200912282009 IRP.pdf

BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-09-33
IDAHO POWER COMPANY
ATTACHMENT NO.1
IPC-E-09-33
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2009 Integrated Resource Plan
December 2009
*SIDA~POR~
An IDACORP Company
Acknowledgement
Resource plannng is a continuous process that Idaho Power Company
constantly works to improve. Idaho Power prepares and publishes a
resource plan every two years and expects the experience gained over the
next few years wil lead to modifications in the 20-year resource plan
presented in this document.
Idaho Power invited outside paricipation to help develop the
2009 Integrated Resource Plan (IRP). Idaho Power values the
knowledgeable input, comments, and discussion provided by the Integrated
Resource Plan Advisory Council, and the comments provided by other
concerned citizens and customers.
In recogntion of the amount of time and effort expended by the IRP
Advisory Council, members discussed the possibility of including a
statement in the IRP indicating the advisory council's support of the IRP.
Because the advisory council represents such a diverse set of stakeholders,
the members determined it would not be possible for the group to
unanimously support all aspects of the IRP. However, the members were
supportive of the public process and asked Idaho Power to include the
following statement in the 2009 IRP: "The members of the IRP Advisory
Council support the public process Idaho Power Company conducted as
par of preparng the 2009 IRP."
Idaho Power looks forward to continuing the resource planing process
with its customers and other interested paries. You can learn more about
Idaho Power's resource planning process at ww.idahopower.com.
Safe Harbor Statement
This document may contain forwrd-looking statements. and it is importnt to note that the future results could differ
materially from those discussed. A full discussion of the factors that could cause future results to differ materially can
be found in Idaho Power's filings with the Securities and Exchange Commission.
Idaho Power Company Table of Contents
TABLE OF CONTENTS
List of Tables ...............................................................................................................................................v
List of Figures............................................................ ............................................. .................... ............... vi
List of Appendices.................................................................................................................................... vii
Glossary of Abbreviations............................................................................................................. .......... viii
I. Sumary...................................................................................................... .................................... .......1
Introduction............................................................................................................................................ i
Public Advisory Process........................................................................................................................2
IRP Methodology.......... ....... ............ ......... ............. .............. ............... ..... .............. ..... ... .... ....................3
Demand-Side Management.. ........... .................................. ............ ... ..... ... ............ ..... ................... ..... .....3
Supply-Side Resource Costs........................................ ............ ............ ....... ....................... ...... ........ ......4
Risk Management .......... ....... .......... ..................................................... ..... ....... ..... ... ................. ..... ........4
Greenhouse Gas Emissions....................................................................................................................5
Preferred Resource Portfolio.............. .......... ................ .......... ............. ... ....... ......... ..... ... ............. ...........6
Near-Term Action Plan.......................................................................................................................... 7
Public Policy Issues ...............................................................................................................................8
New Large Loads........... ......................... .............. ............. ............... .... ...... ...... ..... ........................ ..8
Asset Ownership ..............................................................................................................................8
Renewable Energy Credits...............................................................................................................8
Emission Offsets ...... ....... ....... .............. ..... ......... ........ ...... ................ .......... ...... ..... ... ............... ...... ...9
Technology Risk and Joint Development Opportunities .................................................................9
Solar Pilot Project ............................................................................................................................9
2. Political, Regulatory, Operational, and Technology Issues.................................................................. I I
Political and Regulatory Issues.......................................................................................................... ..11
Idaho Energy Plan..........................................................................................................................11
Idaho Strategic Energy Alliance ..................................................................................;.................12
Idaho State Legislatue-Senate Bil 1 123... .............. ................. ....... .......... .............. ........ ...........12
Oregon Renewable Portfolio Stadard ..........................................................................................12
Proposed Federal Energy Legislation....... ................ ............... ...... ..... .......... ........................... ......13
Renewable Energy Credits (Green Tags) ......................................................................................14
FERC Relicensing..........................................................................................................................15
Idaho Water Issues........................................................................................................................ .16
Fixed Cost Adjustment............ ...................................... ............. ..... ................... ........... .... ....... .....17
20091RP Page i
Table of Contents Idaho Power Company
Operational and Technology Issues ..................................................................................................... i 8
Wind Integration....................... .... ................. ................................................................... ....... ......18
Clean Coal Technologies ............................................................................................................... i 9
Storage Technologies.....................................................................................................................20
3. Idaho Power Today ...............................................................................................................................23
Customer and Load Growth.................................................................................................................23
Existing and Committed Resources................................................................................................... ..25
2008 Energy Sources.................................................................................................................... .25
Existing Supply-Side Resources....................... .................. .......................... ... ........ ....... .............. .26
Committed Supply-Side Resources ...............................................................................................36
4. Demand-Side Management..... .................. ............ ....................... ...... ............ ........ ... .......... ........ ... ...... .41
DSM Potential Study.................................. ...................................... ...... ................. ............ ............ ....41
Residential Efficiency Potential.............,........................................................................................42
Commercial Efficiency Potential ...................................................................................................42
Industrial Efficiency Potential .......................................................................................................42
Irrigation Efficiency PotentiaL.......................................................................................................43
Appliance Standard Assessment ..........................................................................................................43
Demand-Side Management Analysis...................................................................................................44
Energy Effciency Cost Effectiveness........... ....... .................... ........... ....................... ................. ..44
Demand Response Cost Effectiveness...........................................................................................45
Energy Efficiency Programs .. ............... ... ............ ....... ..... ..... ... ....... ........... ........ ..... ... ....... .......... ..... ....45
Residential Program Planning......... ... ... ....... ....... ....... ..... ... ....... ....... .............. ... ... ....... .......... ..... ....46
Commercial Program Plannng......................................................................................................46
Demand Response Resources ..............................................................................................................47
5. Planng Period Forecasts..,..................................................................................................................49
Load Forecast.......................................................................................................................................49
Weather Impacts ............................................................................................................................50
Economic Impacts..........................................................................................................................50
Peak-Hour Load Forecast ..............................................................................................................52
Average-Energy Load Forecast .....................................................................................................53
Additional Firm Load ....................................................................................................................55
Planning Scenarios...............................................................................................................................56
Existing Resources....... ........ ..... ........ ............. ...... ................ ............ ..... ... ... .... ......... .......... ..... ... ..... .... .56
Hydro .............................................................................................................................................57
Page ii 20091RP
Idaho Power Company Table of Contents
Thermal..........................................................................................................................................59
Transmission Resources........ ..... ..................... ............... .................... ...... .... ........................ ........ ..60
Natural Gas Price Forecast...................................................................................................................60
Cost of Carbon Emissions....................................................................................................................62
6. Supply-Side Resources.................................................................................. ...... ............................... ..63
Renewable Resources .. ........... ........................................... ... ... ............... ............ ......... .............. .... ..... .63
Geothermal.....................................................................................................................................63
Wind...............................................................................................................................................64
Hydro .............................................................................................................................................64
Solar ...............................................................................................................................................65
Biomass..........................................................................................................................................66
River In-stream Generation............................................................................................................66
Natural Gas-Fired Resources ...............................................................................................................67
Combined-Cycle Combustion Turbines..................................................... ............ ............ ......... ..67
Simple-Cycle Combustion Turbines................ .................... .................................................. ...... ..67
Conventional Coal Resources ..............................................................................................................68
Advanced Nuclear......... ............ ....... ...... ....................... ... ..... ... ....... ........ ............ ....... ....... ... .., ............ .69
Resource Advantages and Disadvantages......................................... ...................................................69
Resource Cost Analysis .......................................................................................................................69
Emission Adders for Fossil Fuel-Based Resources .......................................................................72
Production Tax Credits for Renewable Generating Resources......................................................72
Levelized Capacity (Fixed) Cost ........ .......................... ........................ ...................... ...................72
Levelized Cost of Production......................................................................................................... 73
7. Transmission Resources...... ..... .............................. .............. ................. ............... ......... ........................77
Transmission Interconnections............................................................................................................ 77
Brownlee-East Path........................................................................................................................80
Oxbow-North Path.........................................................................................................................80
Northwest Path...............................................................................................................................80
Montana Path .................................................................................................................................80
Transmission Plannng.........................................................................................................................81
Transmission Adequacy.... ................................................... ................ ................. ....................... ..81
Nortern Tier Transmission Group................................................................................................81
Proposed Transmission Projects ..........................................................................................................82
Boardman to Hemingway ....................................................................................................................83
20091RP Page iii
Table of Contents Idaho Power Company
Gateway West ......................................................................................................................................85
8. Planning Criteria and Portfolio Selection .............................................................................................87
Planing Scenarios and Criteria...........................................................................................................87
Load and Resource Balance.................................................................................................................87
Average Monthly Energy Plannng.............................................................................................. .88
Peak-Hour Planning .......................................................................................................................89
Portfolio Design and Selection ............................................................................................................91
9. Modeling Approach and Assumptions..................................................................................................95
AURORA Setup Enhancements ..........................................................................................................96
Carbon Modeling Approach............................................................................................................... .96
Renewable Energy Credits...................................................................................................................97
Transmission and Market Purchases....................................................................................................98
Regional Transmission Planing (from the NTTG Plan) ..............................................................99
Market Purchase Assumptions..... ........................................ ..................................... ...................100
Economic Evaluation Components and Assumptions ....... ..... ..... ..... ............ ... ........... .......... .......1 0 1
10. Modeling Results and Risk Analysis ................................................................................................103
Portfolio Modeling Results................................................................................................................1 03
Risk Analysis and Results.............................. ...................... .......... .......................... ......... .................1 05
Quantitative Risk Analysis..... ........ ..................... ....... ........ ............. ......... ............................. ......1 05
Qualitative Risk Analysis...................... ........ .............................................................................. 11 I
Preferred Portfolio Selection................... ............................ ......................... .................................. ....114
2010-2019 (Portfolio 1-4 Boardman to Hemingway) .................................................................1 14
2020-2029 (Portfolio 2-4 Wind and Peakers) .............................................................................114
Developing Alternate Portfolios.......... ......... .............. ....... ................ .............. ................. ................. i 15
Capacity Plannng Margin................................................................................................................ .118
Loss of Load Expectation................................................................................................................. .119
I I. Action Plan...................................................................................................................................... ..123
Near-Term Action Plan......................................................................................................................123
Long- Term Action Plan .....................................................................................................................123
Conclusion .........................................................................................................................................125
Page iv 20091RP
Idaho Power Company Table of Contents
LIST OF TABLES
Table 1.1 Preferred Portfolio .............. ....... ......................... ................. ............... ...................... ....... ....... ...6
Table 1.2 Near-Term Action Plan Milestones ...........................................................................................7
Table 2.1 Phase I Measures......................................................................................................................16
Table 3.1 Historical Capacity, Load, and Customer Data .......................................................................24
Table 3.2 Electricity Delivered to Customers (2008) ..............................................................................26
Table 3.3 Existing Resources...................................................................................................................27
Table 4. I Analyzed Appliances and Code Implementation Status ..........................................................43
Table 4.2 Appliance Standard Potential Savings-Idaho Statewide .......................................................44
Table 4.3 New Energy Efficiency Cost Effectiveness Sumary ............................................................45
Table 4.4 Demand Response Cost-Effectiveness Sumary ....................................................................45
Table 5.1 Load Forecast-Peak-Hour (MW) ..........................................................................................53
Table 5.2 Load Forecast-Average Monthly Energy (aMW) .................................................................54
Table 5.3 Planng Criteria for Average Load and Peak-Hour Load ......................................................56
Table 6.1 Supply-Side Resources Advantages and Disadvantages .........................................................70
Table 6.2 Emissions Adder Assumptions ............... .............. .... ....... ...... ... .......... .... ........ ................... ......72
Table 6.3 Emission Adders (lbs/MWh) ...................................................................................................72
Table 7.1 Transmission Interconnections ................................................................................................78
Table 9.1 Financial Assumptions...........................................................................................................102
Table 10.1 AURORA Results and Capital Costs Used in Portfolio Evaluation (2010-2019) ................103
Table 10.2 AURORA Results and Capital Costs Used in Portfolio Evaluation (2020-2029) ................104
Table 10.3 Market Purchases and Sales Sumary (2010-2019).............................................................113
Table 10.4 Market Purchases and Sales Sumar (2020-2029).............................................................113
Table 10.5 Preferred and Alternate Portfolios (2010-2019)....................................................................1 16
Table 10.6 Preferred and Alternate Portfolios (2020-2029)....................................................................116
Table 10.7 Carbon Legislation Costs (2010-2019) .................................................................................117
Table 10.8 Carbon Legislation Costs (2020-2029) .................................................................................117
Table 10.9 Capacity Planing Margin (2010-2019)................................................................................120
Table 10.10 Capacity Planing Margin (2020-2029)..............................................................................121
Table 11.1 Near-Term Action Plan..........................................................................................................123
Table I I .2 Long-Term Action Plan ..... ..... ....... ..... .... .......... .................. ..... ............ ......... ............... ..........124
Table 11.3 Alternate Portfolio Near-Term Action Plan........................................................................... 124
20091RP Page v
Table of Contents Idaho Power Company
LIST OF FIGURES
Figure 1.1 Cost of Existing and New Supply-Side Resources....................................................................4
Figure 3.1 Historical Capacity, Load, and Customer Data .......................................................................24
Figure 3.2 2008 Energy Sources ...............................................~...............................................................26
Figure 3.3 2008 Long-Term Power Purchases by Resource Type............................................................26
Figure 5.1 Peak-Hour Load Growth Forecast ...........................................................................................52
Figure 5.2 Average Monthly Load Growth Forecast ................................................................................54
Figure 5.3 Brownlee Historical and Forecast Infows...............................................................................58
Figure 5.4 Fuel Price Forecast...................................................................................................................61
Figure 6.1 30- Year Levelized Capacity (Fixed) Costs ......... .......... .... .... ....................... ........... .................74
Figure 6.2 30-Year Levelized Cost of Production (at Stated Capacity Factors).......................................75
Figure 7.2 Boardman to Hemingway Line Project Map .............. ........ ............... ............ ....... .... .............. .84
Figure 8.1 Monthly Average Energy SUi'luses and Deficits with Existing Resources
(70thpercentile Water and 70t Percentile Load) .....................................................................88
Figure 8.2 Monthly Average Energy Surluses and Deficits with Existing and Committed
Resources and New DSM (70th Percentile Water and 70th Percentile Load)...........................88
Figure 8.3 Monthly Average Energy S~luses and Deficits with 2009 IRP Resources
(70th Percentile Water and 70t Percentile Load) .....................................................................89
Figure 8.4 Peak-Hour Deficits with Existing Resources (90th Percentile Water and
95th Percentile Load) ............................. ............... ................. .......................... ............... ......... .89
Figure 8.5 Peak-Hour Deficits with Existing and Committed Resources and New DSM
(90th Percentile Water and 95th Percentile Load) .....................................................................90
Figure 8.6 Peak-Hour Deficits with 2009 IRP Resources (90th Percentile Water and
95th Percentile Load) ................................................................................................................90
Figure 8.7 Initial Resource Portfolios (2010-2019)..................................................................................91
Figure 8.8 Initial Resource Portfolios (2020-2029)..................................................................................92
Figure 9.1 Average Anual Generation from Coal Resources..................................................................97
Figure 9.2 Waxman-Markey RES Requirements and Portfolio RECs.....................................................98
Figure 9.3 Northern Tier Transmission Group Planed Transmission Additions ..................................100
Figure 10.1 REC-Forward Price Cure.................................................................................................106
Figure 10.2 Natural Gas Price Forecast...................................................................................................107
Figure 10.3 Boxer-Kerry Carbon Allowance Price Cap and High Case Scenario..................................l08
Figure 10.4 Average Monthly Load Growth Forecast............................................................................109
Figure 10.5 Cumulative Portfolio Risk (2010-2019) ..............................................................................110
Figure 10.6 Cumulative Portfolio Risk (2020-2029) ..............................................................................111
Page vi 20091RP
Idaho Power Company Table of Contents
Figure 10.72019 Supply-Side Resources................................................................................................115
Figure 10.82029 Supply-Side Resources................................................................................................115
Figure 10.9 Carbon Allowance Cost and Portfolio Costs........................................................................118
Figure 10.10 Loss of Load Expectation...................................................................................................119
LIST OF ApPENDICES
Appendix A-Sales and Load Forecast
Appendix B-Demand-Side Management 2008 Anual Report
Appendix C- Technical Appendix
20091RP Page vii
Glossary of Abbreviations Idaho Power Company
GLOSSARY OF ABBREVIATIONS
AC-Alternating Current
A/C-Air Conditioning
ADI-Ace Diversity Interchange
AFUDC-Allowance for Funds Used During Constrction
AMPS-Associated Mountain Power System
aMW-Average Megawatt
B2H-Boardman to Hemingway Transmission Project
BLM-Bureau of Land Management
BOR-Bureau of Reclamation
BP A-Bonnevile Power Administration
Btu-British Thermal Unit
CAMP-Comprehensive Aquifer Management Plan
CAP-Community Advisory Process
CBM-Capacity Benefit Margin
CCCT -Combined-Cycle Combustion Turbine
CHP-Combined Heat and Power
Clatskane PUD-Clatskanie People's Utilty District
COi-Carbon Dioxide
CPCN-Certificate of Public Convenience and Necessity
CREP-Conservation Reserve Enhancement Program
DC-Direct Curent
DOE-Department of Energy
DG-Distributed Generation
DRAM-Dynamic Random Access Memory
DSM-Demand-Side Management
EA-Environmental Assessment
EEAG-Energy Effciency Advisory Group
EIA-Energy Information Administration
EPRI-Electric Power Research Institute
ESA-Endangered Species Act
ESP A-Eastern Snake River Plain Aquifer
F-Fahenheit
FCA-Fixed-Cost Adjustment
Page viii 20091RP
Idaho Power Company Glossary of Abbreviations
FCP-F ormal Consultation Package
FCRPS-Federal Columbia River Power System
FERC-Federal Energy Regulatory Commission
FPA-Federal Power Act
GHG-Greenhouse Gas
GW-Gigawatt
HRSG-Heat Recovery Steam Generator
ICIP-Industrial Customers of Idaho Power
IDWR-Idaho Department of Water Resources
IGCC-Integrated Gasification Combined Cycle
INL-Idaho National Laboratory
IOER-Idaho Offce of Energy Resources
IPUC-Idaho Public Utilities Commission
IRP-Integrated Resource Plan
IRP AC-IRP Advisory Council
kV-Kilovolt
kW-Kilowatt
kWh-Kilowatt Hour
lbs-Pounds
LED-Light-Emitting Diode
LOLE-Loss of Load Expectation
LT -Long Term
MIT-Massachusetts Institute of Technology
mm-Milimeter
MMBTU-Milion British Thermal Units
MSA- Metropolitan Statistical Area
MW-Megawatt
MWh-Megawatt Hour
NEEA-Northwest Energy Effciency Allance
NEo-Northeast Oregon
NEPA-National Environmental Policy Act
NiCd-Nickel Cadmium
NTTG-Northern Tier Transmission Group
NPCC-Northwest Power and Conservation Council
20091RP Page ix
Glossary of Abbreviations Idaho Power Company
NOx-Nitrogen Oxide
NOI-Notice of Intent
NPV-Net Profit Value
NREL-National Renewable Energy Laboratories
NYMEX-New York Mercantile Exchange
O&M-Operating and Maintenance
OATT -Open Access Transmission Tariff
OPUC-Public Utility Commission of Oregon
PCA-Power Cost Adjustment
PCC-Planing Coordination Council
PM&E-Protection, Mitigation, and Enhancement
PGE-Portland General Electric Company
PP A-Power Purchase Agreement
PTC-Production Tax Credit
PURP A-Public Utility Regulatory Policies Act of 1978
PV -Photovoltaic
QF-Qualifying Facilty
REC-Renewable Energy Credit
RES-Renewable Electricity Standard
RFP-Request for Proposal
RISEC-River In-Stream Energy Conversion
RPS-Renewable Portfolio Standard
SAR-Surrogate Avoided Resource
SCCT -Simple Cycle Combustion Turbine
SMES-Superconducting Magnetic Energy Storage
SOi-Sulfu Dioxide
SRBA-Snake River Basin Adjudication
TEPPC- Transmission Expansion Planing Policy Committee
UAMPS-Utah Associated Muncipal Power Systems
U.S. Ary COE-United States Army Corps of Engineers
USFWS-United States Fish and Wildlife Service
USFS-United States Forest Service
VRB Vanadium Redox Battery
W ACC- Weighted Average Cost of Capital
Page x 20091RP
Idaho Power Company Glossary of Abbreviations
W AQC- Weatherization Assistance for Qualified Customers
WECC- Western Electricity Coordinating Council
20091RP Page xi
Idaho Power Company 1. Summary
1. SUMMARY
Introduction
The 2009 Integrated Resource Plan (IRP) is Idaho Power's ninth resource plan prepared to fulfill the
regulatory requirements and guidelines established by the Idaho Public Utilities Commission (IPUC)
and the Public Utility Commission of Oregon (OPUC).
The 2009 IRP assumes that during the planning period (2010-2029), Idaho Power wil continue to be
responsible for acquiring resources sufficient to serve all of its retail customers in its mandated Idaho
and Oregon service areas and that the company will continue to operate as a vertically integrated electric
utility. In developing this plan, Idaho Power has worked with the IRP Advisory Council (IRP AC),
comprised of major stakeholders representing the environmental community, major industrial customers,
irrgation customers, state legislators, public utility commission representatives, and others. There are
four primary goals of Idaho Power's planng process.
1. Identify sufficient resources to reliably serve the growing demand for energy within Idaho Power's
service area throughout the 20-year planng period
2. Ensure the selected resource portfolio balances cost, risk, and environmental concerns
3. Give equal and balanced treatment to both supply-side resources and demand-side measures
4. Involve the public in the plannng process in a meaningful way
Idaho Power is responsible for providing safe and reliable electrical service to its service area, which
includes most of southern Idaho and a portion of eastern Oregon. In addition to operating under
the regulatory oversight of the IPUC and the OPUC, Idaho Power is a public utilty under the
jurisdiction of the Federal Energy Regulatory Commission (FERC) and is obligated to plan for and
expand its transmission system to provide requested firm transmission service to third parties, and to
construct and place in service sufficient transmission capacity to reliably deliver resources to network
customers i and native load customers
2 . The 2009 IRP only evaluates the need for additional
transmission capacity necessary to serve native load customers. The total capacity of proposed
transmission line projects may be larger than identified in the IRP in order to accommodate third-party
requests and network customer obligations for capacity on the same transmission path.
i Idaho Power has a regulatory obligation to constrct and provide transmission service to network or wholesale customers
pursuant to a FERC Tariff.
2 Idaho Power has a regulatory obligation to constrct and operate its system to reliably meet the needs of native load or
retail customers.
20091RP Page 1
1. Summary Idaho Power Company
The number of customers in Idaho Power's service area is expected to increase from around 486,000 in
2008 to over 680,000 by the end of the planing period in 2029. Even with the curent recession,
population growth in Idaho Power's service area wil require the company to add physical resources to
meet the energy demands of its growing customer base.
