennial Energy Plan every two years.
The ODOE's Biennial Energy PIan provides information on Oregon's energy supply and
consumption, shows how long-term energy costs have been reduced, and highlights current
energy issues and trends.
The ODOE 2015-2017 Biennial Energy Plan highlights some of the current challenges and
opportunities for Oregon, including the following:
Accelerated demand for energy efficiency due to a growing population in Oregon that
drives increases in demand and energy use
a Continued development of clean energy that can help reduce the environmental impact of
energy use
a Reduction of carbon emissions
Energy supply due to numerous market forces that affect the type, number,
and geographic diversity of energy siting projects
The2015-2017 Biennial Energy Plan showed Oregon's energy supply consisting of primarily
hydroelectric power, followed by coal and natural gas. The most significant change in electricity
consumption from 2005 to 2010 is the growth of natural gas, from 3.3 percent to 16.24 percent.
Wind has also grown consistently, increasing from 0.25 percent to 4.31 percent. Oregon's
generation mix includes power generated outside of the state and delivered to Oregon consumers.
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ldaho Power Company 2. Political, Regulatory, and Operational lssues
FERC Relicensing
Like other utilities that operate non-federal
hydroelecuic proj ects on qualified
waterways, Idatro Power obtains licenses
from FERC for its hydroelectic projects.
The licenses last for 30 to 50 years,
depending on the size, complexrty,
and cost ofthe project.
Idaho Power's remaining and most
significant ongoing relicensing effort is for
the Hells Canyon Complex (HCC). The
HCC provides approximately two-thirds of Bavha lsland
Idaho Power's hydroelectric generating
capacity and34 percent of the company's total generating capacity. The current license for the
HCC expired in July 2005. Until the new, multi-year license is issued, Idaho Power continues to
operate the project under annual licenses issued by FERC.
The HCC license application was filed in July 2003 and acceped by FERC for filing in
December 2003. FERC has been processing the application consistent with the requirements of
the Federal Power Act of 1920, as amended (FPA); the National Environmental Policy Act of
1969, as amended (NEPA); the Endangered Species Act of 1973 (ESA); the Cleon Water Act of
1972 (CWA); and other applicable federal laws. FERC is currently waiting for Oregon and Idatro
to issue Section 401 certifications under the CWA. The certifications are expected on or before
April 13,2018.
Efforts to obtain a new multi-year license for the HCC are expected to continue until a new
license is issued, which Idatro Power estimates will occur no earlier thar202l. Considering the
costs incured and the considerable passage of time, in December20l6ldaho Power filed an
application with the IPUC requesting a determination that Idaho Power relicensing expenditures
of $220.8 million through year-end 2015 were prudently incurred and therefore eligible for
inclusion in retail rates. After a new multi-year license is issued, further costs will be incurred to
comply with the terms of the new license. Because the new license for the HCC has not been
issued and discussions on the protection, mitigation, and enhancement @M&E) packages are still
being conducted, it is not possible to estimate the final total cost.
Relicensing activities include the following:
l. Coordinating the relicensing process
2. Consulting with regulatory agencies, tribes, and interested parties on resource and
legal matters
2017lRP Page 1 1
2. Political, Regulatory, and Operational lssues ldaho Power Company
3. Preparing and conducting studies on fish, wildlife, recreation, archaeological resources,
historical flow pattems, reservoir operation and load shaping, forebay and river
sedimentation, and reservoir contours and volumes
4. Analyzing data and reporting study results
5. Preparing all necessary reports, exhibits, and filings to support ongoing regulatory
processes related to the relicensing effort.
Failure to relicense any of the existing hydroelectric projects at a reasonable cost will create
upward pressure on the electric rates of Idaho Power customers. The relicensing process also has
the potential to decrease available capacity and increase the cost of a project's generation
through additional operating constraints and requirements for environmental PM&E measures
imposed as a condition of relicensing. Idaho Power's goal throughout the relicensing process is
to maintain the low cost of generation at the hydroelectric facilities while implementing
non-power measures designed to protect and enhance the river environment.
No reduction of the available capacity or operational flexibility of the hydroelectric plants to be
relicensed has been assumed in the 2017 IRP. If capacity reductions or reductions in operational
flexibility do occur as a result of the relicensing process, Idaho Power will adjust future resource
plans to reflect the need for additional generation resources.
ldaho Water lssues
Power generation at Idaho Power's hydroelectric projects on the Snake River and its tributaries is
dependent on the State water rights held by the company for these projects. The long-term
sustainability of the Snake River Basin streamflows, including tributary spring flows and the
regional aquifer system, is crucial for Idaho Power to maintain generation from these projects.
The company is dedicated to the vigorous defense of its water rights. Idaho Power's ongoing
participation in water-right issues and ongoing studies are intended to guarantee suffrcient water
is available for use at the company's hydroelectric projects on the Snake River.
Idaho Power, along with other Snake River Basin water-right holders, was engaged in the
Snake River Basin Adjudication (SRBA), a general streamflow adjudication process started in
1987 to define the nature and extent of water rights in the Snake River Basin. The initiation of
the SRBA resulted from the Swan Falls Agreement entered into by Idaho Power and the
governor and attomey general of the State of Idaho in October 1984. Idaho Power filed claims
for all its hydroelectric water rights in the SRBA. As a result of the SRBA, the company's water
rights were adjudicated, resulting in the issuance of partial water-right decrees. The Final Unified
Decree for the SRBA was signed on August 25,2014.
In 1984, the Swan Falls Agreement resolved a struggle between the State of Idaho and
Idaho Power over the company's water rights at the Swan Falls Project. The agreement stated
Page 12 20't7lRP
ldaho Power Company 2. Political, Regulatory, and Operational lssues
Idaho Power's water rights at its hydroelectric facilities between Milner Dam and Swan Falls
entitled the company to a minimum flow at Swan Falls of 3,900 cubic feet per second (cfs)
during the irrigation season and 5,600 cfs during the non-irrigation season.
The Swan Falls Agreement placed the portion of the company's water rights beyond the
minimum flows in a trust established by the Idaho Legislature for the benefit of Idaho Power and
the citizens of the State of Idaho. Legislation establishing the trust granted the state authority to
allocate trust water to future beneficial uses in accordance with state law. Idaho Power retained
the right to use water in excess of the minimum flows at its facilities for hydroelectric generation
until it was reallocated to other uses.
Idaho Power filed suit in the SRBA in2007 as a result of disputes about the meaning and
application of the Swan Falls Agreement. The company asked the court to resolve issues
associated with Idaho Power's water rights and the application and effect of the trust provisions
of the Swan Falls Agreement. In addition, Idaho Power asked the court to determine whether the
agreement subordinated the company's hydroelectric water rights to aquifer recharge.
A settlement signed in2009 reaffirmed the Swan Falls Agreement and resolved the litigation by
clarifuing the water rights held in trust by the State of Idaho are subject to subordination to future
upstream beneficial uses, including aquifer recharge. The settlement also committed the State of
Idaho and Idaho Power to further discussions on important water-management issues concerning
the Swan Falls Agreement and the management of water in the Snake River Basin. Idaho Power
and the State of Idaho are actively involved in those discussions. The settlement also recognizes
water-management measures that enhance aquifer levels, springs, and river flows-such as
aquifer-recharge projects-that benefit both agricultural development and hydroelectric
generation.
Idaho Power initiated and pursued a successful weather modification program in the Snake River
Basin. The company partnered with an existing program in the upper Snake River Basin and has
cooperatively expanded the existing weather modification operational program, along with
forecasting and meteorological data support. The company has a long-term plan to continue the
expansion of this program. In20l4,Idaho Power expanded its cloud-seeding program to the
Boise and Wood River basins, in collaboration with basin water users and the Idaho Water
Resource Board (IWRB). Wood River cloud seeding, along with the upper Snake River
activities, will benefit the Eastem Snake River Plain Aquifer (ESPA) Comprehensive Aquifer
Management Plan (CAMP) implementation through additional water supply.
Water management activities for the ESPA are currently being driven by the recent
agreement between the Surface Water Coalition and the Idaho Ground Water Appropriators.
This agreement settled a call by the Surface Water Coalition against groundwater appropriators
for delivery of water to its members at Minidoka Dam and Milner Dam. The agreement provides
a plan for the management of groundwater resources on the ESPA with the goal of improving
2017 tRP Page 13
2. Political, Regulatory, and Operational lssues ldaho Power Company
aquifer levels and spring discharge upstream of Milner Dam. The plan provides short-term and
long-term aquifer level goals that must be met to ensure a sufficient water supply for the
Surface Water Coalition. The plan also references ongoing management activities, such as
aquifer recharge. The plan provided the framework for modeling future management activities
on the ESPA. These management activities were included in the modeling to develop the flow
file for assessing hydropower production through the IRP planning horizon.
On November 4,20l6,Idaho Department of Water Resources (IDWR) Director Gary Spackman
signed an order creating a Ground Water Management Area (GWMA) for the ESPA.
Spackman told the Idaho Water Users Association at theirNovember 2016 Water Law Seminar:
By designating a groundwater management area in the Eastern Snake Plain
Aquifer region, we bring all of the water users into the fold--cities, water districts
and others-who may be affecting aquifer levels through their consumptive use.
[...] As we've continued to collect and analyze water data through the years, we
don't see recovery happening in the ESPA. We're losing 200,000 acre-feet of
water per year.
Spackman said creating a GWMA will embrace the terms of a historic water sefflement between
the Surface Water Coalition and groundwater users, but the GWMA for the ESPA will also seek
to bring other water users under management who have not joined a groundwater district,
including some cities.
Renewable lntegration Costs
Idaho Power has completed two wind integration studies and two solar integration studies since
the mid-2000s. These studies increased the company's understanding of the impacts and costs
associated with integrating variable and intermittent resources without compromising reliability.
The variable and uncertain production from wind and solar resources requires Idatro Power to
provide additional balancing reserves from existing dispatchable generating resources,
which results in opportunity costs and corresponding increases in power-supply expenses.
Idaho Power completed the most recent wind integration study in20l3 and the most recent solar
integration study in20l6. The costs found by these studies are the basis for renewable
integration costs as provided in Idaho Schedule 87 and Oregon Schedule 85.
The results of the integration studies show periods of low customer demand to be the most
difficult to cost-effectively integrate intermittent resources. During low demand periods,
other existing resources are often already running at minimum levels or may already be shut off.
Under these conditions, curtailment of the variable resources may be necessary to keep
generation balanced with customer load. The integration studies also demonstrate the frequency
of curtailment events is expected to increase as additional variable resources are added to
the system.
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ldaho Power Company 2. Political, Regulatory, and Operational lssues
For the IRP, integration costs for existing wind and solar resources are common to all portfolios
analyzed and are not included in the portfolio cost accounting. However, portfolios with new
solar resources include costs consistent with schedules 87 (Idaho) and 85 (Oregon) for the new
resources. The schedule of integration costs is provided tnAppendix C-Technical Appendix.
Community Solar Pilot Program
In the 2009 IRP, Idaho Power proposed a solar PV pilot project. Due to a few extenuating
circumstances, as detailed in the 2015 IRP, the pilot project was not pursued. However,
customer interest in distributed solar generation continued to grow and was the subject of many
2015 IRP discussions.Late in the 2015 IRP public process, Idaho Power was approached by
several interested parties and asked to consider sponsoring a community solar project.
In response to customer interest, in June 2016Idaho Power filed an application with the IPUC
requesting an order authorizing Idaho Power to implement an optional Community Solar
Pilot Program.
For the pilot program, the company proposed to build and own a 5O0-kilowatt (kW) single-axis
tracking community solar array in southeast Boise that would allow a limited number of
Idaho Power's Idaho customers to voluntarily subscribe to the generation output on a first-come
basis. Participating customers would be required to pay a one-time, upfront subscription fee,
and in return would receive a monthly bill credit for their designated share of the energy
produced from the array. Because the company's 2015 IRP did not reflect a load-serving
need for the proposed solar resource, the overall program design was intended to result in
program participants covering the full cost of the project with nominal impact to
non-participating customers.
The IPUC approved the pilot progmm on October 31,2016, and marketing efforts for customer
subscription began immediately. At the time of publishing, the Community Solar Pilot Program
was not fully subscribed, with only 15.5 percent of the allotted subscriptions purchased.
The company is currently evaluating the future of the Community Solar Pilot Program.
Energy lmbalance Market
In November 2014, the Califomia Independent System Operator (CAISO) and PacifiCorp
created the westem EIM to enhance real-time coordination of market trading activity.
The western EIM is a five-minute market administered by a single market operator, CAISO,
which uses an automatic economic dispatch model to find and determine the least-cost energy
resources to serve real-time customer demand across a wide geographic area. The western EIM
focuses solely on real-time imbalances and allows EIM participants to retain all balancing
responsibilities and transmission provider duties. In addition, the western EIM uses generating
resources from market participants to meet real-time load efficiently and cost-effectively across
the entire westem EIM footprint.
2017lRP Page 15
2. Political, Regulatory, and Operational lssues ldaho Power Company
Idaho Power is scheduled to begin participating in the western EIM in April 2018, at which time
the westem EIM participants will include PacifiCorp, CAISO, NV Energy, Puget Sound Energy,
Arizona Public Service Company, and PGE. Market participants voluntarily bid resources into
the western EIM, and the market operator provides least-cost dispatch instructions and generates
a locational marginal price to be used for energy imbalances, factoring in load, available
generation, and existing transmission constraints. Benefits to joining the westem EIM include
the following:
The economic efficiency of an automated dispatch model for both generation and
transmission line congestion
Savings due to diversity of loads and variability of resources within the
expanded footprint
Reduced operational risk due to enhanced system reliability
The ability to better support the integration of renewable resources
Since its inception, the western EIM has resulted in significant cost savings for its participants.
Idaho Power expects its participation in the western EIM will similarly result in net
power-supply expense savings for customers.
Renewable Energy Certificates
RECs, also known as green tags, represent the green or renewable attributes of energy produced
by certified renewable resources. A REC represents the renewable attributes associated with the
production of 1 MWh of electricity generated by a qualified renewable energy resource, such as
a wind turbine, geothermal plant, or solar facility. The purchase of a REC buys the renewable
attributes, or'ogreenness," of that energy.
A renewable or green energy provider (e.g., a wind farm) is credited with one REC for every
1 MWh of electricity produced. RECs and the electricity produced by a certified renewable
resource can either be sold together (bundled), sold separately (unbundled), or be retired to
comply with a state- or federal-level renewable portfolio standard (RPS). A RPS is a policy
requiring a minimum amount (usually a percentage) of the electricity each utility delivers to
customers comes from renewable energy. Retired RECs also enable the retiring entity to claim
the renewable energy attributes of the corresponding amount of energy delivered to customers.
A certifring tracking system gives each REC a unique identification number to facilitate
tracking purchases, sales, and retirements. The electricity produced by the renewable resource is
fed into the electrical grid, and the associated REC can then be used (retired), held (banked),
or traded (sold).
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ldaho Power Company 2. Political, Regulatory, and Operational lssues
REC prices depend on many factors, including the following:
The location of the facility producing the RECs
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REC supply/demand
Whether the REC is certified for RPS compliance
The generation type (e.g., wind, solar, geothermal)
Whether the RECs are bundled with energy or unbundled
When Idaho Power sells RECs, the proceeds are returned to Idaho Power customers through the
power cost adjustment (PCA) as directed by the IPUC in Order No. 32002 and by the OPUC in
Order No. I l-086. Idaho Power cannot claim the renewable attributes associated with RECs that
are sold. The new REC owner has purchased the rights to claim the renewable attributes of
that energy.
Idaho Power customers who choose to purchase renewable energy can do so under
Idaho Power's Green Power Program. Under this program, each dollar of green power purchased
represents 100 kilowatt-hours (kwh) of renewable energy delivered to the regional power grid,
providing the Green Power Program participant associated claims for the renewable energy.
Most the participant funds are used to purchase green power from renewable projects in the
Northwest and to support Solar 4R Schools, a program designed to educate students about
renewable energy by placing solar installations on school property. A portion of the funds are
used to market the program, with the prospect of increasing participation in the program.
On behalf of program participants, Idaho Power obtains and retires RECs. In20l6,Idaho Power
purchased and subsequently retired 15,360 RECs on behalf of Green Power participants.
Green Power is sourced from renewable energy projects in Idaho, Oregon, and Washington.
Renewable Portfolio Standard
As part of the Oregon Renewable Energ,t Act of 2007 (Senate Bill 838), the State of Oregon
established an RPS for electric utilities and retail electricity suppliers. Under the Oregon RPS,
Idaho Power is classified as a smaller utility because the company's Oregon customers represent
less than 3 percent of Oregon's total retail electric sales. In 2015, per Energy Information
Administration (ElA) data, Idaho Power's Oregon customers represented 1.3 percent of
Oregon's total electric sales. As a smaller utility, Idaho Power will have to meet a 5- or
l0-percent RPS requirement beginningin2O25.ln20l6, the Oregon RPS was updated by
Senate Bill 1547 to raise the target from 25 percent by 2025 to 50 percent renewable energy by
2040; however, Idaho Power's obligation as a smaller utility does not change.
The State of Idaho does not currently have an RPS
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2017 tRP Page 17
2. Political, Regulatory, and Operational lssues ldaho Power Company
Clean Power Plan
Rule History
On June 2,2014, the Environmental Protection Agency (EPA), under President Obama's
Climate Action Plan, released a proposal to regulate COz emissions from existing power plants
under the CAA Section 1l l(d) (Clean Power Plan). EPA's proposed Clean Power Plan included
ambitious, mandatory COz reduction targets for each state designed to achieve nationwide
30-percent COz emission reductions over 2005 levels by 2030. On October 23,2015, the final
Clean Power Plan was published in the Federal Register, and the EPA proposed a Federal
Implementation Plan.
Due to ongoing litigation about the legality of the rule, on February 9,2016,the U.S. Supreme
Court issued orders staying the Clean Power Plan pending resolution of challenges to the rule.
The U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) heard oral
arguments en banc before a panel of l0 judges on Septemb er 27 , 2016.
On March 28,2017, President Donald Trump issued an Executive Order on Energy
Independence that, among other things, directs the EPA to review and, if appropriate, suspend,
revise, or rescind the Clean Power Plan. On March 31,2017, Scott Pruitt, the Director of the
EPA, notified each state's governor that if any deadlines under the Clean Power Plan become
relevant in the future, the EPA will toll its requirement for states to comply with the regulation.
On April 28,2017, the D.C. Circuit Court approved an EPA motion to hold the Clean Power
Plan case in abeyance for 60 days, or until June 27,2017. According to the EPA's motion,
"EPA should be afforded the opportunity to fully review the Clean Power Plan and respond to
the President's direction in a manner that is consistent with the terms of the Executive Order,
the Clean Air Act, and the agency's inherent authority to reconsider past decisions."T In the order
ganting the abeyance, the EPA was directed to file status reports every 30 days. The court also
ordered the parties to file supplemental briefs on or before May 15,2017, addressing whether the
challenge should be remanded to the EPA rather than held in abeyance.
Clean Power Plan Final Rule
The final Clean Power Plan establishes interim and final COz emission performance rates for two
subcategories of fossil fuel-fired electric generating units (EGU):
o Fossil fuel-fired EGUs (coal- and oil-fired power plants)
o Natural gas-fired combined cycle generating units
7 West Virginiav. EPA,No. 15-1363 (D.C. Cir. March 28,2017)
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ldaho Power Company 2. Political, Regulatory, and Operational lssues
To maximizethe range of choices available to states in implementing the standards and to
utilities meeting them, the EPA has established interim and final statewide goals in three forms:
l. A rate-based state goal measured in pounds per MWh
2. A mass-based state goal measured in total short tons of COz
3. A mass-based state goal with a new source complement measured in short tons of COz
States must develop and implement plans that ensure the power plants in their state-
individually, collectively, or in combination with other measures-achieve the interim COz
emission performance rates from2022 to 2029 and the final COz emission performance rates for
their state by 2030.
In the final Clean Power Plan, the EPA determined the best system of emissions reduction
(BSER) to reduce COz from fossil fueI-fired power plants consisted of three building blocks:
1. Building Block l-Improve effrciency in existing coal-fired power plants.
2. Building Block 2-Re-dispatch generation from existing coal-fired power plants to
natural gas combined-cycle plants.
3. Building Block 3-Increase generation from non-COz-emitting resources.
The EPA applied the building blocks to all coal and natural gas power plants in each region to
produce a regional emission performance rate for each category. From the resulting regional coal
and natural gas power plant rates, the EPA chose the most readily achievable rate for each
category to arrive at equitable COz emission performance rates that represent the BSER.
The same COz emission performance rates were then applied to all affected sources in each state
to arrive at individual statewide rate- and mass-based goals. Each state has a different goal based
on its own mix of affected sources.
The final rule also gives states the option to work with other states on multi-state approaches,
including emissions trading.
While specific actions based on the EPA's review of the Clean Power Plan are forthcoming,
each resource portfolio in the 2017 IRP is compliant with the final Clean Power Plan mass-based
emission limits. Due to the executive order and the Pruitt letter, Idaho Power anticipates more
stringent compliance measures will not be required under the Clean Power PIan.
Further discussion of these COz emission constraints is provided in Chapter 9. Projected COz
emissions for each analyzedresource portfolio are providedinAppendix C-Technical Appendix.
2017 tRP Page 19
2. Political, Regulatory, and Operational lssues ldaho Power Company
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ldaho Power Company 3. ldaho Power Today
3. loano Powen Tooav
Customer Load and Growth
ln l992,Idaho Power served
approximately 3 06,000 general business
customers. Today, Idaho Power serves
nearly 534,000 general business customers
in Idaho and Oregon. Firm peak-hour load
has increased from 2,164 MW in l992to
over 3,400 MW. On Ju,ly 2,2013,
the peak-hour load reached 3,407 MW-
the system peak-hour record, nearly
matched in 2015 (3,402 MW).
,$
:t
Average firm load increased from Construction in downtown Boise.
1,280 average MW (aMW) nl992to
1,750 aMW in2016 (load calculations exclude the load from the former special-contract
customer Astaris, or FMC). Additional details of Idaho Power's historical load and customer
data are shown in Figure 3.1 and Table 3.1. The data in Table 3.1 suggests each new customer
adds over 5.5 kW to the peak-hour load and over 2 average kW (akw) to the average load.
Since lgg2,Idaho Poweros total nameplate generation has increased from2,694 MW to
3,594 MW. The 900-MW increase in capacity represents enough generation to serve nearly
161,000 customers at peak times. Table 3.1 shows Idaho Power's changes in reported nameplate
capacity since 1992.
Idaho Power has added about 228,000 new customers since 1992.The peak-hour and
average-energy calculations mentioned earlier suggest the additional228,000 customers
require about 1,250 to 1,300 MW of additional peak-hour capacity and about 450 to 500 aMW
ofenergy.
Idaho Power anticipates adding approximately 11,100 customers each year throughout the
2}-year planning period. The expected-case load forecast for the entire system predicts surrmer
peak-hour load requirements will grow over 50 MW per year, and the average-energy
requirement is forecast to grow over 15 aMW per year. More detailed customer and load forecast
information is presented in Chapter 7 andinAppendtx A-Sales ond Load Forecast.
2017 tRP Page21
3. ldaho Power Today ldaho Power Company
6,000
5,m0
4,m0
3,000
2,m0
1,000
01W2 1994 1996 1998 2m0 2@2 2@4 2m6 2008 2010 2012 2014 2016
-Total
Namephte Generatbn (MWf
-Peak
Firm Led (M\A/)
-{vs146
Firm Load (aMV$
Figure 3.1 Historical capacity, load, and customer data
Table 3.1 Historica! capacity, load, and customer data
Year Total Nameplate Generation (MW) Peak Firm Load (MW) Average Firm Load (aMYV) Customeer
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
200/.
2005
2006
2007
2008
2009
20'to
2011
2012
20'13
2014
2015
2016
2,694
2,644
2,661
2,703
2,703
2,728
2,738
2,738
2,738
2,851
2,912
2,912
2,912
3,085
3,085
3,093
3,276
3,276
3,276
3,276
3,594
3,594
3,594
3,594
3,594
2,1U
1,935
2,245
2,224
2,437
2,352
2,535
2,675
2,765
2,500
2,963
2,944
2,843
2,961
3,084
3,193
3,214
3,031
2,930
2,973
3,245
3,407
3,184
3,402
3,299
't,281
1,274
1,375
1,324
1,438
1,457
1,491
1,552
1,654
1,576
1,623
1,658
1,671
1,661
1,747
1,810
1,816
1,74
1,680
1,712
1,746
1,801
1,739
1,748
1,750
306,292
316,504
329,094
339,450
351,261
361,838
372,4U
383,354
393,095
403,061
414,062
425,599
438,912
456,1M
470,950
480,523
486,048
488,813
491,368
495,122
500,731
508,051
5',15,262
524,325
534,528
I Year-end residential, commercial, and industrial customers plus the maximum number of active inigation customers.
Page22 2017 tRP
ldaho Power Company 3. ldaho Power Today
2016 Energy Sources
Idalro Power's energy sources for 2016 are shown in Figure 3.2. Idaho Power-owned generating
capacity was the source for 73 percent of the energy delivered to customers. Hydroelectric
production from company-owned projects was the largest single source of energy at 39 percent
of the total. Coal contributed 24 percent, and natural gas- and diesel-fired generation contributed
l0 percent. Purchased power comprised 27 percent of the total energy delivered to customers.
Of the purchased power, about a third, or 9 percent of the total delivered energy, was from the
wholesale electric market. The remaining purchased power was from long-term energy contracts
(Public Utility Regulatory Policies Act of 1978 [PURPA] and power purchase agreements
[PPA]) primarily from wind, hydro, geothermal, biomass, and solar projects (in order of
decreasing percentage). While Idaho Power enables production from PURPA and PPA projects,
the company sells RECs associated with the production and does not represent the energy from
these projects as energy delivered to customers.
Figure 3.2 2016 energy sources
Existing Supply-Side Resources
To identiff the need and timing of future resources, Idaho Power prepares a load and resource
balance that accounts for forecast load growth and generation from the company's existing
resources and planned purchases. The load and resource balance worksheets showing
Idaho Power's existing and committed resources for average-energy and peak-hour load are
presented inAppendix C-Technical Appendix. Table 3.2 shows all of Idaho Power's existing
company-owned resources, nameplate capacities, and general locations.
Hydroelectric
39%
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3. ldaho Power Today ldaho Power Company
Table 3.2 Existing resources
Resource Type
Generator Nameplate
Capacity (MW)Location
American Falls
Bliss
Brownlee
C. J. Strike
Cascade
Clear Lake
Hells Canyon
Lower Malad
Lower Salmon
Milner
Oxbow
Shoshone Falls
Swan Falls
Thousand Springs
Twin Falls
Upper Malad
Upper Salmon A
Upper Salmon B
Boardman
Jim Bridger
North Valmy
Langley Gulch
Bennett Mountain
Danskin
Salmon Diesel
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Hydroelectric
Coal
Coal
Coal
Natural Gas-CCCT*
Natural Gas-SCCT*
Natural Gas-SCCT*
Diesel
Upper Snake
Mid-Snake
Hells Canyon
Mid-Snake
North Fork Payette
South Centralldaho
Hells Canyon
South Centralldaho
Mid-Snake
Upper Snake
Hells Canyon
Upper Snake
Mid-Snake
South Centralldaho
Mid-Snake
South Centralldaho
Mid-Snake
Mid-Snake
North Central Oregon
Southwest Wyoming
North Central Nevada
Southwest ldaho
Southwest ldaho
Southwest ldaho
Eastem ldaho
92.3
75.0
585.4
82.8
12.4
2.5
391.5
13.5
60.0
59.4
190.0
12.5
27.2
8.8
52.9
8.3
18.0
16.5
64.2
770.5
283.5
318.5
172.8
270.9
5.0
Total existing nameplate capacity 3,594.4
*Combined-cycle combustion turbine
**Simple-cycle combustion turbine
The following sections describe Idaho Power's existing supply-side generation resources and
long-term power purchase contracts.
Hyd roel ectri c F ac i I iti es
Idaho Power operates l7 hydroelectric projects on the Snake River and its tributaries.
Together, these hydroelectric facilities provide a total nzrmeplate capaclty of 1,709 MW and an
annual generation equal to approximately 960 aMW, or 8.4 million MWh under median
water conditions.
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ldaho Power Company 3. ldaho Power Today
Hells Ganyon Gomplex
The backbone of Idaho Power's hydroelectric system is the HCC in the Hells Canyon reach of
the Snake River. The HCC consists of Brownlee, Oxbow, and Hells Canyon dams and the
associated generation facilities. [n a normal water year, the three plants provide approximately
70 percent of Idaho Power's annual hydroelectric generation and enough energy to meet over
30 percent of the energy demand of retail customers. Water storage in Brownlee Reservoir also
enables the HCC projects to provide the major portion of Idaho Power's peaking and
load-following capability.
Idaho Power operates the HCC to comply with the existing annual FERC license, as well as
voluntary arrangements to accommodate other interests, such as recreational use and
environmental resources. Among the arrangements are the Fall Chinook Program, voluntarily
adopted by Idaho Power in 1991 to protect the spawning and incubation of fall Chinook salmon
below Hells Canyon Dam. The fall Chinook salmon is currently listed as threatened under
the ESA.
Brownlee Reservoir is the main HCC reservoir and Idaho Power's only reservoir with significant
active storage. Brownlee Reservoir has l0l vertical feet of active storage capacity, which equals
approximately I million acre-feet of water. Both Oxbow and Hells Canyon reservoirs have
significantly smaller active storage capacities-approximately 0.5 percent and I percent of
Brownlee Reservoir' s volume, respectively.
Brownlee Reservoir is a year-round, multiple-use resource for Idaho Power and the Pacific
Northwest. Although its primary purpose is to provide a stable power source, Brownlee
Reservoir is also used for system flood control, recreation, and the benefit of fish and wildlife
resources.
Brownlee Dam is one of several Pacific Northwest dams coordinated to provide springtime flood
control on the lower Columbia River. Idaho Power operates the reservoir in accordance with
flood-control directions received from the US Army Corps of Engineers (COE) as outlined in
Article 42 of the existing FERC license.
After flood-control requirements have been met in late spring, Idaho Power attempts to refill the
reservoir to meet peak summer electricity demands and provide suitable habitat for spawning
bass and crappie. The full reservoir also offers optimal recreational opportunities through the
Fourth of July holiday.
The US Bureau of Reclamation (USBR) releases water from USBR storage reservoirs in the
Snake River Basin above Brownlee Reservoir to augment flows in the lower Snake River to help
anadromous fish migrate past the Federal Columbia River Power System (FCRPS) projects.
The releases are part of the flow augmentation implemented by the 2008 FCRPS biological
opinion. Much of the flow augmentation water travels through Idaho Power's middle
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3. ldaho Power Today ldaho Power Company
Snake River (mid-Snake) projects, with all the flow augmentation eventually passing through the
HCC before reaching the FCRPS projects.
Brownlee Reservoir's releases are managed to maintain constant flows below Hells Canyon Dam
in the fall as a result of the Fall Chinook Program adopted by Idaho Power in 1991. The constant
flow is set at a level to protect fall Chinook spawning nests, or redds. During fall Chinook
operations, Idaho Power attempts to refill Brownlee Reservoir by the first week of December to
meet wintertime peak-hour loads. The fall Chinook plan spawning flows establish the minimum
flow below Hells Canyon Dam throughout the winter until the fall Chinook fry emerge in
the spring.
Upper Snake and Mid-Snake Projects
Idaho Power's hydroelectric facilities upstream from the HCC include the Cascade, Swan Falls,
C. J. Strike, Bliss, Lower Salmon, Upper Salmon, Upper and Lower Malad, Thousand Springs,
Clear Lake, Shoshone Falls, Twin Falls, Milner, and American Falls projects. Although the
upstream projects typically follow run-of-river (ROR) operations, a small amount of peaking and
load-following capability exists at the Lower Salmon, Bliss, and C. J. Strike projects. These three
projects are operated within the FERC license requirements to coincide with daily system peak
demand when load-following capacity is available.
Idaho Power completed a study to identify the effects of load-following operations at the
Lower Salmon and Bliss power plants on the Bliss Rapids snail, a threatened species under the
ESA. The study was part of a2004 settlement agreement with the US Fish and Wildlife Service
(FWS) to relicense the Upper Salmon, Lower Salmon, Bliss, and C. J. Strike hydroelectric
projects. During the study, Idaho Power annually alternated operating the Bliss and Lower
Salmon facilities under ROR and load-following operations. Study results indicated that while
load-following operations had the potential to harm individual snails, the operations were not a
threat to the viability or long-term persistence of the species.
A Bliss Rapids Snail Protection Plan developed in consultation with the FWS was completed in
March 2010. The plan identifies appropriate protection measures to be implemented by
Idaho Power, including monitoring snail populations in the Snake River and associated springs.
By implementing the protection and monitoring measures, the company has been able to operate
the Lower Salmon and Bliss projects in load-following mode while protecting the stability and
viability of the Bliss Rapids snail. Idaho Power has received a license amendment from FERC
for both projects that allows load-following operations to resume.
Water Lease Agreements
Idaho Power views the rental of water for delivery through its hydroelectric system as a
potentially cost-effective power-supply alternative. Water leases that allow the company to
request delivery when the hydroelectric production is needed are especially beneficial.
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ldaho Power Company 3. Idaho Power Today
Acquiring water through the water bank also helps the company improve water-quality and
temperature conditions in the Snake River as part of ongoing relicensing efforts associated with
the HCC. The company does not currently have any water lease agreements but plans to continue
to evaluate potential water-lease opportunities in the future.
Cloud Seeding
In 2003, Idaho Power implemented a cloud-seeding program to increase snowpack in the south
and middle forks of the Payette River watershed. In 2008, Idaho Power began expanding its
program by enhancing an existing program operated by a coalition of counties and other
stakeholders in the upper Snake River Basin above Milner Dam. Idaho Power has continued to
work with the stakeholders in the upper Snake River to expand the program and has recently
collaborated with irrigators in the Boise and Wood river basins to expand the target area to
include those watersheds.
Idaho Power seeds clouds by introducing silver iodide (AgI) into winter storms. Cloud seeding
increases precipitation from passing winter storm systems. If a storm has abundant supercooled
liquid water vapor and appropriate temperatures and winds, conditions are optimal for cloud
seeding to increase precipitation. Idaho Power uses two methods to seed clouds:
1. Remotely operated ground generators at high elevations
2. Modified aircraft burning flares containing AgI
Benefits of either method vary by storm, and the combination of both methods provides the most
flexibility to successfully introduce AgI into passing storms. Minute water particles within the
clouds freeze on contact with the AgI particles and eventually grow and fall to the ground
as snow.
AgI is a very efficient ice nuclei, allowing it to be used in minute quantities. It has been used as a
seeding agent in numerous western states for decades without any known harmful effects.s
Analyses conducted by Idaho Power since 2003 indicate the annual snowpack in the Payette
River Basin increased between I and 28 percent annually, with an annual average of 14 percent.
Idaho Power estimates cloud seeding provides an additional 346,000 acre-feet from the upper
Snake River and272,000 acre-feet from the Payette River. At program build-out, Idaho Power
estimates additional runofffrom the Payette, Boise, Wood, and Upper Snake projects will total
approximately 1,000,000 acre-feet. Studies conducted by the Desert Research Institute from
2003 to 2005 support the ef;[ectiveness of Idaho Power's progfttm.
8 weathermodification.org/images/AGl toxicity.pdf
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3. ldaho Power Today ldaho Power Company
For the 2016 to 201 7 winter season, Idaho Power continued to collaborate with the State of Idaho
and water users to augment water supplies with cloud seeding. The program included
30 remote-controlled, ground-based generators and two aircraft for Idaho Power-operated cloud
seeding in the west-central mountains of Idatro (Payette, Boise, and Wood River basins).
The Upper Snake River Basin program included 25 remote-controlled, ground-based generators
and one aircraft operated by Idaho Power targeting the Upper Snake, as well as 25 manual,
ground-based generators operated by a coalition of stakeholders in the Upper Snake. The 2016 to
2017 season provided abundant storms and seeding opportunities. Suspension criteria were met
in some areas in early February, and operations were suspended for the season for all target areas
by early March.
Coal Facilities
Jim Bridger
Idatro Power owns one-third, or 771 MW (generator nameplate rating), of the Jim Bridger
coal-fired power plant located near Rock Springs, Wyoming. The Jim Bridger plant consists of
four generating units. PacifiCorp has two-thirds ownership and is the operator of the
Jim Bridger facility.
The2017 IRP considers a range of scenarios for Jim Bridger units I and2. The scenarios relate
to varying options for capital investnents into environmental retrofits. The scenarios are
described in Chapter 7.
North Valmy
Idaho Power owns 50 percent, or 284 MW (generator nameplate rating), of the North Valmy
coal-fired power plant located near Winnemucca, Nevada. The North Valmy plant consists of
two generating units. NV Energy has 50 percent ownership and is the operator of the
North Valmy facility.
A baseline assumption of the 2017 IRP has Idaho Power retiring its share ofNorth Valmy Unit I
at year-end 2019 and its share of North Valmy Urut2 at year-end 2025. Further discussion
surrounding this assumption is provided in Chapter 7.
Boardman
Idatro Power owns l0 percent, or 64.2 MW (generator nameplate rating), of the Boardman
coal-fired power plant located near Boardman, Oregon. The plant consists of a single generating
unit. PGE has 90 percent ownership and is the operator of the Boardman facility.
The2017 IRP assumes Idaho Power's share of the Boardman plant will not be available after
December 31,2020.The2020 date is the result of an agreement reached between the Oregon
Department of Environmental Quality (ODEQ), PGE, and the EPA related to compliance with
Page 28 2017 tRP
ldaho Power Company 3. ldaho Power Today
Regional Haze Best Available Retrofit Technology (RH BART) rules on particulate matter,
sulfur dioxide (SOz), and nitrogen oxide (NOx) emissions.
Natural Gas Facilities
Langley Gulch
Idatro Power owns and operates the
Langley Gulch plant, a nominal 318-MW
natural gas-fired CCCT. The plant consists
of one 187-MW Siemens STG-5000F4
combustion turbine and one 131.5-MW
Siemens SST-700/SST-900 reheat steam
turbine. The Langley Gulch plant, located
south of New Plymouth in Payette Cotrnty,
Idaho, became commercially available in
June 2012.Langley Gulch Power Plant
Danskin
Idatro Power owns and operates the 271-MW Danskin natural gas-fired SCCT facility.
The facility consists of one 179-MW Siemens 501F and two 46-MW Siemens-Westinghouse
W25lBl2A combustion turbines. The Danskin facility is located northwest of Mountain Home,
Idatro. The two smaller turbines were installed in 2001, and the larger turbine was installed in
2008. The Danskin units are dispatched when needed to support system load.
Bennett Mountain
Idaho Power owns and operates the Bennett Mountain plant, which consists of a 173-MW
Siemens-Westinghouse 50lF natural gas-fired SCCT located east of the Danskin plant in
Mountain Home, Idaho. The Bennett Mountain plant is also dispatched as needed to support
system load.
Salmon Diesel
Idaho Power owns and operates two diesel generation units in Salmon, Idaho. The Sahnon units
have a combined generator nameplate rating of 5 MW and are operated during emergency
conditions, primarily for voltage and load support.
Solar Facilities
lnl994, a 25-kW solar PV array with 90 panels was installed on the rooftop of Idaho Power's
corporate headquarters (CHQ) in Boise, Idaho. The 25-kW solar array is still operational,
and Idaho Power uses the hourly generation data from the solar array for resource planning.
2017 tRP Page 29
3. ldaho Power Today ldaho Power Company
In 2015, Idaho Power installed a 50-kW solar array at its new Twin Falls Operations Center
The array came on-line in October 2016.
Idaho Power also has solar lights in its parking lot and uses small PV panels in its daily
operations to supply power to equipment used for monitoring water quality, measuring
streamflows, and operating cloud-seeding equipment. In addition to these solar PV installations,
Idaho Power participates in the Solar 4R Schools Program and owns a mobile solar trailer that
can be used to supply power for concerts, radio remotes, and other events.
Net Metering Service
Idaho Power's net metering service allows customers to generate power on their property and
connect to Idaho Power's system. For net metering customers, the energy generated is first
consumed on the property itself while excess energy flows out to the company's gnd.
The majority of net metering customers use solar PV systems. As of March 1,2017, there were
1,045 solar PV systems were interconnected through the company's net metering service with a
total capacity of 8.079 MW. At that time, the company had received completed applications
for an additional 110 net metered solar PV systems, representing an incremental capacity of
1.376 MW. For further details regarding customer-owned generation resources interconnected
through the company's net metering service, see Table 3.3 and Table 3.4.
Table 3.3 Net metering service customer count as of March 1,2017
Resource Type Active Pending Total
Solar PV
Wind
Other/hydroelectric
1,045
62
10
110
2
1
1,155
64
11
Total 1,117 113 1,230
Table 3.4 Net metering service generation capacity (MW) as of March 1,2017
Resource Type Active Pending Total
Solar PV
V/ind
Other/hydroelectric
8.079
0.378
o.'147
1.3760
0.0016
0.0120
9.455
0.380
0.159
Total 8.604 1.3900 9.994
Oregon Solar PV Pilot Program and Oregon Solar PV Capacity Standard
In 2009, the Oregon Legislature passed Oregon Revised Statute (ORS) 757.365 as amended by
House Bill 3690, which mandated the development of pilot programs for electric utilities
operating in Oregon to demonstrate the use and effectiveness of volumetric incentive rates for
electricity produced by solar PV systems.
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ldaho Power Company 3. ldaho Power Today
As required by the OPUC in Order Nos. 10-200 and 11-089, Idaho Power established the
Oregon Solar Photovoltaic Pilot Program in 2010, offering volumetric incentive rates to
customers in Oregon. Under the pilot program, Idaho Power acquired 400 kW of installed
capacrty from solar PV systems with a nameplate capacity of less than or equal to l0 kW.
In July 2010, approximately 200 kW were allocated, and the remaining 200 kW were offered
during an enrollment period in October 2011. However, because some PV systems were not
completed from the 2011 enrollment, a subsequent offering was held on April 1,2013,
for approximately 80 kW.
In 2013, the Oregon Legislature passed House Bill2893, which increased Idaho Power's
required capacity amount by 55 kW. An enrollment period was held in April 2014, and all
capacity was allocated, bringing Idaho Power's total capacity in the program to 455 kW.
Under the previously required Oregon Solar PV Capacity Standard, Idaho Power was required to
either own or purchase the generation from a 500-kW utility-scale solar PV facility by 2020.
This requirement was repealed, effective March 8,2016, pursuant to Oregon Senate Bill 1547.
PURPA
In 1978, the US congress passed PURPA, requiring investor-owned electric utilities to purchase
energy from any qualiffing facility (QF) that delivers energy to the utility. A QF is defined by
FERC as a small renewable-generation project or small cogeneration project. The acronym CSPP
(cogeneration and small power producers) is often used in association with PURPA. Individual
states were tasked with establishing PPA terms and conditions, including price, that each state's
utilities are required to pay as part of the PURPA agreements. Because Idaho Power operates in
Idaho and Oregon, the company must adhere to IPUC rules and regulations for all PURPA
facilities located in Idaho, and to OPUC rules and regulations for all PURPA facilities located in
Oregon. The rules and regulations are similar but not identical for the two states.
Under PURPA, Idaho Power is required to pay for generation at the utility's avoided cost,
which is defined by FERC as the incremental cost to an electric utility of electric energy or
capacity which, but for the purchase from the QF, such utility would generate itself or purchase
from another source. The process to request an Energy Sales Agreement for Idaho QFs is
described in Schedule 73, and for Oregon QFs, Schedule 85. QFs also have the option to sell
energy "as-available" under Schedule 86.
As of April l,z|l7,Idaho Power had 133 PURPA contracts with independent developers for
approximately 1,135 MW of nameplate capacity. These PURPA contracts are for hydroelectric
projects, cogeneration projects, wind projects, solar projects, anaerobic digesters, landfill gas,
wood-burning facilities, and various other small, renewable-power generation facilities. Of the
133 contracts, 128 were on-line as of April1,2017, with a cumulative nameplate rating of
approximately l,l 15 MW. Figure 3.3 shows the percentage of the total PURPA nameplate
capacity ofeach resource type under contract.
2017 rRP Page 31
3. ldaho Power Today ldaho Power Company
Biomass, 3olo
C,qen,2o/o
Figure 3.3 PURPA contracts by resoulce type
Idaho Power cannot predict the level of future PURPA development; therefore, only signed
contacts are accounted for in Idaho Power's resource planning process. Generation from
PUPJA contracts is forecasted early in the IRP planning process to update the load and resource
balance. The PURPA forecast used in the20lT IRP was completed in December2016.
Power Purchase Agreements
Elkhorn Valley Wind Proiect
In February 2007, the IPUC approved a
PPA with Telocaset Wind Power Parbrers,
LLC a subsidiary of Horizon Wind
Energy, for 101 MW of nameplate wind
generation from the Elkhom Valley Wind
Project located in northeastem Oregon.
The Elkhorn Valley Wind Project was
constructed during 2007 andbegan
commercial operations in December 2007.
Under the PPA, Idaho Power receives all
the RECs from the project.
Elkhom Valley Wind Project, Union County, Oregon
Raft River Geothermal Project
In January 2008, the IPUC approved a PPA for 13 MW of nameplate generation from the
Raft River Geothermal Power Plant (Unit l) located in southem Idaho. The Raft River project
began commercial operations in October 2007 under a PURPA contract with Idaho Power that
was canceled when the new PPA was approved by the IPUC. For the first 10 years Q00V2017)
Page 32 2017 tRP
ldaho Power Company 3. ldaho Power Today
of the agreement, Idaho Power is entitled to 75 percent of the RECs from the project for
generation that exceeds l0 aMW monthly. The Raft River geothermal project has rarely
exceeded the monthly 10 aMW of generation since 2009, and Idaho Power is currently receiving
negligible RECs from the project. For the second 10 years of the agreement (2018-2027),
Idaho Power is entitled to 5l percent of all RECs generated by the project.
Neal Hot Springs Geothermal Project
In May 2010, the IPUC approved a PPA for approximately 22MW of nameplate generation
from the Neal Hot Springs Geothermal Project located in eastern Oregon. The Neal Hot Springs
project achieved commercial operation in November 2012. Under the PPA, Idaho Power receives
all RECs from the project.
Clatskanie Energy Exchange
In September 2009,Idaho Power and the Clatskanie People's Utility District (Clatskanie PUD)
in Oregon entered into an energy exchange agreement. Under the agteement, Idaho Power
receives the energy as it is generated from the 18-MW power plant at Arrowrock Dam on the
Boise River; in exchange, Idatro Power provides the Clatskanie PUD energy of an equivalent
value delivered seasonally, primarily during months when Idaho Power expects to have surplus
energy. An energy bank account is maintained to ensure a balanced exchange between the parties
where the energy value will be determined using the Mid-Columbia market price index.
The Arrowrock project began generating in January 2010, with the initial exchange agreement
with Idaho Power ending in 2015. At the end of the initial term, Idaho Power exercised its right
to extend the agreement through 2020.Idaho Power holds one more option to extend through
2025, exercisable n2020. The Arrowrock project is expected to produce approximately
81,000 MWh annually.
Wholesale Contracts
Idaho Power currently has no long-term wholesale energy contracts (no long-term wholesale
sales contracts and no long-term wholesale purchase contracts).
Power Market Purchases and Sales
Idaho Power relies on regional power markets to supply a significant portion of energy and
capacity needs during certain times of the year. Idaho Power is especially dependent on the
regional power market purchases during peak-load periods. The existing transmission system is
used to import the power purchases. A reliance on regional power markets has benefited
Idaho Power customers during times of low prices through the import of low-cost energy.
Customers also benefit from sales revenues associated with surplus energy from economically
dispatched resources.
2017 tRP Page 33
3. ldaho Power Today ldaho Power Company
Transmission MW Import Rights
Idaho Power's interconnected transmission system facilitates market purchases to access
resources to serve load. Five transmission paths connect Idaho Power to neighboring utilities:
l. Idaho-Northwest @ath 14)
2. Idaho-Nevada (Path 16)
3. Idaho-Montana (Path 18)
Idaho-Wyoming (Path I 9)
Idaho-Utah (Path 20).
However, Idaho Power does not own exclusive rights to all the transmission capacity available
on each path. Idaho Power is either a partial owner of a path shared with other partners, or other
entities have acquired long-term purchased capacity for a portion of a path. Idaho Power is
allowed to set aside portions of its transmission capacity to import energy for load service.
Beyond the existing set-aside capacity and contractual obligations, Idaho Power's import
capacity on these paths is fully allocated, except for 86 MW of available capacity on Path 19.
4
5
Page 34 2017 rRP
ldaho Power Company 4. Future Supply-Side Generation and Storage Resources
4. Furune Supplv-SrDE GeruenATroN AND
SronecE RESoURcES
Generation Resources
Supply-side resources are traditional generation resources. Early IRP utility commission orders
directed Idaho Power and other utilities to give equal treatment to both supply-side and
demand-side resources. As discussed in Chapter 5, demand-side programs are an essential
component of Idaho Power's resource strategy. The following sections describe the supply-side
resources and storage technologies considered when Idaho Power developed the resource
portfolios for the 2017 IRP. While a variety of resource options was analyzed, the portfolio
design for the IRP allowed the selection of a subset for inclusion in resource portfolios.
The primary source of cost information for the 2017 IRP is Lazard's Levelized Cost of Energt
Analysis.e Lazard, a leading independent financial advisory and asset management firm,
issued the levelized cost report in December 2016. Other information sources were relied on or
considered on a case-by-case basis depending on the credibility of the source and the age of the
information. Refer to Chapter 7 for a full list of all the resources considered and cost
information. All cost information presented is in 2017 dollars.
Renewable Resources
Renewable energy resources are the foundation of Idaho Power, and the company has a long
history of renewable resource development and operation. Renewable resources are discussed in
general terms in the following sections.
Solar
The primary types of solar technology are utility-scale PV and distributed PV. In general,
PV technology converts solar energy collected from sunlight shining on panels of solar cells into
electricity. The solar cells have one or more electric fields that force electrons to flow in one
direction as a direct current (DC). The DC energy passes through an inverter, converting it to
altemating current (AC) that can be used on-site or sent to the grid. Even on cloudy days, a solar
PV system can still provide l5 percent of the system's rated output.
Insolation is a measure of solar radiation reaching the earth's surface and is used to evaluate the
solar potential of an area. Typically, insolation is measured in kWh per square meter (m2)
e Lazard.20l6.Lazard's levelized cost of energy analysis 10.0 (LCOE 10.0).
https://www.lazard.com/media/43803 8ilevelized-cost-of-energy-v l00.pdf.
2017lRP Page 35
4. Future Supply-Side Generation and Storage Resources ldaho Power Company
per day (daily insolation average over a year). The higher the insolation number, the better the
solar power potential for an area. National Renewable Energy Laboratory (NREL) insolation
charts show the southwest desert has the highest solar potential in the US.
In designing resource portfolios that included solar resources, Idaho Power chose the utility-scale
PV technology because of its compliance to EPA's proposed CAA Section I I l(d) regulation,
its flexibility, and its lower overall cost. Modern solar PV technology has existed for several
years but has historically been cost prohibitive. Recent improvements in technology and
manufacturing, combined with increased demand due to state RPSs, have made PV resources
more cost competitive with other renewable and conventional generating technologies.
The capital-cost estimate used in the 2017 IRP for utility-scale PV resources is based on the
Lazard report, which estimates a cost of $1,375 per kW for PV with a single-axis tracking
system. The 25-year levelized cost of energy for PV with single-axis tracking is $74 per MWh
with a 27-percent annual capacity factor.
Rooftop solar was considered in two forms as part of the 2017 IRP. The capital-cost estimate
used in the2017 IRP for residential rooftop solar PV resources is based on the Lazardreport,
which estimates a cost of $2,400 per kW for PV on residential rooftops. The 25-year levelized
cost of energy for residential rooftop solar PV resources is $153 per MWh with a 2l-percent
annual capacity factor. The capital-cost estimate used for commercial and industrial rooftop solar
PV resources is based on the Lazard report, which estimates a cost of $2,925 per kW for PV on
commercial and industrial rooftops. The 25-year levelized cost of energy for commercial and
industrial rooftop solar PV resources is $179 per MWh with a 2l-percent annual capacity factor.
The cost ofrooftop solar PV resources is recognized to vary by region, and the Lazard-reported
costs are not indicative of solar PV costs in Idaho Power's service area.l0 Rooftop solar PV cost
estimates vary by source, and based on Idaho Power's review of sources, the Lazard-reported
costs are toward the lower end of the cost range. For example, the Department of Energy (DOE)
Tracking the Sun study indicates rooftop solar pricing of approximately $4,000 per kW for
residential installations and $3,000 per kW for non-residential installations.ll
Energy production from solar PV arrays declines over time. This is known as PV degradation.
For the 2017 IRP, Idaho Power assumes a 0.5 percent annual degradation rate of energy
production from solar PV arrays.
r0 The Open PV Project, NREL, https://openpv.nrel.gov/.
rr DOE. August 2016. Tracking the sun IX, the installed price of residential and non-residential photovoltaic
systems in the United States. https://emp.lbl.gov/sites/defaultlfiesltracking_the_sun_ix_report.pdf.
Page 36 2017lRP
ldaho Power Company 4. Future Supply-Side Generation and Storage Resources
Solar Capacity Credit
Idaho Power applied the solar capacity credit calculations derived from the 2015 IRP. As part of
the 2015 IRP process, Idaho Power, interested members of the IRPAC, and interested members
of the public formed a study goup separate from the IRPAC to evaluate solar peak-hour capacity
factors. The group formally met and conducted meetings and conversations with members of the
study group. Idaho Power updated the solar PV peak-hour capacity factors based on guidance
from members of the solar work group.
The solar capacity credit is expressed as a percentage of installed AC nameplate capacity.
The solar capacity credit is used to determine the amount of peak-hour capacity delivered to the
Idaho Power system from a solar PV plant considered as a new IRP resource option. The solar
capacity credit values used in the20lT IRP are reported in Table 4.1.
Table 4.1 Solar capacity credit values
PV System Description Peak-Hour Capacity Credit
South orientation
Southwest orientation
Tracking
28.4o/o
45.5o/o
513%
Geothermal
Potential for commercial geothermal generation in the Pacific Northwest includes both
flashed-steam and binary-cycle technologies. Based on exploration in southem Idaho,
binary-cycle geothermal development is more likely than flashed steam within Idaho Power's
service area. The flashed-steam technology requires higher water temperatures. Most optimal
locations for potential geothermal development are believed to be in the southeastem part of the
state; however, the potential for geothermal generation in southem Idaho remains somewhat
uncertain. The time required to discover and prove geothermal resource sites is highly variable
and can take years or even decades.
The overall cost of a geothermal resource varies with resource temperature, development size,
and water availability. Flashed-steam plants are applicable for geothennal resources where the
fluid temperature is 300o Fahrenheit (F) or gteater. Binary-cycle technology is used for
lower-temperafure geothermal resources. In a binary-cycle geothermal plant, geothermal water is
pumped to the surface and passed through a heat exchanger where the geothermal energy is
transferred to a low-boiling-point fluid (the secondary fluid). The secondary fluid is vaporized
and used to drive a turbine/generator. After driving the generator, the secondary fluid is
condensed and recycled through a heat exchanger. The secondary fluid is in a closed system and
is reused continuously in a binary cycle plant. The primary fluid (the geothermal water)
is returned to the geothermal reservoir through injection wells.
2017 tRP Page 37
4. Future Supply-Side Generation and Storage Resources ldaho Power Company
Cost estimates and operating parameters used for binary-cycle geothermal generation in the 2017
IRP are based on data from the Northwest Power and Conservation Council (NWPCC)
Seventh Power Plan. The capital-cost estimate used in the20lT IRP for geothermal resources
is $4,675 per kW, and the 25-year levelized cost of energy is $l I I per MWh based on an
88-percent annual capacity factor.
Hydroelectric
Hydroelectric power is the foundation of Idaho Power's generation fleet. The existing
generation is low cost and does not emit potentially harmful pollutants. Idaho Power believes the
development of new, large hydroelectric projects is unlikely because few appropriate sites exist
and because of environmental and permitting issues associated with new, large facilities.
However, small hydroelectric sites have been extensively developed in southem Idaho on
irrigation canals and other sites, many of which have PURPA contracts with Idaho Power.
Small Hydroelectric
Small hydroelectric projects, such as ROR and projects requiring small or no impoundments,
do not have the same level of environmental and permitting issues as large hydroelectric
projects. The potential for new, small hydroelectric projects was studied by the Idaho Strategic
Energy Alliance's Hydropower Task Force, and the results released in May 2009 indicate
between 150 MW to 800 MW of new hydroelectric resources could be developed in Idaho.
These figures are based on potential upgrades to existing facilities, undeveloped existing
impoundments and water delivery systems, and in-stream flow opportunities. The capital-cost
estimate used in the2017 IRP for small hydroelectric resources is $3,753 per kW, and the
75-year levelized cost of energy is $165 per MWh.
Wind
A typical wind project consists of an a:ray of wind turbines ranging in size from I to 3 MW
each. The majority of potential wind sites in southern Idaho lie between the south-central and the
most southeastem part of the state. Areas that receive consistent, sustained winds greater than
15 miles per hour are prime locations for wind development.
When compared to other renewable options, wind resources are well suited for the
Pacific Northwest and Intermountain regions, as evidenced by the number of existing projects.