With hydroelectric generation as the foundation of its energy production, Idaho Power has an obligation
to serve customer loads regardless of the water conditions that may occur. In light of public input and
regulatory support ofthe more conservative plannng criteria used in the 2002 IRP, Idaho Power wil
continue to emphasize a resource plan based upon a worse-than-median level of water. The IRP uses
more conservative planning criteria than median water planning, but the criteria are less conservative
than critical water planning. Furher discussion of Idaho Power's planning. criteria can be found in
Chapter 8.
Idaho Power extended the planning horizon in the 2006 IRP to 20 years. Prior Idaho Power IRPs used a
10-year planing horizon, but with the increased need for baseload resources with long construction lead
times along with the need for a 20-year resource plan to support Public Utilities Regulatory Policies Act
(PURP A) contract negotiations, Idaho Power and the IRP AC decided to extend the planing horizon of
the 2006 and future resource plans to 20 years.
Planing for the futue is necessar to meet the needs of Idaho Power's customers today and tomorrow.
While the 2009 IRP addresses Idaho Power's long-term resource needs, the company plans for the
near-term through the Energy Risk Management Policy that was collaboratively developed in 2002
between Idaho Power, the IPUC staff, and interested customers (IPUC Case No. IPC-E-01-16).
While the IRP has a planning horizon of 20 years and is updated every two years, the Energy Risk
Management Policy focuses on an 18-month period and is updated every month.
Public Advisory Process
Idaho Power has involved representatives of the public in the IRP planning process since the early
1990s. In earlier years, the public foru was called the Technical Advisory PaneL. Idaho Power revised
the public involvement process and formed the IRP AC when preparing the 2004 IRP and has continued
working with the council in the preparation of the 2006 and 2009 resource plans.
The IRP AC generally meets monthly during the development of the IRP and the meetings are open to
the public. Members of the council include political, environmental, and customer representatives,
as well as representatives of other public interest groups. A list of the IRP AC members can be found in
Appendix C-Technical Appendix. Idaho Power continued the public involvement process for the
2009 IRP and the IRP AC meetings served as an open foru for discussions related to the development
of the IRP. The IRPAC members and the public have made significant contributions to the 2009 IRP.
Idaho Power has found that working with members of the IRP AC and the public has been very
rewarding and the company believes the 2004, 2006, and the 2009 IRPs are better because of the public
involvement. Idaho Power and the members of the IRP AC recognize that outside perspective is
valuable, but also recognize that final decisions on the 2009 IRP are made by Idaho Power. Idaho Power
encourages IRP AC members and members of the public to submit comments expressing their views
regarding the 2009 IRP and the planning process in general.
Following the filing of the final plan, Idaho Power presents the IRP at public meetings in various cities
around the company's service area. In addition, Idaho Power staff presents the resource plan and
discusses the planning process with various civic groups and at educational seminars as requested.
Page 2 20091RP
Idaho Power Company 1. Summary
IRP Methodology
The preparation of Idaho Power's 2009 IRP begins with updating the forecast of future customer
demand. Existing resources, the ability to import electricity, and the performance of existing
demand-side management (DSM) programs are then accounted for in the load and resource balance.
The next step involves evaluating new DSM programs and the expansion of existing programs.
Idaho Power is committed to implementing all cost-effective DSM programs and the impact of the new
programs is accounted for in the load and resource balance. Finally, Idaho Power evaluates portfolios of
supply-side resources designed to eliminate any remaining deficits.
Idaho Power primarily uses a financial analysis to compare various resource portfolios in order to
determine the preferred portfolio. Idaho Power attempts to financially value all of the resource costs and
benefits. Traditional resources have both a fuel cost and a market value for the delivered energy and
Idaho Power includes both the cost and the value when evaluating resources. Furher, the value of
renewable energy credits (REC) is also included in the financial analysis.
Each resource portfolio is designed to substantially meet the energy and capacity deficits identified in
the load and resource balance. Idaho Power continues to face load and resource deficits during the next
few years, but each resource portfolio meets the energy and capacity requirements after the 2013 time
period.
Three resources identified in the 2006 IRP are considered committed resources in the 2009 IRP-
1) the Langley Gulch combined-cycle combustion turbine (CCCT) that will be used as a dispatchable
resource, 2) up to 150 megawatts (MW) of wind generation from the 2012 Wind Request for Proposals
(RFP), and 3) two 20 MW increments of geothermal energy coming on-line in 2012 and 2016.
For the 2009 IRP, the 20-year planning period was divided into two lO-year segments. Dividing the
planning period into these two segments prevents near-term resource decisions from being influenced by
the availability of resources that are dependent on technological advancements in the second 10 years.
In the first 10-year period (2010-2019), four resource portfolios were examined. The preferred resource
portfolio from the first 10-year period was coupled with a variety of portfolios containing advanced
technologies in the second 10-year period. Using the preferred portfolio from the first 10-year period
insures that all of the advanced technologies are considered equally in the second 10-year period. It is
not necessary for Idaho Power to commit to a single advanced technology at the present time.
Idaho Power anticipates discussing its preferred long-term portfolio options with other Pacific
Northwest utilities over the next several years and is contemplating forming a regional partership to
further explore some of the more promising advanced technologies.
Demand-Side Management
New energy efficiency programs included in the 2009 IRP are forecast to reduce average load by
127 aMW by 2029, which represents a 53 percent increase over the measures included in the 2006 IRP.
New energy efficiency measures come from a combination of new Idaho Power programs,
new measures recommended in the 2009 potential study performed by Nexant, Inc., and a review of
measures included in the Northwest Power and Conservation Council's (NPCC) Draft 6th Power Plan.
New and expanded demand response programs developed as part of the 2009 IRP are expected to reduce
peak sumer load by 323 MW by 2012 when the programs matue. This reflects tremendous growth
over 2006 IRP forecasts where demand response programs were estimated to provide 78 MW of peak
reduction by 2026. The large increase comes from the introduction of the FlexPeak Management
program which targets commercial and industrial customers and also the transition of the Irrigation Peak
Rewards program into a dispatchable, direct load control program.
20091RP Page 3
1. Summary Idaho Power Company
Chapter 4 contains details on Idaho Power's existing and proposed DSM programs, and
Appendix A-Sales and Load Forecast contains the forecast performance of energy efficiency and
demand response programs by customer class.
Supply-Side Resource Costs
The 2009 IRP forecasts load growth in Idaho Power's service area and identifies supply-side resources
and demand..side measures necessar to meet the future needs of customers. Recent cost increases have
significantly impacted the cost of new supply-side resources, especially when compared to the cost of
the existing resources in Idaho Power's generation portfolio. Figue i. i shows the 2008 costs in dollars
per megawatt hour (MWh) for Idaho Power's existing hydroelectric resources, coal generation facilities,
and power purchased from the Elkhorn Valley Wind Project. In addition, Figure 1.1 shows the estimated
cost of new resources considered in the 2009 IRP. Existing resource costs are based on 2008 actual costs
of capital, fuel, and non-fuel operating and maintenance (O&M). New resource costs are 30-year
levelized estimates (based on expected anual generation), which include capital, fuel, non-fuel O&M,
plus a cost of $43 per ton for carbon-emitting resources.
Figure 1.1 Cost of Existing and New Supply-Side Resources
$300
$250 New Reso urces
$50
$200.c
s:
~$150
$100
$0
Hydro Coal Wind Wind Combined- Geothermal Solar Power AdvancedCycle Natural Tower Nuclear
Gas
IGCC SolarPV
NOTES:1) Cos of exsting resurce bad on 20 costs
2) Cos of ne resurce bad on 3Oyear levlized co esimates
3) Cos of exsting wind is fo th Elkhorn Wind Projec oiy (Elkhorn produc apoxmately80 pecent of the wind genation purchasd by Idaho Power during 20).
In 2008, 78 percent of Idaho Power's electricity came from existing, low-cost hydroelectric and coal
resources. These resources are the primary reason Idaho Power has historically had some of the lowest
retail electric rates in the country. As Idaho Power adds new resources in the future, either due to load
growth or reduced generation from coal facilities, power supply expenses and customer rates are going
to increase. Additional discussion regarding new resources and associated costs is presented in
Chapter 6 of the 2009 IRP.
Risk Management
Long-term resource planning requires many assumptions regarding futue conditions. Forecasts for load
growth, DSM program performance, fuel prices, and many other factors are required as par of the
planing process. Due to the amount of uncertainty in preparing these forecasts, risk factors are
evaluated in the 2009 IRP as part of determining the preferred portfolio. Risk factors are evaluated by
performing sensitivity analyses on each portfolio.
Page 4 20091RP
Idaho Power Company 1. Summary
The load forecast used for the 2009 IRP reflects the curent economic recession as well as the potential
impact of carbon regulation on future energy rates charged to Idaho Power customers. Both of these
factors resulted in a load forecast substantially lower than seen in recent years. To evaluate the risk
associated with higher-than-expected load growth, the 2009 IRP includes an analysis of a high load
growth scenario where projected load growth continues at historical levels.
In the 2009 IRP, considerable energy efficiency measures and demand response programs are expected
to reduce future load growth. In the event these programs do not develop and perform as planed, a low
conservation scenario was analyzed as par of the 2009 IRP risk analysis.
Natural gas prices are highly correlated to market energy prices in the Pacific Northwest as gas
resources typically represent the marginal resource in the region. Natural gas price volatility, as well as
higher than forecast prices, have been analyzed in Idaho Power's previous IRPs. The natural gas price
analysis is also included in the 2009 IRP.
Idaho Power believes some form of carbon regulation wil be enacted in the near future. However,
there is stil a great deal of uncertainty on how the regulation wil be implemented and what the costs
wil be. In the 2009 IRP, Idaho Power has attempted to quatify the impact of a carbon tax scenario as
well as a cap-and-trade scenario based on the provisions contained in the Waxman-Markey bil
(H.R. 2454). In addition to the Waxman-Markey bil passed by the U.S. House of Representatives in
June 2009, the Boxer-Kerr bil (S. 1733) was introduced in the U.S. Senate in September 2009.
Renewable portfolio stadards (RPS) have been passed by many states, including Oregon. In addition,
a federal renewable electricity standard (RES) is included in the provisions of the Waxman-Markey bil.
RECs, which are needed to comply with RPS (or RES) requirements, are valued according to a forward
price cure developed for the 2009 IRP. Although a market for RECs has developed recently, there is
uncertainty associated with the futue market value of RECs and potential limitations on the quantity of
RECs that may be purchased to meet state RPS requirements or a federal RES. As par of the risk
analysis, the 2009 IRP analyzes a high REC price scenario and estimates the effect on each portfolio.
Idaho Power believes that maintaining a diverse resource portfolio is the best way to mitigate risk given
the amount of uncertainty in the planng process. As par of this strategy and in addition to the
quantitative analyses previously discussed, the 2009 IRP contains a qualitative discussion of the
potential risk associated with carbon regulation, developing technologies, resourcing siting, and relying
on market purchases. This discussion can be found in the Qualitative Risk Analysis section in
Chapter 10.
Greenhouse Gas Emissions
Idaho Power owns and operates 17 hydroelectric projects, two natual gas-fired plants,
one diesel-powered generator, and shares ownership in three coal-fired facilities. Idaho Power's carbon
dioxide (C02) emission levels have historically been well below the national average for the 100 largest
electric utilities in the United States, both in terms of total CO2 emissions (tons) and CO2 emissions
intensity (pounds (lbs )IMWh), based on the report of 2006 C02 emissions presented in Benchmarking
Air Emissions of the 100 Largest Electric Power Producers in the United States, released May 2008 by
the Ceres investor coalition, the Natural Resources Defense Council, Public Service Enterprise Group,
and PG&E Corporation.
In September 2009, Idaho Power's Board of Directors approved guidelines to establish a goal to reduce
the CO2 emission intensity of the company's utility operations. The guidelines are intended to prepare
the company for potential legislative and/or regulatory restrictions on greenhouse gas (GHG) emissions,
while minimizing the cost of complying with such reductions on Idaho Power's customers.
20091RP PageS
1. Summary Idaho Power Company
The guidelines establish a goal to reduce Idaho Power's resource portfolio's average CO2 emission
intensity for the 2010 through 2013 time period to a level of 10 percent-15 percent below the
company's 2005 CO2 emission intensity of 1,194 Ibs/MWh. Since Idaho Power's CO2 emission intensity
fluctuates with stream flows and the production levels of existing and anticipated renewable resources,
the company has adopted an average intensity reduction goal, to be achieved over several years.
Generation from company-owned resources and any renewable resources under contract, for which
Idaho Power has long-term rights to RECs, wil be included in the denominator of the intensity
calculation. The company's progress toward achieving this intensity reduction goal, as well as additional
information on Idaho Power's CO2 emissions, wil be reported on the company's Web site at
ww.idahopower.com. Information related to Idaho Power's CO2 emissions is also available through
the Carbon Disclosure Project at ww.cdproject.net.
The guidelines are intended to reduce Idaho Power's near-term C02 emission intensity levels in a
manner that minimizes the costs of the reductions on the company's customers. The 2009 IRP attempts
to quantify the cost and longer term impacts of carbon regulations proposed in the Waxman-Markey bil
(H.R. 2454). Additional details regarding the analysis are presented in Chapter 10 of the 2009 IRP.
Preferred Resource Portfolio
The preferred portfolio for the 2009 IRP presented in Table 1.1 was constructed by combining the
preferred portfolio for the first 10 years of the planning horizon (2010-2019) with the preferred portfolio
for the second i O-year period (2020-2029). In addition to the committed resources previously discussed,
the preferred resource portfolio includes 250 MW of market purchases beginning in 2015 with an
additional 175 MW in 2017. These purchases rely on the completion of the Boardman to Hemingway
Transmission Project (Boardman to Hemingway) in 2015. The total west-to-east transfer capacity
reserved on Boardman to Hemingway by Idaho Power is expected to be 425 MW. The first lO-year
period also includes the Shoshone Falls Upgrade Project in 2015.
The preferred portfolio for the second i O-year period (2020-2029) represents a strategy of adding wind
resources sufficient to provide energy and RECs along with simple-cycle natural gas plants to provide
peaking capacity and operating reserves necessary to integrate wind generation. The preferred portfolio
also assumes the completion of the Gateway West Transmission Project (Gateway West) by 2022 in
order to add the additional wind resources to the portfolio. Due to existing transmission constraints,
all portfolios analyzed for the 2020-2029 timeframe assume capacity is available on the Gateway West
transmission project.
Table 1.1 Preferred Portfolio
1-4 Boardman to Hemingway (2010-2019)Year Resource MW2012 Wind* 150
2012 CCCT (Langley Gulch)* 300
2012 Geothermal* 20
2015 Shoshone Falls 49
2015 Boardman to Hemingway 250
2016 Geothermal* 20
2017 Boardman to Hemingway 175
2-4 Wind & Peakers (2020-2029)
Year Resource MW
2020 SCCT (Large Aero) 1002022 Wind 100
2024 SCCT (Large Aero) 2002025 Gateway West 100
2026 SCCT (Large Aero) 2002027 Wind 400
2028 SCCT (Large Aero) 400
2029 SCCT (Large Aero) 500
*Committed resource
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Idaho Power Company 1. Summary
Idaho Power anticipates the resources in the second 10-year period wil be reconsidered in the 201 I IRP
and subsequent plans as more certainty regarding carbon regulation and a federal RES become available.
Future uncertainty requires alternate portfolios be considered in the resource planning process. Furher
details regarding the preferred portfolio and the alternate portfolios can be found in Chapter 10.
Near-Term Action Plan
Idaho Power has completed the competitive procurement process for the Langley Gulch CCCT and has
nearly completed the RFP process for the 2012 wind resource. Both resources are expected to be on-line
in 2012. Idaho Power anticipates expanding both the irrigation and commercial demand response
programs in 2010 and 2011 to address expected growth in peak-hour loads. Idaho Power anticipates
beginning construction ofthe Shoshone Falls Upgrade Project in 2012 with the project being completed
by 2015. Idaho Power is also continuing to work with federal and state agencies, FERC, other
transmission providers, and the public on the Boardman to Hemingway and Gateway West transmission
projects. Major milestones associated with these resources and programs are presented in Table 1.2.
Table 1.2 Near-Term Action Plan MilestonesYear Action
2010........................................................ Present and gain acceptance of 2009 IRP with regulatory commissions
File wind contract resulting from the 2012 Wind RFP with the IPUC
File geothermal contract with the IPUC (approximately 20 MW)
Irrigation Peak Rewards program increases from 160 MW to 220 MW
FlexPeak Management program increases from 20 MW to 40 MW
Langley Gulch CCCT construction begins
2011........................................................ Wind project construction begins
Langley Gulch CCCT construction continues
Irrigation Peak Rewards demand response program increases from 220 MW to
250MW
FlexPeak Management program increases to from 40 MW to 45 MW
File 2011 IRP with regulatory commissions
2012........................................................ Wind project on-line (approximately 150 MW)
Langley Gulch CCCT on-line (300 MW)
Geothermal project on-line (approximately 20 MW)
2013........................................................ Boardman to Hemingway construction begins
Shoshone Falls Upgrade Project construction begins
File 20131RP with regulatory commissions
2014........................................................ Shoshone Falls Upgrade Project construction continues
Boardman to Hemingway construction continues
2015........................................................ Shoshone Falls Upgrade Project on-line (49 MW)
Boardman to Hemingway completed (250 MW)
File 2015 IRP with regulatory commissions
2016........................................................ Geothermal project on-line (approximately 20 MW)
2017 ........................................................ Boardman to Hemingway additional capacity for market purchases (175 MW)
File 2017 IRP with regulatory commissions
2018........................................................ No action
2019........................................................ File 2019 IRP with regulatory commissions
2009 IRP Page 7
1. Summary Idaho Power Company
Public Policy Issues
The 2009 IRP was completed using computer modeling and other analytical methods. However, certain
public policy questions exist that canot be directly examined through analytical methods. Idaho Power
has presented these issues to the IRP AC for discussion, but the nature of the issues typically precludes a
strong majority opinion from the IRP AC members. The public policy issues presented to the IRP AC are
discussed below.
New Large Loads
Locally, Idaho Power and its customers face internal conflcts created by traditional rate determination
and the cost difference between existing resources and futue resources. New customers that connect to
Idaho Power's system benefit from energy rates based on the low-cost of existing resources that are
embedded in curent rates. However, Idaho Power's existing resources and transmission system are fully
used and new customers require the addition of generation, transmission, and distribution resources.
Each new customer dilutes the existing resource base and increases the cost to all customers.
The question of rate determination based on embedded resources is a significant public policy issue and
Idaho Power senses a desire by some paries to discuss the existing rate determination principles.
Idaho Power's ability to serve new large loads is limited. Previously existing surlus energy and
capacity have been consumed by load growth over the past several years. Idaho Power's ability to serve
new large loads has an impact on Idaho's economy. New businesses are attracted to southern Idaho in
par due to Idaho Power's low rates which have consistently been some of the lowest in the nation.
Asset Ownership
Idaho Power can develop and own generation assets, rely on power purchase agreements (PP As) and
market purchases to supply the electricity needs of its customers, or use a combination of the
two ownership strategies. Idaho Power expects to continue paricipating in the regional power market
and enter into mid-term and long-term PPAs. However, when pursuing PPAs, Idaho Power must be
mindful of imputed debt and its potential impact on Idaho Power's credit rating. In the long ru,
Idaho Power believes asset ownership results in lower costs for customers due to the capital and rate of
retur advantages inherent in a regulated electric utilty. Idaho Power's preference is to own the
generation assets necessary to serve its customer load.
Renewable Energy Credits
In late 2008, Idaho Power filed an application with the IPUC asking to retire RECs received as part of
the long-term PPAs for generation from the Elkhorn Valley Wind Project and the Raft River Geothermal
Project. Because the state of Idaho does not have an RPS, these RECs could be either voluntarily retired
or sold. Idaho Power's application pointed out that these RECs needed to be retired in order for
Idaho Power to represent to its customers that they were receiving renewable energy from these projects.
In May 2009, the IPUC issued Order No. 30818 which required Idaho Power to sell the eligible 2007
and 2008 RECs from these projects. The order also instrcted Idaho Power to fie a business plan
addressing the disposition of futue RECs by the end of 2009. When this issue was presented to the
IRP AC, environmental representatives felt future RECs should be retired while customer representatives
generally felt they should be sold so that the value could be retued to customers.
Idaho Power believes a federal RES requiring Idaho Power to retire RECs for compliance wil be passed
by Congress in the near futue. Idaho Power believes it is prudent to continue acquiring RECs associated
with renewable resources to minimize the impact when a federal RES is implemented. Because of recent
increases in costs and customer rates, along with feedback from the IPUC, Idaho Power feels it would be
Page 8 20091RP
Idaho Power Company 1. Summary
prudent to sell the RECs until they are required by a federal RES. Additional information on RECs and
the proposed federal legislation can be found in Chapter 2.
Emission Offsets
Depending on market conditions and future regulations, it may be possible to purchase emission or
carbon offsets for less than the cost of a carbon allowance. Some members of the IRP AC have suggested
it would be prudent for Idaho Power to hedge carbon emission risk by purchasing emission offsets prior
to the formal passage of carbon legislation. However, there are differing opinions among IRP AC
members. The principal reason cited for not purchasing offsets today is the uncertinty associated with
whether or not carbon offsets purchased today will meet future carbon control requirements and
regulations. In addition, draft federal legislation limits the amount of offsets that may be used to meet
reduction targets.
Idaho Power believes it should investigate purchasing either emission offsets or options to acquire future
carbon offsets. Idaho Power could potentially reduce the large financial exposure of possible carbon
regulation for the cost of the option premium. Idaho Power believes it should be able to recover the cost
of purchasing emission offset options as well as the cost of any emission offsets purchased.
Technology Risk and Joint Development Opportunities
In the 2009 IRP, several resource options dependent on developing technology have been evaluated in
various portfolios. Carbon capture and sequestration, integrated gasification combined-cycle (IGCC),
advanced nuclear, and numerous storage technologies are not yet commercially available; however,
the technology may become available during the 20-year planng horizon evaluated in the IRP.
This raises the question of whether Idaho Power should participate in development efforts related to any
of these technologies prior to them becoming commercially available.
Idaho Power believes that as a medium-sized utility it would be impractical to lead the development
work on any particular technology. However, as certain technologies are identified that show promise as
being beneficial to Idaho Power and its customers, the company may chose to paricipate in
development efforts. Idaho Power's participation would most likely be par of a larger group effort to
develop a technology jointly with other utilities with similar needs.
Similarly, certain existing and emerging resource technologies are available only in large sizes-larger
than what Idaho Power could or would consider developing alone. If opportunities become available to
jointly develop large resources, Idaho Power would evaluate them on a case-by-case basis. A similar
strategy has been used in the past and resulted in Idaho Power's joint ownership of three coal-fired
resources.
Solar Pilot Project
For the 2009 IRP, Idaho Power hired Black & Veatch to prepare a feasibility study to assess the
performance and associated costs of various solar technologies in southwest Idaho. While solar
technology continues to be more expensive than other alternatives, the cost of solar resources has come
down in recent months during a time when the cost of most other resource options has increased
substantially. In addition to providing RECs, solar resources provide the benefit of delivering energy
during the time of day when Idaho Power's customer demand is peaking.
Several possibilities exist for the structure of a solar pilot project. One option Idaho Power is interested
in pursuing would be to develop a photovoltaic (PV) project at a substation near existing load.
This concept would not require the addition of new transmission resources and would have
economy-of-scale advantages over distributed rooftop installations. The cost of the project could be
20091RP Page 9
1. Summary Idaho Power Company
subsidized by allowing customers to buy the output from the project as a means of investing in
renewable energy.
A solar resource at a company substation would provide customers a physical asset they could identify
with as the source of their electricity, and commercial customers would also be able to advertise their
use of renewable energy. The level of customer subscription in this tye of project would also provide
an indication of customers' wilingness to pay a premium for renewable energy. This concept was
generally well received and supported when it was presented and discussed at a recent IRP AC meeting.
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Idaho Power Company 2. Political, Regulatory, Operational, and Technology Issues
2. POLITICAL, REGULATORY, OPERATIONAL,
AND TECHNOLOGY ISSUES
Political and Regulatory Issues
Idaho Power is a regulated utility. On the federal level, Idaho Power is subject to the rules and regulation
ofFERC. On the state level, Idaho Power has customers in both Idaho and Oregon, with approximately
95 percent of Idaho Power's customers being located in the state of Idaho. The following sections
describe some of the federal and state regulatory issues facing Idaho Power.
Idaho Energy Plan
In 2006, the Idaho State Legislature directed an
Interim Committee on Energy, Environment,
and Technology to develop a state energy plan
that provides for the state's power generation
needs and protects the health and safety of the
citizens of Idaho. In Januar 2007, the committee
completed the Idaho Energy Plan and concluded
that all Idaho energy systems have performed
very well with retail electric and natural gas
prices that remain some of the lowest in the
country.
The committee also recognzed that Idaho's
reliance on low-cost coal plants may become a The Idaho Legislature sets state energy policy in Idaho.
source of risk in the future due to the economic impact of potential federal reguation of carbon and
mercur emissions. To address these concerns, the committee recommended increasing investments in
energy conservation and in-state renewable resources. In a resource priority policy statement,
the committee stated, "When acquiring resources, Idaho and Idaho utilities should give priority to:
I) conservation, energy effciency and demand response; and 2) renewable resources; recognizing that
these alone may not fulfill Idaho's growing energy requirements." The committee fuher stated,
". . . energy suppliers must continue to have access to conventional energy resources to keep Idaho's
energy costs as low as possible."
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2. Political, Regulatory, Operational, and Technology Issues Idaho Power Company
The committee also expressed support for the "25x25" vision, which states "By 2025, America's farms,
forests, and ranches wil provide 25 percent of the total energy consumed in the United States, while
continuing to produce safe, abundant, and affordable food, feed and fiber." Additional information
regarding the "25x25" vision can be found at ww.25x25.org.
Idaho Strategic Energy Alliance
In 2007, Governor C.L. "Butch" Otter established the Idaho Office of Energy Resources (IOER) to
oversee energy planing, policy and coordination in Idaho. Under the umbrella of this offce, the Idaho
Strategic Energy Alliance (the alliance) was established to respond to rising energy costs and other
energy challenges facing the state. The governor's philosophy is that there should be a joint effort
between all stakeholders in developing options and solutions for Idaho's energy futue.
The purpose of the allance is to enable the development of a sound energy portfolio for Idaho that
diversifies energy resources and provides stewardship of the environment. The allance consists of a
board of directors and twelve volunteer task forces working in the following areas:
· Conservation and energy efficiency . Forestry
. Wind
. Geothermal
. Hydropower
. Carbon issues
. Baseload resources
. Biogas
. Biofuel
. Solar
. Transmission
. Communication and outreach
· Economic/financial development
Idaho Power representatives serve on many of these task forces. The alliance is governed by a board of
directors comprised of representatives from Idaho stakeholders and industry experts. The workings of
the allance are overseen by the Governor's Council, a group of the governor's cabinet members.
Idaho State Legislature-Senate 8ill1123
Recent economic conditions have increased the cost of financing new capital projects-generation,
transmission, and distribution. The electric utility business is a capital-intensive industry with significant
financing requirements. Idaho Power has worked with the Idaho State Legislature to address some of the
capital issues by proposing legislation to allow the authorization of capital recovery to occur prior to
project construction rather than after the project is completed.
As a result ofthese efforts, the Idaho State Legislatue passed Senate Bil 1123 in April 2009. The bil
became law in July 2009 when it was signed by Governor Otter. Idaho Power recognizes that the policy
change wil require cost-containment commitments from the company, but Idaho Power anticipates that
the legislation wil lower the cost to finance new capital projects and, ultimately lower the capital costs
included in customer rates. In September 2009, the IPUC issued an order granting a certificate of public
convenience and necessity (CPCN) for the Langley Gulch combined-cycle combustion turbine (CCCT)
project. The CPCN included provisions for ratemaking treatment as provided in the new Idaho law.
Oregon Renewable Portolio Standard
The state of Oregon's Renewable Portfolio Standard (RPS) requires utilities and electricity service
suppliers serving Oregon load to include in their portfolio of power sold to retail customers a percentage
of electricity generated from qualifying renewable energy sources. Like most states, Oregon's RPS is
phased-in over a number of years, with final targets set for the year 2025. The Oregon RPS also includes
Page 12 20091RP
Idaho Power Company 2. Political, Regulatory, Operational, and Technology Issues
a tiered system based on the amount of load a utility serves in Oregon. Larger utilities have higher RPS
requirements and interim targets while smaller utilities have less rigorous requirements and no interim
targets.
Under the Oregon RPS, Idaho Power is categorized as a "smaller utility" because the percentage of the
company's retail electric sales in Oregon are between 1.5 and 3 percent of the total retail sales in the
state (approximately 5 percent ofIdaho Power's total load is in Oregon). As a "smaller utility"
Idaho Power is not subject to interim targets; however, by 2025 at least 10 percent ofIdaho Power's
retail sales in Oregon must come from qualifying renewable energy sources.
Proposed Federal Energy Legislation
Congress is developing comprehensive federal energy legislation that addresses two important factors in
resource planning-greenhouse gas (GHG) emission reductions and a federal renewable electricity
standard (RES). Proposed GHG regulations target the reduction of carbon and other GHG emissions
nationwide and a federal RES would require a percentage of electricity supplied to customers to come
from renewable resources.
In June 2009, the U.S. House of Representatives narowly passed H.R. 2454, the American Clean
Energy and Security Act sponsored by Representatives Henr A. Waxman and Edward 1. Markey.
The Waxman-Markey bil proposes a cap-and-trade system that establishes a limit or cap on the total
amount of GHG emissions. Under a cap-and-trade system, utilities would be allocated emission
allowances that would be decreased over time in order to achieve a total emission reduction goal.
A certin amount of allowances would also be auctioned as par of establishing a market where
allowances could be bought and sold. In effect, a buyer would be paying a charge for polluting, while a
seller would be rewarded for having reduced emissions by more than was required. The theory is those
who can reduce emissions most economically wil do so, achieving the pollution reduction at the lowest
possible cost to society. Details of the Waxman-Markey bil related to GHG reduction include:
~ Reduction Goals-Three percent below 2005 levels by 2012, 17 percent by 2020,42 percent by
2030, and 83 percent by 2050. Average annual emissions calculation based upon data from 2006
through 2008, or any three consecutive calendar years between 1999 and 2008.
~ Alocation of Allowances-From 201 i through 2028, 50 percent of allowances are allocated on
the basis of a utility's share of emissions associated with retail sales and 50 percent are allocated
based on a utility's anual average electricity deliveries.
~ Carbon Offsets-Allows the use of some forms of carbon offsets in lieu of allowances for
compliance.
The Waxman-Markey bil also includes provisions for a federal RES that would require a percentage of
electricity supplied to customers come from renewable resources. Details of the RES in the Waxan-
Markey bil include:
~ Required Annual Percentag~Starts at 6 percent in 2012 and escalates to 20 percent by 2020.
~ Resources Eligible to Meet RES-Wind, solar, geothermal, renewable biomass, biogas and
biofuels derived exclusively from renewable biomass, marne, hydrokinetic, and qualified
hydropower (efficiency improvements or capacity additions since Januar 1, 1992). Utilities can
also meet up to 25 percent of their requirements through energy efficiency savings.
~ Treatment of Existig Hydro-Generation from existing hydroelectric resources would be
subtracted from the sales base used to calculate RES requirements. While this does not fully
recognize the renewable aspect of hydropower, it does provide a benefit to utilties with existing
hydroelectric facilities that do not qualify for renewable energy credits (REC).
20091RP Page 13
2. Political, Regulatory, Operational, and Technology Issues Idaho Power Company
In September 2009, Senators Barbara Boxer and John Kerry jointly released the Clean Energy Jobs and
American Power Act which addresses climate change. The draft bil includes a GHG emission reduction
goal of20 percent below 2005 levels by 2020. The Boxer-Kerr bil (S. 1733) does not include a federal
RES provision; however, a separate proposal by Senator Jeff Bingaman does include a federal RES that
includes the following provisions:
~ Required Annual Percentage-Stars at 3 percent in 201 i and escalates to 15 percent by 2021.
~ Resources Eligible to Meet RES-Wind, solar, geothermal, ocean, biomass, landfill gas,
incremental hydropower (efficiency improvements or capacity additions), hydrokinetic, and new
hydropower at existing dams with no generation. Utilities can also meet up to 26.67 percent of
their requirements through energy efficiency savings.
~ Treatment of Existig Hydro-Excluded from the sales base used to calculate the RES.
Idaho Power has incorporated elements of the Waxman-Markey bil in the 2009 IRP to quantify the
impact of the proposed GHG reduction goals. Idaho Power also anticipates that some form of a federal
RES wil be passed in the near future; therefore all portfolios analyzed in the 2009 IRP are designed to
meet the requirements proposed in the Waxman-Markey bilL.
Renewable Energy Credits (Green Tags)
To promote the construction of renewable resources, a system was created that separates renewable
generation into two parts I) the electrical energy produced by a renewable resource and 2) the renewable
attibutes of that generation. These renewable attributes are referred to as RECs or green tags. The entity
that holds a REC has the right to make claims about the environmental benefits associated with the
renewable energy from the project. One REC is issued for each megawatt hour (MWh) of electricity
generated by a qualified resource. Electricity that is split from the REC is no longer considered
renewable and cannot be marketed as renewable by the entity that purchases the electricity.
A REC must be retired once it has been used for regulatory compliance and once a REC is retired,
it canot be sold or transferred to another party. The same REC may not be claimed by more than
one entity, including any environmental claims made pursuant to electricity coming from renewable
energy resources, environmental labeling, or disclosure requirements. State RPS requirements also
typically specify a "shelf life" for RECs so they canot be banked indefinitely.
Idaho Power is currently receiving all of the RECs from the 101 megawatt (MW) Elkhorn Valley Wind
Project in northeast Oregon. The Elkhorn wind project is expected to provide approximately
300,000 RECs to Idaho Power annually throughout the term of the power purchase agreement (PP A)
that expires in 2027.
Idaho Power is also receiving RECs from the 13 MW Raft River Geothermal Project. For the first
10 years of the agreement (2008 -2017), Idaho Power is entitled to 75 percent ofthe RECs from the
project for generation that exceeds a monthly average of 10 MW. For the second 10 years of the
agreement (2018-2027), Idaho Power is entitled to 51 percent of the RECs generated by the project.
Idaho Power expects a federal RES wil be enacted in the near futue, and, in the 2009 IRP,
the portfolios being analyzed are designed to substantially comply with the federal RES contained in the
Waxman-Markey bil. Idaho Power also anticipates RECs generated from both the Elkhorn Valley
Wind Project and the Raft River Geothermal Project wil be needed to meet federal RES requirements
once implemented.
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Idaho Power Company 2. Political, Regulatory, Operational, and Technology Issues
FERC Relicensing
Like other utilities that operate non-federal
hydroelectric projects on qualified
waterways, Idaho Power obtains licenses
from FERC for its hydroelectric projects.
The licenses last for 30 to 50 years
depending on the size, complexity, and cost
of the project. Idaho Power is actively
pursuing the relicensing of the Hells Canyon
Complex and the Swan Falls Hydroelectric
Projects.
Idaho Power's most significant ongoing
relicensing effort is the Hells Canyon
Complex. The Hells Canyon Complex
provides approximately two-thirds of Idaho Power's Hells Canyon Project is licensed by FERC.
Idaho Power's hydroelectric generating
capacity and 40 percent ofthe company's total generating capacity. The current license for the Hells
Canyon Complex expired at the end of July 2005. Until the new multi-year license is issued,
Idaho Power continues to operate the project under an anual license issued by FERC.
The Hells Canyon Complex license application was filed in July 2003 and accepted by FERC for filing
in December 2003. FERC is now processing the application consistent with the requirements of the
Federal Power Act (FPA); the National Environmental Policy Act of 1969, as amended (NEPA);
the Endangered Species Act (ESA); and other applicable federal laws.
The license for the Swan Falls project expires in June 2010. In March 2005, Idaho Power issued a
Formal Consultation Package (FCP) to the public relating to environmental studies designed to
determine project effects for the relicensing of the project. In September 2007, Idaho Power submitted a
draft license application to FERC for public review and comment. The draft application was based on
the results of environmental studies along with agency and public consultation. Idaho Power filed a final
license application for the Swan Falls hydroelectric project with FERC in June 2008, and anticipates
NEPA consultation to initiate in early 2010.
Failure to relicense any of the existing hydropower projects at a reasonable cost wil create upward
pressure on the curent 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 protection, mitigation, and enhancement
(PM&E) measures imposed as a condition for 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 was assumed as par of the 2009 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.
20091RP Page 15
2. Political, Regulatory, Operational, and Technology Issues Idaho Power Company
Idaho Water Issues
Power generation at Idaho Power's hydroelectric projects on the Snake River is dependent on the state
water rights held by the company for these projects. The long-term sustainability of the Snake River
Basin stream flows, including tributary spring flows and the regional aquifer system, is crucial for
Idaho Power to be able to maintain generation from these projects. The company is dedicated to the
vigorous defense of its water rights. None of the pending water management issues are expected to
impact Idaho Power's hydroelectric generation in the near term, but the company canot predict the
ultimate outcome of the legal and administrative water rights proceedings. Idaho Power's ongoing
paricipation in water rights issues is intended to guarantee that suffcient water is available. for use at the
company's hydroelectric projects on the Snake River.
Idaho Power is engaged in the Snake River Basin Adjudication (SRBA), a general streamflow
adjudication process commenced in 1987 to define the natue and extent of water rights in the
Snake River Basin. The initiation of the SRBA resulted from the Swan Falls Agreement entered into by
Idaho Power and the governor and attorney general ofIdaho in October 1984. The purose of the
agreement was to resolve litigation related to the company's water rights at the Swan Falls project.
Idaho Power has fied claims for all of its hydropower water rights in the SRBA, is actively protecting
those water rights, and is objecting to claims that may potentially injure or affect those water rights.
Idaho Power has also actively participated in proceedings associated with the Comprehensive Aquifer
Management Plan (CAMP) of the Eastern Snake River Plain Aquifer (ESPA). Remedial actions
identified in CAMP are intended to address persistently declining aquifer conditions. Given the high
degree of interconnection between ESP A and the Snake River, Idaho Power recognzes the importce
of aquifer management planning in promoting the long-term sustainability of the Snake River.
The company is hopeful the implementation of the ESP A CAMP will restore aquifer levels and tributar
spring flows to the Snake River. For the 2009 IRP, it is assumed that CAMP measures specified under
Phase I of the plan are implemented. Phase I recommendations consist of a combination of ground water
to surface water conversions, managed aquifer recharge, demand reduction programs, and weather
modification programs designed to produce an increase in average annual aquifer discharge between
200,000 and 300,000 acre-feet. Further discussion of the ESPA CAMP is included in Appendix C-
Technical Appendix. The Phase I measures with associated target water volumes are shown in Table 2.1.
Table 2.1 Phase I Measures
Measure
Ground Water to Surface Water Conversions .........................................................................................
Managed Aquifer Recharge...... ................... ........................... ......................................... ................ .......
Demand Reduction. ..... ....... ....... ............. ..... ..................... ... .... .................. .......... ............... ... ......... .........
Surface Water Conservation ...................................................................................................................
Crop Mix Modification.......................................... ......................................... ......... .................. ................
Rotating Fallowing, Dry-Year Lease, Conservation Reserve Enhancement Program (CREP) ...............
Weather Modifications.............................................................................................................................
Target (acre-feet)
100,000
100,000
50,000
5,000
40,000
50,000
Page 16 20091RP
Idaho Power Company 2. Political, Regulatory, Operational, and Technology Issues
Fixed Cost Adjustment
In January 2006, Idaho Power fied an application with
the IPUC requesting to implement a fixed-cost
adjustment (FCA) mechanism similar to the Power
Cost Adjustment (PCA), which accounts for changes
in power supply expenses. The FCA is designed to
separate fixed cost rate recovery from energy sales.
The FCA adjusts rates downward or upward to recover
fixed costs independent of the volume of the
company's energy sales. The filing was a continuation
of a 2004 case that was opened by Idaho Power to
investigate energy efficiency investments and financial
disincentives. Idaho Power recognizes that energy
effciency improvements lower the company's energy The IPUC regulates Idaho Power in Idaho.
sales, which then reduce the company's income.
Like most utilties, Idaho Power recovers a portion of fixed costs through variable energy sales-the
fixed costs to serve customers are much larger than customers' fixed fees, and a significant portion of
the fixed costs are included in customers' kilowatt hour (kWh) energy charges.
Idaho Power and IPUC staff agreed in concept to a three-year pilot program and a stipulation was fied
in December 2006 indicating the pilot program would begin in January 2007. The stipulation called for
the implementation of the FCA mechanism pilot program as proposed by Idaho Power in the original
application, with additional conditions and provisions related to customer count and weather
normalization methods, recording of the FCA deferral amount in reports to the IPUC, and detailed
reporting of demand-side management (DSM) activities. The IPUC approved the stipulation in
March 2007. The pilot program retroactively began in Januar 2007 and runs though December 2009.
The first rate adjustment occured in June 2008, the second in June 2009, and the final adjustment wil
occur in June 2010.
Idaho Power believes the FCA removes an inherent disincentive to utilty-sponsored DSM programs.
In response to implementation of the FCA, Idaho Power has committed to enhancing the efforts
promoting DSM and energy effciency in several key areas, including a broad availability of effciency
and load management programs, building code improvement activity, pursuit of appliance code
standards, continued expansion ofDSM programs beyond peak-shaving and load-shifting programs, and
third-pary verification of program effectiveness. Additional details on Idaho Power's DSM programs
and results can be found in Chapter 4.
Idaho Power has been successful in achieving its previously established DSM targets and the company
continues to pursue additional cost-effective DSM resource options through the IRP planning process.
Furhermore, in response to the FCA, Idaho Power has fuher reduced any financial bias toward
supply-side resource alternatives by removing "earnings neutrality" from the criteria for assessing the
viability of DSM resource options in the 2009 IRP analysis.
In October 2009, Idaho Power submitted an application to the IPUC (Case No. IPC-E-09-28) requesting
authorization for the company to convert the FCA from a pilot program to an ongoing and permanent
program.
20091RP Page 17
2. Political, Regulatory, Operational, and Technology Issues Idaho Power Company
Operational and Technology Issues
Supply-side resources have different characteristics that impact how they ultimately perform. Renewable
resources tend to be variable and intermittent and present operational issues. Many forms of storage
technology aimed at addressing these issues are under development. Likewise, significant effort is being
made to develop technologies such as carbon capture and sequestration, to allow the continued use of
coal as a fueL. These topics are all relevant to resource planng, and the following sections provide
details on the operational and technology issues associated with various resources.
Wind Integration
In February 2007, Idaho Power fied a wind integration study with the IPUC. Idaho Power also filed a
petition requesting removal of the temporary restriction on the size of Public Utilities Regulatory
Policies Act (PURP A) wind projects and an adjustment to the avoided cost rates to compensate for the
increase in system costs due to wind variability. In March and June 2007, public workshops were held to
present and discuss the results of the wind integration study.
Following negotiations, Idaho Power entered into a settlement stipulation in October 2007.
The settlement stipulation prescribed a methodology for calculating a wind integration charge to be
applied to new PURP A wind projects, as well as other provisions to account for the characteristics of
wind generation. The integration charge is calculated as a percentage of the curent 20-year, levelized,
avoided-cost rate and is subject to a cap of $6.50 per MWh. In Februar 2008, the IPUC issued an order
approving the settlement stipulation and retured the PURPA cap to 10 average megawatts (aMW).
In compliance with the terms of the settlement stipulation, Idaho Power held a follow-up public
workshop in August 2008 durng which further analysis results were presented along with the
operational strategies being used to integrate wind.
Idaho Power curently has 192 MW (nameplate) of wind generation on-line. Signed PURPA contracts
exist for 266 MW of wind generation that is expected to be on-line by the end of201O. The 2012 Wind
RFP is also expected to add up to 150 MW by 2012, which wil put the total wind generation on
Idaho Power's system in excess of 600 MW. Given this projected increase, it is critical that integration
methodologies in practice continue to evolve through ongoing operational experience and fuher study.
Idaho Power plans to update its wind integration study in the first half of 20 1 0 during the time between
fiing the 2009 IRP and staring the 201 i IRP process in July 2010. The updated study will incorporate
planned increases in wind generation as well as the capabilty of the new Langley Gulch CCCT to
provide additional operating reserves.
Along with other regional balancing authorities, Idaho Power shares the belief that improvements in
wind forecasting are necessar as wind resources continue to be built in the Pacific Northwest. As a
consequence, the company is curently developing a wind forecasting tool to forecast production from
PURPA wind projects. Data collection and testing of the new system is being performed to determine
whether this low-cost, in-house approach offers comparable performance to services offered by
third-pary forecasting companies. A status report on ths effort wil be included in the updated wind
integration study to be released in 2010.
Idaho Power continues to explore potential changes in operating practices to aid in the integration of
wind resources. Included among these efforts are two programs designed to collaborate with
surounding balancing authorities to manage balancing issues due to the variable and intermittent nature
of wind generation. ACE Diversity Interchange (ADI) and the concepts of dynamic and intra-hour
scheduling are based on the principle that sub-hour imbalances between generation and load will impact
system reliability less if balancing authorities are able to efficiently transfer and account for energy
moving between balancing authority areas within the hour.
Page 18 20091RP
Idaho Power Company 2. Political, Regulatory, Operational, and Technology Issues
Clean Coal Technologies
Integrated Gasification Combined Cycle
Integrated gasification combined cycle (IGCC), is a process that converts low-value fuels such as coal,
petroleum coke, orimulsion, biomass, and municipal wastes into a high-value, low-British thermal unit
(Btu), environmentally friendly natural gas type fuel, also called "synthesis gas" or simply "syngas."
When used to fuel a CCCT, coal-based syngas fuel produces electricity more effciently and with lower
emissions of sulfu dioxide (SOl), particulates, and mercur than traditional direct-fire coal boilers.
A significant amount of work continues worldwide on IGCC research and development.