Wind resources present operational challenges for utilities due to the variable and intermittent
nature of wind generation. Therefore, planning new wind resources requires estimates of the
expected annual energy and peak-hour capacity. For the 2017 IRP, Idaho Power used an annual
average capacity factor of28 percent and an on-peak capacity factor of5 percent for peak-hour
planning. The capital-cost estimate used in the IRP for wind resources is $1,475 per kW, and the
25-year levelized cost of energy is $l l1 per MWh, which includes a wind integration cost of
$16.33 per MWh.
Page 38 2017lRP
ldaho Power Company 4. Future Supply-Side Generation and Storage Resources
Biomass
Biomass resource types considered in the 2017 IRP include wood-burning resources and
anaerobic digesters. Wood-buming resources typically rely on a steady supply of woody residue
collected from forested areas. Fuel supply can be an issue for these types of plants as the radius
of the area used to collect fuel is expanded. Several anaerobic digesters have been built in
southern Idatro due to the size of the dairy industry and the quantity of fuel available. T\e2017
IRP considered anaerobic digesters as a best fit for the service area.
The capital-cost estimate used in the 2017 IRP for an anaerobic digester project is $6,522 per kW
for a 35-MW facility. The anaerobic digester is expected to have an annual capacity factor of
85 percent. Based on the annual capacity factors, the 30-year levelized cost ofenergy is $133 per
MWh for the anaerobic digester.
Conventional Resources
While much attention has been paid to renewable resources over the past few years,
conventional generation resources are essential to provide dispatchable capacity, which is critical
in maintaining the reliability of an electrical power system. These conventional generation
technologies include natural gas-fired resources, nucleat, and coal.
Natu ral Gas-Fi red Resources
Natural gas-fired resources burn natural gas in a combustion turbine to generate electricity.
CCCTs are typically used for baseload energy, while less-efficient SCCTs are used to generate
electricity during peak-load periods. Additional details on the characteristics of both types of
natural gas resources are presented in the following sections.
CCCT and SCCT resources are typically sited near existing gas pipelines, which is the case for
Idaho Power's existing gas resources. However, the capacrty of the existing gas pipeline system
is almost fully allocated. The additional cost as necessary for expanded gas pipeline allocation is
accounted for in portfolios containing new gas resources and not in the resource stack cost
estimate for CCCTs or SCCTs.
Gombined-Gycle Gombustion Turbines
CCCT plants have been the preferred choice for new commercial, dispatchable power generation
in the region. CCCT technology carries a low initial capital cost compared to other baseload
resources, has high thermal efficiencies, is highly reliable, offers significant operating flexibility,
and emits fewer emissions when compared to coal, therefore requiring fewer pollution controls.
Modern CCCT facilities are highly efficient and can achieve efficiencies of approximately
60 percent (lower heating value).
2017 tRP Page 39
4. Future Supply-Side Generation and Storage Resources ldaho Power Company
A traditional CCCT plant consists of a gas turbine/generator equipped with a heat-recovery
steam generator (HRSG) to capture waste heat from the turbine exhaust. The HRSG uses waste
heat from the combustion turbine to drive a steam turbine generator to produce additional
electricity. In a CCCT plant, heat that would otherwise be wasted is used to produce additional
power beyond that typically produced by an SCCT. New CCCT plants can be built or existing
SCCT plants can be converted to combined-cycle units by adding an HRSG.
Several CCCT plants, similar to Idaho Power's Langley Gulch project, are planned in the region
due to a sustained depression in natural gas prices, the need for baseload energy, and additional
operating reserves needed to integrate intermittent resources. While there is no current shortage
of natural gas, fuel supply is a critical component of the long-term operation of a CCCT.
The capital-cost estimate used in the IRP for a CCCT (1 x 1) resource is $1,246 per kW, and the
30-year levelized cost of energy at a 70-percent annual capacity factor is $64 per MWh.
Simple-Cycle Combustion Turbines
Simple cycle, natural gas-turbine technology involves pressurizing air that is then heated by
burning gas in fuel combustors. The hot, pressurized air expands through the blades of the
turbine that connects by a shaft to the electric generator. Designs range from larger,
industrial machines at 80 to 200 MW to smaller machines derived from aircraft technology.
SCCTs have a lower thermal efficiency than CCCT resources and are not typically economical
to operate other than to meet peak-hour load requirements.
Several natural gas-fired SCCTs have been brought on-line in the region in the past decade,
primarily in response to the regional energy crisis of 2000 to 2001. High electricity prices
combined with persistent drought conditions during 2000 to 2001, as well as continued
summertime peak-load growth, created interest in generation resources with low capital costs
and relatively short construction lead times.
Idaho Power has approximately 430 MW of SCCT capacity. As peak summertime electricity
demand continues to grow within Idaho Power's service area, SCCT generating resources remain
a viable option to meet peak load during critical high-demand times when the transmission
system has reached fulI import capacity. The plants may also be dispatched for financial reasons
during times when regional energy prices are attheir highest.
The20lT IRP evaluated a 170-MW industrial-frame (F class) SCCT unit. The capital-cost
estimate used in the 2017 IRP is $878 per kW. The industrial-frame unit is expected to have an
annual capacity factor of l0 percent.
Based on an annual capacity factor of l0 percent, the 35-year levelized cost ofenergy is $197 per
MWh for the industrial-frame SCCT unit. If Idaho Power were to identify the need for a SCCT,
it would evaluate SCCT technologies in greater detail prior to issuing a request for proposal
(RFP) to determine which technology would provide the greatest benefit.
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ldaho Power Company 4. Future Supply-Side Generation and Storage Resources
Reciprocating Engines
Reciprocating engine generation sets are typically multi-fuel engines connected to a generator
through a flywheel and coupling. They are typically capable of burning natural gas. Because they
are mounted on a corlmon baseframe, the entire unit can be assembled, tuned, and tested in the
factory before being delivered to the power plant location, which minimizes capital costs.
Operationally, reciprocating engines are typically installed in configurations with multiple,
identical units, which allows each unit to run at its best efficiency point once started. As more
generation is needed, additional units are started. This configuration also allows for relatively
inexpensive future expansion of the plant capacity. Reciprocating engines provide unique
benefits to the electrical grid. They are extremely flexible in the sense that they can provide
ancillary services to the grid in a few minutes. Engines can go from a cold start to fullJoad in
l0 minutes.
For the IRP, Idaho Power modeled a reciprocating engine similar to the 34SG model
manufactured by Wtirtsil2i with a nameplate rating of approximately l8 MW. The capital-cost
estimate used for a reciprocating engine resource is $775 per kW, and the 40-year levelized cost
of energy at a25-percent annual capacity factor is $94 per MWh.
Combined Heat and Power
Combined heat and power (CHP), or cogeneration, typically refers to simultaneous production
of both electricity and useful heat from a single plant. CHP plants are typically located at,
or near, commercial or industrial facilities capable of using the heat generated in the process.
These facilities are sometimes referred to as a steam host. Generation technologies frequently
used in CHP projects are gas turbines or engines with a heat-recovery unit.
The main advantage of CHP is that higher overall efficiencies can be obtained because the steam
host can use a large portion of the waste heat that would otherwise be lost in a typical generation
process. Because CHP resources are typically located near load centers, investment in additional
transmission capacity can also often be avoided. In addition, reduced costs for the steam host
provide a competitive advantage that would ultimately benefit the local economy.
In the evaluation of CHP resources, it became evident that CHP could be a relatively high-cost
addition to Idaho Power's resource portfolio if the steam host's need for steam forced the
electrical portion of the project to run at times when electricity market prices were below the
dispatch cost of the plant. To find ways to make CHP more economical, Idaho Power is
committed to working with individual customers to design operating schemes that allow power
to be produced when it is most valuable, while still meeting the needs of the steam host's
production process. This would be difficult to model for the IRP because each potential CHP
opportunity could be substantially different.
2O17IRP Page 41
4. Future Supply-Side Generation and Storage Resources ldaho Power Company
Recognizing the actual cost of a CHP resource varies depending on the specific facility being
considered, the capital-cost estimate used in the20lT IRP for CHP is $2,213 per kW, and the
40-year levelized cost ofenergy evaluated at an annual capacrty factor of80 percent is $71
per MWh.
Nuclear Resources
The nuclear power industry has been working to develop and improve reactor technology for
some time, and Idaho Power has continued to evaluate various technologies in the IRP. Due to
the Idaho National Laboratory GNL) site in eastern Idaho, the IRP has typically assumed that an
advanced-design or small modular reactor (SMR) could be built on the site. For the 2017 IRP,
high capital costs coupled with a great amount of uncertainty in waste-disposal issues prevented
a nuclear resource from being included in the portfolio analysis. Recent large-scale nuclear
development in the US has proven to be fraught with project delays and projected construction
cost ovemrns exceeding $1 billion. In addition, the 2011 earthquake and tsunami in Japan,
and the impact on the Fukushima nuclear plant, created a global concem over the safety of
nuclear power generation. While there have been new design and safety measures implemented,
it is difficult to know the full impact this disaster will have on the future of nuclear power
generation. While Idaho Power does not currently view traditional nucleEr resources as a viable
supply-side resource option for the company, it continues to monitor the advancement of SMR
technology and will evaluate it in the future as the Nuclear Regulatory Commission reviews
proposed SMR designs in the coming years.
For the 2017 IRP, a 50-MW small modular plant was analyzed. The capital-cost estimate used in
the IRP for an advanced SMR nuclear resource is $6,126 per kW, and the 40-year levelized cost
of energy, evaluated at an annual capacity factor of 90 percent, is $163 per MWh.
Coal Resources
Conventional coal resources have been a part of Idaho Power's generation portfolio since the
early 1970s. Growing concerns over global warming and climate change coupled with historic
low natural gas prices have made it impractical to consider building new conventional coal
resources.
Integrated gasification combined cycle (IGCC) is an evolving coal-based technology designed to
substantially reduce COz emissions. As the regulation of COz emissions eventually makes
conventional coal resources obsolete, the commercialization of this technology may allow the
continued use of the country's coal resources. IGCC technology is also dependent on the
development of carbon capture and sequestration technology that would allow COz to be stored
underground for long periods.
Coal gasification is a relatively mature technology, but it has not been widely adopted as a
resource to generate electricity. IGCC technology involves turning coal into a synthetic gas or
Page 42 2017 tRP
ldaho Power Company 4. Future Supply-Side Generation and Storage Resources
"s5rngas" that can be processed and cleaned to meet pipeline quality standards. To produce
electricity, the syngas is bumed in a conventional combustion turbine that drives a generator.
The addition of COz-capture equipment decreases the overall efficiency of an IGCC plant by as
much as 15 percent. In addition, once the carbon is captured, it must either be used or stored for
long periods of time. COz has been injected into existing oil fields to enhance oil recovery;
however, if IGCC technology were widely adopted by utilities for power production,
the quantities of COz produced would require the development of underground
sequestration methods.
Carbon sequestration involves taking captured COz and storing it away from the atmosphere by
compressing and pumping it into underground geologic formations. If compression and pumping
costs are charged to the plant, the overall efficiency of the plant is reduced by an additional
15 to 20 percent. Sequestration methods are currently being developed and tested;
however, commercialization of the technology is not expected to happen for some time.
No new coal-based energy resources were modeled as part of the 2017 IRP.
Storage Resources
RPSs and PURPA have spurred the development of renewable resources in the Pacific
Northwest, leading to periodic oversupply of energy in the region. Mid-Columbia wholesale
market prices for electricity continue to remain relatively low. At the same time, retail rates for
electricity continue to grow, as utilities must pass the cost of building these resources on to
customers. The oversupply issue has grown to the point where at certain times of the year,
such as in the spring,low customer demand coupled with large amounts of hydro and wind
generation cause real-time and day-ahead wholesale market prices to decrease into
negative values.
As more intermittent renewable resources like wind and solar continue to be built within the
region, the need for energy storage is amplified. Many storage technologies are at various stages
of development, such as hydrogen storage, compressed air, and flywheels. The 2017 IRP
considered and evaluated multiple energy storage technologies, including battery storage,
ice-based thermal energy storage (TES), and pumped hydro storage.
2017 tRP Page 43
4. Future Supply-Side Generation and Storage Resources ldaho Power Company
Battery Sforage
Just as there are many types of storage
technologies being researched and
developed, there are numerous types of
battery storage technologies at various
stages of development. The 20l7IRP
aralyzed the vanadium redox-fl ow battery
(VRB), lithium-ion battery systems and
zincbattery systems.
EbctbLd
Advantages of the VRB technology
include its low cost, long life,
and scalability to utility/grid applications. Basic ilusrration of a flow battery.12
Most battery technologies are not a good
fit for utility-scale applications because they cannot be easily or economically scaled to much
larger sizes. The VRB overcomes much of this issue because the capacity of the battery can be
increased by increasing the size of the tanks that contain the electrolytes, which also helps keep
the cost relatively low.
VRB technology also has an advantage in maintenance and replacement costs, as only certain
components need to be replaced about every l0 years, whereas other battery technologies require
a complete and often more frequent replacement of the battery depending on the duty cycle.
For the IRP, the capital-cost estimate for the VRB is $3,736 per kW, and the l0-year levelized
cost of energy, evaluated at an annual capacity factor of 4 percent, is $2,010 per MWh.
Idaho Power recognizes the continued technological development of VRB batteries used in
utility-scale storage facilities. Idaho Power will continue to monitor price trends and the
scalability of this technology in the coming years.
ln recent months, lithium-ion battery systems have gone on-line commercially in the US on the
west coast. Lithium-ion battery storage systems rcalize high charging and discharging
effrciencies. Lithium-based energy storage devices present possible safety concerns due
to overheating.
For the IRP, the capital-cost estimate for lithium-ion baffery storage is $3,114 per kW, and the
lO-year levelized cost ofenergy, evaluated at an annual capacity factor of 14 percent, is $476 per
MWh. Idaho Power recognizes the continued technological development of lithium-ion batteries
12 Source : http ://wernerantweil er. calblog. php?item :20 | 4 -09 -28
i/l€fi$.ol.bbn
Edrangc
Page 44 2017 tRP
ldaho Power Company 4. Future Supply-Side Generation and Storage Resources
used in utility-scale storage facilities. Idaho Power will continue to monitor price trends and the
scalability of this technology in the coming years.
A third type of battery storage system analyzed in the 2017 IRP was zinc battery storage.
Zrncbattery storage systems are capable of deep discharge cycles and are relatively low cost due
to the abundance of the primary metals in a zinc battery. Zinc-based energy storage devices do
present concems due to their lack of proven utility-scale application. Zinc battery systems are
typically less efficient than other types of battery storage technologies.
For the IRP, the capital-cost estimate for zinc battery storage is $2,010 per kW, and the l0-year
levelized cost of energy, evaluated at an annual capacity factor of 7 percent, is $621 per MWh.
Idatro Power recognizes the continued technological development of Zinc batteries and will
continue to monitor price trends and the technical viability of this technology in the
coming years.
/ce-Based fES
Ice-based TES is a concept
developed to kke advantage of the
air conditioning (A/C) needs of
mid-sized to large commercial
buildings. The general concept is to
create ice during low-load/low-price
times (light load hours), then to use
the ice for A/C needs during the
high-loadlhigher-price times
(heavy-load hours). While this
concept does not specifically store
electricity, it does shift the time the
energy is consumed, with the
overall goal ofreducing peak
daytime demand.
a
Re&itffiil Man4ffit S)rstfr Refitmnt Pmp Cot Data Controtler
lllustration of an ice-based TES system.13
Tank l-loar Exch{B€r
G
W&ts Pump
\//\
\
Cord!ffjirBCoil
One company currently commercializing the ice-based TES technology is Ice Energy with their
Ice Bear Energy Storage System. Requirements in Califomia to develop energy storage have
allowed several utilities to begin installing and testing this technology, with several installations
of 5 MW to 15 MW in size. For the IRP, the capital-cost estimate used for this technology is
l3 Source: http://www.ice-energy.com/technology/ice-bear-energy-storage-system
2017 tRP Page 45
4. Future Supply-Side Generation and Storage Resources ldaho Power Company
$2,000 per kW, and the 2}-year levelized cost of energy, evaluated at an annual capacity factor
of 6 percent, is $508 per MWh.
Pumped Hydro Sforage
Pumped storage is a type of hydroelectric power generation used to change the "shape" or timing
of when electricity is produced. The technology stores energy in the form of water, pumped from
a lower-elevation reservoir to a higher elevation. Lower-cost, off-peak electricity is used to pump
water from the lower reservoir to the upper reservoir. During higher-cost periods of high
electrical demand, the water stored in the upper reservoir is used to produce electricity.
For pumped storage to be economical, there must be a significant differential (arbitrage) in the
price of electricity between peak and off-peak times to overcome the costs incurred due to
effrciency. Historically, the differential between peak and off-peak energy prices in the
Pacific Northwest has not been sufficient to make pumped storage an economically viable
resource; however, with the recent increase in the number of wind projects, the amount of
intermittent generation provided, and the ancillary services required, Idaho Power continues to
monitor the viability of pumped storage projects in the region. The capital-cost estimate used in
the IRP for pumped storage is$2,352 per kW, and the 50-year levelized cost of energy,
evaluated at an annual capacity factor of 20 percent, is $229 per MWh.
Page 46 2017lRP
ldaho Power Company 5. Demand-Side Resources
5. DenneruD-SrDE ResouRcES
DSM Program Overuiew
Demand-side resources are the first selected
resources in each IRP. No supply-side generation
resource is considered as part of Idaho Power's
plan until all future cost-effective, achievable
potential energy efficiency and forecasted
demand response is accounted for and credited
against future loads. In the 2017 IRP,
demand response provides 390 MW of committed
peak summer capacity, while energy efficiency
will reduce average annual loads by 273 aMW
and 483 MW of peak reduction by the year 2036.
Ghanges from the 2015 IRP
Methods for incorporating and accounting for The Shade Tree Project provides free trees for
energy ef6ciency and demand response resources f::::""' customers in select counties to shade-----eJ ----------J their homes. Shade trees, properly grown on the
in the 2017 IRP were similar to methods used in west side of a home, can hetp reduce energy
the 2015 IRP. As in the 2013 and 2015 IRPs, needed forsummercooling by 15 percent ormore.
the planning case for energy effrciency as a ln 2016' ldaho Power distributed 2'070 trees'
resource potential was determined by a third-party consultant. Notably, the company's 20-year
load forecast for the 2017 IRP accounted for all accumulated potential energy effrciency savings
As a result, over the last seven years of the IRP planning period (2030-2036), no adjustments to
forecast loads were required to reflect incremental energy efficiency savings potential
determined by the third party but not included in the load forecast. The alignment of the energy
efficiency savings potential forecasts is a result of sharing data and assumptions from the 2015
potential study and the early results of the 2017 potential study. Another highlight forthe20lT
IRP is the continued improvement in estimating peak contribution from energy efficiency that
was first estimated using hourly load shapes in the 2015 IRP. Prior to the 2015 IRP,
peak contribution from energy efficiency was estimated using average monthly energy values.
Program Screening
All DSM programs and measures included in Idaho Power's current progrurms and the forecast
have been screened for cost-effectiveness. Cost-effectiveness analyses of DSM forecasts for the
2017 IRP are presented in more detail inAppendix C-Technical Appendix. Appendix B-
Demand-Side Management 2016 Annual Reporl contains a detailed description of Idaho Power's
2016 energy efficiency progftrms, along with historical program performance. A complete
review of Idaho Power's DSM programs, evaluations, and cost-effectiveness can be found in the
2017 tRP Page47
5. Demand-Side Resources ldaho Power Company
2016 annual report, Demand-Side Management 2016 Annual Report, Supplement 1:
Cost-Effectiveness, and Supplement 2: Evaluatton, which are available on Idaho Power's website
at idahopower. com/EnergyEffi ciency/reports.cfm.
DSM Program Performance
While the IRP planning process primarily looks forward, recent DSM performance is a good
predictor of near-term performance for the 2017 IRP. Accumulated annual savings from energy
efficiency investrnents grow over time based on measure lives of the efficient equipment and
measures adopted and installed by customers each year. Additionally, past performance of
demand response programs has changed over time as the design and use of the progftLms
have evolved.
Energy Efficiency Pertormance
Energy efficiency investments since 2002have resulted in a cumulative average annual load
reduction of 209 aMW, or over 1.6 million MWh, of reduced supply-side energy production to
customers through 2016. Figure 5.1 shows the cumulative annual gowth in energy efficiency
effects over the l3-year period from 2002 through 2016, along with the associated IRP targets
developed as part of the IRP process since 2004.
209
2@2 2003 2@4 2m5 2m6 2@7 2@8 2009 2010 2011 2012 2013 2014 2015 20'.t6
-
IPC SavirBs (witt NEEA)
-lRP
Targets
Figure 5.1 Cumulative annual growth in energy efficiency
Demand Respon se Pertormance
Demand response resources have been part of the demand-side portfolio since the 2004 IRP.
The current demand response portfolio is comprised of three progftrms that work together as one
resource. Each program targets a different customer class. Table 5.1 lists the three programs that
2fi
2@
150
100
50
==G
oo
ED
t!
t,coooc
ooo
'E
.E
Eo
0
167
150
114
12
32
20
742
Page 48 2017 tRP
ldaho Power Company 5. Demand-Side Resources
make up the current demand response portfolio, along with the different program characteristics.
The Irrigation Peak Rewards program represents the largest percent of potential demand
reduction. During the 2016 summer season, Irrigation Peak Rewards participants contributed
8l percent of the total potential demand-reduction capacrty, or 317 MW. More details on
Idaho Power's demand response programs can be found nAppendix B-Demand-Side
Management 2016 Annual Report.
Table 5.1 Demand response programs
Program Customer Class
Reduction
Technology
2016 Total Demand
Response Gapacity
(Mw)
Percent of Total
2016 Peak
Performance
tuC CoolCredit
Irrigation Peak Rewards
Flex Peak Program
Residential
lrrigation
Commercial, industrial
CentralA/C
Pumps
Various
u
317
42
9o/o
81o/o
11Yo
Total 392
Figure 5.2 shows the historical annual demand response program capacity between 2004 arrd
2016 along with associated IRP targets between 2006 and 2012 and 2015 through 2016.
There were no demand response targets for 2013 to2014 in the 2013 IRP. The large jump in
demand response capacity from 6l MW in 2008 to 218 MW in 2009 was a result of transitioning
most the krigation Peak Rewards participants to a dispatchable progr{Lm. The demand response
capacity in20ll and20l2 included 320 alnd 340 MW of capacity, respectively, from the
Irrigation Peak Rewards program, which was not used based on the lack of need and the variable
cost to dispatch the program. The reported demand response capacity value was lower lr,2013
because of the one-year suspension of both the irrigation and residential progftrms.
403 390 392
2@4 2@5 2m6 2007 2008 2m9 2010 2011 2012 2013 2014 2015 2016
IAnnual DR Performarrce/Capacity (MW)
-2906-20'12,2015-2016
DR IRP Targets
Figure 5.2 Historical annualdemand response programs
500
450
== 4oo
;Et*8sm
tr.9
E 2s0
tt&, zgo
EE 150
gim
Goo' 50
0
43 50 6'l 48
6
2017 tRP Page 49
5. Demand-Side Resources ldaho Power Company
Committed Energy Efficiency Forecast
For the 2017 IRP, Applied Energy Group
(AEG) was retained to update the previous
study prepared for the 2015 IRP and
provide an updated 20-year comprehensive
view of Idaho Poweros energy
efficiency potential.
AEG developed three levels of potential:
technical, economic, and achievable.
Technical and economic potential are both
theoretical limits to efficiency savings,
while achievable savings become the
planning case forecast for energy Typical irrigation pivots
efficiency in the 2017 IRP. Achievable potential embodies a set of assumptions about the
decisions consumers make regarding the efficiency of the equipment they purchase, the
maintenance activities they undertake, the controls they use for energy-consuming equipment,
and the elements of building construction. The three levels of potential are described below.
Technical-Technical potential is defined as the theoretical upper limit of energy
efficiency potential. Technical potential assumes customers adopt all feasible measures
regardless of cost. At the time of equipment replacement, customers are assumed to select
the most efficient equipment available. In new construction, customers and developers
are also assumed to choose the most efficient equipment available. Technical potential
also assumes the adoption of every other applicable measure available. The retrofit
measures are phased in over several years, which is increased for higher-cost measures.
a
o
o
Economic-Economic potential represents the adoption of all cost-effective energy
efficiency measures. In the potential study, AEG applies the total resource cost (TRC)
test for cost-effectiveness, which compares lifetime energy and capacity benefits to the
incremental cost of the measure. Economic potential assumes customers purchase the
most cost-effective option at the time of equipment failure and adopt every other
cost-effective and applicable measure.
Achievable-Achievable potential considers market maturity, customer preferences for
energy-efficient technologies, and expected program participation. Achievable potential
establishes a realistic target for the energy efficiency savings a utility can achieve through
its programs. It is determined by applying a series of annual market-adoption factors to
the economic potential for each energy efficiency measure. These factors represent the
ramp rates at which technologies will penetrate the market.
Page 50 2017 tRP
ldaho Power Company 5. Demand-Side Resources
The market characterization study bundles industries and building types into homogenous
groupings. Idaho Power's special-contract customers were treated outside of the potential study
model. Forecasts for these unique customers, who tend to be very active in efficiency,
were based on the combined customer group's history of participation along with the near-term
projected projects.
AEG provides the annual savings potential forecast to Idaho Power in gigawatt-hours (GWh),
where it is converted to hourly, then monthly, average energy reduction (aMW) to compare with
supply-side resources for the IRP analysis. The savings are shaped by end-use load shapes that
spread the forecasted savings across all hours ofthe year. The load shapes used to allocate
savings by end use were provided by AEG as part of the study deliverables. All reported energy
efficiency and demand response forecasts ile expressed at generation level and therefore include
line losses of 9.6 percent for energy and9.7 percent for peak demand to account for energy that
would have been lost as a result of transmitting energy from a supply-side generation resource to
the meter level.
Table 5.2 shows the forecasted potential effect of the current portfolio of energy efficiency
programs for 2017 to 2036 in five-year blocks in terms of cumulative average annual energy
reduction (aMW) by customer class. Detailed annual forecast values can be found in
Appendix C-Te chnical Appendix.
Table 5.2 Totalenergy efficiency portfolio forecasted effects 12017-2036) (aMW)
Customer CIass 2017 2021 2026 2031 2036
I ndustrial/commercial/special contracts
Residential
lrrigation
140
46
23
I
2
2
51
14
I
105
27
16
175
66
31
Total*13 73 147 208 273
*Totals may not add exactly due to rounding.
Table 5.3 shows the 20-year cost-effectiveness summary based on the AEG potential study and
preliminary DSM alternative costs. TRCs account for both the costs to administer the programs
and the customer's incremental cost to invest in efficient technologies and measures offered
through the programs. The benefit of the programs is avoided energy, which is calculated by
valuing energy savings with the DSM preliminary altemative costs.
2017 tRP Page 51
5. Demand-Side Resources ldaho Power Company
Table 5.3 Total energy efficiency portfolio cost-effectiveness summary
Customer Class
2036
Load
Reduction
(aMW)
2036
Peak-Load
Reduction
(Mwr
Resource
Costs ($000s)
20-Year NPV)
Total Benefits
($000s)
(20-Year NPV)
TRC:
BenefiU
Cost
Ratio
TRC
Levelized
Costs
(cents/kWh)
Residential
I ndustrial/commercial/
special contract
lrrigation
66
176
31
$155,425
$302,559
$295,479
$567,923
1.9
1.9
6.7
3.9
6.7$81,981 $133,498 1.6
Total 273 483 $539,965 $996,900 1.8 4.8
*Final peak-reduction estimates were calculated only for the portfolio as a whole.
The completed energy efficiency forecast is included in the IRP planning horizon and the load
and resource balance analysis after ensuring all future energy efficiency was properly accounted
for and netted out of future loads prior to portfolio analysis. As noted earlier in this chapter,
the company's IRP load forecast accounted for all of the accumulated2}-year potential energy
efficiency savings, exceeding the AEG-determined potential over the last seven years of the IRP
planning period (2030-2036). Portfolios for the IRP were developed based on the assumption
that for 2030 to 2036, the amount of energy efficiency in the load and resource balance is the
amount accounted for in the company's load forecast, rather than the smaller amount determined
by AEG in the potential study. For the energy load and resource balance, the accumulated energy
efficiency in the company's load forecast is 300 aMW, rather than the 273 aMW load reduction
provided in Table 5.3 above. The accumulated peak-load reduction in the company's load
forecast is 531 MW, rather than the 483 MW noted in Table 5.3.
The amount of energy efficiency determined by the DSM potential study to be cost-effective
and achievable sets an appropriate and prudent target for energy efficiency for the 2017 IRP;
this amount of energy effrciency is included in all analyzed portfolios before all other resources.
Idaho Power recognizes that the amount of energy efficiency achieved in practice may ultimately
exceed the2017 IRP target amount as a result of implementation efforts of the company and the
Energy Efficiency Advisory Group (EEAG). The achievable potential is in no way considered a
ceiling for funding or the company's efforts.
Further, the company recognizes that alternative (or avoided) costs used for the
cost-effectiveness evaluation are likely to change in the interim between the 2017 IRP and 2019
IRP as key drivers of these costs (e.g., natural gas price) vary. Thus, it is the company's view
that the DSM potential study-determined cost-effective and achievable energy efficiency sets the
target for the amount of energy efficiency available in this IRP. This target does not represent a
ceiling or finite amount for actual energy efficiency activities. It is emphasized that neither the
cost-effectiveness nor the achievability of this target is fixed; both attributes can change
following completion of this IRP, and future analysis (e.g., the 2019 IRP) will reflect
these changes.
Page 52 2017 tRP
ldaho Power Company 5. Demand-Side Resources
Transmissfon and Distribution Deferral Benefits Assocrated with
Energy Efficiency
The transmission and distribution (T&D) deferral benefits associated with energy efficiency
were determined using all growth projects from Idaho Power's officer-reviewed three-year
budget for 2016. Transmission, substation, and distribution projects were represented.
The limiting capacity (determined by feeder or transformer) was identified for each project along
with the anticipated in-service date, projected cost, peak loading, and projected growth rate.
The forecast for the penetration of energy efficiency was incorporated into the formula.
Independent energy effrciency demand reduction forecasts for different rate classes were applied
at summer and winter peak. If the adjusted forecast was below the limiting capacity, it was
assumed the project could be deferred. The financial savings of deferring the project were
then calculated.
The total savings from all the defenable projects were divided by the total annual energy
efficiency reduction forecast over the service area. A sensitivity analysis was conducted with an
energy efficiency forecast multiplier of 0 to l0 times the existing forecast. Based on the analysis,
a value of $3.76 per kW per year will be used as the T&D deferral value.
Committed Demand Response Forecast
Under the current progrcm design and participation levels, demand response from all programs is
forecast to provide 390 MW of peak capacity during July throughout the IRP planning period,
with additional program potential available during June and August. The committed demand
response included in the IRP has acapacity cost of $29 per kW per year.
Additiona! Demand Response
As part of the IRP's expressed strategy to set the highest standard for evaluating B2H
cost-effectiveness, B2H alternative portfolios include an additional 50 MW of demand response
in 25 MW increments in202l and2026. The achievement of this additional 50 MW is
reasonable and consistent with the role of demand response as a cost-effective capacity resource
available to shift peak loading for a finite number of hours. While the B2H-based portfolios did
not include the added demand response for the purpose of focusing the costs and benefits of
these portfolios on B2H, the company does not view B2H as precluding the continued evaluation
and as-needed expansion of demand response resources.
2017lRP Page 53
5. Demand-Side Resources ldaho Power Company
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Page 54 2017lRP
ldaho Power Company 6. Transmission Planning
6. TnerusMrssroN PmruNrNG
Past and Present Transmission
High-voltage transmission lines are vital to the
development of energy resources to serve
Idaho Power customers. Transmission lines have
facilitated the development of southern Idaho's
network of hydroelectric projects that serve southern
Idaho and eastern Oregon. Regional transmission
lines that stretch from the Pacific Northwest to the
HCC and to the Treasure Valley were central to the
development of the HCC projects in the 1950s and
1960s. In the 1970s and 1980s, transmission lines
facilitated partnerships in the three coal-fired
power plants located in neighboring states that. r r i 500-kilovolt (kV) transmission line nearoellver energy to loano rower cusromers. Melba, ldaho
Finally, transmission lines allow Idaho Power to
economically balance the variability of its intermittent resources with access to wholesale
energy markets.
Idaho Power's transmission interconnections provide economic benefits and improve reliability
through the flexibility to move electricity between utilities to serve load and to share operating
reserves. Historically, Idaho Power has been a summer peaking utility, while most other utilities
in the Pacific Northwest experience peak loads during the winter; as a result, Idaho Power can
purchase energy from the Mid-Columbia energy trading market to meet peak summer load and
sell excess energy to Pacific Northwest utilities during the winter and spring. Additional regional
transmission connections to the Pacific Northwest will benefit the environment and Idaho Power
customers in the following ways:
The construction of additional resources to serve summer peak load is delayed
or avoided.
Revenue from off-system sales during the winter and spring is credited to customers
through the PCA.
Revenue from others' use of the transmission system is credited to
Idaho Power customers.
System reliability is increased.
Increased capacity can help integrate intermittent resources, such as wind and solar.
a
a
a
a
2017 tRP Page 55
6. Transmission Planning ldaho Power Company
a Improve the ability to more efficiently implement advanced market tools, such as
the EIM.
Transmission Planning Process
FERC mandates several aspects of the transmission planning process. FERC Order No. 1000
requires Idaho Power to participate in transmission planning on a local, regional,
and interregional basis, as described in Attachment K of the Idaho Power Open-Access
Transmission Tariff(OATT) and summarized in the following sections.
Local Transmissron Planning
The expansion planning of Idaho Power's transmission network occurs through the biennial local
transmission planning (LTP) process which identifies the transmission required to interconnect
load centers, integrate planned generation resources, and incorporate regional transmission plans.
The LTP is a 20-year plan that incorporates the planned supply-side resources identified in the
IRP process, the transmission upgrades identified in the local-area transmission advisory process,
the forecasted network customer load (e.g., Bonneville Power Administration [BPA] customers
in eastern Oregon and southem Idaho), Idaho Power's retail customer load, and third-party
transmission customer requirements. By identi$ing potential resources, potential resource
locations, and load-center growth, the required transmission system capacity expansions are
identified to safely and reliably provide service to customers. The LTP is shared with the
regional transmission planning process.
Idaho Power develops long-term, local-area transmission plans for various load centers within
Idaho Power's service area by applying a local-area transmission advisory process.
This process uses community advisory committees and is performed every l0 years for each
area. The community advisory committees consist ofjurisdictional planners; mayors;
council members; commissioners; and large industry, commercial, residential, and environmental
representatives. The plans identifu the transmission and substation infrastructure required for the
full development of the area. The plans account for land-use limits and other resources of the
local area. The plans identifu the approximate year aproject will be placed in service. Local-area
plans have been created for the following load centers in southern Idaho:
1. Eastern Idaho
2. Magic Valley
3. Wood River Valley
4. Eastem Treasure Valley
5. Westem Treasure Valley
6. West Central Mountains
Page 56 2017 tRP
ldaho Power Company 6. Transmission Planning
Regional Transmissfon Plan ni ng
Idaho Power is active in regional transmission planning through the NTTG. The NTTG was
formed in early 2007 to improve the operation and expansion of the high-voltage transmission
system that delivers power to consumers in seven western states. In addition to Idaho Power,
other members include Deseret Power Electric Cooperative, NorthWestem Energy, PGE,
PacifiCorp (Rocky Mountain Power and Pacific Power), Montana-Alberta Tie Line (MATL),
and the Utah Associated Municipal Power Systems (UAMPS). Biennially, the NTTG develops a
regional transmission plan using a public stakeholder process to evaluate transmission needs
resulting from members' load forecasts, LTPs, IRPs, generation interconnection queues,
other proposed resource development, and forecast uses of the transmission system by
wholesale transmission customers.
I nterco n nectio n-Wi de T ransm i ssion P I an n i ng
The WECC Transmission Expansion Planning Policy Committee (TEPPC) serves as
the interconnection-wide transmission planning facilitator in the westem US.
Specifically, the TEPPC has three functions:
l. Oversee data management for the westem interconnection.
2. Provide policy and management of the planning process.
3. Guide the analyses and modeling for Westem Interconnection economic transmission
expansion planning.
In addition to providing the means to model the transmission implications of various load and
resource scenarios at an interconnection-wide level, the TEPPC coordinates planning between
transmission owners, transmission operators, and regional planning entities.
The WECC Planning Coordination Committee manages additional transmission planning and
reliability-related activities on behalf of electric-industry entities in the West. WECC activities
include resource adequacy analyses and corresponding NERC reporting, transmission security
studies, and the transmission line rating process.
Existing Transmission System
Idaho Power's transmission system extends from eastem Oregon through southem Idaho to
western Wyoming and is composed of I l5-, 138-, 161-, 230-,345-, and 500-kV transmission
facilities. The sets of lines that transmit power from one geographic area to another are known as
transmission paths. There are defined transmission paths to other states and between specific
southem Idaho load centers. Idaho Power's transmission system and paths are shown in Figure
6.1.
2017 tRP Page 57
6. Transmission Planning ldaho Power Company
MONTANA
OREGON
loslmLb
EII(R
IDAHO
N
utao
oHl.lA
o
=o
=
@rqdrw
$i[l{it e@-rft
bc
illcu[mJw
-
^^,NORTH
?atrr
@8dW
W'truEa
*m-weca,
EVAD !ifrnit UTAH
,ts
=Ee
Figure 6.1 ldaho Power transmission system map
The transmission paths identified on the map are described in the following sections, along with
the conditions that result in capacity limitations.
ldahuNorthwest Path
The Idaho-Northwest transmission path consists of the 500-kV Hemingway-Summer Lake
line, the three 230-kV lines between the HCC and the Pacific Northwest, and the 115-kV
interconnection at Hamey Substation near Bums, Oregon. The Idaho-Northwest path is
capacity-limited during sunmer months due to energy imports from the Pacific Northwest to
serve Idaho Power retail load and transmission-wheeling obligations for the BPA load in eastern
Oregon and southern Idaho. To access new resources, including market purchases, located west
of the path, additional transmission capacrty will be required to deliver the energy to
Idaho Power's service area.
Brownlee Easf Path
The Brownlee East transmission path is on the east side of the Idaho-Northwest Interconnection
shown in Figure 6.1. Brownlee East is comprised of the 230-kV and 138-kV lines east of the
Page 58 2017 tRP
ldaho Power Company 6. Transmission Planning
HCC and Quartz Substation near Baker City, Oregon. When the Hemingway-Summer Lake
500-kV line is included with the Brownlee East path, the path is typically referred to as the
Brownlee East Total path.
The Brownlee East path is capacity-limited during the summer months due to a combination of
HCC hydroelectric generation flowing east into the Treasure Valley concurrent with
transmission-wheeling obligations for BPA southern Idaho load and Idaho Power energy imports
from the Pacific Northwest. Capacity limitations on the Brownlee East path limit the amount of
energy Idaho Power can import from the HCC, as well as off-system purchases from the Pacific
Northwest. If new resources, including market purchases, are located west of the path, additional
transmission capacity will be required to deliver the energy to the Treasure Valley load center.
Montan*ldaho Path
The Montana-Idaho transmission path consists of the Antelope-Anaconda 230-kV and Goshen-
Dillon l6l-kV transmission lines. The Montana-Idaho path is also capacity-limited during the
summer months as Idaho Power, BPA, PacifiCorp, and others move energy south from Montana
into Idaho.
Borah West Path
The Boratr West transmission path is internal to Idaho Power's system and is jointly owned
between Idaho Power and PacifiCorp. Idaho Power owns 1,467 MW of the path, and PacifiCorp
owns 1,090 MW of the path. The path is comprised of 345-kV, 230-kV, and 138-kV
transmission lines west of the Borah Substation located near American Falls, Idaho.
Idaho Power's one-third share of energy from the Jim Bridger plant flows over this path,
as well as energy from east-side resources and imports from Montana, Wyoming, and Utah.
Heavy path flows are also likely to exist during the light-load hours of the fall and winter
months as high eastern thermal and wind production move east to west across the system to the
Pacific Northwest. Additional transmission capacity will likely be required if new resources or
market purchases are located east of the Borah West path.
Midpoint West Path
The Midpoint West transmission path is internal to Idaho Power's system and is ajointly owned
path between Idaho Power and PacifiCorp. Idaho Power owns 1,710 MW of the path and
PacifiCorp owns 1,090 MW of the path (all on the Midpoint-Hemingway 500-kV line). The path
is comprised of 500-kV, 230-kV, and 138-kV transmission lines west of Midpoint Substation
located near Jerome, Idaho. Like the Borah West path, the heaviest path flows are likely to exist
during the fall and winter when significant wind and thermal generation is present east of the
path. Additional transmission capacity will likely be required if new resources or market
purchases are located east of the Midpoint West path.
2017 tRP Page 59
6. Transmission Planning ldaho Power Company
ldahuNevada Path
The Idaho-Nevada transmission path is comprised of the 345-kV Midpoint-Humboldt line.
Idaho Power and NV Energy are co-owners of the line, which was developed at the same time
the North Valmy Power Plant was built in northem Nevada. Idaho Power is allocated
100 percent of the northbound capacity, while NV Energy is allocated 100 percent of the
southbound capacity. The available import, or northbound, capacity on the transmission path is
fully subscribed with Idaho Power's share of the North Valmy generation plant.
ldahuWyoming Path
The Idaho-Wyoming path, referred to as Bridger West, is comprised of three 345-kV
transmission lines between the Jim Bridger generation plant and southeastern Idaho.
Idaho Power ovtns774 MW of the 2,400-MW east-to-west capacity. PacifiCorp owns the
remaining capacity. The Bridger West path effectively feeds into the Borah West path when
power is moving east to west from Jim Bridger; consequently, the import capability of the
Bridger West path is limited by Borah West path capacity constraints.
ldahtUtah Path
The Idaho-Utah path, referred to as Path C, is comprised of 345-,230-,161-, and 138-kV
transmission lines between southeastern Idaho and northern Utah. PacifiCorp is the path owner
and operator of all the transmission lines. The path effectively feeds into Idaho Power's Borah
West path when power is moving from east to west; consequently, the import capability of
Path C is limited by Borah West path capacity limitations.
Table 6.1 summarizes the import capability for paths impacting Idaho Power operations and lists
their total capacity and available capacity; most of paths are completely allocated with no
capacity remaining.
Table 6.1 Transmission import capacity
Transmission Path ATC (MWr
ldaheNorthwest
ldaheNevada
ldahrMontana
Brownlee East
MidpointWest
Borah West
ldaheWyoming (Bridger West)
ldaheUtah (Path C)
0
0
0
lnternal Path
lnternal Path
lnternal Path
86 (ldaho Power Share)
PacifiCorp Path
* The available transmission capacity (ATC) of a specific path may change based on changes in the transmission service and
generation interconnection request queue (i.e., the end of a transmission seruice, granting of transmission service, or cancelation
of generation projec{s that have granted future transmission capacity).
lmport Direction Capacity (MW)
West to east
South to north
North to south
West to east
East to west
East to west
East to west
South to north
1,200
262
383
1,915
1,710
2,557
2,400
1,250
Page 60 2017 rRP
ldaho Power Company 6. Transmission Planning
82H
ln the 2006 IRP process, Idaho Power identified the need for a transmission line to the
Pacific Northwest electic market. At that time, a 230-kV line interconnecting at the
McNary Substation to the greater Boise area was included in IRP portfolios. Since its initial
identification, the project has been refined and developed, including evaluating upgrade options
of existing transmission lines, evaluating terminus locations, and sizing the project to
economically meet projected demand. The project identified in 2006 has evolved into what is
currently the B2H project. The project involves permitting, constructing, operating, and
maintaining a new, single-circuit 500-kV transmission line approximately 300 miles long
between the proposed Longhom Station near Boardman, Oregon, and the existing Hemingway
Substation in southwest Idaho. The new line will provide many benefits, including the following:
Greater access to the Pacific Northwest electric market to economically serve homes,
farms, and businesses in Idaho Power's service area
Improved system reliability and resiliency
Reduced capacity limitations on the regional transmission system as demands on the
system continue to gtow
Flexibility to integrate renewable resources and more efficiently implement advanced
market tools, such as the EIM
The B2H project was identified as part of the preferred resource portfolio in Idaho Power's 2009,
2011,2013, and 2015 IRPs.
The B2H project is a regionally significant project. The project has been identified as producing
a more efficient or cost-effective plan in the NTTG's 2007,2009,2011,2013, and 2015 biennial
regional transmission plans.la NTTG regional transmission plans aim to produce a more efficient
or cost-effective regional transmission plan that meets the transmission requirements associated
with the load and resource needs of the NTTG footprint.
Additionally, the B2H project is a nationally recognized project. The project was selected by
the Obama administration as one of seven nationally significant transmission projects that,
when built, will help increase electric reliability, integrate new renewable energy into the grid,
create jobs and save consumers money.ls
r4 nttg.biy'site/
!5 boardmantohemingway.com/documents/RRTT_Press_Release_10-5-201 I .pdf
o
a
2017 tRP Page 61
6. Transmission Planning ldaho Power Company
Project Participants
In January 2012,Idaho Power entered into a joint funding agreement with PacifiCorp and BPA
to pursue permitting of the project. The agreement designates Idaho Power as the permitting
project manager for the B2H project. Table 6.2 shows each party's B2H capacity and permitting
cost allocation.
Table 6.2 B2H capacity and permitting cost allocation
ldaho Power BPA PacifiCorp
Capacity (MW) west to east
Capacity (MW) east to west
Permitting cost allocation
350
200 winter/S00 summer
85
21%
400
550 winter/2S0 summer
97
24o/o
300
818
55o/o
Additionally, a Memorandum of Understanding (MOU) was executed between Idaho Power,
BPA, and PacifiCorp to explore opportunities for BPA to serve eastern Idaho load from the
Hemingway Substation. BPA identified six solutions-including two B2H options-to meet its
load-service obligations in southeast Idaho. On October 2,2012, BPA publicly announced the
preferred solution to be the B2H project. The participation of three large utilities working toward
the permitting of B2H further demonstrates the regional significance and regional benefits of
the project.
Permitting Update
The permitting phase of the B2H project is subject to review and approval by, among other
govemment entities, the Bureau of Land Management (BLM), US Forest Service (USFS),
Department of the Nurny, and ODOE. The federal permitting process is dictated primarily by the
Federal Land Policy Management Act and National Forest Manogement Act and is subject to
NEPA review. The BLM is the lead agency in administering the NEPA process for the B2H
project. On November 25,2016, BLM published the Final Environmental Impact Statement
(EIS). Figure 6.2 shows the proposed transmission line routes included in the Final EIS with the
agency preferred route. Idaho Power expects the BLM to issue a Record of Decision (ROD)
by summer 20L7.
For the State of Oregon permitting process, Idaho Power submiued the preliminary Application
for Site Certificate (pASC) to the ODOE in February 2013.Idaho Power plans to submit an
amended pASC in summer 2017.
Given the ongoing permitting requirements, Idaho Power is unable to accurately determine
an approximate in-service date for the line but expects the in-service date would be in2024
or beyond.
Page 62 2017 tRP
ldaho Power Company 6. Transmission Planning
I t
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7
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Figure 6.2 B2H routes with the agency-preferred alternative
Activities after BLM ROD
After the BLM issues a ROD and the amended pASC has been submitted to the ODOE and
deemed complete, suffrcient route certainty will exist to begin preliminary construction
activities. These activities include, but are not limited to, the following:
Geotechnical surveys
Detailed ground surveys (light detection and ranging [LiDAR] surveys)
Sectional surveys
a
a
a
BOARD\'{AN TO HE\{ING\YAY
TRANSl{ISSION LINE PRO.IECT
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Bureau of Rcclaoatioo
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2017 tRP Page 63
6. Transmission Planning ldaho Power Company
Right-of-way (ROW) activities
Detailed design
Construction bid package development
After the Oregon permitting process concludes, construction activities would corlmence.
Construction activities include, but are not limited to, the following:
Long-lead material acquisition
Transmission line construction
Substation construction or upgrades
The specific timing of each of the preliminary construction and construction activities will be
coordinated with the project co-participants. Additional project information is available at
boardmantohemingway. com.
B2H Cost Treatment in the IRP
The B2H transmission line project is modeled in AURORA as additional transmission capacity
available for Idaho Power energy purchases from the Pacific Northwest. [n general, for new
supply-side resources modeled in the IRP process, surplus sales of generation are included as a
cost offset in the AURORA portfolio modeling. However, historically, additional transmission
wheeling revenue has not been quantified for a transmission capacity addition. For the 2017 IRP,
Idaho Power modeled the additional transmission wheeling revenue for the B2H project.
After the B2H line is in-service, the cost of Idaho Power's share of the transmission line will go
into Idaho Power's transmission rate base as a transmission asset. Idaho Power's transmission
assets are funded by native load customers, network customers, and transmission wheeling
customers based on a ratio of each party's usage of the transmission system. In the IRP
modeling, the estimated incremental transmission wheeling revenue from non-native load
customers was modeled as an annual revenue credit for B2H portfolios.
Northwesf Seasonal Reso urce Availability Forecast
The assessment of regional resource adequacy is part of the regional transmission planning
process, and the review of adequacy assessments is useful in understanding the liquidity of
regional wholesale electric markets. For the 2017 IRP, Idaho Power has reviewed trvo recent
assessments and their respective charactenzations of regional resource adequacy in the
Pacific Northwest: 1) the adequacy assessment conducted by the NWPCC Resource Adequacy
Advisory Committee (RAAC) andZ) the adequacy assessment conducted by the BPA.
a
o
a
o
Page 64 2017 tRP
ldaho Power Company 6. Transmission Planning
In July 2013, the NWPCC approved a charter for the RAAC, which provided that the RAAC's
purpose is to assess power-supply adequacy in the Northwest. Idaho Power has participated in
the RAAC since its inception, and also in the NWPCC's Resource Adequacy Forum,
which preceded the RAAC.
The NWPCC adopted an adequacy standard used by the RAAC as a metric for assessing
resource adequacy. The purpose of the resource adequacy standard is to provide an early warning
should resource development fail to keep pace with demand growth. The analytical information
generated with each resource adequacy assessment assists regional utilities when preparing their
individual IRPs. The statistic used to assess compliance with the adequacy standard is the
likelihood of supply shortage, which is commonly known as the loss-of-load probability (LOLP).
Under the adequacy standard, the LOLP is held to a maximum level of 5 percent.
The RAAC issued a report in September 2016 on resource adequacy for the 2021 operathg
year.16 The 2021operating year follows the 2020 retirement of 1,330 MW of coal-fired
generating capacity at Centralia (Washington) Unit 1 and the Boardman power plant. The RAAC
adequacy assessment reports the LOLP for operating year 2021 is l0 percent, and that to
maintain resource adequacy at the maximum level of 5 percent the Pacific Northwest needs to
add slightly more than 1,000 MW of new capacity. The RAAC also reports that the retirement
of approximately 600 MW of coal-fired generating capacity at Colstrip units I and2,
cunently anticipated for summer 2022, would increase the LOLP to approximately l3 percent
if the retirement of the Colstrip units was moved up to earlier than operating year 2021.
The adequacy assessment demonstrates Pacific Northwest adequacy concems in both winter
and summer. Winter LOLP exceeds summer LOLP, except for the analysis assuming pre-2021
retirement of Colstrip units 1 and2, wherein late summer LOLP exceeds winter LOLP.
Under both assumptions for Colstrip units 1 and2, the LOLP in June and July is zero.
The RAAC is currently conducting an updated adequacy assessment for the 2022 operuting year.
Preliminary results of the updated assessment released by the RAAC indicate a lowered LOLP
for operating year 2022 ofjrst under 8 percent. A report on the updated adequacy assessment
from the RAAC is anticipatedin2}lT.
BPA annually assesses regional resource adequacy in its Pacific Northwest load and resource
study. The BPA assessment accounts for forecast load growth in the Pacific Northwest
(including Idaho and Montana), existing generation, planned new generation considered as
highly certain, and committed generation retirements. In their assessment, BPA considers
regional load diversity (i.e., winter- or summer-peaking utilities) and expected monthly
16 NWPCC. Pacific Northwest power supply adequacy assessment for 2021.2016. Document 2016-10
https;//www.nwcouncil.orglmedia/715059112016-10.pdf. Accessed on: April 25,2017.
2017 tRP Page 65
6. Transmission Planning ldaho Power Company
production from the Pacific Northwest hydroelectric system under the critical case water year for
the region (1937).
The most recent BPA adequacy assessment report was released in December 2016 and evaluates
resource adequacy from 2018 through 2027.17 Monthly capacity adequacy is analyzed from the
perspective of one-hour capacity and 120-hour sustained capacity. In the 2016 assessment,
the Pacific Northwest region is projected in2027 to have summer surpluses from the one-hour
perspective in June through the first half of August, then a deficit of nearly 200 MW in the
second half of August. From the 120-hour sustained capacity perspective, the Pacific Northwest
region is projected in2027 to have a surplus in June, then to be in deficit for July and August.
However, the projected 120-hour deficits in July and the first half of August are less than half
those predicted for the winter months, suggesting the addition of sustained capacity needed to
address winter deficits would be available as surplus capacity to the suflrmer wholesale market in
the region.
The Pacific Northwest was historically characterized as an energy-constrained region, rather than
capacity constrained. Load-serving entities could typically serve capacity needs, but during
periodic low water conditions may encounter energy constraints. However, over time the region
has trended toward becoming capacity constrained, as shown by the RAAC and BPA adequacy
assessments. While the regional adequacy assessments suggest potential capacity inadequacies,
these inadequacies for both assessments are shifted from the timing of Idaho Power's peak
needs. Specifically, the adequacy assessments find surlmer inadequacies in the region occur in
the late summer, by which time demand for energy from Idaho Power's irrigation customers has
substantially declined from its late-June through early-July peak. Further, the RAAC adequacy
assessment acknowledges that its assessment does not include generating capacity not yet sited
or licensed, or generating capacity additions driven by RPS requirements. Known new
generating capacity planned by 2021of about 550 MW, along with RPS requirements in
Washington, Oregon, and Califomia, will drive resource expansion. The regional resource
adequacy assessments are consistent with Idaho Power's view that expanded transmission
interconnection to the Pacific Northwest (i.e., B2H) provides access to a market with capacity for
meeting its summer load needs and abundant low-cost energy, and that expanded transmission is
critical in a future with automated energy markets (i.e., western EIM) and high penetrations of
renewable intermittent resources.
17 BPA. 2016 Pacific Northwest loads and resources study (2016 white book).
https://www.bpa.gov/power/pgp/whitebook/2016/index.shtml. Accessed on: May 19,2017
Page 66 2017 tRP
ldaho Power Company 6. Transmission Planning
Gateway West
The Gateway West transmission line project is a joint project between Idaho Power and
PacifiCorp to build and operate approximately 1,000 miles of new transmission lines from the
planned Windstar Substation near Glenrock, Wyoming, to the Hemingway Substation near
Melba, Idaho. PacifiCorp has been designated the permitting project manager for Gateway West,
with Idaho Power providing a supporting role.
Figure 6.3 shows a map of the project identifying the currently authorized routes in the federal
permitting process based on the BLM's November 2013 ROD for segments 1 through 7 and 10.
Segments 8 and 9 were further considered through a Supplemental EIS by the BLM. The BLM
issued a ROD for segments 8 and 9 on January 20,2017 .In March 2017, this ROD was
rescinded by the BLM for further consideration. On May 5, 2017,the Morley Nelson Snake River
Birds of Prey National Conservation Area Boundary Modification Act of 20l 7 (H.R. 2104)
was enacted. H.R. 2104 authorized the Gateway West route through the Birds of Prey area that
was proposed by Idaho Power and PacifiCorp and supported by the Idaho Governor's Office,
Owyhee County and certain other constituents. Per this legislation, the Secretary of the Interior
must issue a ROW for Idaho Power's proposed routes for segments 8 and 9 by early
August 2017.
Idaho Power has a one-third interest in the segments between Midpoint and Hemingway,
Cedar Hill and Hemingway, and Cedar Hill and Midpoint. Further, Idaho Power has sole interest
in the segment between Borah and Midpoint (segment 6), which is an existing transmission line
operated at345 kV but constructed at 500 kV.
,-Fo*t !8, _. trfrbt:li
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ah.
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Figure 6.3 Gateway West map
2017 tRP
v
Page 67
6. Transmission Planning ldaho Power Company
The Gateway West project will provide many benefits to Idaho Power customers,
including the following:
l. Relieve Idaho Power's constrained transmission system between the Magic Valley area
(Midpoint) and the Treasure Valley area (Hemingway). Transmission connecting the
Magic Valley and Treasure Valley is part of Idaho Power's core transmission system,
connecting two major Idaho Power load centers.
2. Provide the option to locate future generation resources east of the Treasure Valley.
3. Provide future load-service capacity to the Magic Valley from the Cedar Hill Substation.
4. Help meet the transmission needs of the future, including transmission needs associated
with intermittent resources.
Phase I of the Gateway West project is expected to provide up to 1,500 MW of additional
transfer capacity between Midpoint and Hemingway. The fully completed project would provide
a total of 3,000 MW of additional transfer capacrty. Idaho Power has a one-third interest in these
capacity additions.
The Gateway West and B2H projects are complementary and will provide upgraded transmission
paths from the Pacific Northwest across Idaho and into eastern Wyoming.
More information about the Gateway West project can be found at gatewaywestproject.com.
Nevada without North Valmy
The Idaho-Nevada transmission path is co-owned by Idaho Power and NV Energy,
with Idaho Power having full allocation of northbound capacity and NV Energy having full
allocation of southbound capacity. As noted earlier in this chapter, the northbound capacity of
the path is fully subscribed with Idaho Power's share of the North Valmy generation plant.