IGCC technology is already being demonstrated at several plants around the world, and there are at least
five IGCC plants being planned in the United States. More than 40 IGCC projects with a combined
capacity of over 20 gigawatts (GW) have been announced globally. Major power generation equipment
suppliers, including Siemens and GE Energy, are investing substatial amounts of capital in IGCC
research and development. Idaho Power will continue to monitor the activities and results ofIGCC
research and development and wil continue to evaluate this technology in future IRPs.
Sequestration
Carbon captue and sequestration begins with the separation and captue of carbon dioxide (COl) from
power plant flue gas and other stationary COl sources. At present, the process is costly and energy
intensive, accounting for the majority ofthe cost of sequestration. Post-combustion, pre-combustion, and
oxy-combustion capture systems being developed are expected to be capable of capturing more than
90 percent of flue gas COl.
After separating the COl, the next step is to sequester or store the COl by injecting it into geologic
formations or using terrestrial applications. Geologic sequestration involves taking the COl that has been
captured from power plants and other stationar sources and storing it deep underground. Geologic
formations, such as oil and gas reservoirs, un-mineable coal seams, and underground saline formations
are potential options for storing COl. Storage in basalt formations and organic-rich shales is also being
investigated.
Terrestrial sequestration involves the net removal of COl from the atmosphere by plants and
microorganisms that use COl in their natual cycles. Terrestrial sequestration requires the development
of technologies to quantify, with a high degree of precision and reliabilty, the amount of carbon stored
in a given ecosystem. Program efforts in this area are focused on increasing carbon uptake on mined
lands and evaluation of no-til agriculture, reforestation, rangeland improvement, wetlands recovery,
and riparian restoration.
Research and development continues on carbon capture and sequestration with the U.S. Deparment of
Energy (DOE) in a lead role. The DOE is pursuing evolutionary improvements in existing CO2 captue
systems and exploring new captue and sequestration concepts. Additional research is being performed
in the private sector with companies such as Alstom and with utility-affliated organizations, such as the
Electric Power Research Institute (EPRI). Idaho Power will continue to monitor the activities and results
of carbon captue and sequestration research and development and wil modify future portfolios as
appropriate.
Carbon Recycling Using Algae
Carbon recycling using algae is an emerging technology and an alternative method for reducing COl
emissions. Algae "farms" rely on the captue of COl from coal plant flue gases, which is then used to
accelerate algae growth and eventually produce a biofuel that is similar to natural gas.
20091RP Page 19
2. Political, Regulatory, Operational, and Technology Issues Idaho Power Company
To create the biofuel, algae (biomass) is harvested and then gasified in a highly efficient, catalytic,
hydrothermal gasifier to produce a fuel that can be either injected into a natual gas pipeline or bured in
a combustion turbine to produce electricity. Compared with other methods of gasifying biomass, this
process is 400 times faster than anaerobic digestion and gives higher yields according to the DOE's
Pacific Northwest National Laboratory. Curently, fuding is being solicited to constrct a commercial
demonstration project next to an existing coal-fired facility.
Storage Technologies
In order to keep the electric power system balanced, generation must match system load at all times.
Intermittent renewable resources, such as wind and solar, present a problem because they are not
dispatchable. The advent of large-scale storage technologies may help utilities address this issue because
surplus energy could be stored and used at a later time. Energy storage technologies convert electrical
power into potential or kinetic energy, which can then be converted back into electrical energy when
needed, in effect making it dispatchable. The following sections present an update on the status of
various storage technologies.
Pumped Storage
Pumped storage technology has existed for some time, and Idaho Power has evaluated the technology in
numerous IRPs. The economics of pumped storage has always relied on a significant differential
between peak and off-peak market prices because the value is realized by storing water during off-peak
times and generating electricity with it during peak load periods. Historically, the differential between
peak and off-peak market prices in the Pacific Northwest has not been enough to justify the economics
of pumped storage.
Pumped storage recovers about 75 percent of the energy consumed, and is curently one ofthe most
cost-effective technologies for power storage. Pumped storage requires two nearby reservoirs at
considerably different elevations, linked with a pipeline or penstock. Because of the required facilties
and equipment, pumped storage typically requires considerable capital expenditures.
A relatively new concept in pumped storage is using wind power or other intermittent renewable
resources to pump water to the upper reservoir instead of relying on off-peak, baseload generation.
However, the capital cost of this pumped storage concept is stil considerable because of the required
equipment and facilities.
Batteries
Battery technology has existed for a long time; however, utility-scale battery storage technologies are
stil under development. Batteries are generally expensive and have a limited lifespan, but they also have
a relatively high efficiency, as high as 90 percent or better. To date, the most common use of batteries
has been in small off-grid domestic systems.
A nickel cadmium (NiCd) battery uses nickel oxide hydroxide and metallic cadmium as electrodes.
The world's largest NiCd installation is in Fairbans, Alaska and is used to stabilize voltage at the end
of a long transmission line. This battery system has a capacity of 27 MW for a duration of i 5 minutes.
A Vanadium Redox Battery (VRB) is a type ofrechargeable flow battery that employs vanadium redox
couples in both half cells. The King Island Wind Farm in Tasmania is connected to a VRB that allows
up to 800 kWh of surplus electricity to be stored. The battery has an output of200 kW and is used to
help stabilize and improve the reliability of the local power system.
As the adoption of plug-in hybrid electric vehicles increases, batteries could be used for energy storage.
Vehicle-to-grid technology would tu each vehicle into a 20 to 50 kWh distributed, load-balancing
device or emergency power source. For example, during peak daytime hours when people tend to be at
Page 20 20091RP
Idaho Power Company 2. Political, Regulatory, Operational, and Technology Issues
work and their vehicles are parked, utilities could draw power from the batteries. During off-peak
nighttime hours when people and their cars are at home, the batteries would be recharged.
Compressed Air
Compressed air technology typically involves compressing and storing air in underground geological
features. During times of peak electricity demand, the compressed air is heated with a small amount of
natural gas and run through a turbine to generate electricity. A proposed hybrid power plant using
compressed air is curently under consideration in Iowa. This project also proposes a 75 to 150 MW
wind project to generate the electricity needed for air compression.
Thermal
Thermal storage technology typically uses molten salt to store heat collected by a solar thermal
generation plant. Heat from the molten salt is then used to generate electricity for a few hours after the
sun sets or during cloudy periods when normal generation is reduced. Molten salt technologies can
provide three to seven hours of energy storage. Solar Milennium and Abengoa are constructing two
50 MW solar thermal plants in Spain with seven hours of thermal storage.
Flywheel
Mechanical inertia is the basis of the flywheel storage technology where energy is stored in the kinetic
motion of a rotating mass. A heavy, rotating disc is typically accelerated by an electric motor, which
also functions as a generator when reversed. Friction loss must be kept to a minimum to extend the
relatively short storage time. Because of the limited storage time, flywheel technology is best suited for
back-up applications during brief outages.
Flywheel storage technology is curently being used for unnterrptible power supply systems in large
data centers. The flywheel provides generation during transfer, which is the relatively brief time between
loss of power and the start up of an alternate source, such as a diesel generator. In addition, flywheels
can be used to minimize minor power distubances and improve power quality.
Hydrogen
The concept of hydrogen as a storage technology involves using electricity from intermittent renewable
resources to extract hydrogen through the electrolysis of water. The resulting hydrogen is stored and
later bured as fuel to generate electricity. A pilot project using wind turbines and hydrogen generators
was undertaken in 2007 on Ramea Island in Newfoundland, Canada. Wind energy is also curently
being used to extract hydrogen through the electrolysis process at a small facility southeast of Boise,
Idaho. The hydrogen generated at the Idaho facilty is sold commercially.
Superconducting Magnetic Energy Storage
Superconducting magnetic energy storage (SMES) systems store energy in the magnetic field created by
the flow of direct current in a superconducting coil that has been cryogenically cooled to a temperature
below its superconducting critical temperature. A typical SMES system includes three parts,
I) a superconducting coil, 2) the power conditioning system, and 3) a cryogenically cooled refrgerator.
Once the superconducting coil is charged, the curent will not decay and the magnetic energy can be
stored indefinitely. The stored energy can then be released back into the electric system by discharging
the coiL.
SMES systems are highly efficient, greater than 95 percent; however, the high cost of superconductors
limits the commercial application of this technology. The SMES technology would most likely be useful
to utilities as a diural storage device where less expensive, off-peak energy could be used to charge the
system which would then be discharged during the peak-load hours the following day. SMES is
20091RP Page 21
2. Political, Regulatory, Operational, and Technology Issues Idaho Power Company
currently being used in a utility application in northern Wisconsin where a string of distributed SMES
units are deployed to enhance the reliability of a transmission loop.
Fuel Conservation
The concept of fuel conservation combines an intermittent renewable resource with a dispatchable fossil
fuel generation resource. Under this concept, generation from the intermittent resource is combined with
an appropriate amount of generation from the fossil fuel resource to maintain a constat level of output
from the combined resources. While the concept is not specifically a storage technology, fuel
conservation does provide a means of firming the generation from a renewable resource. Other benefits
of this concept include reduced fossil fuel consumption and better use of available transmission
capacity.
Page 22 20091RP
Idaho Power Company 3. Idaho Power Today
3. IDAHO POWER TODAY
Customer and Load Growth
In 1990, Idaho Power had approximately
290,000 general business customers. Today,
Idaho Power serves more than
486,000 general business customers in Idaho
and Oregon. Firm peak-hour load has
increased from 2,052 megawatts (MW) in
1990 to over 3,000 MW in 2006,2007,
2008, and 2009. In June 2008, the peak-hour
load reached 3,214 MW, which was a new
system peak-hour record. Average firm load
(excluding Astaris/FMC) has increased from
nearly 1,200 average megawatts (aMW) in
1990 to over 1,800 aMW in 2008.
Additional details of Idaho Power's
historical load and customer data are shown
in Figure 3.1 and Table 3.1.
Simple calculations using the data in Table 3.1 suggest that each new customer adds approximately
5.9 kilowatts (kW) to the peak-hour load and about 3.1 average kilowatts to average load. In actuality,
residential, commercial, and irrigation customers generally contribute more to the peak-hour load,
whereas industrial customers contribute more to average load. Industrial customers generally have
a more consistent load shape, whereas residential, commercial, and irrigation customers have a load
shape with greater daily and seasonal variation.
Since 1990, Idaho Power's total nameplate generation has increased from 2,635 MW to 3,276 MW.
This includes Idaho Power's newest supply-side resource, a 170 MW simple-cycle combustion turbine
(SCCT) at the Danskin Project that was completed in April 2008. The 641 MW increase in capacity
represents enough generation to serve approximately 108,000 customers at peak times. Table 3.1 shows
Idaho Power's changes in reported nameplate capacity since 1990.
Idaho Power commercial customers in downtown Boise.
20091RP Page 23
3. Idaho Power Today Idaho Power Company
Since 1990, Idaho Power has added more than 195,000 new customers. The simple peak-hour and
average-energy calculations mentioned earlier suggest the additional 195,000 customers require over
i, i 00 MW of additional peakhour capacity and about 600 aMW of energy.
Figure 3.1 Historical Capacity, Load, and Customer Data
5,000
4,500
4,000
3,500
3,000
~ 2,500
2,000
1,500
1,000
500
500,000
450,000
400,000
350,000
300,000 ~
~.s
g¡u
250,000
200,000
150,000
100,000
50,000
oo i
1990 1998 20081992199419962000200220042006
-Total NameplateGeneration(MW) -Peak Firm Load (MW) -AverageFirmLoad(àMW) -NumberofCustomers
Table 3.1 Historical Capacity, Load, and Customer Data
Year
1990.........................................................................................
1991.........................................................................................
1992.........................................................................................
1993.........................................................................................
1994.........................................................................................
1995.........................................................................................
1996.........................................................................................
1997.........................................................................................
1998.........................................................................................
1999.........................................................................................
2000.........................................................................................
2001.........................................................................................
2002.........................................................................................
2003.........................................................................................
2004.........................................................................................
2005.........................................................................................
2006.........................................................................................
2007.........................................................................................
2008.........................................................................................
Total Nameplate
Generation (MW)
2,635
2,635
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
Peak Firm Average Firm
Load (MW)Load (aMW)Customers
2,052 1,205 290,492
1,972 1,206 296,584
2,164 1,281 306,292
1,935 1,274 316,564
2,245 1,375 329,094
2,224 1,324 339,450
2,437 1,438 351,261
2,352 1,457 361,838
2,535 1,491 372,464
2,675 1,552 383,354
2,765 1,653 393,095
2,500 1,576 403,061
2,963 1,622 414,062
2,944 1,657 425,599
2,843 1,671 438,912
2,961 1,660 456,104
3,084 1,745 470,950
3,193 1,808 480,523
3,214 1,815 486,048
Page 24 20091RP
Idaho Power Company 3. Idaho Power Today
Idaho Power anticipates adding nearly 10,000 customers each year throughout the planning period.
The expected-case load forecast predicts that peak-hour load requirements are expected to grow at about
57 MW per year and average energy is forecast to grow at approximately 1 i aMW per year.
More detailed customer and load forecast information is presented in Chapter 4 and in Appendix A-Sales
and Load Forecast.
The simple peak-hour load growth calculation indicates Idaho Power would need to add peaking
capacity equivalent to the 173 MW Bennett Mountain plant every three years throughout the entire
plannng period. However, this calculation does not include the expected impact demand response
programs will have on peak-hour load. The near-term and long-term action plans to meet the
requirements of Idaho Power's load growth are discussed in Chapter 11.
The generation costs per kW included in Chapter 6 help put forecast customer growth in perspective.
Load research data indicate the average residential customer requires about 1.5 kW of base load
generation and 5.0 to 5.5 kW of peak-hour generation. Baseload generation capital costs are about
$2,000 per kW for wind resources, and peak-hour generation capital costs are about $750 per kW for a
natual gas-fired SCCT. These capital costs do not include fuel or any other operation and maintenance
expenses.
Based on these capital cost estimates, each new residential customer requires about $3,000 of capital
investment for 1.5 kW ofbaseload generation, plus an additional $4,000 for 5.0 to 5.5 kW of peak-hour
capacity for a total generation capital cost of $7,000. Other capital expenditues for transmission,
distribution, customer systems, and other administrative costs are not included in the $7,000 capital
generation requirement. THe forecasted residential customer growth rate of 10,000 new customers per
year translates into over $70 milion of new generation plant capital per year to serve new residential
customers.
Existing and Committed Resources
Idaho Power primarily relies on company-owned hydroelectric and coal-fired generation facilities and
long-term power purchase agreements (PPAs) to supply the energy needed to serve customers.
Idaho Power's annual hydroelectric generation varies depending on water conditions in the Snake River
and market purchases and sales used to balance supply and demand throughout the year. The next
sections provide specific details on Idaho Power's sources of energy in 2008 followed by a description
of Idaho Power's existing and committed resources.
2008 Energy Sources
In 2008, 79 percent of Idaho Power's supply of electricity came from company-owned generation
resources. In above-average water years, Idaho Power's low-cost hydroelectric plants are typically the
company's largest source of electricity. Figure 3.2 shows Idaho Power's electricity sources for 2008,
including generation from company-owned resources and purchased power. Market purchases are
electric power purchases from other utilities in the wholesale electric market.
Long-term power purchases are electric power contracts with independent power producers and firm
PPAs 3with other utilities and can typically be identified by resource type. In 2008, Idaho Power
purchased 1, i 94,087 megawatt hours (MWh) of electricity through long-term PPAs that are shown by
resource tye in Figure 3.3. Long-term power purchases that cannot be identified by resource type are
shown as "other" in the chart.
20091RP Page 25
3. Idaho Power Today Idaho Power Company
Figure 3.2 2008 Energy Sources Figure 3.3 2008 Long-Term Power Purchases by
Resource Type
Long-Term
Power
Purchases
7%
Natural Gas
and Diesel
1%
Geothermal
7%
Wind
27%
Market
Purchased
Power
14%
Coal
40%
Combined
Heatand
Power
5%
Hydro
38%Hydro
37%
Electricity delivered to retail customers includes both electricity generated by Idaho Power-owned
facilities and energy purchased from others. Electricity produced by resources typically considered to be
renewable, such as wind, biomass, geothermal, etc., is not counted as renewable energy delivered to
retail customers in a given year, unless Idaho Power holds and retires an equivalent number of
renewable energy credits (REC) in that year. Energy for which Idaho Power holds and retires an
equivalent number of RECs wil be counted as renewable energy delivered to customers in the year the
RECs are retired.
Idaho Power has been directed by the IPUC to sell its eligible 2007 and 2008 RECs. The IPUC also has
directed Idaho Power to file by December 31, 2009, a report explaining how the company intends to
manage its RECs on an ongoing basis. Table 3.2 represents the electricity Idaho Power delivered to
customers in 2008. Because Idaho Power sells electricity to other utilities and to retail customers, not all
electricity purchased or generated by Idaho Power is delivered to its retail customers. Table 3.2 assumes
that all 2008 RECs wil be sold. If any of the 2008 RECs are retained and retired, the actual amount of
renewable energy delivered to retail customers could be higher than what is presented in Table 3.2.
Table 3.2 Electricity Delivered to Customers (2008)
Resource by Type
Hydroelectric.................................................................................................................. ...........................
Coal...........................................................................................................................................................
Natural Gas & Diesel. ....... ......................................... ....... ............... ........... ............. ..... ..... ........ ..... ...........
Purchased Power .,. ... ................................................ ....... ..... ... ... .... ......... ......... .... ....... ..... ........ ..... ...........
Total..........................................................................................................................................................
MWh
6,908,211
7,278,844
217,152
3,716,429
18,120,636
Existing Supply-Side Resources
In order to identify the need and timing of futue resources, Idaho Power prepares a load and resource
balance which accounts for forecast load growth and generation from all of the company's existing
resources and planed purchases. The load and resource balance worksheets showing Idaho Power's
existing and committed resources for average energy and peak-hour load are presented in Appendix C-
Technical Appendix. Table 3.3 shows all ofIdaho Power's existing resources, nameplate capacities, and
general locations.
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Idaho Power Company 3. Idaho Power Today
Table 3.3 Existing Resources
Resource Type
American Falls..........................................................................................................Hydro
Bliss .........................................................................................................................Hydro
Brownlee.................................................................................................................. Hydro
C.J. Strike.................................................................................................................Hydro
Cascade................................................................................................................... Hydro
Clear Lake................................................................................................................Hydro
Hells Canyon............................................................................................................Hydro
Lower Malad.............................................................................................................Hydro
Lower Salmon ..........................................................................................................Hydr0
Milner .......................................................................................................................Hydro
Oxbow ......................................................................................................................Hydro
Shoshone Falls.................... ............... ............... .... .............. ............... ......................Hydro
Swan Falls................................................................................................................Hydro
Thousand Springs ............. ................... ................... ............ .... ................ ... ............ ..Hydro
Twin Falls ............ ................. ........................... ........................ ... ...................... ........Hydro
Upper Malad.............................................................................................................Hydro
Upper Salmon A.......................................................................................................Hydro
Upper Salmon B .......................................................................................................Hydro
Boardman.................................................................................................................Coal
Jim Bridger ...............................................................................................................Coal
Valmy.......................................................................................................................Coal
Bennett Mountain..................................................................................................... Natural Gas
Danskin ............................ ........................................................................................Natural Gas
Salmon Diesel ............................ ....................................................... .......................Diesel
Total Existing Nameplate Capacity ...............................................................................................
Generator Nameplate
Capacity (MW)
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
17.0
64.2
770.5
283.5
172.8
270.9
5.0
3,276.4
Location
Upper Snake
Mid-Snake
Hells Canyon
Mid-Snake
North Fork Payette
South Central
Idaho
Hells Canyon
South Central
Idaho
Mid-Snake
Upper Snake
Hells Canyon
Upper Snake
Mid-Snake
South Central
Idaho
Mid-Snake
South Central
Idaho
Mid-Snake
Mid-Snake
North Central
Oregon
Southwest
Wyoming
North Central
Nevada
Southwest Idaho
Southwest Idaho
East Idaho
The following sections describe Idaho Power's existing supply-side resources and long-term PPAs.
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3. Idaho Power Today Idaho Power Company
Hydro Facilties
Idaho Power operates 17 hydroelectric projects located on the Snake River and its tributaries. Together,
these hydroelectric facilities provide a total nameplate capacity of 1,709 MW and anual generation
equal to approximately 970 aMW, or 8.5 milion MWh under median water conditions.
Hells Canyon Complex
The backbone of Idaho Power's
hydroelectric system is the Hells Canyon
Complex in the Hells Canyon reach of the
Snake River. The Hells Canyon Complex
consists of the Brownlee, Oxbow, and
Hells Canyon dams and the associated
generation facilities. In a normal water year,
the three plants provide approximately
68 percent of Idaho Power's annual
hydroelectric generation and approximately
35 percent ofthe total energy generated.
Water storage in Brownlee Reservoir also
enables the Hells Canyon Complex projects
to provide the major portion of
Idaho Power's peaking and load-following
capability.
Idaho Power operates the Hells Canyon Complex to comply with the existing FERC license, as well as
voluntary arrangements to accommodate other interests, such as recreational use and environmental
resources. Among the arangements are the fall Chinook plan, voluntarly adopted by Idaho Power in
199 i to protect spawning and incubation of fall Chinook below Hells Canyon Dam. The fall Chinook
species is listed as threatened under the Endangered Species Act (ESA).
Brownlee Reservoir is the only one of the thee Hells Canyon Complex reservoirs~and Idaho Power's
only reservoir-with significant active storage. Brownlee Reservoir has 101 vertical feet of active
storage capacity, which equals approximately one milion acre-feet of water. Both Oxbow and
Hells Canyon reservoirs have significantly smaller active storage capacities-approximately 0.5 percent
and 1.0 percent of Brownlee Reservoir's volume, respectively.
Brownee Reservoir is a year-round, multiple-use resource for Idaho Power and the Pacific Northwest.
Although the primary purpose is to provide a stable power source, Brownlee Reservoir is also used for
flood control, recreation, and for the benefit of fish and wildlife resources.
Brownee Dam is one of several Pacific Northwest dams that are 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 United States Ary Corps of Engineers (U.S. Ary COE) as
outlined in Aricle 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 opportities through the Fourh of July
holiday.
The U.S. Bureau of Reclamation (BOR) periodically releases water from BOR storage reservoirs in the
upper Snake River in an effort to augment flows in the lower Snake River to help anadromous fish
High runoff at Idaho Power's Hell's Canyon Dam.
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Idaho Power Company 3. Idaho Power Today
migrate past the Federal Columbia River Power System (FCRPS) projects. The periodic releases are part
of the flow augmentation implemented by the 2000 FCRPS biological opinion. The flow augmentation
water travels through Idaho Power's Mid-Snake projects and eventually through the Hells Canyon
Complex 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 plan adopted by Idaho Power in 1991. The constant flow is set at a
level to protect fall Chinook spawnng nests, or redds. During the fall Chinook plan 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 fr emerge in the spring.
Maintaining constant flows to protect the fall Chinook spawning contributes to the need for additional
generation resources during the fall months. The fall Chinook operations result in lower reservoir
elevations in Brownlee Reservoir, which reduces the power production capabilty of the project.
The reduced power production may necessitate Idaho Power to acquire power from other sources
to meet customer load.