In its evaluation of North Valmy retirement options, Idaho Power has reviewed the potential to
import wholesale energy across the Idaho-Nevada transmission path following retirement of
North Valmy generating capacity. Idaho Power has principally participated in the Mid-Columbia
wholesale power market to the northwest and considers the availability of wholesale energy
for import across the Idaho-Nevada path as less certain. In particular, the frequent import of
wholesale energy from Nevada is likely to encounter scarcity and/or costly energy.
Therefore, while Nevada is not considered a viable source for abundant wholesale energy, it may
have potential to source seldom-needed capacity during peakJoading periods. For this reason,
Idaho Power is assuming for the 2017 IRP that the retirement ofNorth Valmy generating
capacity can be adequately replaced with infrequent wholesale capacity imports across the
Idaho-Nevada transmission path.
Page 68 2017 tRP
ldaho Power Company 6. Transmission Planning
Idaho Power recognizes the uncertainty of assuming wholesale capacrty imports from Nevada
can replace Norttr Valmy generating capacrty. The viability of the Idatro-Nevada path can be
evaluated as the company continues to transition away from coal in a measured and responsible
manner. Idatro Power expects to develop greater understanding of the viability of the Idaho-
Nevada path with participation in the western EIM beginning in spring 2018. As it continues its
evaluation, Idatro Power recognizes the assumption that wholesale capacity imports from Nevada
can replace North Valmy generating capacrty may prove unfounded, and future IRPs may need
to reflect such a change.
Transmission Assumptions in the IRP Portfolios
Idatro Power makes resource location
assumptions to determine transmission
requirements as part of the IRP development
process. Regardless of the location,
supply-side resources included in the
resource stack typically require local
transmission improvements for
integration into Idaho Power's system.
Additional transmission improvement
requirements depend on the location and size
of the resource. The tansmission
assumptions and transmission upgrade Transmission lines leading from Danskin Power Plant
requirements for incremental resources are
summarized in Table 6.3. The assumptions about the geographic area where supply-side
resources are developed determine the transmission upgrades required.
Table 6.3 Transmission assumptions and requirements
Resource Capacity CostAssumption Notes
Local lnterconnection
Assumptions
Backbone Transmiseion
Assumptions
Biomass indirec{-
Anaerobic digester
Geothermal
(binary-cycle)-ldaho
HydreCanaldrop
(seasonal)
Natural gas-
SCCT ftame F class
Assume distribution feeder
locations in the Magic
Valley; displaces equivalent
MW of portfolio resources
in same region.
Assume Raff River area
location; displaces
equivalent MW of portfolio
resouroes in same region.
Assume Magic Valley
location connecting to
46-kV sub-transmission or
local feeder.
Assume Mountain Home
location; displaces
Assume $3.5 million of
distribution feeder
upgrades and
$1.2 million in
substation upgrades.
Requires $mile 138-kV
line to nearby station
with new 138-kV
substation line
terminal bay.
Assume 4 miles of
distribution rebuild at
$150,000 per mile plus
$100,000 in substation
upgrades.
Assume 2-mile 230-kV
line required to connect
Assigns pro-rata share for
transmission upgrades
identifi ed for resources
east of Boise.
Assigns pro-rata share for
transmission upgrades
identified for resources
east of Boise.
No backbone upgrades
required.
Assigns pro-rata share for
transmission upgrades
35
35
2017 tRP
170
Page 69
6. Transmission Planning ldaho Power Company
Resource Capacity Cost Assumption Notes
Local lnterconnection
Assumptions
Backbone Transmission
Assumptions
(ldaho Powe/s peaker
plants use this
technology)
Natural gas-
Reciprocating gas
engine Wdrtsild 34SG
equivalent MW of portfolio
resources in same region.
Assume Mountain Home
location; displaces
equivalent MW of portfolio
resources in same region.
to nearby station.
lnterconnecting at
230-kV Rattle Snake
Substation.
identified for resources
east of Boise.
Assigns pro-rata share for
transmission upgrades
identifi ed for resources
east of Boise.
18
Naturalgas-CCCT
(1xl) F class with
duct firing
Natural gas-
CCCT (1xl) F class
with duct firing
Natural gas-
CCCT (2xl) F class
Naturalgas-CHP
Nuclear-SMR
Pumped storage-
New upper reservoir
and new generation/
pumping plant
Solar PV-Utility-scale
1-axis tracking
Wind-ldaho
Assume Langley Gulch
location; displaces
equivalent MW of portfolio
resources in same region.
Assume Mountain Home
location; displaces
equivalent MW of portfolio
resources in same region.
Build new facility south of
Boise (assume Simco
Road area).
Assume location in
Treasure Valley.
Assume tie into ANTS
230-kV transmission
substation; displaces
equivalent MW of portfolio
resources east of Boise.
Assume Anderson Ranch
location; displaces
equivalent MW of portfolio
resources in same region.
Assume Magic Valley
location; displaces
equivalent MW of portfolio
resouroes in same region.
Assume location within
5 miles of Midpoint
Substation; displaces
equivalent MW of portfolio
resources in same region.
New LGSY-GARNET
230-kV line w/ Garnet
2301138 transformer
and Gamet 138-kV tap
line. Bundle conductor
on the LGSY-CDWL
230-kV line.
Reconductor CDWL-
LNDN.
Assume 2-mile 230-kV
line required to connect
to nearby station.
New 230-kV switching
station with a 22-mile
230-kV line to Boise
Bench Substation and
wrap 230-kV Danskin
Power Plant to Hubbard
line into new station.
Assume 1-mile tap to
existing 138-kV line and
new 138-kV souroe
substation.
Two 2-mile 138-kV lines
to interconnect to
Antelope Substation.
New 138-kV terminal at
Antelope Substation.
18-mile 23GkV line to
connect to Rattle Snake
Substation.
Assume 1-mile 230-kV
line and associated
stations equipment.
Assume S-mile 230-kV
transmission from
Midpoint Substation to
project site.
No additional backbone
upgrades required.
Assigns pro-rata share for
transmission upgrades
identifi ed for resources
east of Boise.
Rebuild Rattle Snake to
DRAM 230-kV line, rebuild
Boise Bench to DRAM
230-kV line, rebuild
Micron to Boise Bench
138-kV line.
No backbone upgrades
required.
New parallel 55-mile
230-kV line from Antelope
to Brady Substation. New
230-kV terminal at Brady
Substation. Assigns pro-
rata share for transmission
upgrades identified for
resources east of Boise.
Assigns pro-rata share for
transmission upgrades
identifi ed for resources
east of Boise.
Assigns pro-rata share for
transmission upgrades
identifi ed for resources
east of Boise.
Assigns pro-rata share for
transmission upgrades
identifi ed for resources
east of Boise.
300
550
35
50
300
100
100
30
Page 70 2017lRP
ldaho Power Company 7. Planning Period Forecasts
7 PIeTruING PERIoD FoREcASTS
The IRP process requires Idaho Power to
prepare numerous forecasts and estimates,
which can be grouped into four main
categories:
l. Load forecasts
2. Generation forecast for
existing resources
3. Natural gas price forecast
4. Resource cost estimates Pedestrians at the Drive Electric Week event in Boise
The load and generation forecasts-including supply-side resources, DSM, and transmission
import capability-are used to estimate surplus and deficit positions in the load and resource
balance. The identified deficits are used to develop resource portfolios evaluated using financial
tools and forecasts. The following sections provide details on the forecasts prepared as part of the
2017IRP.
Load Forecast
Each year, Idaho Power prepares a forecast of sales and demand of electricity using the
company's electrical T&D network. This forecast is a product of historical system data and
trends in electricity usage along with numerous external economic and demographic factors.
Idaho Power has its annual peak demand in the sumner, with peak loads driven by irrigation
pumps and A/C in June, July, and August. Historically, Idaho Power's growth rate of the
summertime peak-hour load has exceeded the growth of the average monthly load.
Both measures are important in planning future resources and are part of the load forecast
prepared for the 2017 IRP.
The expected case (median) load forecasts for peak-hour and average energy (average load)
represent Idaho Power's most probable outcome for load growth during the planning period.
In addition, Idaho Power prepared two probabilistic load forecasts that address the load
variability associated with abnormal weather trends. The 7Off-percentile and 90ft-percentile load
forecasts were developed to assist Idaho Power in reviewing the resource requirements that
would result from higher loads due to variable weather conditions.
The expected case forecast for system load growth is determined by summing the load forecasts
for individual classes of service, as describednAppendix A-Sales and Load Forecast.
2017 tRP Page71
7. Planning Period Forecasts ldaho Power Company
For example, the expected annual average system load growth of 0.9 percent (over the period
2017 through 2036) is comprised of a residential load growth of 1.2 percent, a commercial load
growth of 0.7 percent, an irrigation load growth of 0.6 percent, an industrial load growth of
0.7 percent, and an additional firm load growth of 0.7 percent.
The number of residential customers in Idaho Poweros service area is expected to increase
1.8 percent annually from 444,000 at the end of 2016 to nearly 632,000 by the end of the
planning period in2036. Growth in the number of customers within Idaho Power's service area,
combined with an expected declining consumption per customer, results in a 1.2-percent average
residential load-growth rate.
Significant factors and considerations that influenced the outcome of the 2017 IRP load forecast
include the following:
The load forecast used for the2017 IRP reflects the continuing recovery of the
service-area economy following a severe recession in 2008 and 2009. Customer growth
was at a near standstill urfiil2012, but since then acceleration of net migration and
business investment has resulted in renewed growth. By 2017, customer additions have
approached sustainable growth rates experienced prior to the housing bubble (2000-
2004) and are expected to continue.
The electricity price forecast used to prepare the sales and load forecast in the 2017 IRP
reflects the impact of additional plant investments and associated variable costs of
integrating new resources identified in the 2015 IRP preferred portfolio, including the
expected cost to comply with carbon-emission regulations. Compared to the electricity
price forecast used to prepare the 2015 IRP sales and load forecast, the20lT IRP price
forecast yields lower future prices. The retail prices are most evident after the first
two years of the planning period and can impact the sales forecast positively,
a consequence of the inverse relationship between electricity prices and
electricity demand.
o
a
a There continues to be significant uncertainty associated with the industrial and
special-contract sales forecasts due to the number of parties that contact Idaho Power
expressing interest in locating operations within Idaho Power's service areq
typically with an unknown magnitude of the energy and peak-demand requirements.
The expected load forecast reflects only those industrial customers that have made a
sufficient and signifrcant binding investment indicating a commitment of the highest
probability of locating in the service area. The large numbers of prospective businesses
that have indicated an interest in locating in Idaho Power's service area but have not
made sufficient commitments are not included in the current sales and load forecast.
Page72 2017 tRP
ldaho Power Company 7. Planning Period Forecasts
a
Conservation impacts, including DSM energy efficiency programs and codes and
standards, and other naturally occurring efficiencies are considered and integrated into
the sales forecast. Impacts of demand response progftrms (on peak) are accounted for in
the load and resource balance analysis within supply-side planning (i.e., are treated as a
supply-side peaking resource). The amount of committed and implemented DSM
programs for each month of the planning period is shown in the load and resource
balance in Appendix C-Technical Appendix.
T\e2017 irrigation sales forecast is higher than the 2015 IRP forecast throughout the
entire forecast period due to the significant trend toward more water-intensive crops,
primarily alfalfa and corn, occurring as a result of growth in the dairy industry.
The irrigation sales forecast is higher also as a consequence of renewed production from
high-lift acreage. Additionally, load increases have come from the conversion of
flood/furrow irrigation to sprinkler irrigation, primarily related to efforts to reduce
labor costs.
Weather Effects
The expected-case load forecast assumes median temperatures and median precipitation,
which means there is a 50-percent chance loads will be higher or lower than the expected-case
load forecast due to colder-than-median or hotter-than-median temperatures and wetter-than-
median or drier-than-median precipitation. Since actual loads can vary significantly depending
on weather conditions, two alternative scenarios were analyzed to address load variability due to
weather-706-percentile and 90e-percentile load forecasts. Seventieth-percentile weather means
that in 7 out of 10 years, load is expected to be less than forecast, and in 3 out of l0 years, load is
expected to exceed the forecast. Ninetieth-percentile load has a similar definition with a l-in-10
likelihood the load will be greater than the forecast.
Weather conditions are the primary factor affecting the load forecast on a monthly or seasonal
basis. Over the longer-term, economic conditions, demographic conditions, and changing
technologies influence the load forecast.
Economic Effects
Numerous external factors influence the sales and load forecast that are primarily economic
and demographic in nature. Moody's Analytics serves as the primary provider for this data.
The national, state, metropolitan statistical area (MSA) and county economic and demographic
projections are tailored to Idaho Power's service area using an in-house economic database.
Specific demographic projections are also developed for the service area from national and local
census data. Additional data sources used to substantiate Moody's data include, but are not
limited to, the US Census Bureau, the Bureau of Labor Statistics, the Idaho Deparhnent of
Labor, Woods & Poole, Construction Monitor, and Federal Reserve Economic Databases.
2017 tRP Page 73
7. Planning Period Forecasts ldaho Power Company
The number of households in Idaho is projected to grow at an annual rate of 1.2 percent during
the forecast period. The growth in the number of households within individual counties in
Idaho Power's service area is projected to grow faster than the remainder of the state over the
planning period. The number of households in the Boise City-Nampa MSA is projected to grow
faster than the rest of Idaho, at an annual rate of 1.6 percent during the forecast period. The Boise
MSA (or the Treasure Valley) is an area that encompasses Ada, Boise, Canyon, Gem,
and Owyhee counties in southwestem Idaho. ln addition, the number of households, incomes,
employment, economic output, electricity prices, and customer consumption pattems are used to
develop load projections.
The population in Idaho Power's service area, due to migration to Idaho from other states,
is expected to increase throughout the planning period. This population increase is included in
the load forecast models. Idaho Power also continues to receive requests from prospective
large-load customers attracted to southern Idaho's positive business climate and relatively low
electric rates. In addition, the economic conditions in surrounding states may encourage some
manufacturers to consider moving operations to Idaho.
The2017 IRP average annual system load forecast reflects continued improvement in the
service-area economy. While economic conditions during the development of the 2015 IRP were
positive, the resulting sales forecast was more optimistic than the actual performance
experienced in the interim period leading up to the 2017 IRP. The improving economic and
demographic variables driving the2017 forecast are reflected by a positive sales outlook
throughout the planning period. However, the2017IRP forecast is more moderate, and the
growth path is less steep.
Ave rag e- E n e rgy Lo ad F o rec ast
Potential monthly average-energy use by customers in Idaho Power's service area is defined
by three load forecasts that reflect load uncertainty resulting from different weather-related
assumptions. Figure 7.1 and Table 7.1 show the results of the three forecasts used in the
2017 IRP as annual system load growth over the planning period. There is an approximately
50-percent probability Idaho Power's load will exceed the expected-case forecast, a 30-percent
probability of load exceeding the 70s-percentile forecast, and a 1O-percent probability of load
exceeding the 90th-percentile forecast. The projected 2O-year average compound annual growth
rate in each of the forecasts is 0.9 percent over the 2017 through2036 period.
Idaho Power uses the 7Oft-percentile forecast as the basis for monthly average-energy
planning in the IRP. The 70th-percentile forecast is based on 70th-percentile weather to forecast
average monthly load and 95ft-percentile average peak-day temperature to forecast monthly
peak-hour load.
Page74 2017lRP
ldaho Power Company 7. Planning Period Forecasts
as00
2,no
1,S0
=-6
1,600
1,300
1,m0
700
Figurc 7.1
Table 7.1
1Sl 1S6 1S1 1S6 2fi1 2m6
rWA lessAstaris
-
fxpscted Case
-
90th Percentile
Average monthly loadgrowth forecast
2011 2016 2@.1
-[[g6fier
A{usted--- 70th Percentile
2@6 281 286
Load forccast--ayerage monthly enetgy (aii$4
Year Median 70s Percentite 90fr Percentite
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
203/.
2035
2036
Grourtr Rate (201 7-2036)
1,810
1,840
1,84r
1,874
1,894
1,914
1,935
1,955
1,975
1,990
2,007
2,O18
2,039
2,053
2,067
2,O74
2,095
2,112
2,129
2,142
0.9%
1,853
1,883
1,907
1,918
1,939
1,959
1,981
2,OO1
2,O22
2,037
2,oil
2,066
2,O87
2,102
2,116
2,123
2,145
2,162
2,179
2,'t93
0.9%
1,917
1,%8
1,973
1,984
2,006
2,O27
2,M9
2,070
2,092
2,108
2,126
2,137
2,160
2,175
2,190
2,197
2,220
2,237
2,255
2,269
0.9%
2017 tRP Page 75
7. Planning Period Forecasts ldaho Power Company
Peak-Hour Load Forecast
As average demands as discussed in the preceding section are an integral component to the load
forecast so is the impact of peak-hour demands on the system. Peak-hour forecasts are expressed
as a firnction of the sales forecast, as well as the impact of peak-day temperafures.
The system peak-hour load forecast includes the sum of the individual coincident peak demands
of residential, commercial, industrial, and irrigation customers, as well as special contracts.
Idaho Power uses the 956-percentile forecast as the basis for peak-hour planning in the IRP.
The 95ft-percentile forecast is based on the 956-percentile average peak-day temperature to
forecast monthly peak-hour load.
Idaho Power's system peak-hour load record-3,407 MW-was recorded on July 2,2013,
at 4:00 p.m. The system peak-hour load record was nearly matched on June 30,2015,
at 4:00 p.m., when the system peak reached3,402 MW. Summertime peak-hour load growth
accelerated in the previous decade as A/C became standard in nearly all new residential home
construction and new commercial buildings. System peak demand slowed considerably in 2009,
2010, and 201l-the consequences of a severe recession that brought new home and new
business construction to a standstill. Demand response progrulms operating in the summer have
also had a significant effect on reducing peak demand. The 2017 IRP load forecast projects
peak-hour load to grow by over 50 MW per year throughout the planning period in the
95ft-percentile case. The peak-hour load forecast does not reflect the company's demand
response programs, which are accounted for in the load and resource balance in a manner
similar to a supply-side resource.
Idaho Power's winter peak-hour load record is 2,527 MW, recorded on January 6,2017 ,
at 9:00 a.m., matching the previous record peak dated December 10,2009, at 8:00 a.m.
Historical winter peak-hour load is much more variable than sunmer peak-hour load. The winter
peak variability is due to peak-day temperature variability in winter months, which is far greater
than the variability of peak-day temperatures in summer months.
Figure 7.2 and Table 7.2 summarizetfuee forecast outcomes of Idaho Power's estimated annual
system peak load-median, 90ff percentile, and 95ft percentile. The 95ft-percentile forecast uses
the 95tr-percentile peak-day average temperature to determine monthly peak-hour demand and
serves as the planning criteria for determining the need for peak-hour capacity. The alternative
scenarios are based on their respective peak-day average temperature probabilities to determine
forecast outcomes.
Page 76 2017 tRP
ldaho Power Company 7. Planning Period Forecasts
5,100
4,700
4,300
3,900
3,500
3,100
2,700
2,300
1,900
1,500
1981 1986 '1991 1S6 2fi1 2m6 2011
Actual less Asfa.is
-
flstr;s I
-90th
Percentile 95th Percentile
Peak-hou r loadgrowth forecast (MW)
2016 2U21 2026
-50th
Percentile
2031 2036
Figure 7.2
Table7.2 Load forecast-peak hour (MW)
Year Median 90s Percentile 95s Percentile
2016 (Actual)
2017
2018
20't9
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
203/.
2035
2036
Growth Rate (201 7-2036)
3,327
3,46
3,508
3,567
3,618
3,668
3,722
3,778
3,838
3,888
3,937
3,989
4,U2
4,O92
4,141
4,192
4,239
4,289
4,y2
4,395
4,449
1.4%
3,327
3,566
3,630
3,692
3,745
3,797
3,854
3,912
3,974
4,026
4,O78
4,132
4,187
4,240
4,292
4,W
4,394
4,47
4,502
4,557
4,613
1.4Yo
3,327
3,586
3,651
3,7'.ts
3,766
3,819
3,876
3,934
3,998
4,050
4,',t02
4,157
4,212
4,265
4,317
4,370
4,420
4,474
4,529
4,584
4,641
1.4%
2017 tRP Page77
7. Planning Period Forecasts ldaho Power Company
The median or expected case peak-hotr load forecast predicts that peak-hour load will grow
fuom3,446 MW in 2017 to 4,449 MW in 2036-an average annual compound growth rate of
1.4 percent. The projected average annual compound growth rate of the 95tr-percentile peak
forecast is also 1.4 percent. In the 95tr-percentile forecast, srrnmer peak-hour load is expected to
increase from 3,586 MW in 2017 to 4,641MW in 2036. Historical peak-hour loads, as well as
the three forecast scenarios, are shown in Figure 7.2.
Additional Firm Load
The additional firm-load category consists of Idaho Power's largest customers. Idaho Power's
tariffrequires the company to serve requests for electric service greater than 20 MW under a
special-contract schedule negotiated between Idaho Power and each large-power customer.
The contract and tariff schedule are approved by the appropriate commission. A special contract
allows a customer-specific cost-of-service analysis and unique operating characteristics to be
accounted for in the agreement.
Individual energy and peak-demand forecasts are developed for special-contract customers,
including Micron Technology, Inc.; Simplot Fertilizer Company (Simplot Fertilizer); and the
NL. These three special-contract customers comprise the entire forecast category labeled
additional firm load.
Micron Technology
Micron Technology represents Idaho Power's largest electric load for an individual customer
and employs approximately 5,000 workers in the Boise MSA. The company operates its research
and development fabrication facility in Boise and performs a variety of other activities,
including product design and support; quality assurance (QA); systems integration; and related
manufacturing, corporate, and general services. Micron Technology's electricity use is a function
of the market demand for their products.
Simplot Fertilizer
The Simplot Fertilizer plant is the largest producer of phosphate fertilizer in the western US.
The future electricity usage at the plant is expected to grow slowly through 2017, then stay flat
throughout the remainder of the planning period.
INL
The INL is part of the DOE's complex of national laboratories. The INL is the nation's leading
center for nuclear energy research and development. The DOE provided an energy-consumption
and peak-demand forecast through 2036 for the INL. The forecast calls for loads to increase
through 2024, then levelize through the remainder of the forecast period.
Page 78 2017 tRP
ldaho Power Company 7. Planning Period Forecasts
Generation Forecast for Existing Resources
To identiff the need and timing of future
resources, Idaho Power prepares a load
and resource balance that accounts for
forecast load growth and generation from
the company's existing resources and
planned purchases. Updated load and
resource balance worksheets showing
Idaho Power's existing and committed
resources for average-energy and peak
hour load are shown inAppend* C-
Technical Appendix. The following
sections provide a description of Hells canyon Dam
Idaho Power's hydroelectric, t}ermal,
and transmission resources and how they are accounted for in the load and resource balance.
H y d ro e I e ctri c Reso urces
For the 2017 IRP, Idaho Power continues the practice of using 70tr-percentile future streamflow
conditions for the Snake River Basin as the basis for the projections of monthly average
hydroelectric generation. The 70ft percentile means basin streamflows are expected to exceed the
planning criteria 70 percent of the time and are expected to be worse than the planning criteria
30 percent of the time.
Likewise, for peak-hour resource adequacy, Idaho Power continues to assume 9Oe-percentile
streamflow conditions to project peak-hour hydroelectric generation. The 90ft percentile means
streamflows are expected to exceed the planning criteria 90 percent of the time and to be worse
than the planning criteria only l0 percent of the time.
The practice of basing hydroelectric generation forecasts on worse-than-median streamflow
conditions was initially adopted in the 2002 IRP in response to suggestions that Idaho Power use
more conservative water planning criteria as a method of encouraging the acquisition of
sufficient firm resources to reduce reliance on market purchases. However, Idaho Power
continues to prepare hydroelectric generation forecasts for 50ft-percentile (median) streamflow
conditions because the median streamflow condition is still used for rate-setting purposes and
other analyses.
Idaho Power uses two primary models for forecasting future flows for the IRP. The Snake River
Planning Model (SRPM) is used to determine surface-water flows, and the Enhanced Snake
Plain Aquifer Model (ESPAM) is used to determine the effect of various aquifer management
practices on Snake River reach gains. The two models are used in combination to produce a
2017 tRP Page 79
7. Planning Period Forecasts ldaho Power Company
normalized hydrologic record for the Snake River Basin from 1928 through 2009. The record
is normalized to account for specified conditions relating to Snake River reach gains, water-
management facilities, irrigation facilities, and operations. The 50th-, 70ft-, and 9Oft-percentile
streamflow forecasts are derived from the normalized hydrologic record. Further discussion of
flow modeling for the20lT IRP is included inAppendix C-Technical Appendix.
A review of Snake River Basin streamflow trends suggests that persistent decline documented in
the ESPA is mirrored by downward trends in total surface-water outflow from the river basin.
The current water-use practices driving the steady decline over recent years are expected to
continue, resulting in declining basin outflows assumed to persist well into the 2030s.
The declining basin outflows for this IRP are assumed to continue through the planning period.
A water-management practice affecting Snake River streamflows involves the release of water to
augment flows during salmon outmigration. Various federal agencies involved in salmon
migration studies have, in recent yeurs, supported efforts to shift delivery of flow augmentation
water from the Upper Snake River and Boise River basins from the traditional months of July
and August to the spring months of April, May, and June. The objective of the streamflow
augmentation is to more closely mimic the timing of naturally occurring flow conditions.
Reported biological opinions indicate the shift in water delivery is most likely to take place
during worse-than-median water years. Because worse-than-median water is assumed in the IRP,
and because of the importance of July as a resource-constrained month, Idaho Power continues
to incorporate the shifted delivery of flow augmentation water from the Upper Snake River and
Boise River basins for the IRP. Augmentation water delivered from the Payette River Basin is
assumed to remain in July and August. Additionally, yearly flow augmentation shortages from
the upper Snake River Basin are filled from the Boise River Basin if adequate water is available.
Monthly average generation for Idaho Power's hydroelectric resources is calculated with a
generation model developed internally by Idaho Power. The generation model treats the projects
upstream of the HCC as ROR plants. The generation model mathematically manages reservoir
storage in the HCC to meet the remaining system load while adhering to the operating
constraints on the level of Brownlee Reservoir and outflows from the Hells Canyon project.
For the peak-hour analysis, a review of historical (2001--2016) operations was performed to
estimate the maximum HCC output achieved on an annual basis with 90-percent probability.
A representative measure of the streamflow condition for any given year is the volume of
inflow to Brownlee Reservoir during the April through July runoff period. Figure 7.3 shows
historical April through July Brownlee inflow, as well as forecast Brownlee inflow for the 50tr,
70th, and 90rt percentiles. The historical record demonstrates the variability of inflows to
Brownlee Reservoir. The forecast inflows do not reflect the historical variability but do include
reductions related to declining base flows in the Snake River. As noted previously in this section,
these declines are assumed to continue through the planning period.
Page 80 2017 tRP
ldaho Power Company 7. Planning Period Forecasts
oo+g
C)
E
E
=
13
12
11
10
I
I
7
6
5
4
3
2
1
0
^"tP ^""",.p",N ,"r",s"
+Historiel
-50th
Percentile - - 70h Percentile
-90h
Percentile
Figure 7.3 Brownlee historicaland forecast inflows, April through July
Idaho Power recognizes the need to remain apprised of scientific advancements conceming
climate change on the regional and global scale. Idaho Power believes too much
uncertainty exists to predict the scale and timing of hydrologic effects due to climate change.
Therefore, no adjustments related to climate change have been made in the 2017 IRP.
Further discussion of climate change and expectations of possible effects on Snake River
water supply is available starting on page 64 of the IDACORP Inc. 2016 Form 10-K.
Coal Resources
Idaho Power's coal-fired power plants continue to deliver generating capacity during
high-demand periods. However, production of baseload energy from the company's coal plants
has declined over recent years, a trend mirrored by coal plants across the region and nation.
The decline in baseload energy production is primarily viewed as driven by low natural gas
prices and the expansion of renewable generating capacity; because of the low natural gas prices
and expanded renewable generating capacity, wholesale electric market prices over recent
years have frequently been too low to merit economic dispatch of coal generating capacity.
The challenging economics posed by low wholesale electric market prices, particularly when
coupled with the need for capital investments for environmental retrofits, have increasingly led
owners of coal-fired power plants to evaluate the cost-effectiveness of continued capital
expenditure and continued operation. For the2017 IRP, Idaho Power makes such economic
evaluations for the Jim Bridger and North Valmy coal-fired power plants, as described in the
following sections.
I I
\d I I A
I I l IU6
/\\ a\J
2017 tRP Page 81
7. Planning Period Forecasts ldaho Power Company
While coal-fired power plants over recent years are less frequently dispatched for baseload
energy production, the projected monthly average energy output from the coal plants in the load
and resource balance continues to reflect typical baseload output levels. Because the load and
resource balance is a tool for assessing resource adequacy, rather than a forecast ofactual
resource output, it is appropriate to include the amount of production a resource can produce.
With respect to peak-hour output, the capacity load and resource balance includes the coal-fired
power plants at their full-rated, maximum dependable capacity, minus 6 percent to account for
forced outages. A summary of the expected coal price forecast is included in Appendix C-
Technical Appendix.
Boardman Retirement
The20lT IRP assumes Idaho Power's share of the Boardman plant will not be available for
coal-fired operations after December 31, 2020. This date is the result of an agreement reached
between the ODEQ and PGE related to compliance with regional-haze regulations on particulate
matter, SOz, and NOx emissions.
North Valmy
The preferred portfolio from the 2015 IRP included retirement of both North Valmy units
year-end 2025. The baseline assumption for North Valmy for the 2017 IRP is updated to reflect
retirement of Unit I year-end 2019 andUnit2 year-end 2025. The selection of the preferred
portfolio for the 2015 IRP, including the2025 retirement of both North Valmy units,
was consistent with strategies to manage exposure to qualitative risk factors. The qualitative risk
factors considered in selecting the preferred portfolio for the 2015 IRP included PURPA contract
uncertainty, cooperation with NV Energy on retirement planning,B2H execution, and the Clean
Power Plan. For the2017 IRP, these qualitative risks have diminished.
A review of a North Valmy Unit I shutdown year-end 2019 determined the likelihood of
customer economic benefits associated with the 2019 retirement outweighs the diminished 2015
IRP qualitative risks. The2017 IRP load and resource balance impact of retiring North Valmy
units 1 and2in20l9 and2025, respectively, is mitigated by the assumption that import capacity
across the Idaho-Nevada transmission path will be available. For the 2017 IRP, Idaho Power
assumed new resources will not be required to replace retiring North Valmy units, as the existing
transmission path can satisff hourly peak needs. Further discussion of the viability of wholesale
capacity imports across the Idaho-Nevada transmission path is included in Chapter 6.
Jim Bridger Units 1 and 2 Scenarios
Each of the four Jim Bridger units requires capital investment for retrofitting to comply with
regional-haze regulations. The implementation of these regulations is stipulated in a state
implementation plan (SIP). PacifiCorp and Idaho Power, as joint owners of the Jim Bridger
plant, with the Wyoming Department of Environmental Quality (WDEQ), have developed a plan
to implement the regional-haze regulation. The current SIP stipulates installation of SCR
Page 82 2017lRP
ldaho Power Company 7. Planning Period Forecasts
retrofitting on Jim Bridger units 3 and 4 in 2015 and2016, and on units I and2 n2022 and
2021, respectively. The installation of SCRs on Jim Bridger Units 3 and 4 is complete, and as a
baseline assumption, units 3 and 4 are operating resources through the 2O-year IRP
planning period.
The2017 IRP analyzes four scenarios related to SCR installation on Jim Bridger units I and2.
The scenarios include one in which the SCR investments are made by the required dates in 2021
and2022, and three alternative scenarios in which units I and2 are retired early at varying dates
within the 2O-year IRP planning period. The three early-retirement scenarios are analyzed to
evaluate the economics of altematives to SCR installation and to help guide future discussions
with the WDEQ in developing a SIP for regional-haze compliance. The four scenarios are
as follows:
l. Make the SCR investments and operate Jim Bridger units I and2 through the end of the
planning period.
2. Do not make SCR investments and retire Jim Bridger units I and2 year-end 2028 and
year-end 2024, respectively.
3. Do not make SCR investments and retire Jim Bridger units 1 and2 year'end 2032 ard
year-end 2028, respectively.
4. Do not make SCR investments and retire Jim Bridger units I and2 on their respective
compliance dates of year-end 2022 and year-end 2021.
The four Jim Bridger scenarios are discussed further in Chapter 8
Natural Gas Resources
Idaho Power owns and operates four natural gas-fired SCCTs and one natural gas-fired CCCT.
The SCCT units are typically operated during peak-load events in the swnmer and winter.
The monthly average-energy forecast for the SCCTs is based on the assumption that the
generators are operated at full capacrty for heavyJoad hours during January, June, July, August,
and December and produce approximately 235 aMW of gas-fired generation for the five months.
With respect to peak-hour output, the SCCTs are assumed capable of producing an on-demand
peak capacity of 416 MW. While the peak dispatchable capacity is assumed achievable for all
months, it is most critical to system reliability during sunmer and winter peakJoad months.
Idaho Power's CCCT, Langley Gulch, became commercially available in June 2012. Because of
its higher efficiency rating, Langley Gulch is expected to be dispatched more frequently and for
longer runtimes than the existing SCCTs. Langley Gulch is forecast to contribute approximately
280 aMW, with an on-demand peaking capacity of 300 MW.
2017 tRP Page 83
7. Planning Period Forecasts ldaho Power Company
Natural Gas Price Forecast
Future nafural gas price assumptions significantly influence the financial results of the
operational modeling used to evaluate and rank resource portfolios. For the 2017 IRP,
Idaho Power is continuing to use the EIA as the source for the natural gas price forecast.
Idaho Power reviewed two natural gas price forecast cases reported by the EIA in the 2016
Annual Energy Outlook (AEO): l) the Reference Case and 2) the High Oil and Gas Resource
and Technology Case. These forecasts are reported by the EIA at Henry Hub, which is an
important natural gas distribution hub and pricing point in Louisiana. A graph of historical
Henry Hub prices and the reviewed EIA forecasts is provided in Figure 7.4.
$10.00
$9.00
$8.00
$7.00
$6.00
$5.00
$4.00
$2.00
$1.00
$-
d6
==o
TE
Eotr
$3.00
1997 20@. 2007 2012
-Hi$orical
Henry Hub
-2016
AEO - EIA Rebrence Case
Figure 7.4 Henry Hub natural gas spot price
202 2027 20p.
- - .f16n{ (2009-2016)
-2016
AEO - EIA High Oil & Gas Resource & Technology
2017
Importantly, historical Henry Hub prices beginning in2009 have remained relatively stable and
have even trended slightly downward; the illustrated trendline fit to the annual prices for 2009
through 2016 declines at a rate of $0.20 per year. The natural gas price trends since 2009 are
highly related to marked expansion of natural gas production from shale. Based on natural gas
price trends since 2009 and the coincident expansion of shale gas production, Idaho Power uses
the High Oil and Gas Resource and Technology Case as the planning case natural gas price
forecast for the 2017 IRP; this case is more consistent with recent price trends than the
reference case.
A sensitivity analysis using altemative natural gas price forecasts is described in Chapter 9.
The natural gas price is also included as a risk variable in the stochastic risk analysis performed
on the IRP resource portfolios.
Page 84 2017 tRP
Idaho Power Company 7. Planning Period Forecasts
Idaho Power applies a Sumas basis adjustment and transportation cost to the Henry Hub price to
derive an Idaho Citygate price. The Idaho Citygate price is representative of the gas price
delivered to Idaho Power's natural gas plants. The Idaho Citygate price forecast is provided in
App endix C-T e chni c al Appe ndix.
Analysis of IRP Resources
The electrical energy sector has experienced considerable transformation during the past decade.
Variable energy resources, such as wind and solar, have markedly expanded their market
penetration during this period, and through this expansion they have affected the wholesale
market for electrical energy. The expansion of variable energy resources has also highlighted the
need for flexible capacity resources to provide balancing. A consequence of the expanded
penetration of variable energy resources is periodic energy oversupply alternating with energy
undersupply. Flexible capacity is provided by multiple resources. Dispatchable natural gas-fired
generating capacity is commonly designated as cost-eflectively providing flexible capacity,
particularly during the recent era of low natural gas prices. Transmission resources can be used
to provide balancing by the locational moving of energy from parts of the regional grid
experiencing oversupply to parts experiencing undersupply. Storage resources can provide
balancing by the temporal moving of energy from oversupply periods to undersupply periods.
Demand response resources can also provide balancing by temporally moving the demand for
energy from periods of undersupply to periods of oversupply.
For the 2017 IRP, Idaho Power continues to analyze resources on the basis of cost,
specifically the cost of a resource to provide energy and capacity to the system. The IRP also
qualitatively analyzes resources on the basis of their system attributes. In addition to the
capability to provide flexible capacity, the system attributes analyzed include the capability to
provide dispatchable capacity, non-dispatchable (i.e., coincidental) capacity, and energy.
Importantly, energy in this qualitative analysis is considered to include not only baseload-type
resources but also resources, such as wind and solar, that provide relatively predictable output
when averaged over long periods (i.e., monthly or longer). The resource athibute analysis
also designates those resources whose intermittent production gives rise to the need for
flexible capacity.
Resource Cosfs-IRP Res o u rces
Resource costs are compared using two cost metrics: levelized cost of capacity (fixed)
(LCOC) and levelized cost of energy (LCOE). These metrics are discussed later in this section.
The resource cost analysis performed for the IRP assumes Idaho Power incurs all costs of
ownership and operation, even for resources for which this ownership paradigm has historically
not been typical, such as for geothermal, wind, and solar resources. The assumption that
Idaho Power incurs the total resource costs of ownership and operation allows a like-versus-like
comparison between resources.
2017 tRP Page 85
7. Planning Period Forecasts ldaho Power Company
In resource cost calculations, Idaho Power assumes potential IRP resources have varying
economic lives. Financial analysis for the IRP assumes the annual depreciation expense of
capital costs is based on an apportionment of the capital costs over the entire economic life of a
given resource.
The levelized costs for the various resource altematives analyzed include capital costs,
O&M costs, fuel costs, and other applicable adders and credits. The initial capital invesfrnent and
associated capital costs of resources include engineering development costs, generating and
ancillary equipment purchase costs, installation costs, plant construction costs, and the costs for a
transmission interconnection to Idaho Power's network system. The capital costs also include an
allowance for funds used during construction (AFUDC) (capitalized interest). The O&M portion
of each resource's levelized cost includes general estimates for property taxes and property
insurance premiums. The value of RECs is not included in the levelized cost estimates but is
accounted for when arralyzrngthe total cost of each resource portfolio. The B2H resource
includes an offsetting cost associated with estimated transmission tariffrevenue.
The levelized costs for demand-side resource options include annual program administrative and
marketing costs, an annual incentive, and annual participant costs. The demand-side resource
costs do not reflect the financial effects resulting from the load-reduction programs.
Specific resource cost inputs, fuel forecasts, key financing assumptions, and other operating
parameters are provide d in Appendix C-Te chni c al Appendix.
LCOC-IRP Resources
The annual fixed revenue requirements in nominal dollars for each resource are srmlmed and
levelized over the assumed economic life and are presented in terms of dollars per kW of
nameplate capacity per month. Included in these LCOCs are the initial resource investment and
associated capital cost and fixed O&M estimates. As noted earlier, resources are considered to
have varying economic lives, and the financial analysis to determine the annual depreciation of
capital costs is based on an apportioning of the capital costs over the entire economic life.
The LCOCs for the potential IRP resources are provided in Figure 7.5.B.2H, after netting
out transmission tariff revenue, is the lowest-cost resource in terms of LCOC. Other resources
among those having a lower LCOC include demand response, reciprocating gas engines,
and SCCTs.
Page 86 2017 tRP
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LCOE-IRP Resources
Certain resource altematives carry low fixed costs and high variable operating costs, while other
alternatives require significantly higher capital investrnent and fixed operating costs but have
low (or zero) operating costs. The LCOE metric represents the estimated annual cost
(revenue requirements) per MWh in nominal dollars for a resource based on an expected level of
energy output (capacity factor) over the economic life of the resource. The nominal LCOE
assuming the expected capacity factors for each resource is shown in Figure 7.6. Included in
these costs are the capital cost, non-fuel O&M, fuel, integration costs, and wholesale energy for
transmission and storage resources. Variable costs are offset by transmission tariffrevenue for
B2H, steam sales for CHP, and RECs for renewable-qualiffing resources. B2H is the lowest-cost
energy resource, followed by energy efficiency and natural gas-fired generation (CCCT).
When comparing LCOEs between resources, consistent assumptions for the computations must
be used. The LCOE metric is the annual cost of energy over the life of a resource converted into
an equivalent annual annuity. This is similar to the calculation used to determine a car payment;
however, in this case the car payment would also include the cost of gasoline to operate the car
and the cost of maintaining the car over its useful life.
An important input into the LCOE calculation is the assumed level of annual energy output over
the life of the resource being analyzed. The energy output is commonly expressed as a capacity
factor. At a higher capacity factor, the LCOE is reduced as a result of spreading resource fixed
costs over more MWh. Conversely, lower capacity-factor assumptions reduce the MWh over
which resource fixed costs are spread, resulting in a higher LCOE.
For the portfolio cost analysis, resource fixed costs are annualized over the assumed economic
life for each resource and are applied only to the years of output within the IRP planning period,
thereby accounting for end effects.
Page 88 2017 tRP
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7. Planning Period Forecasts ldaho Power Company
Resourc e Attri b utes-l RP Resources
While the cost metrics described in this section are informative, caution must be exercised when
comparing costs for resources providing different attributes or qualities to the power system.
For the LCOC metric, this critical distinction arises because of differences for some resources
between installed capacity and on-peak capacity. Specifically, for intermittent renewable
resources, an installed capacity of I kW equates to an on-peak capacity of less than I kW.
For example, wind is estimated to have an LCOC of $18 per month per kW of installed
capacity.ls However, assuming wind delivers on-peak capacity equal to 5 percent of installed
capacity, the LCOC ($18/month/kW) converts to $360 per month per kW of on-peak capacity.
For the LCOE metric, the critical distinction between resources arises because of differences for
some resources with respect to the timing at which MWh are delivered. For example, wind and
geothermal have effectively equivalent LCOEs. However, the energy output from geothermal
generating facilities tends to be delivered in a steady and predictable manner, including relatively
dependably during peakJoading periods. Conversely, wind tends to less dependably deliver
during the high-value peak-loading periods; in effect, the energy delivered from wind tends to be
of lesser value than that delivered from geothermal, and because of this difference caution should
be exercised when comparing LCOEs for these resources.
In recognition of differences between resource attributes, potential IRP resources for the
2017 IRP are classified based on their attributes or qualities. The following resource attributes
are considered in this analysis:
a Intermittent renewable-Renewable resources, such as wind and solar, characteized by
intermittent output and causing an increased need for resources providing balancing
or flexibility
a Dispatchable capacity-providing-Resources that can be dispatched as needed to provide
capacity during periods of peak-hour loading or to provide output during generally
high-value periods
a Non-dispatchable (coincidental) capacity-providing-Resources whose output tends to
naturally occur with moderate likelihood during periods of peak-hour loading or during
generally high-value periods
18 The units of the denominator can be expressed in reverse order from the cost estimates provided in Figure 7.5
without mathematically changing the cost estimate.
Page 90 2017 tRP
ldaho Power Company 7. Planning Period Forecasts
Balancing(lexibility-providing-Fast-ramping resources capable of balancing the
variable output from intermittent renewable resources
Energt-providing-Resources producing relatively predictable energy when averaged
over long time periods (i.e., monthly or longer).
Table 7.3 provides classification of potential IRP resources with respect to the above attributes.
The table also provides cost information as graphed previously and the estimated size potential
and scalability for each resource.
a
a
2017 tRP Page 91
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ldaho Power Company 7. Planning Period Forecasts
IRP Resources and Portfolio Design
As described in the following chapter, the portfolio design for the 2017 IRP focuses on
evaluating two key resource actions: the capital investment in environmental retrofits at
Jim Bridger units I and2, and the B2H transmission line. This portfolio design allows the2017
IRP resource portfolios to be composed of resources that most cost competitively test the key
resource actions while providing the necessary system attributes to ensure continued reliability.
Based on Idaho Power's assessment of resource costs and resource attributes, the analysis of IRP
resource portfolios containing natural gas-fired generating capacity (reciprocating engines and
CCCTs), expanded demand response, and single-axis tracking solar PV is consistent with the
portfolio design objectives of the 2017 IRP.
Idaho Power recognizes that resources attaining modest market penetration to date,
particularly electrochemical energy storage technologies (i.e., battery technologies), may become
increasingly cost competitive and in future IRPs outcompete natural gas-fired generating
capacity. Idaho Power values the discussions held during IRPAC meetings related to emerging
technologies and understands that the analysis of a variety of resource technologies,
supply- and demand-side, is vital to long-term planning. The focused portfolio design of the
2017 IRP permits the development of portfolios containing resources demonstrated by today's
analysis to be most cost competitive.
T&D Deferral Benefit Assoctated with DERs
The T&D deferral benefits associated with solar distributed energy resoruces (DER)
were discussed at the T&D Deferral Workshop on December 19, 2016. The main considerations
in determining the potential for solar DERs to defer T&D investments were discussed.
Idaho Power performed a preliminary analysis to determine locations where solar DERs could
result in an asset replacement deferral opportunity.
Several criteria were considered to determine viable candidates for asset deferral:
Summer-peaking assetsa
Peak loads that occur before 4:00 p.m.
Assets that have a use factor at peak greater than or equal to 90 percent
a Load growth rate
o Cost of alternatives
Only two substation transformers and two feeders in Idaho Power's service area fit the
criteria, representing approximately 0.5 percent of the total transfonners and feeders.
a
a
2017 tRP Page 93
7. Planning Period Forecasts ldaho Power Company
However, Idaho Power is aware that the rapid decrease in the cost of solar PV and energy storage
may provide future opportunities for asset replacement deferral. Idaho Power will continue to
look for opportunities where DERs may result in cost-effective asset replacement deferral
opporttrnities in the next few years.
Load and Resource Balance
Idaho Power assumes drier-than-median water conditions and higher-than-median load
conditions in its resource planning process. Targeting a balanced position between load and
resources while using the conservative water and load conditions is considered comparable to
requiring a capacity margin in excess of load while using median load and water conditions.
Both approaches are designed to result in a system having sufficient generating reserve capacity
to meet daily operating reserve requirements.
To identiff the need and timing of future resources, Idaho Power prepares a load and resource
balance that accounts for generation from all the company's existing resources and planned
purchases. For the 2017 IRP, load and resource balances were developed for each of the four
scenarios for Jim Bridger units 1 and2. A baseline assumption in the load and resource balances
is the early retirement of Valmy units 1 and2in2019 arrd2025, respectively. North Valmy units
are assumed to be replaced with market purchases imported across the Idaho-Nevada path.
Each Jim Bridger scenario will include a load and resource balance using average monthly
energy planning assumptions and peak-hour plaruring assumptions.
Average-energy surpluses and deficits are determined using 70s-percentile water and
70tr-percentile average load conditions, coupled with Idaho Power's ability to import energy
from firm market purchases using reserved network capacity.
Peak-hour load deficits are determined using 90th-percentile water and 95s-percentile peak-hour
load conditions. The hydrologic and peak-hour load criteria are the major factors in determining
peak-hour load deficits. Peak-hour load planning criteria are more stringent than average-energy
criteria because Idaho Power's ability to import additional energy is typically limited during
peak-hour load periods.
All load and resource balances include the following:
Existing demand reduction due to the demand response programs and the forecast effect
of existing energy effrciency progftLms.
Expected generation from all Idaho Power-owned resources. The Boardman coal plant
has a planned retirement date of 2020. Additionally, the 2017 IRP includes a baseline
assumption for the early retirement of Valmy Unit I at the end of 2019 and Valmy Unit 2
at the endof 2025.
a
o
Page 94 2017 tRP
ldaho Power Company 7. Planning Period Forecasts
Firm Pacific Northwest import capability, including import capacity over the Idaho-
Nevada path. The northbound capacity of this line has historically been fully subscribed
with Idaho Power's share of energy from the North Valmy generation plant. The load and
resource balance scenarios do not include the import capacity from the B2H transmission
line or the Gateway West transmission line.
a
Existing PPAs with Elkhom Valley Wind, Raft River Geothermal, and Neal Hot Springs.
The agreement with Elkhorn Valley Wind expires at the end of 2027, and a replacement
contract is not contemplated. The agreement with Raft River Geothermal expires at the
end of 2033 and is expected to be replaced. The agreement with Neal Hot Springs does
not expire within the planning period.
Existing PURPA projects and contracts. The 2017 IRP forecast includes all contracts
completed by December 9,2016. Since that time, one biomass project with a nameplate
of 5 MW has been added and is scheduled to come on-line in 2018. Idaho Power assumes
all PURPA contracts, except for wind projects, will continue to deliver energy throughout
the planning period, and the renewal of contracts will be consistent with PURPA rules
and regulations existing at the time the replacement contracts are negotiated.
Wind projects are not expected to be renewed. Currently,627 MW of wind are under
PURPA contract, and contract expirations begin in October 2025. By February 2033,
the total wind under contract drops to 130 MW and remains at that level through the end
of the planning period.
At times of peak summer load, Idaho Power is using all ATC from the Pacific Northwest.
If Idaho Power encountered a significant outage at one of its main generation facilities or a
transmission intemrption on one of the main import paths, the company would fail to meet
reserve requirement standards. If Idaho Power was unable to meet reserve requirements,
the company would be required to shed load by initiating rolling blackouts. Although infrequent,
Idaho Power has initiated rolling blackouts in the past during emergencies. Idaho Power has
committed to a build program, including demand-side programs, generation, and transmission
resources, to reliably meet customer demand and minimizethe likelihood of events that would
require the implementation of rolling blackouts.
Idaho Power's customers reach a maximum energy demand in the sunmer. From a resource
adequacy perspective, July has historically been the month during which Idaho Power's system
is most constrained. Based on projections for the2017 IRP, July is likely to remain the most
resource-constrained month. Table 7.4 provides the monthly average energy deficits, and Table
7.5 provides the monthly peak-hour deficits for July for each of the Jim Bridger futures
considered in the 2017 IRP. Darker shading in the tables corresponds with larger deficits, which
occur more in later years and begin earlier with the retirement of units I and2 in202l and2022,
respectively. Surplus positions are not specified in the tables. Because no deficits exist prior to
2023, the tables include data only for the period 2023 to 2036.
a
a
2017 tRP Page 95
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ldaho Power Company 8. Portfolios
8. PonrroLlos
Portfolio Design
Idaho Power designed the portfolio analysis for the 2017 IRP with the objective of informing the
IRP's Action Plan with respect to two key resource actions: 1) SCR investments required for
Jim Bridger units I and2by 2022 ard202l, respectively, and 2) the B2H transmission line.
To achieve this objective, the portfolio design consisted of four Jim Bridger SCR investment
scenarios, with three resource portfolios formulated within each scenario, resulting in
12 resource portfolios. The SCR investment scenarios sfudy a range of early retirement scenarios
at Jim Bridger units I and2 versus a scenario in which the SCR investments are made. The three
resource portfolios formulated within each SCR investment scenario include one B2H-focused
portfolio and two B2H altemative portfolios. The portfolio design is considered to approximate a
controlled experiment isolating two key factors: 1) the cost-effectiveness of making the SCR
investments versus practicable early retirement altematives and2) the cost-effectiveness of B2H
in meeting resource needs versus practicable resource altematives. This type of portfolio design
is also described as a factorial experimental design. Further discussion of the portfolio design is
provided in Chapter 1 and at the end of this chapter.
To analyze the SCR investments for Jim Bridger, four scenarios were analyzed:
l. Scenario l-Install SCRs and operate Jim Bridger units I and2 through the end of the
planning period.
2. Scenario 2-Do not make SCR investments and retire Jim Bridger units 1 and2 at
year-end 2028 and year-end 2024, respectively.
3. Scenario -l-Do not make SCR investments are retire Jim Bridger units I and2 at
year-end 2032 and year-end 2028, respectively.
4. Scenario 4-Do not make SCR investments and retire Jim Bridger units I and2 on their
respective compliance dates of year-end 2022 and year-end 2021.
The B2H alternative portfolios within each Jim Bridger SCR investment scenario have similar
characteristics: an alternative portfolio containing a mix of solar- and natural gas-powered
generating capacity, and a second alternative containing solely natural gas-powered generating
capacity. Demand response capacity is also added to the B2H alternative portfolios in two steps
in the early- to mid-2020s. The supply- and demand-side resources composing the B2H
altemative portfolios set the highest standard for B2H economics based on current costs.
The portfolio design objective is to determine whether a B2H-based portfolio can be
outperformed based on current cost estimates of alternative resources. The resources judged to
practicably set the highest standard for B2H cost-effectiveness included expanded demand
response, flexible capacity-providing natural gas-fired reciprocating engines, single-axis solar
2017 tRP Page 97
8. Portfolios ldaho Power Company
PV, and natural gas-fired CCCTs. Other potential IRP resources were analyzed and considered
for inclusion in portfolios. However, the inclusion of less cost-effective resources would lower
the standard for the evaluation of B2H.
Capacity needs require the addition of natural gas-powered generating capacity to the B2H-based
portfolios; however, this added generating capacity is relatively small compared to B2H, and the
costs and benefits of the B2H-based portfolios are considered primarily driven by B2H as a
portfolio element. Detailed porrfolio descriptions are provided later in this chapter.
The SCR compliance alternatives considered in this IRP are in recognition of past negotiations
between owners of coal-powered generating units, regulators, and other stakeholders that yielded
a resolution permitting extended operation in exchange for early unit retirement. Idaho Power
views the analyzed compliance altematives as placeholder assumptions representing negotiated
resolutions permitting varying operation extensions. The company does not presuppose
extensions will be necessarily negotiated, nor that specific altematives analyzed in this IRP are
more likely outcomes than other possible early retirement dates.
Energy savings achieved from implementing cost-effective energy efficiency programs and
measures are included in all portfolios prior to the inclusion of supply-side resources.
The forecasted energy savings are based on the assessment performed by AEG for Idaho Power.
The AEG assessment and the projected energy savings are discussed in Chapter 5.
Studied Portfolios
The following sections describe the portfolios analyzed for each Jim Bridger scenario.
All portfolios are designed to balance forecast load with available or additional resources to
eliminate energy and capacity deficits according to the IRP planning criteria described in
Chapter 7. The energy and capacity deficits for the Jim Bridger scenarios are also provided in
Chapter 7.
Jim Bridger Scena rio 1
Three portfolios were developed for the Jim Bridger scenario in which the SCR investments are
made and Jim Bridger units I and2 are operable through the end of the planning period. Pl is the
B2H-based portfolio. P2 is the B2H altemative portfolio containing a blend of solar- and natural
gas-powered generating capacity. The reciprocating engine generating capacity of P2 is
considered to provide the flexible capacity necessary to reliably integrate the solar-powered
capacity of the portfolio. The single-axis solar PV generating capacity is assumed to deliver
peak-hour capacity equal to 51.3 percent of installed (AC) nameplate capacity. The analysis
supporting the assumed peak-hour capacity for solar-powered PV generating capacity is
discussed in Chapter 4. P3 is the B2H altemative portfolio composed of natural gas-powered
generating capacity. In addition to supply-side capacity,P2 and P3 include added demand
response capacity developed in two steps in 2021 and2026.
Page 98 2017 tRP
ldaho Power Company 8. Portfolios
P1
Table 8.1 Pl timeline
Date Resource Installed Capacity (MW) Peak-Hour Capacity (MW)
2026 B2H
2034
2035
2036
500, 200 (Apr-Sep, Oct-Mar
transfer capacity)
500
36
54
54
36
54
54
Reciprocating engines
Reciprocating engines
Reciprocating engines
Total 64 6M
Table 8.2 Pl resource summary
Resource lnstalled Capacity (MW)
B2H (Apr-Sep capacity)
Natural gas
500
144
P2
Table 8.3 P2 timeline
Date Resource !nstalledCapacity Peak-HourCapacity
2021
2026
2027
2027
2028
2028
2029
2029
2030
2030
2031
203',|
2032
2032
2033
2033
2034
2034
2035
2035
2036
2036
Demand response
Demand response
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
25
25
36
13
36
26
36
26
36
26
36
26
36
18
36
31
36
23
36
21
36
23
25
25
36
25
36
50
36
50
36
50
36
50
36
35
36
60
36
45
36
40
36
45
Total*
*lncludes demand response
2017 tRP
850 643
Page 99
8. Portfolios ldaho Power Company
Table 8.4 P2 resource summary
Resource lnstalled Capacity (MW)
Demand response
Solar
Natural gas
50
450
360
P3
Table 8.5 P3 timeline
Date Resource lnstalled Gapacity (MW) Peak-Hour Capacity (MW)
2021
2026
2027
2028
2029
2030
2031
2036
Demand response
Demand response
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
CCCT (1xl)
Reciprocating engines
25
25
54
u
72
54
300
54
25
25
54
54
72
il
300
54
Total*638 638
'lncludes demand response
Table 8.6 P3 resource summary
Resource Installed Capacity (MW)
Demand response
Natural gas
50
588
Jim Bridger Scena rio 2
Three portfolios were developed for the Jim Bridger scenario in which the SCR investments are
not made and Jim Bridger units 1 and2 are permitted to operate through 2028 and2024,
respectively. Within this scenario, P4 is the B2H-based portfolio. P5 is the B2H alternative
portfolio containing a blend of solar- and natural gas-powered generating capacity, including a
300 MW CCCT. P6 is the B2H alternative portfolio composed of natural gas-powered generating
capacity. In addition to supply-side capacity, P5 and P6 include added demand response capacity
developed in two steps in 2021 and2026.