Mid-Snake Projects
Idaho Power's hydroelectric facilties
upstream from the Hells Canyon Complex
include the American Falls, Milner,
Twin Falls, Shoshone Falls, Clear Lake,
Thousand Springs, Upper and Lower Malad,
Upper and Lower Salmon, Bliss, C.J. Strike,
Swan Falls, and Cascade projects. Although
the Mid-Snake projects of Upper and
Lower Salmon, Bliss, and C.l. Strike,
typically follow ru-of-river operations,
the Lower Salmon, Bliss, and C.J. Strike
plants do provide a limited amount of
peaking and load-following capability.
When possible, the projects are operated Idaho Power's C.J. Strike project on the Mid-Snake.
within FERC license requirements to
coincide with the daily system peak demand. All of the other upstream plants are operated as
ru-of-river projects.
Idaho Power has entered into a settlement agreement with the U.S. Fish and Wildlife Service (USFWS)
that provides for a study of the ESA listed snails and their habitat. The objective of the research study is
to determine the impact of load-following operations on the Bliss Rapids snail and the
Idaho SpringsnaiL. The study required Idaho Power to operate the Bliss and Lower Salmon facilities
under varying operational constraints to facilitate the Idaho Springsnail research. Run-of-river
operations during 2003 and 2004 serve as the baseline, or control, for the study. These facilties were
again operated as ru-of-river plants during 2004 and 2005 and then were used to follow load during
2006, 2007, 2008, and 2009. Idaho Power is developing, in consultation with the USFWS, a snail
protection plan that wil be completed in March 2010. The plan wil define how the Bliss and
Lower Salmon hydroelectric facilities wil be operated in the futue.
Water Lease Agreements
Idaho Power views the lease of water for delivery through its hydroelectric system as a potentially
cost-effective power supply alternative. This approach is paricularly attractive for water lease
agreements allowing the company to request delivery as needed. Water lease agreements in 2008
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3. Idaho Power Today Idaho Power Company
included the release of 41,620 acre-feet of water from the Idaho Water District NO.1 rental pool and
45,716 acre-feet from the Shoshone-Bannock Tribal Water Supply Ban. The water released under both
of these agreements was delivered through the company's entire system of main stem Snake River
hydroelectric projects.
The company also signed agreements with two irrigation districts on the Boise and Payette River
systems to lease approximately 16,400 acre-feet of storage water released in December 2008 and
Januar 2009. Because of high carryover storage levels in the Boise River reservoir system, the lease
agreement for the Boise system water (approximately 10,500 acre-feet) has been renewed for the winter
of 2009-2010.
In August 2009, the company also entered into a five year (2009-2013) water lease agreement with the
Shoshone-Bannock Tribal Water Supply Ban for 45,716 acre-feet of American Falls storage water.
Under the terms of this agreement, Idaho Power can schedule the releases of the water in order to
maximize the value of the generation. The company plans to schedule delivery of the water between
July and October of each year during the term of the lease. The Shoshone-Banock agreement was
executed in par to offset the impact of drought and changing water use patterns in southern Idaho and to
provide additional generation in summer months when customer demand is high. Acquiring water
through leases also helps the company to improve water quality and temperature conditions in the
Snake River as part of ongoing relicensing efforts associated with the Hells Canyon Complex.
Idaho Power intends to continue to pursue water lease opportunties as part of its regular operations.
Cloud Seeding
In 2003, Idaho Power implemented a winter cloud-seeding program for snowpack augmentation.
The program initially focused on increasing snow accumulation in the south fork of the Payette River
watershed. In 2008 it was expanded to enhance an existing program operated by a coalition of counties
and other entities (coalition) in the Upper Snake River system above Milner Dam. Cloud seeding, as
practiced by Idaho Power, extracts additional precipitation from passing storm systems. Storms with an
abundance of super-cooled liquid water vapor provide optimal conditions to increase precipitation.
To seed clouds, ground generators located near mountain tops, or special flares attached to modified
airplanes, release silver iodide into passing storms. Minute water particles within the clouds freeze on
contact with the silver iodide and eventually grow and fall to the ground in the form of snow. Silver
iodide has been used as a seeding agent in numerous western states for decades, and there are no known
harmful effects. Analysis conducted since the program began in 2003 suggests consistent enhancement
of anual snowpack in the Payette River between 5 and 15 percent, which is estimated to provide an
additional 120,000 to 180,000 acre-feet of water. Studies conducted by the Desert Research Institute
from 2003 to 2005 support the effectiveness of the program.
For the 2009-2010 winter season, the program consists of 10 remote-ontrolled, ground-based
generators and one airplane for the Payette Basin operations. The Upper Snake Basin cloud seeding
program consists of nine remote-controlled ground-based generators operated by Idaho Power and
25 manual ground-based generators operated by the coalition. Idaho Power provides the coalition with
meteorological data and forecasting to guide their operations.
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Idaho Power Company 3. Idaho Power Today
Thermal Facilties
Jim Bridger
Idaho Power owns a one-third share of the
Jim Bridger coal-fired plant located near
Rock Springs, Wyoming. The plant consists
of four nearly identical generating units.
Idaho Power's one-third share of the
generator nameplate capacity of the
Jim Bridger plant currently is 771 MW.
After adjustment for scheduled maintenance
periods, estimated forced outages, de-ratings,
efficiency upgrades, and transmission losses,
the annual energy generating capability of
Idaho Power's share of the plant is
approximately 625 aMW. PacifiCorp has
two-thirds ownership and is the operator of
the Jim Bridger facility.
Valmy
Idaho Power owns a 50 percent share, or 284 MW, ofthe 568 MW (nameplate) Valmy coal-fired plant
located east of Winnemucca, Nevada. The plant is owned jointly with NY Energy, which pedorms
operation and maintenance services. After adjustment for scheduled maintenance periods, estimated
forced outages, de-ratings, and transmission losses, the annual energy generating capability of
Idaho Power's share of the Valmy plant is approximately 230 aMW.
The Jim Bridger Plant is located near Rock Springs, Wyoming.
Boardman
Idaho Power owns a 10 percent share, or 64 MW, of the 642 MW (nameplate) coal-fired plant near
Boardman, Oregon, operated by Portland General Electric Company (PGE). After adjustment for
scheduled maintenance periods, estimated forced outages, de-ratings, and transmission losses, the anual
energy generating capability ofIdaho Power's share of the Boardman plant is approximately 50 aMW.
Because of concerns regarding the future of the Boardman plant and pending legal action, PGE analyzed
two scenarios in its 2009 IRP regarding the future of the Boardman plant. First, shutting down the plant
in 2014 and, second, adding pollution control equipment required to continue operating the plant until
the year 2040. Due to uncertinty in the ability to find alternate sources of replacement energy, PGE
indicated the best option was to invest in the pollution control equipment and continue to operate the
plant.
While Idaho Power has not specifically modeled either ofPGE's scenarios in the 2009 IRP, significant
reductions in generation from all of Idaho Power's coal resources, including Boardman, have been
modeled in the 2009 IRP. IfPGE continues to operate the plant beyond 2014, Idaho Power will evaluate
the required additional capital cost and the associated risk when more details are known. Ifthe project is
shut down in 2014, the existing transmission capacity from the Pacific Northwest currently used to
deliver Boardman's generation to Idaho Power's system would be available to import energy from other
resources.
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3. Idaho Power Today Idaho Power Company
Peaking Facilties
Danskin
Idaho Power owns and operates the Danskin
plant, a 271 MW natural gas-fired project.
The plant consists of one 179 MW Siemens
50lF simple-cycle combustion tubine and
two 46 MW Siemens W251B12A combustion
turbines. The 12-acre facility was initially
constructed during 2001 and is located
northwest of Mountain Home, Idaho.
The two smaller tubines were installed in
200 i and the larger tubine was recently
installed in 2008. The Danskin plant operates
as needed to support system load.
Bennett Mountain
Idaho Power owns and operates the Bennett The 45-MW combustion turbines at Danskin are used
Mountain plant, which consists of a 173 MW to meet peak customer load.
Siemens-Westinghouse 501F simple-cycle, natural gas-fired combustion tubine located near the
Danskin plant in Mountain Home, Idaho. The Bennett Mountain plant also operates as needed to support
system load.
Salmon Diesel
Idaho Power owns and operates two diesel generation units located in Salmon, Idaho. The Salmon units
have a combined generator nameplate rating of 5 MW and are primarily operated during emergency
conditions.
Solar Facilties
In 1994, a 25 kW photovoltaic (PV) array
with 90 individual panels was installed on the
rooftop ofIdaho Power's corporate
headquarters in Boise, Idaho. The company
also maintains a remote off-grid 80 kW PV
aray for the U.S. Air Force near Grasmere,
Idaho.
Idaho Power uses small PV panels in its daily
operations to supply power to equipment used
for monitoring water quality, measuring
stream flows, and for operating cloud seeding
equipment. In addition to these PV
installations, Idaho Power participates in the
Solar 4R Schools Program; has a mobile solar
trailer that can be used to supply power for
concerts, radio remotes, and other events and has a 200 watt solar water pump that is used for
demonstrations and the promotion ofPV technology.
Idaho Power's net metering program also allows customers to install small-scale, renewable generation
projects on their property and connect to Idaho Power's system. Under the program, net energy
generated beyond what the customer uses is sold back to Idaho Power. A majority of the program's
25 kW PV array on top of Idaho Powets
corporate headquarters.
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Idaho Power Company 3. Idaho Power Today
participants are solar projects. Curently there are 77 PV installations under this program with a total
capacity of227 kW.
Power Purchase Agreements
Elkhorn Valley Wind Project
In February 2007, the IPUC approved a PPA with
Telocaset Wind Power Partners, LLC, a subsidiar
of Horizon Wind Energy, for 101 MWof
nameplate wind generation from the
Elkhorn Valley Wind Project located in
norteastern Oregon. The Elkhorn wind project
was constrcted during 2007 and began
commercial operations in December 2007.
Under the PP A, Idaho Power receives the RECs
from the project. However, in May 2009 the IPUC
issued Order No. 30818, which required
Idaho Power to sell 2007 and 2008 RECs and to
submit a business plan by the end of 2009
addressing the disposition of future RECs from this The Elkhom Valley Wind Project in northeast Oregon.
project. This issue is discussed fuher in the public
policy section in Chapter 1 and the renewable energy credits section in Chapter 2.
Raft River Geothermal Project
The 2006 IRP identified a need for Idaho Power to acquire geothermal generation resources and
a request for proposals (RFP) for geothermal energy was released in June 2006. In March 2007,
Idaho Power identified U.S. Geothermal, Inc. as the successful bidder based on their proposal to supply
45.5 MW of geothermal energy. In January 2008, the IPUC approved a PPA for 13 MW of nameplate
generation from the Raft River Geothermal Power Plant (Unit 1) located in southern Idaho.
The Raft River project began commercial operations in October 2007 under a Public Utilities Regulatory
Policies Act (PURP A) contract with Idaho Power that was subsequently canceled when the new PPA
was approved by the IPUC.
For the first 10 years (2008-2017) ofthe agreement, Idaho Power is entitled to 75 percent of the RECs
from the project for generation that exceeds 10 aMW monthly. For the second 10 years of the agreement
(2018-2027), Idaho Power is entitled to 51 percent of the RECs generated by the Raft River Geothermal
Project. These RECs are also subject to IPUC Order No. 30818, as discussed above.
Neal Hot Springs Geothermal Project
After extensive discussions with U.S. Geothermal, it was mutually agreed that development of the
additional 32.5 MW of geothermal generation units originally proposed in the 2006 RFP process was not
feasible within the terms and conditions as specified in the RFP. However, over the past two years
Idaho Power continued discussions with U.S. Geothermal regarding the development of the Neal Hot
Springs project in eastern Oregon. During much of2009, Idaho Power negotiated a PPA with
U.S. GeothermaL. In December 2009, Idaho Power submitted a PPA to the IPUC for approval for
approximately 20 MW of geothermal energy from the Neal Hot Springs project.
Clatskanie Energy Exchange
In September 2009, Idaho Power and the Clatskanie People's Utility District (Clatskanie PUD) in
Oregon entered into an energy exchange agreement. Under the agreement, Idaho Power receives the
energy as it is generated from the newly constrcted 18 MW power plant at Arowrock Dam on the
Boise River, and in exchange Idaho Power provides Clatskane PUD energy of equivalent value
20091RP Page 33
3. Idaho Power Today Idaho Power Company
delivered seasonally-primarily during months when Idaho Power expects to have surlus energy. An
energy bank account wil be maintained to ensure a balanced exchange between the paries where the
energy value wil be determined using the Mid-Columbia market price index. The Arowrock project is
expected to begin generating in Januar 2010, and the agreement term extends through 2015.
Idaho Power also retains the right to renew the agreement through 2025. The Arowrock project is
expected to produce approximately 81,000 MWh annually.
Public Utilty Regulatory Policies Act
In 1978, Congress passed PURP A requiring
investor-owned electric utilities to purchase the
energy from any qualifying facilty (QF) that
delivers energy to the utility. A QF is defined
within the FERC regulations as a small renewable
generation project or small cogeneration project.
Individual states were given the task of establishing
the PP A terms and conditions, including price, that
each state's utilities are required to pay as part of
the PURP A agreements. Because Idaho Power
operates in both Idaho and Oregon, the company
must adhere to both the IPUC rules and regulations
for all PURP A facilities not located in the state of
Oregon, and the OPUC rules and regulations for all The Bennett Creek and Hot Springs PURPA
PURP A facilties located in the state of Oregon. wind projects are located in Elmore County.
The rules and regulations are similar, but not
identical, for the two states. Because Idaho Power cannot accurately predict the level of future PURP A
development, only signed contracts are accounted for in Idaho Power's resource plannng process.
Idaho Power curently has 96 contracts with independent developers for over 560 MW of nameplate
capacity. The PURP A generation facilities consist of low head hydro projects on varous irrigation
canals, cogeneration projects at industrial facilities, wind projects, anaerobic digesters, landfill gas,
wood-buring facilities and various other small renewable power projects. Of the 96 contracts, 80 are
on-line as of November 2009 with a cumulative nameplate rating of approximately 300 MW. Of the
remaining contracts, 15 are expected to be on-line in late 2010 and one in late 2012.
Published Avoided Costs
A key component of the PURP A contracts is the energy price contained within the agreements.
The federal PURPA regulations specify that a utility must pay energy prices based on the utility's
avoided costs. Subsequently, the IPUC and OPUC have established specific rules and regulations to
calculate the published avoided cost that Idaho Power is required to include in the PURP A contracts.
Idaho PURPA Contracts and Published Avoided Costs
· The term of the agreements canot exceed 20 years.
· For projects up to 10 aMW, energy prices are based on the published avoided cost.
· For projects greater than 10 aMW, energy prices and other contract terms and conditions are
negotiated.
· The published avoided costs are based upon a surogate avoided resource (SAR) model and both
non-firm and firm contracts are available:
~ Firm contracts have a specific term and contain published avoided cost energy pricing.
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Idaho Power Company 3. Idaho Power Today
~ Non-firm contracts contain no specific term and energy pricing is based on market prices.
Oregon Published Avoided Costs
OPUC docket UM 1129 established PURPA PPA rules and regulations for projects located in Oregon.
In UM 1129, the OPUC adopted the basic published avoided cost concepts used in Idaho for
Idaho Power agreements. One exception is that Oregon QF projects also have the option of selecting
energy pricing that is based on monthly natual gas prices. Idaho Power's Oregon Schedule 85 is the
direct result ofOPUC docket UM 1129.
Oregon PURPA Contracts and Published Avoided Costs
· The term of the agreements canot exceed 20 years.
· For projects up to 10 MW nameplate rating, energy prices are based on the published avoided cost.
Idaho Power is required to use standard contracts that have been pre-approved by the OPUC
(Oregon Schedule 85).
· For projects greater than 10 MW nameplate rating, energy prices and other contract terms and
conditions are negotiated. The starting point for the negotiations are the terms and conditions of the
Oregon Schedule 85 standard contract and there are three pricing options available:
~ Fixed Price Option-The energy price is fixed for all energy deliveries.
~ Deadband Option-The deadband option contains a fixed price component plus a variable price
component that is based on monthly natual gas prices. The calculated gas price is then confined
between a cap and floor creating the "deadband".
~ Gas Index Option-The gas price option contains a fixed price component plus a varable price
component that is based on monthly natural gas prices.
Wholesale Contracts
Idaho Power curently has one, fixed-term, off-system sales contract to supply 6 aMW to the Raft River
Rural Electric Cooperative. Since the 2006 IRP was published, the term of the contract has been
renewed anually and is expected to continue to be renewed each year until the contract expires at
the end of September 2011.
The Raft River Cooperative is the electric distribution utility serving Idaho Power's former customers in
Nevada. The agreement was established as a full-requirements contract after being approved by FERC
and the Public Utilities Commission of Nevada.
The contract requiring Idaho Power to supply 6 aMW to the City of Weiser expired at the end of2006
and was not renewed. The expiration of the City of Weiser contract was anticipated in the 2006 IRP.
Idaho Power and Montana's NorthWestern Energy negotiated a load-following agreement in which
Idaho Power provided NorthWestern Energy 30 MW ofload-following service. Idaho Power did not
renew the load-following agreement at the end of 2007 because of concerns regarding the integration of
new wind generation anticipated to be interconnected on Idaho Power's system.
NortWestern has provided load-following services for the Salmon, Idaho area which is located in the
NortWestern Balancing Authority Area. Idaho Power and NorthWestern are curently working together
to move the Salmon area load into the Idaho Power Balancing Authority Area. Idaho Power continues to
use its transmission capacity on the Jefferson line to import power from Montana during the sumer
months. At present, Idaho Power purchases 83 MW during sumertime, heavy-load hours from PPL
EnergyPlus, LLC. Although the purchase agreement expires in 2012, Idaho Power plans to continue to
use the available transmission capacity during the sumer months.
20091RP Page 35
3. Idaho Power Today Idaho Power Company
Market Purchases and Sales
Idaho Power relies on regional markets to supply a significant portion of energy and capacity.
Idaho Power is especially dependent on the regional markets and the existing transmission system used
to import these purchases during peak periods. Reliance on regional markets has benefited Idaho Power
customers during times of low prices as the cost of purchases, revenue from surlus sales, and fuel
expenses are shared with customers through the power cost adjustment (PCA).
Committed Supply-Side Resources
Langley Gulch
The need for a new baseload power plant was identified in Idaho Power's 2004 and 2006 IRPs.
The initial decision was to construct a coal-fired baseload resource, but regulatory, price, and
environmental issues led Idaho Power to reconsider the coal resource and instead select a natual
gas-fired combined-cycle combustion tubine (CCCT). Idaho Power completed the competitive bidding
process in early 2009 and selected a 300 MW CCCT project near New Plymouth, Idaho to meet the
resource need.
The Langley Gulch project is expected to begin delivering energy in time to meet sumer peaking needs
in July 2012. The Langley Gulch project will require the constrction of short segments of 138-kV and
230-kV transmission lines to connect to the existing system in order to deliver energy and provide
capacity support to Idaho Power customers in Idaho and Oregon. The Langley Gulch resource is
included when calculating the energy and capacity deficits discussed later in the IRP.
Wind RFP
Idaho Power's acknowledged 2006 IRP included a 150 MW wind generation resource to be added in
2012. With the passage ofthe American Recovery and Reinvestment Act of 2009 (the economic
stimulus package), Idaho Power believed it would be advantageous to accelerate the timing of this
resource acquisition. In May 2009, Idaho Power released an RFP for up to 150 MW of wind generation.
Proposals were received in June 2009; however, the evaluation process was delayed due to the analysis
of transmission constraints impacting all of the proposed projects. In October 2009, the company
initiated contract negotiations which are anticipated to be completed by the end of2009. Idaho Power
expects to have a signed contract to submit for regulatory approval during the first quarer of2010.
Shoshone Falls Upgrade Project
In August 2006, Idaho Power fied a license amendment application with FERC to upgrade the
Shoshone Falls Hydroelectric Project from 12.5 MW to 61.5 MW. The project currently has
three generator/turbine unts with nameplate capacities of 11.5 MW, 0.6 MW, and 0.4 MW. The upgrade
project involves replacing the two smaller units with a single 50 MW unit which will result in a net
upgrade of 49 MW.
In March 2007, Idaho Power received a draft Environmental Assessment (EA) and Notice of Ready for
Environmental Analysis from FERC that provided a 60-day comment period for interested paries.
FERC issued a supplemental EA in December 2007 and Idaho Power expects a license amendment wil
be issued during 2010. For the 2009 IRP, Idaho Power is planing on the additional capacity from the
Shoshone Falls upgrade being available in October 2015. When the project is completed, Idaho Power
expects the additional generation from the upgrade will qualify for RECs that can be used to satisfy
federal renewable electricity standard (RES) requirements.
The Shoshone Falls Upgrade Project has been included in previous Idaho Power IRPs as a committed
resource. For the 2009 IRP, the project was treated as an uncommitted resource; however, it was
included in all the portfolios analyzed because it is the most cost-effective new supply-side resource
Page 36 20091RP
Idaho Power Company 3. Idaho Power Today
available. In order to quantify the value of the project, the preferred portfolio was subsequently analyzed
without the upgrade project included. The results of this analysis indicate the project adds approximately
$11.5 milion of value (excluding capital cost and REC value) to the portfolio each year (average anual
nominal dollars for 2016-2019), and $15 milion with RECs using the expected-case REC price cure.
In the 2009 IRP, the expected levelized cost of energy from the upgrade (without RECs) is $73 per
MWh under median water assumptions, which makes the project the least expensive of all the
supply-side options analyzed in the 2009 IRP. The project becomes even more economically attractive
depending on the assumed future value ofRECs. While the evaluation of the Shoshone Falls upgrade
was done under median water conditions, some uncertainty exists regarding future Snake River
streamflows that would not only impact the Shoshone Falls project, but all ofIdaho Power's
Snake River hydroelectric projects. Additional details regarding water issues can be found in Chapter 2.
Because of the benefits and additional value provided by the Shoshone Falls Upgrade Project, it remains
in the 2009 IRP preferred portfolio. Idaho Power will continue to pursue this project in conjunction with
the resolution of water issues in the state of Idaho.
Geothermal, Combined Heat and Power, and Small Hydro
The preferred portfolio in Idaho Power's 2006 IRP included 50 MW of geothermal energy in 2009 and
50 MW of energy from Combined Heat and Power (CHP) in 2010. In June 2006, Idaho Power released a
geothermal RFP that resulted in a long-term PPA with U.S. Geothermal, Inc. for approximately 13 MW
of generation from the Raft River Geothermal Project. In Janua 2008, Idaho Power released another
RFP for up to 100 MW of geothermal energy; however, by the time the evaluation process was
completed all the bidders had withdrawn their proposals.
Although the results of the geothermal RFP processes have been disappointing, Idaho Power has
continued to work with project developers capable of delivering energy to the company's service area.
Idaho Power has included two 20 MW increments of geothermal energy in 2012 and 2016 in the
2009 IRP as a committed resource. While there is stil uncertainty regarding the development of
geothermal projects, ongoing contract negotiations warant the inclusion of a small amount of
geothermal energy in the IRP. Idaho Power will continue to monitor geothermal project development
and is hopeful geothermal energy wil become an economic and readily available resource for its
customers.