Page 100 2O17IRP
ldaho Power Company 8. Portfolios
P4
Table 8.7 P4 timeline
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2026 B2H 500, 200 (Apr-Sep, Oct-Mar
transfer capacity)
500
72
72
54
54
72
54
54
36
72
72
54
54
72
54
54
36
2029
2030
2031
2032
2033
2034
2035
2036
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Total 968 968
Table 8.8 P4 resource summary
Resource lnstalled Capacity (MW)
B2H (Apr-Sep capacity)
Natural gas
500
468
P5
Table 8.9 P5 timeline
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2021
2025
2025
2026
2026
2026
2027
2027
2028
2028
2029
203',|
203',|
2032
2032
2033
2033
25
54
140
25
18
35
36
45
36
55
300
36
55
36
40
36
55
Demand response
Reciprocating engines
Single-axis solar PV
Demand response
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single'axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single.axis solar PV
Reciprocating engines
Single-axis solar PV
25
54
72
25
18
18
36
23
36
28
300
36
28
36
2',1
36
28
2017lRP Page 101
8. Portfolios ldaho Power Company
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2034
2034
2035
2035
2036
2036
36
23
36
13
36
13
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single.axis solar PV
36
45
36
25
36
25
Total'1,230 977
*lncludes demand response
Table 8.10 P5 resource summary
Resource !nstalled Capacity (MW)
Demand response
Solar
Natural gas
50
660
520
P6
Table 8.11 P6 timeline
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2021
2025
2026
2026
2027
2028
2029
2031
2032
2033
2034
2035
2036
Demand response
Reciprocating engines
Demand response
Reciprocating engines
Reciprocating engines
Reciprocating engines
CCCT (1x1)
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
25
126
25
36
72
54
300
72
54
54
54
54
54
25
't26
25
36
72
54
300
72
54
54
54
54
54
Total*980 980
*lncludes demand response
Table 8.12 Resource P6 resource summary
Resource Installed Capacity (MW)
Demand response
Natural gas
50
930
Page 102 2017lRP
ldaho Power Company 8. Portfolios
Jim Bridger Scenario 3
Three portfolios were developed for the Jim Bridger scenario in which the SCR investments are
not made and Jim Bridger units 1 and2 are permitted to operate through 2032 and2028,
respectively. Within this scenario,PT is the B2H-based portfolio. P8 is the B2H alternative
portfolio containing a blend of solar- and natural gas-powered generating capacity, including two
300-MW CCCTs. P9 is the B2H alternative portfolio composed of natural gas-powered
generating capacity. In addition to supply-side capacity, P8 and P9 include added demand
response capacity developed in two steps in 202t and2026.
P7
Table 8.13 P7 timeline
Date Resource Installed Capacity (MW) Peak-Hour Capacity (MW)
2026 B2H
2031
2032
2033
2035
2036
Reciprocating engines
Reciprocating engines
CCCT (1xl)
Reciprocating engines
Reciprocating engines
500, 200 (Apr-Sep, Oct-Mar
transfer capacity)
36
36
300
54
54
500
36
36
300
54
54
Total 980 980
Table 8.{4 P7 resource summary
Resource Installed Capacity (MW)
B2H (Apr-Sep capacity)
Natural gas
500
480
P8
Table 8.15 P8 timeline
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2021
2026
2027
2027
2028
2028
2029
2031
2031
Demand response
Demand response
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Singleaxis solar PV
CCCT (1x1)
Reciprocating engines
Single.axis solar PV
25
25
36
25
36
50
300
36
50
25
25
36
13
36
26
300
36
26
2017 tRP Page 103
8. Portfolios ldaho Power Company
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2032
2032
2033
2035
2035
2036
2036
Reciprocating engines
Single'axis solar PV
CCCT (1x1)
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
36
35
300
18
55
18
60
36
18
300
18
28
18
31
Total*1,105 972
'lncludes demand response
Table 8.16 P8 resource summary
Resource Installed Capacity (MW)
Demand response
Solar
Natural gas
50
275
780
P9
Table 8.17 P9 timeline
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2021
2026
2027
2028
2029
2031
2032
2033
2035
2036
Demand response
Demand response
Reciprocating engines
Reciprocating engines
CCCT (1xl)
Reciprocating engines
Reciprocating engines
CCCT (1x1)
Reciprocating engines
Reciprocating engines
25
25
54
54
300
72
54
300
36
54
25
25
54
54
300
72
54
300
36
54
Total*974 974
'lncludes demand response
Table 8.18 P9 resource summary
Resource Installed Capacity (MW)
Demand response
Natural gas
50
924
Page 104 2017lRP
ldaho Power Company 8. Portfolios
Jim Bridger Scenario 4
Three portfolios were developed for the Jim Bridger scenario in which the SCR investments are
not made and Jim Bridger units I and2 are retired on their respective compliance dates of year
2022 and year-end 2021. Within this scenario, Pl0 is the B2H-based portfolio. P1l is the B2H
altemative portfolio containing a blend of solar- and natural gas-powered generating capacity,
including two 300-MW CCCTs. P12 is the B2H alternative portfolio composed of natural
gas-powered generating capacity. In addition to supply-side capacity, Pl I and Pl2 include
added demand response capacity developed in two steps in 2021 and2026.
Pl0
Table 8.,l9 P{0 timeline
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2023
2024
2032
2033
203/.
2035
2036
Reciprocating engines
BzH
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
216
500, 200 (Apr-Sep, Oct-Mar
transfer capacity)
54
il
il
il
36
216
500
u
54
il
il
36
Total 968 968
Table 8.20 P10 resource summary
Resource lnstalled Capacity (MW)
B2H (Apr-Sep capacity)
Natural gas
500
468
2017 tRP Page 105
8. Portfolios ldaho Power Company
P11
Table 8.21 Pl1 timeline
Date Resource lnstalled Capacity (MW) Peak-Hour Capacity (MW)
2021
2023
2023
2024
2024
2025
2025
2026
2026
2026
2027
2027
2028
2028
2029
2029
2030
2030
2031
2031
2032
2032
2033
2033
2034
2034
2035
2035
2036
2036
Demand response
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Demand response
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single-axis solar PV
Reciprocating engines
Single.axis solar PV
25
108
155
36
55
36
30
25
18
30
36
50
36
60
36
50
36
50
36
55
36
40
36
55
36
50
18
60
36
25
1
25
08
80
36
28
36
15
36
18
15
36
26
36
31
36
26
36
26
36
28
36
21
36
28
36
26
18
31
36
13
Total*1,355 995
*lncludes demand response
Table 8.22 P11 resource summary
Resource Installed Capacity (MW)
Demand response
Solar
Natural gas
50
765
540
Page 106 20't7 tRP
ldaho Power Company 8. Portfolios
P12
Table 8.23 P12 timeline
Date Resource Installed Capacity (MW) Peak-Hour Capacity (MW)
2021
2023
2026
2026
2027
2028
2029
2030
2031
2036
Demand response
CCCT (1xl)
Demand response
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
Reciprocating engines
CCCT (1x1)
Reciprocating engines
25
300
25
36
72
54
72
54
300
36
25
300
25
36
72
il
72
il
300
36
Total*974 974
*lncludes demand response
Table 8.24 P12 resource summary
Resource Installed Capacity (MW)
Demand response
Natural gas
50
924
Portfolio Design with Two Factors
The portfolio analysis for the 2017IRP is described as a factorial design. This type of
experimental design allows an analysis isolating on two (or more) factors, each factor having
more than one level describing it. The two factors studied in the portfolio analysis with their
respective levels are as follows:
Factor 1: Treatment of Jim Bridger units I and2a
a Level l: Invest in SCRs and operate through 2036
a Level2: Retire Unit I in2028 and Unit 2in2024 (without investing in SCRs)
Level3: Retire Unit I in2032 and Unit 2in2028 (without investing in SCRs)
Level 4: Retire Unit I in2022 and Unit 2 in202l (without investing in SCRS)
2017lRP Page 107
8. Portfolios ldaho Power Company
a Factor 2: Primary portfolio element(s)
Level l: B2H
a
a
Level2: Solar PV/natural gas-fired generation
Level 3 : Natural gas-fired generation
Table 8.25 provides a matrix of the factorial design with the portfolios corresponding to each
factorial combination.
Table 8.25 Factorial design applied to portfolios
Primary Portfolio Element(s)
Treatment of Jim Bridger Units 1 and 2 B2H Solar PV/Natural Gas Natural Gas
lnvest in SCR
Retire Unit 1 in 2028 and Unit 2 in 2024
Retire Unit 1 in 2032 and Unit 2 in 2028
Retire Unit 1 in 2022 and Unit 2 in 2021
P1
P4
P7
P10
P2
P5
P8
P11
P3
P6
P9
P12
Importantly, to validate this design, portfolios must be devised so they can be categorized
according to the studied factor levels. For example, P4, P5, and P6 must all include retirement of
Jim Bridger units I and2 in2028 and2024, respectively. Similarly,P2, P5, P8, and Pl I must all
be characterized as having solar PV and natural gas-fired generation as their primary portfolio
elements. A tabulation of the portfolio analysis results in the form of the factorial design is
provided in Chapter 9.
Page 108 2017lRP
ldaho Power Company 9. Modeling Analysis and Results
9. MooeIING ANALYSIS AND Resuurs
Planning Case Portfolio Analysis
Idaho Power evaluated the net present value (NPV) costs of each resource portfolio over the full
2}-year planning horizon. The resource portfolio cost is the expected cost to serve customer load
using all resources in the portfolio.
The IRP portfolio costs consist of fixed and variable components. The fixed component includes
annualized capital costs for new portfolio resources, including transmission interconnection costs
for new generating facilities, fixed O&M costs, and return on investment (ROI). Capital costs for
new resources are annualized over the resource's estimated economic life. Annualized capital
costs beyond the IRP planning window (2017-2036) are not included in portfolio costs.
Portfolios that consider early retirement of coal units include costs for the accelerated recovery
of depreciation expenses and accelerated recovery of estimated decommissioning and demolition
costs (net of salvage). The costs of coal-retirement portfolios are countered by savings from
avoiding future coal plant capital upgrades and fixed operating expenses beyond the early
retirement dates, including avoidance of environmental retrofit upgrades where applicable.
Idaho Power uses the AURORA electric market model as the primary tool for modeling resource
operations and determining operating costs for the 2}-year planning horizon. AURORA
modeling results provide detailed estimates of wholesale market energy pricing and resource
operation and emissions data.
The AURORA software applies economic principles and dispatch simulations to model the
relationships between generation, transmission, and demand to forecast market prices.
The operation of existing and future resources is based on forecasts of key fundamental
elements, such as demand, fuel prices, hydroelectric conditions, and operating characteristics of
new resources. Various mathematical algorithms are used in unit dispatch, unit commitment,
and regional pool pricing logic. The algorithms simulate the regional electrical system to
determine how utility generation and transmission resources operate to serve load.
Multiple electricity markets, zones, and hubs can be modeled using AURORA. Idaho Power
models the entire WECC system when evaluating the various resource portfolios for the IRP.
A database of WECC data is maintained and regularly updated by the software vendor EPIS Inc.
Prior to starting the IRP analysis, Idaho Power updates the AURORA database based on
available information on generation resources within the WECC and calibrates the model to
ensure it provides realistic results.
2017 tRP Page 109
9. Modeling Analysis and Results ldaho Power Company
Portfolio costs are calculated as the NPV of the 2}-year stream of annualized costs, fixed and
variable, for each portfolio. The full set of financial variables used in the analysis is shown in
Table 9.1. Each resource portfolio was evaluated using the same set of financial variables.
Table 9.1 Financialassumptions
PIant Operating (Book) Life 30 Years
Discount rate (weighted average capital cost)
Composite tax rate
Deferred rate
General O&M escalation rate
Annual property tax escalation rate (% of investment)
Property tax escalation rate
Annual insurance premium (% of investment)
lnsurance escalation rate
AFUDC rate (annual)
6.74o/o
39.10%
35.00%
2.1Oo/o
0.29o/o
3.00%
0.3'to/o
2.OOo/o
7.720/o
Idaho Power is limiting the CAA Section I l1(d) analysis to a state-by-state mass-based
approach. Under state-by-state mass-based compliance, CAA Section l1l(d) proposed
state-specific target reductions are the basis for compliance. Langley Gulch is assumed to be
unconstrained. The proposed target reductions are defined in Table 9.2.
Table 9.2 Proposed target reductions for state-by-state mass-based compliance (ldaho
Power share)
Affected Source
2022-2024
Target MWh
2025-2027
Target MWh
2028-2029
Target M\lVh
2030 and Beyond
Target MWh
Jim Bridger Below 2012
North Valmy Below 2012
3,499,795 (-23%)
790,247 (-3o/o)
3,176,356 (-30%)
737,627 (-9%)
2,986,317 (-34Vo)
715,611 (-12%)
2,873,560 (-37%)
708,848 (-13%)
The planning case natural gas price variable costs, the new resource fixed costs, and the Bridger
units I and2 fixed costs are shown in Table 9.3.
Page 1 10 2017 tRP
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9. Modeling Analysis and Results ldaho Power Company
Natural Gas Price Sensitivities
The planning case natural gas shown in Table 9.3 reflects a2017 IRP lower bound of future gas
prices. An additional eight natural gas price sensitivities described as 125,150,175,200,225,
250,300, and 400 percent of the planning case price were modeled for each of the l2 portfolios.
The natural gas price sensitivities represent a phasing-in of the named percentage over the years
2017 to 2026 and the full named percentage escalation for 2027 to 2036.
f
6
==O
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$6.00
$4.00
$2 00
$0.00
.r'*'
2017 20',18 2019 2020 2021 20n 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 203/. 2035 2036
-flanning
Q656 HH 125 pct Baso
-HH
150 pct Base HH 175 pct Base - - HH 2m pcl Base.. ... . HH 225 pct Base HH 25O pct Base *. .- * HH 3010 pct Base
-
HH 400 pct Base
Figure 9.1 Natural gas planning case and eight sensitivities (nominal $)
The relative difference between the NPV of the lowest-cost portfolio under the natural gas price
planning case and eight higher natural gas sensitivities, along with the rankings of the
12 portfolios under the nine Natural Gas Price forecasts, are shown in Table 9.4 and Table 9.5.
Page 112 2017 tRP
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9. Modeling Analysis and Results ldaho Power Company
Stochastic Risk Analysis
The stochastic analysis assesses the effect on portfolio costs when select variables take on values
different from their planning-case levels. Stochastic variables are selected based on the degree to
which there is uncertainty regarding their forecasts and the degree to which they can affect the
analysis results (i.e., portfolio costs).
Idaho Power identified the following three variables for the stochastic analysis
1. Natural gas price-Natural gas prices follow a log-normal distribution adjusted
upward from the planning case gas price forecast, which is shown as the dashed line in
Figure 9.2. Natural gas prices are adjusted upward from the planning case to capture
upward risk in natural gas prices. The correlation factor used for the year-to-year
variability is 0.60, which is based on historic values from 1997 through 2015.
gl
==O
24
22
20
18
16
14
12
10
8
6
4
2
0
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Figure 9.2 Naturalgas sampling (Nominal $/MMBtu)
_ -:.-
Page 114 2017 tRP
ldaho Power Company 9. Modeling Analysis and Results
2. Customer load-Ctstomer load follows a normal distribution and is adjusted around the
planning case load forecast, which is shown as the dashed line in Figure 9.3.
22,000,000
21,000,000
20,000,000
19,000,000
E 18,000,000
== tz,ooo,ooo
16,000,000
15,000,000
14,000,000
13,000,000
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
Figure 9.3 Customer load sampling (annual MWh)
3. Hydroelectric variabili4r-Hydroelectric variability follows a log-normal distribution
and is adjusted around the planning case hydroelectric generation forecast, which is
shown as the black dashed line in Figure 9.4. The correlation factor used for the year-to-
year variability is 0.50, which is based on historic values from 1975 through 2015.
13,000,000
12,000,000
11,000,000
10,000,000
=
e,ooo,ooo
=8,000,000
7,000,000
6,000,000
5,000,000
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 203/. 2035 2036
Figure 9.4 Hydro generation sampling (annual MWh)
The three selected stochastic variables are key drivers of variability in year-to-year power-supply
costs and therefore provide suitable stochastic shocks to allow differentiated results for analysis.
'!r$ -
2017 tRP Page 1 15
9. Modeling Analysis and Results ldaho Power Company
The purpose of the analysis is to understand the range of portfolio costs across the full extent of
stochastic shocks (i.e., across the full set of stochastic iterations) and how the ranges for
portfolios difter.
Idaho Power created a set of 100 iterations based on the three stochastic variables
(hydro condition, load, and natural gas price). Idaho Power then calculated the 20-year NPV
portfolio cost for each of the 100 iterations for all 12 portfolios. The distibution of 20-year NPV
portfolio costs for all 12 portfolios is shown in Figure 9.5.
Portfolio 1
Portfolio 2
Portfolio 3
Portfolio 4
Portfolio 5
Portfolio 6
Portfolio 7
Portfolio I
Portfolio 9
Portfolio 10
Portfolio 11
Portfolio 12
a o aa
aa
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aa
ao
aa
aa
aa
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$5,200,000 $5,7@,000 $6,200,000 $6,700,000 $7,2m,000 $7,700,000 $8,200,000 $8,700,000
Figure 9.5 Portfolio stochastic analysis, total portfolio cost 12017, NPV, $ millions)
$9,200,000
The horizontal axis on Figure 9.5 represents the portfolio cost (NPV) in millions of dollars,
and the 12 portfolios are represented by their designation on the vertical axis. Each portfolio has
100 dots for the 100 different stochastic iterations scattered across different NPV ranges. P7 is
the lowest-cost portfolio for 92 of the 100 stochastic iterations. P4 is the lowest-cost portfolio for
the remaining eight stochastic iterations.
Table 9.6 is a descriptive statistical table for all 12 portfolios after the NPV is calculated for each
of the 100 stochastic iterations. When calculated for the 100 iterations, P7 ranked the lowest in
average, median, lowest minimum value, and lowest maximum value. P5 ranked the lowest in
the standard deviation value. While P5, with 520 MW of installed solar PV capacity, has the
lowest standard deviation, the approximately $20 million difference between its standard
deviation and that for P7 is small when compared to the $175 million by which average portfolio
costs for P7 are lower than those for P5. The difference in median portfolio costs between P7 and
P5 is even greater at approximately $195 million.
Page 1 16 2017 tRP
ldaho Power Company 9. Modeling Analysis and Results
Table 9.6 AURORA variable + fixed costs (NPV nominaldollars)
Portfolio Average Rank Median
StandardRank Deviation Rank Minimum Rank Maximum Rank
P1
P2
P3
P4
P5
P6
P7
P8
P9
P10
P11
P12
$6,918,595
$6,975,320
$7,036,514
$6,888,487
$7,0/.1,812
$7,040,185
$6,867,722
$7,003,716
$7,000,725
$6,991,750
$7,073,1 1 I
$7,249,564
$6,894,944
$6,956,065
$7,005,725
$6,854,217
$7,026,159
$7,021,875
$6,831,522
$6,980,730
$6,970,350
$6,971,770
$7,071,4U
$7,244,615
$658,486
$o48,41s
$648,272
$661,474
$634,864
$649,384
$655,351
$639,1 07
$643,279
$671 ,318
$644,490
$647,536
$s,505,259
$5,597,7s2
$5,651,871
$5,469,530
$5,686,144
$5,654,847
$5,458,222
$5,638,058
$5,623,483
$s,566,1 08
$5,708,125
$5,880,2s8
$8,839,719
$8,862,931
$8,913,532
$8,794,886
$8,882,295
$8,903,320
$8,766,645
$8,8s0,010
$8,852,332
$8,907,014
$8,934,737
$9,078,774
3
6
10
2
7
I
1
4
5
I
11
12
3
5
8
2
10
9
,|
7
6
4
11
12
10
7
6
11
1
I
9
2
3
12
4
5
3
4
I
2
10
I
1
7
6
5
11
12
3
4
8
2
10
I
1
7
5
6
11
't2
lnvest in SCR
Retire Unit 1 in 2028 and Unit 2 in 2024
Retire Unit 1in2032 and Unit 2in2028
Retire Unit 1in2022 and Unit 2in2021
Portfolio Analysis Results in Factorial Design Format
As discussed in Chapter 8, the portfolio analysis for the 2017 IRP uses a factorial design. Table
9.7 presents the results of the design.
Table 9.7 2017 lRP portfolios, NPV, 2017-2036 ($ x 1,000)
Treatment of Jim Bridger Units I and 2 Average Rank
$6,476,352
$6,471JU
$6,440,765
$6,550,595
Average
Rank
A review of the row averages indicates the lowest-cost level of the factor related to the
treatment of Jim Bridger units I and2 is the 2032 (Untt 1) and 2028 (Unit 2) retirement scenario.
Similarly, reviewing the column averages indicates the B2H-based portfolios are low cost.
These findings support P7 as the low-cost portfolio, but they are also instrumental in allowing
the IRP's portfolio analysis to inform the action plan with respect to the cost-effectiveness of the
SCR investments and B2H.
3
2
1
4
Primary Portfolio Element(s)
Solar PV/
Natural Gas Natural GasB2H
$6,400,696
$6,338,683
$6,335,771
$6,400,507
$6,497,505
$6,566,567
$6,503,524
$6,579,769
$6,530,856
$6,508,242
$6,483,000
$6,671,510
$6,368,915
1
$6,536,842
2
$6,548,402
3
2017 rRP Page 1'17
9. Modeling Analysis and Results ldaho Power Company
Solar Tipping-Point Analysis
At the direction of the IRPAC, a solar tipping-point analysis was performed to evaluate the
sensitivity of the portfolio rankings to a reduction in solar cost. The solar tipping-point analysis
reduces the capital cost of the solar PV included inP2, P5, P8, and Pl I by 50 percent and
100 percent from the base-case capital cost of $1,375 per kW. The impact of the reduced solar
capital costs on the NPV ranking of portfolios is shown in Table 9.8.
Assuming solar capital costs are reduced by 50 percent, P7 and P4 remain the two lowest-cost
portfolios. Pl l, with 765 MW of installed solar capacity, is the third lowest in the 5O-percent
reduction case, moving up eight positions from its ranking under base-case capital costs.
Assuming solar capital costs are reduced by 100 percent (i.e., free solar), Pl l, P5 (520 MW
installed solar), and P2 (450 MW installed solar) are the lowest-ranked portfolios. P7 is the
fourth lowest-cost portfolio in the 100-percent reduction case.
The conclusion is the economic performance of P7 under a reduction in solar costs is
very robust.
Table 9.8 2017 IRP portfolios, NPV, 20{7-2036 ($ x 1,000)
Portfolio Details 100% Reduction
Portfolio
lndex
P11
P12
B2H
Bridger
Capacity
Retirement Rank
Lowest
Cost
Relative
Difference
$290,518
$219,766
$420,678
P1
P2
P3
P4
P5
P6
P7
P8
P9
Portfolio Description
SCR invest, B2H, recips
SCR invest, DR, recips, solar
SCR invest, DR, recips, CCCT
Bridger retire in 24 &28,
B2H, recips
Bridger retire in 24 & 28, DR,
recips, solar
Bridger retire in 24 &28,DR,
recips, CCCT
Bridger retire in 28 &32,B.2H,
recips, CCCT
Bridger retire in 28 & 32, DR,
recips, solar, CCCT
Bridger retire in 28 & 32, DR,
recips, CCCT
Bridger retire in 21 &22,
B2H, recips
Bridger retire in 21 &22,DR,
recips, solar
Bridger retire in 21 &22,DR,
recips, CCCT
7
3
11
P10
4
8
9
5 $228,505
2 $170,539
10 $398,08r
$225,593
$299,982
$372,822
6 $290,329
12 $561,332
50% ReductionPlanning Case
Lowest
Cost
RelativeRank Difference
Lowest
Cost
RelativeRank Difference
4
6
9
$64,925
$161,733
$195,084
5
6
't1
$64,92s
$85,878
$195,084
10 $230,796
8 $172,470
$2,9122
10 $172,470
$2,912
$101 ,391
2
7
$167,7s3
$147,229
1
7
5
$125,487
$147,229
1
8
9
11 $243,998
12 $335,739
$o4,7363
12 $335,739
$64,736
$31,413
4
3
Page 1 18 2017lRP
ldaho Power Company 9. Modeling Analysis and Results
Qualitative Risk Analysis
The quantitative portfolio cost analysis indicates P7 as the lowest-cost portfolio. For the
2017 IRP, Idaho Power is assessing qualitative risk in terms of each portfolio's exposure to
selected qualitative risk factors relative to P7's exposure to the same risk factors.
This comparative analysis recognizes that differing exposure to qualitative risks can lead to the
selection of a preferred portfolio different from the portfolio emerging as the lowest-cost
portfolio from the quantitative analysis. Idaho Power has expanded the qualitative analysis to not
only assess differing exposure to qualitative risks but also differing exposure to qualitative
benefits. The considered qualitative risks and benefits are described in the following sections.
Qualitative Risks
Hydro-Water Supply Risk
The long-term sustainability of the Snake River Basin streamflows is important for Idaho Power
to sustain hydro generation as a resource to meet future demand. Several assumptions related to
the management of streamflows were made in developing the 20-year streamflow forecasts for
the IRP. These assumptions include the following:
The implementation of aquifer management practices on the ESPA, including aquifer
recharge, system conversions, and the Conservation Reserve Enhancement Progtam
(cREP)
o
Future irrigation demand and retum flows
Declines in reach gains tributary to the Snake fuver
Expansion of weather-modification efforts (i.e., cloud seeding).
The assumptions used in developing the 2}-year streamflow forecast are carefully planned and
based on the current knowledge of Idaho Power staffin consultation with other stakeholders.
Those assumptions are also subject to the limitations of the current forecasting models.
Additional risks to future hydro generation not included in the development of the 2D-year
streamflow outlook consist of the following:
a
a
Changes in the timing and demand for irrigation water due to climate variability
Changes to the sources of flow augmentation water and the potential for overestimation
of flow augmentation availability in low-water years
Long-term changes in the timing of flood control releases at Brownlee Reservoir in
response to earlier snowmelt
o
o
o
o
2017lRP Page 119
9. Modeling Analysis and Results ldaho Power Company
The potential for underestimation of the decline in reach gains within the
Snake River Basin
o Changes to funding or the ability to achieve forecasted levels of aquifer management on
the ESPA.
Relicensing Risk
Working within the constraints of the original FERC licenses, the HCC has historically provided
operational flexibility that has benefited Idaho Power's customers. The operational flexibility of
the HCC is increasingly critical to the successful integration of variable-energy resources. As a
result of the FERC relicensing process, operational requirements, such as minimum reservoir
elevations, minimum flows, and limitations on ramping rates, may become more stringent.
The loss of operational flexibility will limit Idaho Power's ability to optimally manage the HCC,
making the integration of variable-energy resources more challenging and ultimately increasing
power-supply costs.
Regulatory Risk
Idaho Power is a regulated utility with an obligation to serve customer load in its service area
and is therefore subject to regulatory risk. Idaho Power expects future resource additions and
removals will be approved for inclusion in the rate base and it will be allowed to earn a fair rate
of ROIs related to resource actions of the IRP portfolios. Idaho Power includes public
involvement in the IRP process through an IRPAC and by opening the IRPAC meetings to the
public. The open public process allows a public discussion of the IRP and establishes a
foundation of customer understanding and support for resource additions and removals when the
plan is submitted for approval. The open public process reduces the regulatory risk associated
with developing a resource plan.
NOx Compliance Alternatives Risk
Six of the 12 portfolios, including P7, assume Jim Bridger units I and2 will be permitted to
operate beyond their regional-haze compliance dates without installation of SCRs.
The remaining six portfolios either assume SCR installation or retirement of the units in 2021
(Unit 2) ard2022 (Unit l) as stipulated by regional-haze requirements. While agreements
permitting operating extensions have been reached in the past, uncertainty remains that such
agreements can be reached for Jim Bridger units I and2. An inability to successfully achieve
permiuing consistent with the assumptions of these compliance alternatives would likely have a
significant effect on the costs and feasibility of portfolios with extended operations without
SCR installation.
Permitting/Siting Risk
Significant challenges are often encountered during permitting and siting for energy resources.
While these challenges are not uniform for all resources or for all proposed resource locations,
a
Page 120 2017 IRP
ldaho Power Company 9. Modeling Analysis and Results
it is nevertheless reasonable to assume all portfolios are exposed to permitting/siting risk,
and no portfolio is markedly less exposed than P7;B2Hplanners have been collaborating with
stakeholders for several years on resolving permitting/siting issues, and while challenges remain,
much progress has been made.
Regional Resource Adequacy
B2H-based portfolios have higher exposure to potential regional resource inadequacies.
However, Idaho Power's review of regional resource adequacy assessments conducted by the
NWPCC and BPA indicates B2H will provide access to a wholesale electric market with
capacity for meeting sufllmer load needs and abundant low-cost energy. Further discussion of the
NWPCC and BPA adequacy assessments is in Chapter 6.