The 2006 IRP also included 50 MW ofCHP coming on-line in 2010. In April 2008, Idaho Power
solicited large industrial customers to determine the level of interest in CHP development. Because the
level of interest in CHP development was far less than anticipated in the 2006 IRP, CHP is not shown as
a committed resource in the 2009 IRP. However, Idaho Power continues to work with paries to explore
CHP projects and will pursue opportunities as they develop.
Idaho Power's commitment to continue investigating CHP projects is evidenced by an agreement signed
in November 2009 with the Idaho Offce of Energy Resources (IOER) and Amalgamated Sugar, one of
Idaho Power's large industrial customers. The agreement establishes the framework for a CHP
feasibility study to be performed at Amalgamated Sugar's Nampa, Idaho facility that could be as large
as 100 MW. Under the agreement, IOER wil allocate up to $20,000 of DOE grant fuds and
Idaho Power will contribute up to an additional $20,000 to fud the study.
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 hydro sites have been extensively developed in southern Idaho on irrigation
canals and others sites, many of which have PURPA contracts with Idaho Power.
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3. Idaho Power Today Idaho Power Company
Because small hydro, in paricular, ru-of-river and projects requiring small or no impoundments, does
not have the same level of environmental and permitting issues as large hydro, the IRP Advisory
Council (IRP AC) expressed an interest in including small hydro in the 2009 IRP. The potential for new
small hydro projects was recently studied by the Idaho Strategic Alliance's Hydropower Task Force.
The results of this evaluation are presented in a draft report available on the IOER's Web site at
ww.energy.idaho.gov. Idaho Power and others also continue to evaluate pumped storage opportunities
and the state of Idaho is examining possible large water storage projects for flow augmentation and the
potential for hydropower.
Due to potential regulation of carbon emissions and the associated costs, new small hydro may be
a feasible resource option for Idaho Power. However, uncertainty exists in the level of available sites
and the likelihood the sites would be developed as PURPA projects. Therefore, Idaho Power has not
included small hydro as a committed resource in the 2009 IRP. Similar to geothermal and CHP
resources, Idaho Power wil evaluate small hydro development opportunities as they emerge.
Distributed Generation
In 2006, Idaho Power renewed its investigation of a dispatchable customer generation program.
As initially conceptualized by the company, the program would use non-residential customers' standby
generators for up to 400 hours a year to help meet system peak power demands. Customer generators
would operate parallel with Idaho Power's generation resources during times of peak energy demand
and also provide back-up for the customer's facilty when needed. The customers' generators would be
started remotely by Idaho Power's dispatch center.
Idaho Power performed a feasibility analysis of the concept, examining the varous costs involved in the
interconnection of backup generators as well as the resulting operations and maintenance costs.
Both initial generator installations and existing retrofits were considered. The analysis concluded that
Idaho Power would have to make a significant infrastructure investment.
Idaho Power determined that it was necessary to do an in-depth analysis of the interconnection costs,
targeting generators of different sizes, ages, and locations. Five Idaho Power customers committed to
the detailed analysis and allowed the company to perform an on-site interconnection analysis.
The on-site analysis provided a more detailed cost estimate and determination of the program's potential
viabilty. Idaho Power concluded that it may be economical to operate customers' generators during
short periods of high energy demand.
Following the detailed analysis, Idaho Power began investigating air quality and permitting issues. If a
customer generation program was implemented, Idaho Power would most likely dispatch customers'
generators, almost all of which use diesel fuel, at times of peak system demand, which occurs most often
on hot, sumer afternoons-the times when air quality may already be compromised. In addition,
Idaho Power has received concerns from the environmental community regarding air quality issues
associated with operating diesel generators.
In April 2008, Idaho Power filed an updated status report on the investigation with the IPUC. In late
2008, Idaho Power held several meetings with the Industrial Customers of Idaho Power (ICIP) and the
IPUC staff to discuss the research and findings related to a dispatchable generation program. However,
none of the meetings resulted in sufficient support to fie a dispatchable generation program at that time.
Idaho Power did agree to fuher analyze a dispatchable generation resource option targeting new
generator installations that are fueled by natual gas as part of the company's 2009 IRP.
Both natual gas- and diesel-fueled distributed generation (DG) options were analyzed as part of the
2009 IRP. Because of air quality concerns the potential programs were analyzed at a lower capacity
factor of 0.69 percent (60 hours-per-year), which more closely matches the capacity factor of demand
response programs. At a capacity factor of 0.69 percent, the results of the analysis indicated a natural gas
Page 38 20091RP
Idaho Power Company 3. Idaho Power Today
option would have a 30-year, levelized cost of $5 i 9 per MWh and $808 per MWh for dieseL. The cost
estimate for a natural gas-fired peakng resource (SCCT) is $234 per MWh at a 6 percent capacity factor
and $1,165 per MWh at a capacity factor of 0.69 percent. Because the cost estimates for the DG options
fall within the range of costs for a SCCT, Idaho Power has committed to work with the ICIP to
determine if a cost-effective program can be established.
Several questions remain to be answered regarding air quality issues and whether the backup generators
can qualify as operating reserves. Based on Idaho Power's surey of industrial customers, the initial size
of the program is expected to reach approximately 15 MW; however, the ICIP is more optimistic and
believes the program could reach 80 MW. Idaho Power wil continue to work with the ICIP to resolve
outstanding issues and is optimistic a program can be developed that wil benefit all ofIdaho Power's
customers.
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Idaho Power Company 4. Demand-Side Management
4. DEMAND-SIDE MANAGEMENT
Demand-side management (DSM) customer programs are an essential component of Idaho Power's
resource strategy. Idaho Power works with its customers to promote energy efficiency and produce the
same output or provide the same level of service with lower energy consumption. Through demand
response programs, Idaho Power provides incentives to customers to identify applications where a
short-term load reduction can be timed to coincide with peak energy consumption when purchased
power is most expensive. Energy effciency and demand response programs address all four major
customer classes: residential, irrgation, commercial, and industriaL.
Market transformation, an additional program category, targets energy savings through engaging and
influencing large national and regional organzations to promote energy efficiency. Idaho Power
collaborates with other regional utilities and organizations in funding the Northwest Energy Effciency
Allance (NEEA) market transformation promotional activities. Appendix B-Demand-Side
Management 2008 Annual Report shows a detailed description of Idaho Power's energy effciency
program portfolio.
During each Integrated Resource Plan (IRP) planing period, Idaho Power uses various resources,
including current program expansion, new program development, potential studies, Northwest Power
and Conservation Council (NPCC) research, NEEA, and Idaho Power's Energy Efficiency Advisory
Group (EEAG), to determine how futue energy effciency and demand response programs can fulfill
electricity resource needs from demand-side resources. Idaho Power adopts new demand-side resources
when determined cost-effective, indicating the benefits of avoided power generation costs exceed the
costs of offering an energy efficiency program. Energy efficiency resources are usually one of the
least-cost resources available for Idaho Power's resource stack. Figures 6.1 and 6.2 in Chapter 6
compare demand response and energy effciency program costs with Idaho Power's supply-side resource
options.
DSM Potential Study
In August 2007, Idaho Power contracted with Nexant, Inc. to conduct a DSM potential study to identify
cost-effective new programs and opportunities to expand existing programs. The study took place during
2008, with a draft report delivered in September 2008. The DSM potential study included a
comprehensive report detailing forecast reductions from Idaho Power's existing programs and the
forecast reductions from new programs. In early 2009, Idaho Power requested a revision to the study
methodology to make the models used for the study more adaptable and useful for the IRP process.
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4. Demand-Side Management Idaho Power Company
Interactive models were provided by Nexant, which allowed Idaho Power to change the inputs based on
new DSM avoided costs, market penetration, and other factors affecting energy savings potentiaL.
The overall potential assessment for Idaho Power's DSM programs was determined by characterizing a
baseline profile for energy consumption by customer class, defining a list of applicable measures within
each customer class, and calculating the achievable potentiaL.
The achievable potential for energy efficiency programs was calculated by determining the techncal and
economic potentiaL. Technical potential describes the possible savings if all baseline equipment stock in
a program is replaced. Economic potential is a calculation of savings when all cost-effective measures
are installed. Achievable potential is determined by applying expected market penetration rates to the
economic potentiaL. Achievable potential represents the savings Idaho Power expects to achieve from
energy effciency programs.
Forecast program savings were determined using the results of the DSM potential study and analyzing
cost effectiveness with calculated avoided costs. The following sections provide additional details of the
DSM potential study. Analysis for the IRP focused solely on new cost-effective measures that are
curently not par of existing programs for the residential and commercial sectors and potential
expansion over existing program performance for industrial efficiency.
Residential Efficiency Potential
Residential efficiency potential focused on increased savings by expanding weatherization measures for
homes. Expansion potential included program measures similar to existing low income weatherization
programs that would be available to all residential homes in Idaho Power's service area. Other measures
included adding high effciency water heating and freezers to the Home Products program, which
promotes and incents the purchase and use of ENERGY STARiI products. As new products receive
ENERGY STAR certification, the products wil be reviewed for possible inclusion in the program. In
addition, potential new savings could come from expanding Idaho Power's ENERGY STAR Homes
Northwest program to non-owner occupied multi-family housing units. Savings from these new
measures are forecast to star out at approximately 0.3 average megawatts (aMW) in 2010 and grow to
16 aMW by 2029.
Commercial Efficiency Potential
Nexant provided recommendations focused on the existing Easy Upgrades program, which was adopted
as part of the 2006 IRP. The program targets commercial energy efficiency retrofit projects and offers a
menu of measures. Nexant recommended several measures, including the expansion of high-efficiency
motor offerings and various measures that would benefit commercial dairies, a growing industry in
Idaho Power's service area. Savings from these new measures are forecast to be 0.8 aMW in 2010 and
grow to 31 aMW by 2029.
Industrial Efficiency Potential
The primary driver for industrial effciency potential is customer adoption rates, which are correlated to
the incentive levels being offered. Nexant provided four tracks of achievable potential: low, moderate,
aggressive, and maximum, correlating to incentives levels of 25, 50, 75 and 100 percent of customer
costs, respectively. Idaho Power chose the aggressive potential level to model potential expansion to the
curent Custom Effciency program, which pays industrial and large commercial customers
proportionally to the electrical savings achieved on a per-project basis. With the adoption of the
aggressive potential level, it is anticipated that 1 aMW of additional industral energy efficiency can be
obtained in 2010, which wil increase to 67 aMW by 2029.
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Idaho Power Company 4. Demand-Side Management
Irrigation Efficiency Potential
DSM potential research ofIdaho Power's irrigation efficiency program offerings looked at energy
savings relative to irrigation load, anual customer participation, turover, and the list of measures
available in the program for customers relative to other similar programs. In 2007, savings from the
819 completed projects under the Irrgation Efficiency Rewards program totaled 12,304 megawatt hours
(MWh), representing 0.76 percent of the sector energy sales for the year. The present level of savings is
at the high end of the range of results of similar programs offered by other utilities (0.1 to 0.8 percent).
Considering the number of systems that might be replaced on an annual basis, Idaho Power's program
may be reaching 80 percent of the potential customers. Because of the current success of the existing
program, Nexant did not recommend implementation of any new energy efficiency programs for the
irrigation sector.
Appliance Standard Assessment
Idaho Power contracted with Quantec, LLC, in 2007 to conduct a study of the potential energy savings
and costs associated with enacting appliance energy efficiency standards in Idaho similar to the
standards enacted in Oregon during 2007. The intent of the evaluation was to provide information
regarding the costs and potential for energy savings that would occur if the appliance standards enacted
by Oregon were applicable in Idaho. In addition, the evaluation provided information and an analytical
base to promote new or additional appliance standards in Idaho. The study also addressed the concern
that higher standards already in place in Washington and Oregon would increase the potential of
less-efficient equipment being marketed and sold to Idaho residents.
Unlike a potential study, Idaho Power's Appliance Standards Assessment did not address the creation of
corresponding cost-effective utility programs that would capture the savings discussed in the report.
Some basic qualitative information about the level and type of effort required to conduct an appliance
standards development program were considered as part of the report, while detailed programatic
recommendations were beyond the scope of the report. The energy savings shown in the report are
similar in methodology to the technical potential savings defined in a typical energy efficiency potential
study, where it is assumed that every available measure or appliance is replaced. Table 4.1 shows the
10 appliances that were considered for the study and their status in neighboring states. Table 4.2
sumarizes the total savings forecast if standards were enacted, adopted, and allowed to penetrate the
marketplace over 20 years throughout Idaho.
Table 4.1 Analyzed Appliances and Code Implementation Status
Oregon
Enacted EffectiveAppliance
Metal halide lamps/fixtures.........................
Incandescent reflector lamps.....................
External power supplies............ .................
Bottle-type water dispensers......................
Hot food holding cabinets...........................
Walk-in refrigerators and freezers ..............
Compact audio products (CD players) .......
DVD players and recorders........................
Portable electnc spas/hot tubs...................
Residential furnace fans.............................
Sector
Commercial 2005 2008
Commercial 2005 2007
Commercial/Residential 2005 2007
Commercial 2007 2009
Commercial 2007 2009
Commercial 2007 2009
Residential 2007 2009
Residential 2007 2009
Residential 2007 2009
Residential 2007 2009
Neighboring States
Washington California
Enacted Enacted
Enacted Enacted
Enacted Enacted
Enacted
Enacted
Enacted
Enacted
Enacted
Enacted
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4. Demand-Side Management Idaho Power Company
Table 4.2
Commercial... ... ............... ....... ..... ........ ............... ............................
Residential........................ ................................. ............................
Overall............................................................................................
Appliance Standard Potential Savings-Idaho Statewide
Total estimated Energy
Savings (MWh)
56,916
221,893
278,809
Sector
Total Estimated
Demand Savings (MW)
12
31
43
Based on the findings, Quantec recommended that Idaho Power consider developing and adopting Idaho
appliance standards for the first nine appliances shown in Table 4.1. In addition, Quantec recommended
specific alternatives be investigated for the possibility of increasing the efficiency of fuace fans.
Quantec also recommended Idaho Power examine the options and monitor progress in setting standards
for general service incandescent and metal halide fixtures.
To support the development of efficiency standards, Quantec also recommended that Idaho Power and
other entities in Idaho identify priorities for conducting research and develop the data needed for such'
efforts. Expanding curent collaborative efforts would leverage existing resources and minimize the
need for additional resources.
At the state level, Quantec recommended the State of Idaho invest in the capability required to research
and adopt standards for the appliances analyzed in the study. In addition, the state could investigate the
option of developing a regulatory framework similar to California's that would recognize utilities'
efforts dedicated to efficiency standards; similar to how utilty energy efficiency acquisition programs
are treated.
Demand-Side Management Analysis
Prior to the final portfolio selection, the curent working portfolio of supply-side resources is used to
model the value of avoided supply-side generation and market purchases that are being avoided through
the implementation of DSM. The value of avoided generation is then balanced against program costs
and costs incured by customers in programs to create benefit-cost ratios.
Tables 4.3 and 4.4 sumarize the analysis for the new energy effciency and demand response resources
forecasted for the 2009 IRP plannng period. Each colum represents the net present value of the
20-year stream of energy, utility costs, and resource costs. Utility costs are the direct expenses
Idaho Power incurs in planning, implementing, and evaluating a DSM program, while the total resource
cost is a measure of the total net resource expenditues of a DSM program from the point of view of the
utility and its ratepayers as a whole. Appendix C-Technical Appendix describes Idaho Power's
methodology of calculating cost effectiveness.
Energy Efficiency Cost Effectiveness
Table 4.3 demonstrates the new energy efficiency program measures and expansions adopted for
resource planng in the 2009 IRP. The new energy effciency programs are estimated to be effective
with a total resource benefit-to-cost ratio of3.2. The ratio indicates that the benefits of avoided power
generation due to the energy efficiency programs exceed the costs to the utility and its customers by
more than three times. The highest total resource benefit-to-cost ratio is the industrial efficiency
programs with a benefit-to-cost ratio of 4.9 and levelized cost of 2.6 cents per kilowatt hour (kWh).
Cost effectiveness screening for the residential and commercial sectors yielded benefit-to-cost ratios of
2.8 and 2.1, respectively.
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Idaho Power Company 4. Demand-Side Management
The 20-year levelized total resource cost of each saved kWh is 4.0 cents; the programs save energy at a
cost of$41 per MWh. For all of the energy efficiency programs, the combined net present value of the
20-year stream of avoided generation costs is over $587 milion.
T blae4.3 New Enerav Efficiency Cost Effectiveness Summary
Impact 20-Year NPV Costs Utilty Costs Total Resource Costs
2029
Load 20-Year Energy Benefit/Cost Levelized Benefit/Cost Levelized
(aMW)(MWh)Utilty Resource Avoided Energy Ratio ($/kWh)Ratio ($/kWh)
Residential 29 1,097,000 $42,647,000 $51,412,000 $142,492,000 3.3 $0.039 2.8 $0.047
Commercial 31 1,043,000 15,207,000 68,482,000 143,366,000 9.4 0.015 2.1 0.066
Industrial 67 2,391,000 46,583,000 61,693,000 301,075,000 6.5 0.019 4.9 0.026
Total 127 4,531,000 104,437,000 181,587,000 586,933,000 5.6 0.023 3.2 0.040
Demand Response Cost Effectiveness
Table 4.4 sumarizes the cost-effectiveness analysis for all demand response programs, existing or new,
that were considered for the 2009 IRP. The overall 20-year levelized cost for the demand response
portfolio of programs is estimated at $46 per kW, with a peak forecasted demand reduction of
367 megawatts (MW) during the planning period. The benefit-to-cost ratio for the portfolio of programs
is 1.5, with an estimated net present value of $258 milion in avoided generation capacity costs over
20 years, relative to the estimated $176 milion dollars to administer the programs.
T bl 44 D dR C Sae.eman esponse ost-Effectiveness ummary
Impact 20-Year NPV Costs Total Resource Costs
2029 Load 20- Year Energy Avoided Benefit/Cost Levelized
(MW)(MWh)Utilty Resource Energy Ratio ($IkW)
Residential 51 555 $21,020,000 $21,020,000 $33,418,000 1.6 $38
Commercial/lndustrial 56 574 35,339,000 35,339,000 39,982,000 1.1 62
Irrigation 260 2,749 120,389,000 120,389,000 185,239,000 1.5 44
Total 367 3,878 176,748,000 176,748,000 258,639,000 1.5 46
Energy Efficiency Programs
During the preparation of the IRP, Idaho Power analyzes various DSM options, including curent
program expansion and new program development. Idaho Power also uses potential studies, NPCC
research, NEEA, and the EEAG to determine the best methods of designing and implementing DSM
programs. Idaho Power is committed to adopting all cost-effective DSM, which is determined by
comparing the cost of DSM programs to the cost of supply-side resource options. Table 6.2 compares
the cost of DSM options to varous supply-side alternatives that were also evaluated in the 2009 IRP.
The methodology used to screen the cost effectiveness of DSM programs is discussed later in this
chapter and in greater detail in Appendix C-Technical Appendix.
In addition to the new program identification resulting from the DSM potential study, internal program
development identified an additional four new energy efficiency programs and one demand response
program for the 2009 IRP. One existing demand response program, Irrigation Peak Rewards,
was redesigned as a dispatchable program with significantly more peak reduction capability.
The additional peak reduction potential from the program was modeled as a new resource for the
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4. Demand-Side Management Idaho Power Company
2009 IRP, along with the other new programs. No new industrial or irrigation efficiency programs were
planed as new resources for the 2009 IRP.
By 2029, existing and committed energy efficiency programs are forecast to provide 255 aMWof
system load reduction and 289 MW of peak-hour load reduction. The energy and capacity effects from
the company's existing and committed energy efficiency programs are accounted for in Idaho Power's
sales and load forecast. However, peak-hour load reduction due to demand response programs is not
included in the forecast, but is accounted for in the peak-hour load and resource balance. Appendix A-
Sales and Load Forecast includes the anual forecast impact of existing and committed DSM programs
by customer class for each year of the IRP planning horizon.
New energy effciency measures are forecast to offset 127 aMW of average annual load by 2029 at an
estimated total resource cost of 4.0 cents per kWh. Industrial effciency program expansion identified in
the potential study wil provide more than 50 percent of the reduction, or almost 67 aMW at a cost of
2.6 cents per kWh. The next lowest cost energy effciency acquisition is from residential programs
which include new weatherization program measures and an expansion of the Home Products Program
that provides incentives for customers to purchase ENERGY STAR qualified appliances. The combined
contribution is forecast to reduce load by 29 aMW at a total resource cost of 4.7 cents per kWh. For the
commercial customer class, the new energy effciency portfolio from the potential study includes higher
cost measurès, such as higher efficiency motors and agricultual measures along with one new small
commercial Holiday Lighting program. The commercial sector is forecast to provide 31 aMW of load
reduction by 2029 at a total resource cost of 6.6 cents per kWh.
Residential Program Planning
Three new effciency programs were implemented during 2009. The Home Improvement Program offers
customer incentives for attic insulation retrofits into existing residential homes. The Weatherization
Solutions for Eligible Customers program provides increased home weatherization opportties for
families that do not qualify for the long standing Weatherization Assistance for Qualified Customers
(W AQC) program. The See Ya Later Refrigerator program incents customers to recycle secondary
refrigerators and freezers. The combined forecasted impact for these three new programs in 2010 is
2,440 MWh in anual energy savings, or 0.28 aMW of system load reduction, growing to an estimated
impact of 82, i 13 MWh in 2029 or 9.4 aMW of reduced average system load.
Commercial Program Planning
The Holiday Lighting program enables commercial customers to recycle old incandescent holiday lights
and replace them with light-emitting diode (LED) bulbs. The seasonal program was added to the
portfolio of existing commercial programs during 2009 and will result in savings of approximately
0.1 aMW in 2010, growing to 0.5 aMW at the end of the IRP planng period. While relatively small,
the Holiday Lighting program provides a unique opportty for educating all customers about the
energy savings potential of LED technologies.
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Idaho Power Company 4. Demand-Side Management
Demand Response Resources
The goal of demand response programs at
Idaho Power is to reduce the sumer peak
electric load during periods of high demand
and minimize or delay the need to build new
supply-side alternatives, such as gas-turbine
peaking resources.
Two major demand response program
changes occurred in 2009 that expanded the
dispatch capability of Idaho Power to reduce
system demand during critical sumer peak
load events. The Irrigation Peak Rewards
program, originally identified as a resource
in 2004, was changed to a direct load control
or dispatchable program. In prior years, Irrigation customers make significant contributions to
demand reduction through the program was Idaho Power's DSM programs.
controlled with programmed timers that provided demand reduction from irrigation pumping systems
from 4:00 p.m. to 8:00 p.m. on weekdays in June, July, and August. Options added to the program in
2009 allowed direct load control or dispatch capabilities to match demand response resources with
actual system peaks. While fixed timers remain an option, the dispatchable change in the program wil
increase the program's peaking resource capacity from its previous range of 34 to 37 MW to a
forecasted impact of260 MW at program maturity in 2012. Actual demand reductions from the revised
program will depend on the level of irrgation customer paricipation, drought conditions, and
agricultural business cycles. Details on the approved Irrigation Peak Rewards tariff changes are listed as
part of Case No. IPC-E-08-23 on the IPUC Web site.