DSM lmplementation
While Idaho Power has considerable experience in DSM programs and has consistently
achieved IRP energy efficiency targets, an implementation risk always exists with a new
progftrm. The actual energy savings and peak reductions may vary significantly from the
estimated amounts if customer participation rates are not achieved.
Technological Obsolescence
The energy industry is experiencing considerable technological innovation, a trend expected to
continue well into the future. This innovation could lead to greater market penetration for
emerging resources and correspondingly drive competing resources to obsolescence.
The determination of competitive resources in the energy industry of the future is highly
speculative. However, current trends support the critical role the electric grid is expected to
continue to play well into the future, with a growing need to move intermittently produced
energy from grid locations experiencing oversupply to those experiencing undersupply.
Moreover, a gnd resource such as B2H positions Idaho Power to participate in the
Pacific Northwest wholesale electric market as the energy sources comprising that market evolve
over the coming decades. Therefore, Idaho Power qualitatively views portfolios without B2H as
having greater exposure to technological innovation than those with B2H.
Qualitative Benefits
Reg iona! Resource Diversity
The Pacific Northwest wholesale electric market is a diverse mix of renewable and thermal
resources. Renewable resources primarily consist of hydropower and wind generation,
with lesser amounts of solar and geothermal. B2H provides expanded access to the
Pacific Northwest wholesale market and its attendant diverse mix of low-cost energy
resources and abundant zero-carbon energy.
2017 tRP Page 121
9. Modeling Analysis and Results ldaho Power Company
Regional Transmission lnitiatives
Idaho Power has a long history of collaboration in regional transmission planning. B2H is a
resource providing value to project co-participants, and also to the region as a whole, with the
spread of automated energy markets, such as the westem EIM. B2H positions Idaho Power and
the region well in furthering the interconnectivity of the regional transmission system.
Transmission Tariff Reven ue
B2H is a critical interconnection to the Pacific Northwest providing Idaho Power access to
low-cost energy, capacity, and balancing. B2H, uniquely among the potential IRP resources
considered, provides revenue in the form of transmission tariffs when used by other entities
during periods Idaho Power is not using it to transfer energy.
Local Economic Effects
The scope of the IRP does not include an analysis of macroeconomic impacts associated with
considered resource portfolios. Therefore, any evaluation of macroeconomic impacts is strictly
qualitative in nature and highly conjectural. Locally sited resources, such as solar PV and natural
gas-fired power plants, can be reasonably linked to localized job growth associated with plant
construction and operation; however, long-term job opportunities associated with plant operation
are expected to be more significant with natural gas power plants than solar PV power plants.
Further, solar PV modules are substantially sourced from overseas markets, whereas fuel for
natural gas power plants relies heavily on domestic production and consequently can be
linked more closely to domestic macroeconomic growth. B2H can be expected to lead to
construction-related job growth. Moreover, B2H, as a source for reliable and low-cost energy,
is consistent with Idaho Power's mission to provide reliable and fair-priced energy services,
qualities recognized as instrumental in promoting economic growth in Idaho Power's
service area.
Summary of Qualitative Risks and Benefits
Table 9.9 and Table 9.10 summarize the relative risks and benefits of the 12 portfolios analyzed.
As noted earlier, the qualitative risk analysis is structured as an assessment of qualitative risks
and benefits in relation to the lowest-cost P7, with the objective of assessing whether qualitative
risk leads to the selection of apreferred portfolio different from P7. The findings of the
qualitative risk analysis do not support the selection of a portfolio other than P7 as preferred.
Page 122 2017 tRP
ldaho Power Company 9. Modeling Analysis and Results
Table 9.9 Qualitative risk analysis
Risk Pl P2 P3 P10 Pll P12
HydreWater Supply Risk
Relicensing Risk
Regulatory Risk
NOx Compliance Alternatives Risk
Permitting/Siting Risk
Regional Resource Adequacy
DSM lmplementation
Technological Obsolescence
< Less risk
> More risk
= Equal risk
Table 9.10 Qualitative benefit analysis
Benefit Pl P2 P3 Pto P1l P12
Regional Resource Diversity
Regional Transmission lnitiatives
Transmission Tariff Revenue
Local Economic Effects
< Less benefit
= Equal benefit
CAA Secfion 111(d)
All 12 portfolios in the 2017 IRP comply with the mass-based carbon-emission regulations as
stipulated in the final rule for Section 1l l(d). While Idaho Power believes carbon-emission
regulations in some form are likely during the next 20 years, the final regulations will likely not
be as modeled in this IRP. Qualitatively, under a non-carbon-constrained future Idaho Power
believes SCR investrnents that extend the time period of coal-fired generation at Jim Bridger
units I and2 would likely result in a better financial outcome for customers. Conversely,
a carbon-constrained future would favor an earlier retirement of the Jim Bridger units and
preclude investment in additional SCRs at Jim Bridger. While uncertainty exists regarding
carbon-emission regulations, Idaho Power is not inclined to pursue a direction toward making the
SCR investments. The additional SCR investments are counter to the findings of the portfolio
analysis, in which portfolios without SCRs on Jim Bridger units I and2 generally performed
beffer. Finally, the company's expressed objectives related to transitioning away from coal-fired
generating capacity weigh against making additional SCR investments at Jim Bridger.
P4 P5 P6 P7 P8 P9
P4 P5 P6 P7 P8 P9
2017 tRP Page 123
9. Modeling Analysis and Results ldaho Power Company
Capacity Planning Margin
Idaho Power discussed planning criteria with state utility commissions and the public in the early
2000s before adopting the present planning criteria. Idaho Power's future resource requirements
are not based directly on the need to meet a specified reserye margin. The company's long-term
resource planning is driven instead by an objective to develop resources sufficient to meet
higher-than-expected load conditions under lower-than-expected water conditions,
which effectively provides a reserve margin.
As part of preparingthe 2017 IRP, Idaho Power calculated the capacity planning margin
resulting from the resource development identified in P7, the preferred resource portfolio.
When calculating the planning margin, the total resources available to meet demand consist of
the additional resources available under the preferred portfolio plus the generation from
existing and committed resources, assuming expected-case (50th-percentile) water conditions.
The generation from existing resources also includes expected firm purchases from regional
markets. The resource total is then compared with the expected-case (50tr-percentile) peak-hour
load, with the excess resource capacity designated as the planning margin. The calculated
planning margin provides an alternative view of the adequacy of the preferred portfolio,
which was formulated to meet more stringent load conditions under less favorable
water conditions.
Idaho Power maintains 330 MW of transmission import capacity above the forecast peak load to
cover the worst single planning contingency. The worst single planning contingency is defined as
an unexpected loss equal to Idaho Power's share of two units at the Jim Bridger coal facility or
the loss of Langley Gulch. The reserve level of 330 MW translates into a reserve margin of over
10 percent, and the reserved transmission capacity allows Idaho Power to import energy during
an emergency via the Northwest Power Pool (NWPP). A 330-MW reserve margin also results
in a loss of-load expectation (LOLE) of roughly I day in 10 years, a standard industry
measurement. Capacity planning margin calculations for July of each year through the planning
period are shown in Table 9.1l.
Page 124 2017lRP
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ldaho Power Company 9. Modeling Analysis and Results
Flexible Resource Needs Assessment
Idaho Power analysis for the 2017 IRP indicates Idaho Power customers and independent power
producers will place increasing flexibility needs on the power system. Idaho Power analyzed
historical dat4 then compared the historical data with a forecast of conditions in 2026.
Flexibility needs increase in most months based on the analysis.
Historical Analysis
Idaho Power analyzed hourly load and hourly energy production from intermittent wind
generation resources during the historical time period 2012through2016.Idaho Power
calculated hourly net load by subtracting hourly wind generation from hourly system load
(there was very limited solar production on Idaho Power's system during the2012 through 2016
time period).
Hourly net load : Hourly load - Hourly wind generation
Idaho Power then calculated the change in hourly net load over four time intervals:
/ Net Loado: Net Load Houro- Net Load Hour-t
/ Net Load-t : Net Load Hourl - Net Load Hour-z
/ Net Load-z : Net Load Hour-z - Net Load Hour-s
/ Net Load-s : Net Load Hour-j - Net Load Hour-t
Idaho Power calculated a flexibility score by averaging the four calculated absolute (ABS)
changes in net load (a four-hour moving average of the hourly change in net load):
Flexibility Score : [ABS(/ Net Loado) + ABS(I Net Load-)
+ ABS(I Net Load-z) + ABS(I Net Load-lJ / 4
The absolute change was used so a significant positive change in one hour coupled with a
significant negative change in an adjoining hour would not cancel the flexibility score
calculation. Significant net load changes in adjoining hours are considered to represent a genuine
need for system flexibility regardless of whether the net load changes are positive or negative.
The five years of historical data yielded approximately 44,000 hourly flexibility scores.
Idaho Power then specified a flexibility threshold:
Flexibility Score >: 100 MW
AND
Flexibility Score/Hourly Net Load >: 0. I 2
2017 tRP Page 127
9. Modeling Analysis and Results ldaho Power Company
The flexibility threshold is used to identifu a specific number of flexibility events. The flexibility
score must be equal to or exceed 100 MW, and the flexibility score must be equal to or greater
than 12 percent of the net system load to be identified as a flexibility event; both criteria must
be satisfied.
The flexibility threshold and resulting number of flexibility events are not based on any specific
system requirements or regulations from NERC, FERC, WECC, or any other regulatory agency
The flexibility events are solely a metric used for comparison purposes. Figure 9.6 shows the
distribution of events where the flexibility score was 100 MW or greater, and Figure 9.7 shows
the distribution of events where the flexibility score was 12 percent of net load or greater.
6,000
5,000
4,000
3,000
2,000
1,000
0 50 100 150 200 250
Flexibility Score (MW)
Distribution of events with flexibility score 100 MW or greater
300
Figure 9.6
16,000
14,000
12,000
1 0,000
8,000
6,000
4,000
2,000
0
Figure 9.7
0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4
Flexibility Score Proportion of System Load
Distribution of events with flexibility score 12 percent of net load or greater
oE
.9
t!uoolto
o
ott
E32
0
o
.9
TEIootto
o
(,ltE
z
Page 128 2017lRP
ldaho Power Company 9. Modeling Analysis and Results
There were slightly over 600 hours during the five-year historical period that exceeded the
flexibility threshold. The 600 hours represent slightly over 1.4 percent of the total hours in the
historical period.
Projected Flexibility Score in 2026
Idaho Power selected 2026 as a test year in the IRP analysis. Idaho Power estimated the
flexibility score for 2026 wingthe same arithmetic techniques that were used to analyze the
2012 tltrough20l6 historical period. Idaho Power used forecast hourly load and forecast
independent power production from intermittent renewable resources. The independent power
production from intermittent resources includes both wind and solar generation facilities in2026.
As with the historical analysis, Idaho Power calculated hourly net load, the change in net load,
the four-hour moving average of the change in net load, and a flexibility score based on the same
flexibility threshold:
Flexibility Score >: 100 MW
AND
Flexibility Score/Hourly Net Load >: 0.12
There are 220 hours projected in2026 that exceed the flexibility threshold, which represent
about 2.5 percent of the hours h2026. Table 9.12 shows the hours exceeding the flexibility
threshold in2026 by month, as well as the results from analyzing the historical period.
Table 9.12 Hourc exceeding flexibility threshold by month
Yearly History, 2012-2016 2026 Forecast
Month Minimum Maximum FIex Score FIex Need*
January
February
March
April
May
June
July
August
September
October
November
December
* Plus signs indicate a forecast change in flexibility need.
I
15
21
17
14
11
I
14
18
26
18
13
I
17
33
20
27
21
13
9
27
30
12
2
1
2
7
4
6
5
3
5
5
7
5
3
+
+
++
+
++
++
+
+
+
2017 tRP Page 129
9. Modeling Analysis and Results ldaho Power Company
Only three months in2026-August, November, and December-are projected to have a
flexibility need approximately equivalent to the flexibility need in the historical period.
Three months-March, May, and June-are projected to have a significant increase in flexibility
need when compared with the historical period. The other six months-January, February, April,
July, September, and October-are projected to have a moderate increase in flexibility need.
March is projected to have the largest number of flexibility events at 33 in the forecast period.
Idaho Power recorded 26 flexibility events in October during the historical period. The increase
in flexibility events is anticipated to be manageable by comparison with the historical period.
Flexibility management will likely require curtailment of intermittent renewable generation at
times to maintain system stability.
The summary conclusion is that the changes in customer load and the increase in independent
power production from intermittent renewable resources will increase Idaho Power's need for
system flexibility in 2026.
Solar Capacity Credit
Idaho Power updated the solar PV peak-hour capacity factors based on guidance from members
of the solar work group in the 2015 IRP. The update used simulated solar generation for water
years 201I through 2013, specifically focusing the analysis on solar generation occurring during
the highest 150 load hours from the three water years.
The solar capacity credit is expressed as a percentage of installed AC nameplate capacity.
The solar capacity credit is used to determine the amount of peak-hour capacity delivered to
Idaho Power's system from a solar PV plant considered as a new IRP resource option. The solar
capacity credit values used in the 2015 and2017 IRPs are reported in Table 9.13.
Table 9.13 Solar capacity credit values
PV System Description Peak-Hour Capacity Credit
South orientation
Southwest orientation
Tracking
28.40/o
45.50/o
51 .3o/o
OPUC Docket No. UM I 719 examined the determination of solar capacity credit in several
recently filed IRPs. The Docket No. UM 1719 settlement agreement required Idaho Power to
conduct an LOLE study, or an approximation method, to validate that Idaho Power's analysis
focusing on the highest 150 load hours adequately defines Idaho Power's capacity timing need.
The LOLE was to include all 8,760 hours of a test year and result in an LOLP for each hour.
Idaho Power selected 2025 for examination using an approximation method for a complete
LOLE study. The evaluation used median hydro and load forecasts and the AURORA hourly
Page 130 2017 tRP
ldaho Power Company 9. Modeling Analysis and Results
preferred portfolio output as a starting point. An Excel workbook was used to simulate 500 years
of random outages. The 500 years of random outages resulted in an LOLE of approximately
2.07 hours per year. The 2.07 hours per year equates to an LOLE of approximately 1 day in l0
years, a frequently used standard in determining a system as resource adequate.
The hourly LOLP of the 500 iterations for 2025 is shown in Table 9.14
Tabte 9.14 Hourly LOLP of 500 iterations tor 2025
Hour Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total
0
1
2
3
4
5
6
7
I
9
10
11
12
13
14
15
't6
17
18
19
20
21
22
23
0.00%
0.00%
0.00%
0.00%
0.00%
0.19%
0.00%
0.68%
1.25o/o
2.41o/o
1.45o/o
0.87o/o
0.77o/o
0.29o/o
0.10%
o.100/o
0.00%
o.10%
0.58%
2.030/o
1.640/o
0.87%
0.39%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
O.O0o/o
0.48o/o
2.600/o
3.47o/o
2.510/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
O.1Oo/o
2.22o/o
3.18o/o
1.25%
't,.350/o
0.58%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.10%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.19o/o
O.1Oo/o
0.39%
0.39%
0.39%
o.'loo/o
0.190/o
0.29o/o
0.48o/o
0.29o/o
0.48o/o
0.39%
O.1Oo/o
0.19%
O.19o/o
0.100/o
0.00%
0.00%
0.00%
0,00%
0.00%
0.00%
0.00%
O.19o/o
o.19%
0.00%
0.19%
0.00%
0.39%
0.19o/o
0.39%
0.19%
0.19%
0.48o/o
0.48o/o
0.290/o
0.19%
0.29o/o
0.00%
0.100/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.19o/o
O.lOo/o
0.48o/o
0.96%
1.06%
2.5',1o/o
1.06%
1.54%
0.87o/o
0.48o/o
O.19o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.39%
0.68%
1.U%
2.80o/o
5.30%
5.79o/o
8.68%
7.520/o
3.28o/o
2.22o/o
0.770/o
O-1Oo/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.19o/o
0.68%
1.35o/o
1.160/o
0.96%
0.480/o
0.190/o
0.19o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.007o
0.00%
0.00%
0.100/o
0.'loo/o
0.10o/o
0.00%
0.10o/o
0.00%
0.58%
0.77%
1.35o/o
0.96%
0.96%
o.77%
0.19o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0-00o/o
0.00%
0,00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
O.1Oo/o
0.00%
0.00%
0.00%
O.1Oo/o
0.00%
0.00%
0.00%
0.00%
0.00%
O.1Oo/o
0.10o/o
0.10o/o
0.19o/o
0.00%
0.00%
0.19o/o
0.00%
0.00%
0.00%
0.00%
0.190/o
0.00%
1.160/o
4.15o/o
6.27o/o
4.',|50/o
f .il%
1.74o/"
1.93%
2.22%
4.15%
8.00%
9.74%
'15.240/o
15.810/"
11.860/o
6.6s%
3.95%
1.06%
Total 14olo 18o/o O% 4% 4% 10% 39"/o 5o/o 6%1o/o 100.00%
A large percentage of the LOLP hours occur in June and July and are coincident with the
150 highest load hours used in defining the capacity credit used in the 2015 and2017IRPs.
However, a number of the LOLP hours occur outside the hourly periods containing the
150 highest load hours. The winter-hour LOLPs are especially interesting. December, January,
and February contain 33 percent of the LOLP hours identified in the study compared to 0 percent
of the hours evaluated in the 150 highest hours.
2017 tRP Page 131
9. Modeling Analysis and Results ldaho Power Company
The distribution of the 150 highest load hours for 2013 to 2015 is given in the following monthly
hour probability table (Table 9.15).
Table 9.15 Monthly probabilities
Hour Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total
0
1
2
3
4
5
6
7
I
I
10
11
12
13
't4
15
16
17
18
19
20
2'l
22
23
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.007o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.00%
0.00%
0.00o/o
0.00o/o
0.00o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.000/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.000/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.00o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0-00o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.670/o
'l .330/o
2.OOo/o
4.OO%
5.33o/o
6.00%
5.33%
6.00%
6.00%
2.670/o
1.33o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0,00%
0.00%
0.00%
0.00%
0.00%
1.330/o
3.33%
5.33%
7.33o/o
8.67o/o
9.33%
8.67o/o
6.670/o
2.67o/o
2.00o/o
0.670/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.00o/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.670/o
0.670/o
1.33o/o
0.670/o
0.00%
0.00%
0,00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0-00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00o/o
0.00%
0.00o/o
0.000/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.000/o
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.670/o
2.67%
5.33%
9.33%
13.33o/o
15.33%
16.00%
15.33%
'i.2.67%
5.33o/o
3.33o/o
0.670/o
Total Oolo 0o/o Oo/o Oo/o 0% 4'lo/o 56% 3o/o Oolo Oo/o Oo/o Oolo 100.00%
The LOLE study identifuing LOLP outside of the 150 highest load hours methodology leads
Idaho Power to re-evaluate the 150-hour methodology and update the solar capacity credit with
the best available information. This analysis will be conducted in the interim between the2017
and20l9IRPs, and resulting updates to the solar capacity credit will be included in the
2019IRP.
LOLE
The solar capacity credit LOLE study Excel workbook described in the preceding section
was also used to evaluate the LOLE sufficiency of Idaho Power's future system plan.
The 500 random outages resulted in an LOLE of approximately 2.07 hours per year.
T\e2.07 hours per year eqwrtes to an approximately l-day-in-I0-years LOLE, a standard used in
determining a system as resource adequate.
Page 132 2017 tRP
ldaho Power Company 10. Preferred Portfolio and Action Plan
10. PnereRRED PoRrroLro AND Acnoru Pleru
Preferred Portfolio
The cost analysis performed for the IRP included an analysis of resource portfolio costs under
planning-case conditions for natural gas price, hydroelectric production, and system load.
The cost analysis also included an analysis of resource portfolio costs under a range of
sensitivities for natural gas price, a key cost driver. A third element of the cost analysis was the
stochastic risk analysis, in which resource portfolio costs were computed for 100 different
iterations (or futures) for the studied stochastic risk variables: natural gas price, hydroelectric
production, and system load. The B2H-based P7 consistently outperformed the other portfolios
in the cost analysis. In addition to the B2H transmission line in2026, P7 includes 180 MW of
reciprocating engines and a 300-MW CCCT in the 2030s. P7 also assumes Jim Bridger
units I and2 are retired early at year-end 2032 and year-end 2028, respectively,
without installing SCRs.
A qualitative risk analysis found thatPT does not carry greater exposure to qualitative risk
factors relative to other resource portfolios. In fact, P7 has unique qualitative benefits in a future
where the electric grid is a critical element to the successful development of automated energy
markets (i.e., westem EIM) and the integration of expanded intermittent renewable resources.
Further, P7 is consistent with Idaho Power's expressed goals related to the measured and
responsible transition away from coal-fired generating capacity. Following the retirement of
Jim Bridger units I and2,Idaho Power's coal-fired generating capacity will have dropped to
approximately one-third of the capacity on-line in2017. Based on the analysis for the 2017 IRP,
P7 is selected as the preferred portfolio. A listing of the resource additions included in P7 is
provided in Table 10.1.
Table 10.1 P7 Resources
Date Resource lnstalled Capacity
2026 B2H 500 MW transfer capacity, Apr-Sep
200 MW transfer capacity, Oct-Mar
36 MW
36 MW
3OO MW
54 MW
54 MW
2031
2032
2033
2035
2036
Reciprocating engines
Reciprocating engines
CCCT (1x1)
Reciprocating engines
Reciprocating engines
Action Plan (2017 -20211
The expressed objective of the portfolio design for the 2017 IRP was to inform the action plan
regarding SCR investrnents at Jim Bridger units 1 and2 and the B2H transmission line.
Idaho Power charucteized these two key resource actions as pivotal to this IRP, recognizingthat
2017 tRP Page 133
'10. Preferred Portfolio and Action Plan ldaho Power Company
an essential function of the 2017 IRP is to inform the direction of these resource decisions.
With respect to B2H, the action plan includes not only actions to continue permitting and
planning, but also necessary preliminary construction and construction activities extending
beyond 2021. These activities are described in Chapter 6.
The IRP portfolio analysis indicates a pivot away from making the SCR investments on
Jim Bridger units I and 2. Therefore, the action plan includes actions consistent with the
planning and negotiations necessary to facilitate the units' continued operation without SCRs and
their ultimate2028 and2032 retirement. A baseline assumption common to all portfolios is the
retirement of North Valmy units 1 and2 at year-end 2019 andyear-end 2025, respectively.
Actions necessary to achieve these North Valmy retirement dates and assess the import
dependability from northem Nevada are included in the action plan.
The Gateway West transmission line continues to be identified as a beneficial future upgrade to
Idaho Power and the region, creating additional capacity and promoting continued grid reliability
in a time of expanding variable energy resources. Therefore, in support of Idaho Power's
agreement with our project partner, PacifiCorp, the action plan includes actions related to the
continued permitting and planning associated with the Gateway West project.
The action plan also includes the following items
Continued pursuit of cost-effective energy efficiency, working with stakeholder groups,
such as EEAG and regional groups, such as the Northwest Energy Efficiency Alliance
(NEEA)
Continued preparation for participation in the western EIM beginning in April20l8
Continued involvement as a stakeholder in CAA Section I I l(d) proceedings or
alternative regulations constraining carbon emissions
a Investigation of solar PV contribution to peak and LOLP for use in the 2019 IRP
Table 10.2 provides actions with dates for the action plan period.
a
a
Page 134 2017 tRP
ldaho Power Company 10. Preferred Portfolio and Action Plan
Table 10.2 Action plan 12017-202111s
Year Resource Action Action Number
2017-2018 EtM
2017-2018
2017-2019
2017-2021
2017-2021
2017-2021
Loss-of-load and solar
contribution to peak
North Valmy Unit 1
Jim Bridger units 1
and2
Energy efficiency
Carbon emission
regulations
2017-2020 B2H
2018-202620 BzH
2017-2021 Boardman
2017-2021 Gateway West
Continue planning for western EIM participation beginning in
April2018.
lnvestigate solar PV contribution to peak and loss-of-load
probability analysis.
Plan and coordinate with NV Energy ldaho Power's exit
from coal-fired operations by year-end 2019. Assess import
dependability from northern Nevada.
Plan and negotiate with PacifiCorp and regulators to achieve
early retirement dates of year-end 2O28 lor Unit 2 and
year-end 2032 for Unit '1.
Conduct ongoing permitting, planning studies,
and regulatory filings.
Conduct preliminary construction activities, acquire long-lead
materials, and construct the B2H project.
Continue to coordinate with PGE to achieve cessation of
coal-fired operations by year-end 2020 and the subsequent
decommission and demolition of the unit.
Conduct ongoing permitting, planning studies,
and regulatory filings.
Continue the pursuit of cost-effective energy efficiency.
Continue stakeholder involvement in CAA Section 11 't (d)
proceedings, or altemative regulations affecting
carbon emissions.
Plan and coordinate with NV Energy ldaho Power's exit
from coal-fired operations by year-end 2025.
2
3
4
1
9
10
11
5
6
7
8
2017-2021 North Valmy Unit 2
ldaho Power and the Utility of the Future
A new energy world, driven by technological innovation and changing customer preferences,
is emerging, one that is efficient, green, resilient, and interconnected. In the new energy world,
conventional generation and increasingly complex grid connectivity will continue to exist and
remain indispensable for ensuring a reliable, round-the-clock supply of power. Idaho Power is
focused on transforming unidirectional powerlines into smart energy networks that incorporate
renewables, providing customers with options while increasing system reliability and resiliency
The company is investing in next-generation communication and monitoring capabilities that
will facilitate the more complex web of power flow that the future will bring. Idaho Power is
re The B2H short-term action plan is 2017 to 2026. All other action plan items are for 2017 to 2021.
20 B2H in-service date of 2024 or later, subject to coordination of activities with project co-participants.
2017lRP Page 135
10. Preferred Portfolio and Action Plan ldaho Power Company
laying the groundwork for future tools that will allow more automated power routing,
self-healing capabilities, and enhanced power quality. The company is incorporating big-data
tools and predictive analyics to anticipate issues, power flow, and usage patterns, etc.,
to facilitate proactive management of issues before they occur. Technological developments and
capabilities will continue to occur at a rapid pace, and Idaho Power is actively, but judicially,
evaluating the costs and benefits of these opportunities to take advantage of them
when appropriate.
Conclusion
The 2017 IRP indicates favorable
economics associated with the B2H
transmission line, the early retirement of
Valmy units 1 and2, and the early
retirement (and corresponding avoided
SCR investments) for Jim Bridger units 1
and2. B2H has been treated as an
uncommitted resource in every IRP
beginning with the 2006 IRP. The20I7
IRP continues to show B2H as a
top-performing resource altemative,
capable of providing low-cost energy and Hemingway Substation
capacity, as well as increasingly critical
flexibility. Moreover, B2H positions Idaho Power and the region well in a future in
which automated energy markets and enabling grid resources are likely to become
increasingly important.
Idaho Power has expressed the objective to transition away from reliance on coal-fired
generating capacity, provided this transition can be conducted in a responsible,
economically beneficial, and measured manner. The findings of the 2017 IRP are consistent
with this objective. The Boardman coal plant is scheduled for a2020 retirement. A baseline
assumption for the IRP is the retirement of North Valmy units I and2 in2019 and2025,
respectively. The preferred portfolio assumes the retirement of Jim Bridger Unit2 in 2028 and
Jim Bridger Unit I in2032. While the North Valmy and Jim Bridger retirement dates are
planning targets and subject to planning considerations with plant co-owners and/or negotiations
with regulatory agencies, it can generally be asserted that over the next l5 years Idaho Power
will retire more than 730 MW of coal-fired generating capacity.
Idaho Power focused the portfolio analysis for the 2017 IRP on the pivotal decisions related to
SCR investments in Jim Bridger units 1 and2 and the B2H transmission line and proffered a
portfolio analysis designed to isolate these factors. However, the company recognizes resources
achieving only modest market penetration to date, including notably electrochemical energy
Page 136 2017 tRP
ldaho Power Company 10. Preferred Portfolio and Action Plan
storage, are likely to achieve greater market penetration in the coming years and may outcompete
the low-cost natural gas-fired resources of today. Idaho Power recognizes the importance of
understanding the cost and value characteristics of all emerging resources to effective long-term
resource planning.
Idaho Power strongly supports public involvement in the planning process. Idaho Power thanks
the IRPAC members and the public for their contributions to the 2017 IRP. The IRPAC
discussed many technical aspects of the 2017 resource plan, along with a significant number of
political and societal topics at the meetings. Idaho Power's resource plan is better because of the
contributions from IRPAC members and the public.
Idaho Power prepares an IRP every two years, and the next plan will be filed in 2019.
The electric energy industry is experiencing what many consider a transformational era,
and undoubtedly new challenges and questions necessarily addressed in integrated resource
planning will be encountered in the 2019 IRP. Idaho Power will monitor the trends in the electric
energy industry and adjust as necessary in the 2019 IRP.
2017 tRP Page 137
10. Preferred Portfolio and Action Plan ldaho Power Company
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Page 138 2017lRP