Another demand response program that emerged for the 2009 IRP planing period was the FlexPeak
Management program. The program is offered to commercial and industrial customers through a
third-pary demand response aggregator. FlexPeak Management is expected to provide nearly 40 MW of
peak demand reduction in 2010 and over 56 MW by 20 i 2, as par of a five-year contract. For details
corresponding to the program addition, view Case No. IPC-E-09-02, Order No. 30805 on the IPUC Web
site.
As part of the 2009 IRP process, Idaho Power prepared an updated forecast of the A/C Cool Credit
program. Using communication hardware and software, Idaho Power cycles participants' central air
conditioners on and off during sumer peak load events. The A/C Cool Credit program is forecast to
exceed 50 MW in potential reduction with continued growth in the Treasure Valley and planed
expansion into Twin Falls, Mountain Home, and Pocatello, Idaho. Through the life of the planing
period, combined total impact of the three programs is forecast to be 310 MW in 2010 and 367 MW in
2012. Table 4.4, in the Demand Response Cost Effectiveness section ofthis chapter shows expected
program performance and associated costs.
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Idaho Power Company 5. Planning Period Forecasts
5. PLANNING PERIOD FORECASTS
The Integrated Resource Plan (IRP) process
requires the preparation of numerous
forecasts which can be grouped into
three main categories-load forecasts, a
generation forecast, and financial
assumptions. The load and generation
forecasts, including supply-side resources,
demand-side management (DSM), and
transmission import capability, are used to
estimate surlus and deficit positions in the
load and resource balance. The identified
deficits are then used to develop resource
portfolios which are evaluated using
financial tools and forecasts. The following
sections provide details on the forecasts
prepared as part of the 2009 IRP.
Load Forecast
Idaho Power has served Idaho and Oregon customers
for almost 100 years.
Historically, Idaho Power has been a sumer peaking utility, with peak loads driven by irrigation pumps
and air conditioning in the months of June, July, and August. In recent years, the growth rate of
peak-hour load has exceeded the growth of average monthly load. However, both measures are
important in planning for future resources and are par of the load forecast prepared for the 2009 IRP.
The expected-case (median) load forecasts for peak-hour and average energy represent Idaho Power's
most probable outcome for load growth during the planng period. However, the actual path of future
electricity sales wil not exactly follow the path suggested by the expected-case forecast. Therefore,
four additional load forecasts were prepared, two that provide a range of possible load growths due to
economic uncertainty, and two that address the load variabilty associated with abnormal weather.
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5. Planning Period Forecasts Idaho Power Company
The high-growth and low-growth scenarios provide boundaries on each side of the expected-case
forecast and historical load variability potential on future load due to demographic, economic, and other
non-weather related influences. The 70th percentile and 90th percentile load forecast scenarios were
developed to assist Idaho Power's review of the resource requirements that would result from higher
loads due to adverse weather conditions.
Idaho Power prepares a sales and load forecast each year as part of the company's anual financial
forecast. The economic forecast is based on a forecast of national and regional economic activity
developed by Moody's Analytics, a national econometric consulting firm. Moody's Analytics June 2009
macroeconomic forecast strongly influenced the 2009 IRP load forecast. The national, state,
metropolitan statistical area (MSA), and county econometric projections are tailored to Idaho Power's
service area using an economic database developed by an outside consultant. Specific demographic
projections are also developed for the service area from national and local census data. National
economic drivers from Moody's Analytics are also used in developing the 2009 IRP load forecast. The
forecast of the number of households and employment projections, along with customer consumption
patterns, are used to develop customer forecasts and load projections.
Weather Impacts
The expected-case load forecast assumes median temperatures and median precipitation meaning that
there is a 50 percent chance that loads wil 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 drer-than-median
precipitation. Since actual loads can var significantly depending on weather conditions, two alternative
scenarios are analyzed to address load variability due to weather. Idaho Power has generated load
forecasts for 70th percentile and 90th percentile weather. Seventieth percentile weather means that in
7 out of 10 years, load is expected to be less than forecast and in 3 out of 10 years, load is expected to
exceed the forecast. Ninetieth percentile load has a similar definition with a i in 10 likelihood that the
load wil be greater than the forecast.
Idaho Power's system load is highly dependent upon weather. The three scenarios allow careful
examination of load variabilty and how the load variability may impact resource requirements. It is
importt to understand the probabilities associated with the load forecasts apply to any given month
and an extreme month may not necessarily be followed by another extreme month. In fact, a typical 'Year
likely contains some extreme months as well as some mild months.
Weather conditions are the primary factor affecting the load forecast on the hourly, daily, weekly,
monthly, and seasonal time horizon. Economic and demographic conditions affect the load forecast over
the long-term time horizon.
Economic Impacts
The national recession that began in 2007 underscores the effects of the national and local economy on
energy use in Idaho Power's service area. The severity ofthe current recession has resulted in a
reduction in new residential customer growth from an average of2,000 new residential customers per
month prior to the recession, to approximately 200 new customers per month at the present time.
Commercial and industrial customer energy use has contracted and overall system energy use has
declined by 3.6 percent in 2009 from the prior year; the first time that overall energy use has declined
since the energy crisis of 200 1.
Increased population in Idaho Power's service area due to migration to Idaho from other states is
expected to continue throughout the planing period and has been included in the load forecast modeL.
Idaho Power also continues to receive requests from prospective new large load customers that are
Page 50 20091RP
Idaho Power Company 5. Planning Period Forecasts
attracted to southern Idaho due to the relatively low electric rates. In addition, the economic conditions
in surrounding states may encourage some manufacturers to consider moving operations to Idaho.
The number of households in Idaho is projected to grow at an annual average rate of 1.3 percent during
the 20-year forecast period. Growth in the number of households within individual counties in
Idaho Power's service area differs from statewide household growth patterns. Service area household
projections are derived from individual county specific household forecasts. Growth in the number of
households within Idaho Power's service area, combined with estimated consumption per household
adjusted for DSM measures, results in a 0.7 percent residential load growth rate. The number of
residential customers in Idaho Power's service area is expected to increase 1.7 percent anually from
approximately 404,000 at the end of2008 to over 563,000 by the end of the planning period in 2029.
The expected-case load forecast represents the most probable projection of load growth during the
planing period. The forecast for system load growth is determined by suming the load forecasts for
individual classes of service, as described in Appendix A-Sales and Load Forecast. For example,
the expected anual average system load growth of 0.6 percent (over the period 2010 through 2029) is
comprised of residential load growth of 0.7 percent, commercial load growth of 0.7 percent,.declining
irrigation load growth of -0.3 percent, industrial load growth of 1.0 percent, and additional firm load
growth of 2.3 percent.
The 2009 IRP average system load forecast is lower than the 2006 IRP average system load forecast in
all years of the forecast period. The slowdown in the national and service-area economy caused load
growth to slow significantly. In addition, the significant increase in assumed DSM combined with retail
electricity price assumptions that incorporate estimates of assumed carbon legislation both serve to
decrease the forecast of average loads. Significant factors and considerations that influenced the
outcome ofthe 2009 IRP load forecast include:
· For the first time, the sales and load forecast is infuenced by the estimated impact of proposed
carbon legislation on retail electricity prices. Retail electricity prices move signficantly higher
throughout the forecast period, reducing futue electricity sales.
· Existing energy efficiency program performance is estimated and included in the sales and load
forecast base, lowering the energy and peak demand forecast. However, the impact of demand
response programs is accounted for in the load and resource balance. The amount of committed and
implemented DSM programs for each month of the planing period is shown in the load and
resource balance in Appendix C-Technical Appendix.
· A collapse in the housing sector has significantly slowed the growth in the number of residential
customers being added within Idaho Power's service area. The number of commercial customers
being added has also slowed as a result of the economic downtur. Both forecasts of the number of
residential and commercial customers were adjusted downward in the near term to reflect the curent
housing slowdown and credit crisis. By 2012, residential and commercial customer growth is
expected to recover and customer additions are expected to be similar to the growth that occured in
the 1993-2003 timeframe, prior to the housing bubble.
· A somewhat higher irrigation sales forecast compared to recent years due to a substantial increase in
weather-adjusted irrigation sales over the last two years (6 percent in 2007 and 8 percent in 2008).
High commodity prices appear to be the primar reason behind the irrigation sales increase. Farers
appear to have taken advantage of the commodities market by planting all available acreage.
In addition, the conversion of hand lines to electrically operated pivots may explain a part of the
increased energy consumption. In recent years, the increased labor costs associated with moving
hand lines has triggered the substitution of labor with electrically operated pivots.
20091RP Page 51
5. Planning Period Forecasts Idaho Power Company
· The uncertainty associated with the industrial and special contract sales forecasts. The forecast
uncertainty is due to the number of parties that contacted Idaho Power and expressed interest in
locating production operations within Idaho Power's service area and the unown magnitude of
the energy and peak demand requirements. The current sales and load forecast reflects only those
customers that have a high probability of locating in the service area or have made financial
commitments and whose facilities are actually being constructed at this time. Therefore, the number
of large customers that have contacted Idaho Power and shown interest, but have not made
commitments, are not included in the curent sales and load forecast.
Peak-Hour Load Forecast
The firm peak-hour load forecast includes the sum of the individual coincident peak demands of
residential, commercial, industrial, and irigation customers, as well as special contracts (excluding
Astaris), and the Raft River Rural Electric Cooperative wholesale agreement. Idaho Power uses the 95th
percentile forecast as the basis for peak-hour planning in the IRP. The 95th percentile forecast is based
on 95th percentile average peak day temperatues to forecast monthly peak-hour load.
Idaho Power's system peak-hour load record is 3,214 MW, which was recorded on Monday, June 30,
2008, at 3:00 p.m. The previous year's summer peak demand was 3,193 MW and occured on Friday,
July 13, 2007, at 4:00 p.m. Summertime peak-hour load growth has accelerated over the past 10 years as
air conditioning has become standard in nearly all new residential home constrction and new
commercial buildings. The 2009 IRP load forecast projects peak-hour load to grow by approximately
53 MW per year throughout the planing period. The peak-hour load forecast does not reflect the
company's demand response programs, which are accounted for in the load and resource balance.
Figure 5.1 and Table 5.1 sumarize three forecast outcomes ofIdaho Power's estimate of anual system
peak load considering median, 90th percentile and 95th percentile weather impacts on the expected
(median) peak forecast. The 95th percentile forecast uses the 95th percentile peak-day average
temperature to determine monthly peak-hour demand. The planing criteria for determining the need for
peak-hour capacity assumes the 95th percentile peak-day temperature conditions.
Figure 5.1 Peak-Hour Load Growth Forecast
4,800
4,500
4,200
3,900
3,600
Š 3,300::
3,000
2,700
2,400
2,100
1,800
1,500 'i iii iii iii iii iii iii iii iii iii iii iii iii iii iii iii iii iii iii
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
-Actual (w/o Demand Response) -Actual -50t Percentile -90th Percentile -95th Percentile
Page 52 20091RP
Idaho Power Company 5. Planning Period Forecasts
Table 5.1 Load Forecast-Peak-Hour (MW)
Year
2009 (Actual) ...................................................................................................
2010.................................................................................................................
2011 .................................................................................................................
2012 .................................................................................................................
2013.................................................................................................................
2014.................................................................................................................
2015.................................................................................................................
2016.................................................................................................................
2017 .................................................................................................................
2018.................................................................................................................
2019.................................................................................................................
2020.................................................................................................................
2021.................................................................................................................
2022.................................................................................................................
2023.................................................................................................................
2024.................................................................................................................
2025.................................................................................................................
2026.................................................................................................................
2027.................................................................................................................
2028.................................................................................................................
2029.................................................................................................................
Growth Rate (2010-2029) ...............................................................................
Median 90th Percentile 95th Percentile
3,160 3,160 3,160
3,279 3,439 3,460
3,375 3,538 3,560
3,447 3,614 3,636
3,533 3,703 3,726
3,592 3,766 3,789
3,641 3,819 3,843
3,689 3,871 3,895
3,739 3,925 3,949
3,790 3,978 4,003
3,842 4,034 4,060
3,895 4,091 4,118
3,933 4,133 4,160
3,980 4,183 4,210
4,027 4,234 4,261
4,052 4,262 4,290
4,098 4,312 4,341
4,146 4,364 4,393
4,173 4,394 4,424
4,204 4,430 4,460
4,216 4,445 4,475
1.5%1.5%1.5%
The median or expected-case peak-hour load forecast predicts peak-hour load will grow from 3,160 MW
in 2009 to 4,216 MW in 2029, an average annual compound growth rate of 1.5 percent. The projected
average anual compound growth rate of the 95th percentile peak forecast is also 1.5 percent. In the
95th percentile forecast, sumer peak-hour load is expected to increase from 3,160 MW in 2009 to
4,475 MW in 2029. Historical peak-hour loads as well as the three forecast scenarios are shown in
Figure 5.1.
Idaho Power's winter peak-hour load record was 2,527 MW, recorded on Thursday, December 10,2009,
at 8:00 a.m. Historical winter peak-hour load is much more variable than sumertime peak-hour load.
The winter peak variability is due to the variability of peak day temperatues in winter months which is
far greater than the variabilty of peak day temperatures in sumer months.
Average-Energy Load Forecast
Potential monthly average energy use by customers in Idaho Power's service area is defined by a series
of four load forecasts that reflect a range of load uncertainty resulting from differing economic growth
and weather-related assumptions. Figue 5.2 and Table 5.2 show the results of the four forecasts used in
the 2009 IRP to estimate the boundaries of anual system load growth over the planning period. There is
approximately a 90 percent probability that Idaho Power's load growth will exceed the low-load growt
forecast, a 50 percent probability of load growth exceeding the expected-case forecast, a 30 percent
probability of load growth exceeding the 70th percentile forecast, and approximately a 10 percent
probability that load growth wil exceed the high-growth forecast. The projected 20-year average anual
compound growth rate in the expected-load forecast is 0.7 percent.
20091RP Page 53
5. Planning Period Forecasts Idaho Power Company
Idaho Power uses the 70th percentile forecast as the basis for monthly average energy plannng in
the IRP. The 70th percentile forecast is based on 70th percentile weather to forecast average monthly
load, 70th percentile water to forecast hydro generation, and 95th percentile average peak day
temperature to forecast monthly peak-hour load.
Figure 5.2 Average Monthly Load Growth Forecast
2,400
2,200
2,000
1,800
~
1,600
11 1,400
1,200
1,000
800
600 , i i
1975
iii iii iii iii iii iii iii iii Ii iii iii iii iii iii iii iii iii i ¡I
1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030
-WeatherAdjustedActual -50th Percentile -70th Percentile -90th Percentiie
Table 5.2 Load Forecast-Average Monthly Energy (aMW)
Year
2010.....................................................................................................................
2011.....................................................................................................................
2012.....................................................................................................................
2013.....................................................................................................................
2014.....................................................................................................................
2015.....................................................................................................................
2016.....................................................................................................................
2017 .....................................................................................................................
2018.....................................................................................................................
2019.....................................................................................................................
2020.....................................................................................................................
2021.....................................................................................................................
2022.....................................................................................................................
2023.....................................................................................................................
2024.....................................................................................................................
2025.....................................................................................................................
2026.....................................................................................................................
2027.....................................................................................................................
2028.....................................................................................................................
2029.....................................................................................................................
Growth Rate............................. ............ ............. ............... ......... .............. .............
Median 70th Percentile Low High
1,797 1,842 1,796 1,863
1,869 1,914 1,834 1,933
1,906 1,952 1,851 1,974
1,926 1,972 1,859 2,003
1,947 1,994 1,857 2,020
1,957 2,005 1,858 2,039
1,967 2,015 1,858 2,055
1,979 2,028 1,864 2,078
1,991 2,040 1,857 2,085
2,002 2,051 1,862 2,105
2,013 2,063 1,867 2,125
2,017 2,067 1,872 2,145
2,026 2,077 1,886 2,174
2,032 2,083 1,901 2,205
2,024 2,077 1,917 2,237
2,035 2,088 1,932 2,268
2,041 2,094 1,947 2,297
2,034 2,088 1,961 2,328
2,030 2,084 1,977 2,359
2,015 2,070 1,991 2,389
0.7%0.7%0.6%1.6%
Page 54 20091RP
Idaho Power Company 5. Planning Period Forecasts
Additional Firm Load
Special contracts curently exist for five large customers that are recognized as firm load customers.
The five customers are Micron Technology, Simplot Fertilizer, Idaho National Laboratory (INL),
Hoku Materials, and Raft River. Together, these customers make up the additional firm load category.
Micron Technology
Micron Technology is currently Idaho Power's largest individual customer. In this forecast, electricity
sales to Micron Technology are expected to move downward in 2009 as Micron phases out
200 milimeter (mm) dynamic random access memory (DRAM) operations at its Boise facility.
Micron Technology wil continue to operate its 300 mm research and development fabrication facility in
Boise and perform a variety of other activities, including product design and support, quality assurance,
systems integration and related manufactuing, corporate, and general services. Once establishing a new
floor for energy consumption at the facility, at about a quarter less energy use than in recent years,
Micron Technology's electricity use is expected to increase based on Moody's forecast of
manufacturng employment in the Electronic and Electrical sector for the Boise MSA.
Simplot Fertilzer
The Simplot Fertilizer plant is the largest producer of phosphate fertilizer in the western United States.
The future electricity usage at the plant is expected to grow at a slow pace thoughout the planing
period (2010-2029). The primary driver oflong-term electricity sales growth at Simplot Fertilizer is
Moody's forecast of gross product in the Pesticide, Fertilizer, and Other Agricultural Chemical
Manufacturing sector for the Pocatello MSA.
Idaho National Laboratory
The INL is a U.S. Department of Energy (DOE) research facility located in eastern Idaho. The INL is
operated for the DOE by Battelle Energy Allance, LLC which includes the Battelle Memorial Institute
teamed with several institutions, including BWXT Services, Inc., Washington Group International,
the Electric Power Research Institute, and the Massachusetts Institute of Technology (MIT).
The laboratory employs about 8,000 people.
The DOE provided an energy consumption and peak demand forecast through 2029 for the INL.
The DOE forecast calls for loads to increase through 2012, remain flat for six years, and then slowly
decline throughout the remainder of the forecast period.
Hoku Materials, Inc.
The sales and load forecast reflects the increased expected demand for energy and peak capacity of
Idaho Power's newest special contract customer, Hoku Materials, located in Pocatello, Idaho.
Hoku Materials plans to begin operation in December 2009 and reach full capacity by October 2010.
The curent sales and load forecast assumes that Hoku Materials wil consume 74 aMW of energy each
year and have a peak demand of 82 MW (each measure excluding line losses), once continuous
operation is reached in 2012.
20091RP Page 55
5. Planning Period Forecasts Idaho Power Company
Planning Scenarios
The timing and necessity of future generation resources are based on a 20-year forecast of surluses and
deficiencies for monthly average load (energy) and peak-hour load. For both of these areas, one set of
criteria has been chosen for plannng purposes; however, additional scenarios have been analyzed to
provide a comparison. Table 5.3 provides a sumar of six planning scenarios analyzed for the
2009 IRP and the criteria used for planning puroses are shown in bold. Median water and median load
forecast scenarios were included to enable comparison of the 2009 IRP with plans developed durng the
i 990s. The median forecast is no longer used for resource planing, although the median forecast is used
to set retail rates and avoided cost rates during regulatory proceedings. The planing criteria used to
prepare Idaho Power's 2009 IRP are consistent with the criteria used in the 2006 IRP.
Table 5.3 Planning Criteria for Average Load and Peak-Hour Load
Average Load/Energy (aMW) 50th Percentile Water, 50th Percentile Average Load
70th Percentile Water, 70th Percentile Average Load
90th Percentile Water, 70th Percentile Average Load
Peak-Hour Load (MW) 50th Percentile Water, 90th Percentile Peak-Hour Load
70th Percentile Water, 95th Percentile Peak-Hour Load
90th Percentile Water, 95th Percentile Peak-Hour Load
The planning criteria used for energy or average load are 70th percentile water and 70th percentile
average load. In addition, 50th percentile water and 50th percentile average load conditions are analyzed
to represent a median condition, and 90th percentile water and 70th percentile average load are analyzed
to examine the effects of low water conditions.
Peak-hour load plannng criteria consist of 90th percentile water and 95th percentile peak-hour load
conditions, coupled with Idaho Power's ability to import additional energy on its transmission system.
A median condition of 50th percentile water and 50th percentile peak hour load are also analyzed, as well
as 70th percentile water and 95th percentile peak-hour load. Peak-hour load planning criteria are more
stringent than average load planng criteria because Idaho Power's ability to import additional energy is
typically limited during peak-hour load periods. Surluses and deficiencies for the average and
peak-hour load scenaros can be found in Appendix C- Technical Appendix.
Existing Resources
In order to identify the need and timing of future resources, Idaho Power prepares a load and resource
balance which accounts for forecast load growt and generation from all of the company's existing
resources and planed purchases. Updated load and resource balance worksheets showing
Idaho Power's existing and committed resources for average energy and peak-hour load are shown in
Appendix C- Technical Appendix. The following sections describe recent events or changes that are
accounted for in the load and resource balance regarding Idaho Power's hydro, thermal,
and transmission resources.
Page 56 20091RP
Idaho Power Company 5. Planning Period Forecasts
Hydro
For the 2009 IRP, Idaho Power continues the
practice of using 70th percentile streamflow
conditions for the Snake River Basin as the
basis for the projections of monthly average
hydroelectric generation. The 70th percentile
means that 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
90th percentile streamflow conditions to
projectJ?eak-hour hydroelectric generation.
The 90 percentile means that streamflows Idaho Power manages stream .flows for energy and wildlife.
are expected to exceed the plannng criteria
90 percent of the time and to be worse than the planing criteria only 10 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 50th percentile (median) streamflow conditions because the median streamflow condition is
stil used for rate setting puroses and other analyses.
The 50th, 70th, and 90th percentile streamflow forecasts used in the IRP are derived from a streamflow
planning model developed by the Idaho Department of Water Resources (IDWR). The IDWR
streamflow planing model is used by Idaho Power to produce a normalized hydrologic record for the
Snake River Basin from 1928 through 2005. The normalized model accounts for curent hydro
conditions and historical hydro development with regard to groundwater discharge to the river, water
management facilities, irrigation facilties, and operations.
In the past, Idaho Power has assumed the representative streamflow conditions calculated from the
normalized record are static through the IRP planing period. For example, the practice has been to
assume that a 70th percentile year in 2010 is identical to a 70th percentile year in 2015. A review of
Snake River Basin streamflow trends suggests that persistent decline documented in the Eastern Snake
Plain Aquifer (ESPA) is mirrored by downward trends in total surface water outflow from the river
basin. The Comprehensive Aquifer Management Plan (CAMP) for the ESPA includes demand reduction
and weather modification measures which wil add new water to the basin water budget. However, it is
the judgment of Idaho Power hydrologists that the positive effect of the new water associated with the
new measures is likely to be temporar, and over time the water use practices driving the steady decline
over recent years are expected to resume and result in a retur to persistently declining basin outflows.
For this reason, Idaho Power assumes that aside from a temporar increase in flows associated with the
phasing in of demand reduction and weather modification measures, flows in the Snake River Basin are
expected to decline year to year throughout the IRP planng period. The expected year to year decline
in anual hydroelectric generation is less than 0.5 percent.
River temperature is an important concern that can affect the timing of Snake River streamflows.
Various federal agencies involved in salmon migration studies have indicated a desire to shift delivery
of flow augmentation water from the Upper Snake River and Boise River basins from the traditional
20091RP Page 57
5. Planning Period Forecasts Idaho Power Company
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 the natually occurng flow conditions.
A federal study report indicates 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 the importance of July as a resource
constrained month, Idaho Power has incorporated the shifted delivery of flow augmentation water from
the Upper Snake River and Boise River basins for the 2009 IRP. Augmentation water delivered from the
Payette River Basin is assumed to remain in July and August. Based on preliminary resource plannng
analyses, monthly average hydroelectric generation for July under the 70th percentile streamflow
condition is projected to decline by approximately 115 aMW as a result of the water being shifted out of
the month of July.
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
Hells Canyon Complex as ru-of-river plants. The generation model mathematically manages reservoir
storage in the Hells Canyon Complex 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 peak-hour analysis, an internally developed spreadsheet utilizing a commercial optimization routine
is used to shape the montWy average generation for the Brownlee, Oxbow, and Hells Canyon projects
into hourly generation profies, while approximating compliance with Hells Canyon outflow ramp rate
constraints, Brownlee Reservoir level constraints, and operating reserve obligations.
A representative measure of the streamflow condition for any given year is the volume of infow to
Brownlee Reservoir durng the April-July ruoff period. Figure 5.3 shows historical April-July
Brownlee infow as well as forecast Brownlee inflow for the 50th, 70th, and 90th 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.
Figure 5.3 Brownlee Historical and Forecast Inflows
13
12
11
10
9
8
7
6
5
4
3
2
1
o I i
1980
Æ
~
:l
~~
jir
f J\
~J "-
'I 1 1
,.\ft F
~t"~l1\\I \A)l~ ""?f
I:
¡Ii ¡Ii iii iii iii
2005
¡Ii
2010
¡Ii
2015
¡Ii
2020
iii
20251985199019952000
-: Historical - 50th Percentile -70th Percentile -90th Percentie
Page 58 20091RP
Idaho Power Company 5. Planning Period Forecasts
Idaho Power recognizes the need to remain apprised of scientific advancements concernng climate
change on the regional and global scale. Idaho Power believes that there is too much uncertainty to
predict the scale and timing of hydrologic effects due to climate change. Therefore, no adjustments
related to climate change have been made in the 2009 IRP.
Thermal
Idaho Power's thermal generation resources are comprised of coal and natural gas-fired facilities.
The coal-fired resources generally operate 24 hours-per-day, every day, to provide baseload energy.
The natural gas-fired resources are generally used to meet peak-hour load on certain days during the
sumer months.
Monthly average energy forecasts for the coal-fired projects are based on typical baseload output levels,
with seasonal reductions occuring primarily during spring months for regularly scheduled maintenance
activities. Idaho Power schedules periodic maintenance to coincide with periods of high hydro
generation, seasonally low market prices, and moderate customer load.
Plant modifications that are required to maintain compliance with air-quality standards are projected for
the Boardman plant in 2014 and 2018, for the Valmy plant in 2018, and for the Bridger plant in 2009,
2015, and 2016. The total effect of the air quality modifications is a reduction in coal-fired generation of
less than one percent. Offsetting the modifications at the Jim Bridger plant are planned efficiency
upgrades that wil create a net increase in average generation of 17 aMW by 20 i 6.
With respect to peak-hour output, the coal-fired projects are forecast to generate at the full rated
maximum dependable capacity, minus six percent to account for forced outages. The gas-fired resources
are projected to be fuly available to meet extreme load conditions or during periods of transmission
congestion. The peaking capability of the natural gas resources is adjusted seasonally to reflect the effect
of ambient air temperature.
Planned Upgrades at Thermal Facilties
Efficiency upgrades are planed for each ofthe four units at the Jim Bridger plant staing in 2010.
The upgrades consist of replacing turbine components with higher efficiency designs for each unit's
high pressure, intermediate pressure, and low pressure turbines. This project will star with the high
pressure/intermediate pressure turbine upgrade on Unit 1 which wil result in a generation increase of
2.1 MW. The low pressure turbines on Unit i wil be replaced in 2018 which will increase output by
another 4 MW for a total of 6.1 MW. Units 2, 3, and 4 will have all high pressure, intermediate pressure,
and low pressure turbines replaced in 2016,2017, and 2019. Idaho Power's share of the projected
generation increase associated with each upgrade is a total of 6.1 MW per unt, with the increased output
related solely to efficiency improvements with no additional fuel required. Idaho Power's share of the
costs for the upgrades is expected to be approximately $11 milion per unit.
Coal Price Forecast
The expected coal price forecast for the 2009 IRP is an average of Idaho Power's coal forecasts for its
Valmy and Jim Bridger thermal plants. The coal price forecasts were created using current coal and rail
transportation market information and the Global Insight 2008 U.S. Power Outlook report. The resulting
costs are shown in Figure 5.4 and represent the delivered cost of coal, including rail costs, and use taxes.
A sumary of the coal price forecast can also be found in Appendix C- Technical Appendix.
20091RP Page 59
5. Planning Period Forecasts Idaho Power Company
Transmission Resources
Transmission constraints are an important factor in Idaho Power's ability to reliably serve peak-hour
load. Idaho Power uses spot market purchases when the company's generating resources and firm
purchases are inadequate to meet peak-hour load requirements and transmission constraints limit
Idaho Power's ability to import additional energy.
For the IRP, the transmission analysis requires hourly forecasts for the entire 20-year planing period for
both customer load and company generation. The hourly transmission analysis is used to quantify the
magnitude of off-system market purchases necessary to serve forecast load, and to determine if adequate
transmission capacity is available to deliver additional market purchases to load centers.
From the hourly load and generation forecasts, a determination can be made regarding the need for,
and the magnitude of, the off-system market purchases needed to serve system load. The projected
off-system market purchases are added to all other committed transmission obligations to determine if
the additional imported energy wil exceed the operational limits of the transmission system.
The analysis assumes that all off-system market purchases wil come from the Pacific Northwest.
Historically, durng Idaho Power's peak-hour load periods, off-system market purchases from the east
and south have proven to be unavailable or very expensive. Many of the utilties to the east and south of
Idaho Power also experience a sumer peak, and the weather conditions that drive Idaho Power's
summer peak-hour load are often similar across the Intermountain Region. Therefore, Idaho Power does
not typically rely on imports from the Intermountain Region for planing puroses.
For the 2009 IRP, Idaho Power has restricted its transmission analysis to the scenario assuming
90th percentile streamflows, 70th percentile load, and 95th percentile peak-hour load. The 95th percentile
peak-hour load planning criterion means that there is a one in twenty chance that Idaho Power wil be
required to initiate more drastic measures such as curiling load if attempts to acquire energy and
transmission access from the spot market are unsuccessfuL.
Idaho Power used the results of the transmission analysis to establish a capacity target for planng
puroses. The capacity target identifies the amount of additional generation, demand response programs,
or transmission resources that must be added to Idaho Power's system to avoid capacity deficits.
On a yearly basis, Idaho Power's transmission capacity is reserved for native load service based on
annual load and resource forecasts. Although transmission resources are owned by Idaho Power,
the uneserved transmission capacity may be purchased by other paries due to FERC's open access
requirements. Idaho Power must reserve the use of its own transmission system under FERC' s open
access rules. Often, Snake River flow forecasts for the remainder of the year are not known with a high
degree of accuracy until Mayor June and late spring is often too late to acquire firm transmission
capacity for the sumer months.
Natural Gas Price Forecast
Future natural gas price assumptions significantly infuence the financial results of the operational
modeling used to evaluate and rank resource portfolios. The 2009 IRP natural gas price forecast uses
several outside public and private forecast sources to develop a composite future yearly Henry Hub price
cure. The forecast sources include the Northwest Power and Conservation Council (NPCC), the New
York Mercantile Exchange (NYMEX), the Natual Gas Exchange, the Energy Information
Administration (EIA), and Global Insight.
The individual anual forecasts from the outside sources are evaluated and weighted to calculate the
composite forecast. The weighting is based on a combination of Idaho Power's expectation of price,
the reasonableness when compared with other forecasts, and the current forward price of actual contracts
Page 60 20091RP
Idaho Power Company 5. Planning Period Forecasts
being executed on various exchanges. In the near-term forecast horizon, greater weight is given to actual
commitment contracts being executed on the NYMEX compared to the longer term forecast which is
weighted more heavily towards projected prices without underlying financial trades (EIA,
Global Insight).
Regional price variabilty from the Henr Hub can be significant. Idaho Power uses a price adjustment
based on the cost of delivering natural gas from the Sumas trading hub to model natural gas prices in
southwest Idaho. The Sumas price adjustment incorporates the Pacific Northwest regional price
variation from Henr Hub and the transportation charges from Nortwest Pipeline Corporation to
deliver natural gas to Idaho Power's service area. The 2009 IRP assumes pipeline transport capacity wil
be available for future resources at the curent tariff rate that is included in the natural gas price forecast.
The Henry Hub price including the Sumas adjustment is shaped by month to reflect the normal seasonal
supply and demand price variation. The gas price forecast in all future years receives the same monthly
price shaping. Sumas gas prices can have high spot seasonal price variability, especially in the winter
months and the Sumas price volatility is not included in the regional adjustment. Idaho Power's
geographic position between Sumas gas and Rockies gas allows Idaho Power to access two independent
gas markets that may not have high price correlation. Also, Idaho Power expects the majority of the gas
planned for use in the resource portfolios wil be scheduled and purchased on longer term contracts
which wil diminish Idaho Power's exposure to spot price and seasonal price volatility.
In addition to an expected gas price forecast, high and low natural gas price forecasts are developed in
order to analyze the risk associated with prices substantially different than the expected-case. Figure 5.4
shows the expected, high and low natural gas price forecasts used in the 2009 IRP.
Figure 5.4 Fuel Price Forecast
$14
$13
$12
$11
$10
$9
:æ $8c:
'Ë $7
~ $6'".,
$5
$4
$3
$2
$1
$0
2010
- -- -- --~- --- _..... --
- -..------ - - - ~.-~-------- -------
ti::i
2012 2014 2016 2018 2020 2022 2024 2026 2028
-Sumas Delivered (Expected) - - Sumas Delivered (High) - - Sumas Delivered (Low) - Regional Coal
20091RP Page 61
5. Planning Period Forecasts Idaho Power Company
Cost of Carbon Emissions
Idaho Power's 2009 IRP analyzes the potential cost of carbon emissions differently than has been done
in previous IRPs. Historically, a "carbon adder" or tax has been used to account for the social costs of
emitting carbon or other combustion byproducts. The purose of a carbon adder is to account for all of
the costs in the price of energy produced by carbon-emmitting resources. Both the Waxman-Markey bil
(H.R. 2454) and the Boxer-Kerr bil (S. 1733) propose a cap-and-trade system for reducing carbon
emissions and Idaho Power considers the implementation of a cap-and-trade system to be more likely
than a carbon tax.
Although Idaho Power believes a cap-and-trade system is more likely, regulatory requirements dictate
the analysis be performed using a carbon adder, which Idaho Power has also done. However, the
primary discussion in the 2009 IRP regarding carbon emissions is related to Idaho Power's attempt to
model a cap-and-trade scenario under the provisions of the Waxman-Markey bilL. To model the
cap-and-trade scenario, Idaho Power has reduced the output from its coal facilities based on the number
of allowances that are expected to be allocated to the company. The cost of resource portfolios with
emissions in excess of the allocated amount of allowances are increased by purchasing additional
allowances.
The primary reason for adopting the cap-and-trade analysis in the 2009 IRP is to quantify the effects of
the proposed carbon legislation. Idaho Power's analysis indicated that a pure carbon tax increased
portfolio costs but did not result in a substantial reduction of emissions. Since the purose of the
legislation is to reduce carbon emissions, Idaho Power selected a modeling approach that actually
reduced carbon emissions. In addition, Idaho Power considers the cap-and-trade legislation the most
likely to be implemented.
In order to quantify the cost of the proposed legislation, Idaho Power has also modeled a scenario where
output from existing coal facilities has not been curtailed. A more thorough discussion of the analysis of
carbon emissions is contained in Chapters 8, 9 and 10.
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Idaho Power Company 6. Supply-Side Resources
6. SUPPLY-SIDE RESOURCES
Supply-side facilities are traditional generation resources. Early integrated resource plan (IRP) utility
commission orders directed Idaho Power and other utilities to give equal treatment to both supply-side
and demand-side resources. The company has done that and today, demand-side programs are an
essential component ofIdaho Power's resource strategy. The following sections describe all of the
supply-side resources that were considered when Idaho Power developed the resource portfolios for the
2009 IRP. Not all of the supply-side resources described in this section were included in the preliminary
resource portfolios, but every resource described below was considered.
Renewable Resources
Renewable resources are the foundation of
Idaho Power and the company has a long history
of renewable resource development and
operation. In the 2009 IRP, renewable resources
were included in all portfolios analyzed in order
to meet proposed federal renewable electricity
standard (RES) legislation. Renewable resources
are discussed in general terms in the following
sections.
Geothermal
Potential commercial geothermal generation in
the Pacific Northwest includes both flashed
steam and binar-cycle technologies. Based on The Raft River Geothermal Project is located in southern Idaho.
exploration to date in southern Idaho,
binary-cycle geothermal development is more likely than flashed steam within Idaho Power's service
area. Most of the optimal locations for potential geothermal development are believed to be in the
southeastern part of the state. However, the potential for geothermal generation in southern Idaho is
somewhat uncertain. In addition, 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 temperatue, development size, and water
availability. Flash steam plants are applicable for geothermal resources where the fluid temperature is
3000 Fahrenheit (F) or greater. Binary-cycle technology is used for lower temperatue geothermal
resources. In a binary-cycle geothermal plant, geothermal water is pumped to the surface and passed
20091RP Page 63
6. Supply-Side Resources Idaho Power Company
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 retured to the geothermal reservoir through injection wells.
Cost estimates and operating parameters for binar cycle geothermal generation in the IRP are based on
data from independent geothermal developers and information from the Geothermal Energy Association.
Estimates for flashed steam geothermal generation are based on data from the Northwest Power and
Conservation Council's (NPCC) Fifth Power Plan (2005).
Wind
A typical wind project consists of an aray of wind tubines ranging in size from 1-3 megawatts (MW)
each. The majority of the potential wind sites in southern Idaho lie between the south central and the
most southeastern par 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 Region, which is evidenced by the number of existing and planned projects.
Wind resources present a problem for utilities due to the varable and intermittent nature of wind
generation. Therefore, planning for new wind resources requires estimates of the expected anual energy
and peak-hour capacity. For the 2009 IRP, Idaho Power used an anual average capacity factor of
32 percent and a capacity factor of 5 percent for peak-hour planing.
Idaho Power curently has 192 MW (nameplate) of wind generation on-line. Signed PURPA contracts
exist for 266 MW of wind generation that is expected to be on-line by the end of2010. The 2012 Wind
Request for Proposals (RFP) is also expected to add up to 150 MW by 2012, which will put the total
wind generation on Idaho Power's system in excess of 600 MW. Given this projected increase, it is
critical that integration methodologies in practice continue to evolve though ongoing operational
experience and fuher study. Idaho Power plans to update its wind integration study in the first half of
2010 during the time between filing the 2009 IRP and starting the 2011 IRP process in July 2010. The
updated study wil incorporate planed increases in wind generation as well as the capability of the new
Langley Gulch combined-cycle combustion tubine (CCCT) to provide additional operating reserves.
Hydro
Hydropower is the foundation of Idaho Power's generation fleet. The existing generation is low cost and
does not emit potentially harful pollutants like fossil fuel based resources. Idaho Power believes the
development of new large hydroelectric projects is unikely because few appropriate sites exist and
because of environmental and permitting issues associated with new, large facilities. However, small
hydro sites have been extensively developed in southern Idaho on irrigation canals and others sites,
many of which have PURP A contracts with Idaho Power.
Because small hydro, in particular, ru-of-river and projects requiring small or no impoundments, does
not have the same level of environmental and permitting issues as large hydro, the IRP Advisory
Council (IRP AC) expressed an interest in including small hydro in the 2009 IRP. The potential for new
small hydro projects was recently studied by the Idaho Strategic Allance's Hydropower Task Force.
The results of this evaluation are presented in a draft report available on the Idaho Offce of Energy
Resources' (IOER) Web site at ww.energy.idaho.gov. Idaho Power and others also continue to
evaluate pumped storage opportunities and the state of Idaho is examining possible large water storage
projects for flow augmentation and the potential for hydropower.
Page 64 20091RP
Idaho Power Company 6. Supply-Side Resources
Due to the potential regulation of carbon emissions and associated costs, new small hydro may become a
good resource option for Idaho Power. However, uncertainty exists in the level of available sites and the
likelihood the sites would be developed as PURP A projects.
Solar
There are two primary types of solar technology; solar thermal and photovoltaic (PV). Solar thermal
technologies utilize mirrors to focus the sun's rays onto a central receiver or a "collector" to collect
thermal energy that can be used to make steam and power a turbine, creating electricity. PV panels
absorb solar energy collected from sunlight shining on panels of solar cells, and a percentage of the solar
energy is absorbed into the semiconductor materiaL. The energy accumulated inside the semiconductor
material energizes the electrons creating an electric curent.
On cloudy days, solar thermal generation will not produce power. However, thermal storage using
molten salt fuctions as an energy storage system allowing solar thermal generation plants to generate
electricity after the sun sets or during brief cloudy periods, generally for three to seven hours.
PV technology uses panels that convert the sun's rays directly to electricity. Even on cloudy days,
a PV system can stil provide 15 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 kilowatt hour (kWh)/m2/day (daily insolation
average over a year). The higher the insolation number, the better the solar power potential for an area.
National Renewable Energy Laboratories (NREL) insolation charts show the Desert Southwest has the
highest solar potential in the United States.
For the 2009 IRP, Idaho Power hired Black & Veatch to perform an independent, evaluation of the
feasibility of using solar generation technology in southwest Idaho. The purpose of the study was to
identify solar power generation technology options for southwest Idaho and to develop cost estimates
associated for each technology. In the study, Black & Veatch concluded that during the summer,
southwest Idaho's insolation is very similar to the desert Southwest. However, during winter months
insolation values are approximately 50 percent lower than the Desert Southwest.
Black and Veatch modeled generation output of the various technologies using the Boise weather station
because of its robust data set. Depending on the solar technology, capacity factors ranged from 17 to
28 percent, and for a 100 MW facility, land requirements ranged from 570-1,300 acres. The modeled
generation for an entire year resulted in the highest production occuring in July and the lowest in
Janua and February.
Idaho Power's peak demand occurs during July typically between 4:00 p.m. and 8:00 pm and is
primarily due to air conditioning and irrigation load. Modeled July daily generation output from a
parabolic trough or power tower with molten salt storage closely follows the system load curve on
sumer peak days. Additional details and the entire Black & Veatch study can be found on
Idaho Power's Web site at ww.idahopower.com. The cost estimates contained in the study were used
in the 2009 IRP.
Solar Generation Technologies
Black & Veatch analyzed various solar thermal and photovoltaic technologies in the study.
The following sections contain details on each of the technologies.
Parabolic Trough
Parabolic trough technology is a closed looped system that consists of a solar field where single axis
parabolic mirrors heat pipes containing a transfer fluid. The hot fluid returs from the solar field where
heat energy is transferred to water, creating steam at 700 F. The steam is then used to drive a turbine and
20091RP Page 65
6. Supply-Side Resources Idaho Power Company
generate electricity. In addition to heating water for steam, the hot fluid can also heat salt until the salt
becomes molten. When the sun is not shining, the transfer fluid can be heated by the molten salt.
After transferring the heat energy, the fluid retus to the solar field to be reheated.
Power Tower
Power tower technology uses thousands of small, flat, two-axis mirrors, called heliostats, to reflect the
sun's rays onto a boiler at the top a central tower. The concentrated sunlight strikes the boiler's pipes,
heating the water inside to 1,000°F. The high temperature steam is then piped from the boiler to a
tubine where electricity is generated.
Parabolic Dish Engine
A two-axis parabolic dish focuses the sunlight striking the dish onto a collector placed above the dish.
The collector is connected to a Stirling engine which uses the thermal energy to heat hydrogen in a
closed-loop system. The expansion of the hydrogen gas creates a pressure wave on the pistons of the
Stirling engine which turns a generator to create electricity.
Photovoltaic
PV panels absorb solar energy collected from sunlight shining on panels of solar cells, and a percentage
of the solar energy is absorbed into the semiconductor materiaL. The energy accumulated inside the
semiconductor material energizes the electrons creating an electric current. The solar cells have one or
more electric fields which force electrons to flow in one direction as a direct curent (DC). The DC
energy is passed through an inverter, converting it to alternating curent (AC) which can then be used
on-site, stored in a battery, or sent to the grid.
Biomass
Biomass fuels, such as wood residues, organic
components of municipal solid waste, animal manure,
and wastewater treatment plant gas, can be used to
power a turbine or reciprocating engine to produce
electricity. Most of the biomass generating resources
in the region are small-scale local cogenerating
facilities operating under PURP A contracts. The use
of biomass fuels has not proven to be economic for
large scale commercial power production. A vailable
fuel supply can vary as production from the industr
fluctuates. The biomass fuel sources assumed in the
resource cost analysis for the 2009 IRP are wood
by-products from the forest and wood products
industry. Because of the relatively small size of
biomass projects and recent PURP A biomass project
development, biomass resources were not included in
the portfolios analyzed for the 2009 IRP.
River In-stream Generation
Biomass energy is produced from agricultural
waste in southern Idaho.
River in-stream generation is the conversion of the kinetic energy of water in free flowing rivers and
channels to electricity. River in-stream energy conversion (RISEC) technology is stil largely in a
conceptual stage of development, with a few small vendors focused on the technology and limited
operating experience in natural waters. The use of in-stream generation has not proven to be economic
for large scale or commercial power production. The cost estimates and operating parameters for
Page 66 20091RP
Idaho Power Company 6. Supply-Side Resources
in-stream generation are based on data from a feasibility study performed by the Electric Power
Research Institute (EPRI) on two specific locations in Idaho Power's service area.
Natural Gas-Fired Resources
Natual gas-fired resources burn natural gas in a combustion turbine in order to generate electricity.
CCCT are typically used for baseload energy, while less effcient SCCT are used to generate electrcity
during peak load periods. Additional details on the characteristics of both types of natual gas resources
are presented in the following sections.
Combined-Cycle Combustion Turbines
Until recently, CCCT plants have been the
preferred choice for new commercial power
generation in the region. CCCT technology
caries a low initial capital cost compared to
other baseload resources, has high thermal
efficiencies, is highly reliable, offers
significant operating flexibility, and emits less
harmful emissions when compared to coaL.
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 produces steam that drives a
steam-tubine generator to produce electricity. Natural gas-fired generation is an important component
In a CCCT plant, heat that would otherwise be of Idaho Power's resource portolio.
wasted is used to produce additional power beyond that typically produced by a SCCT. New CCCT
plants can be built or existing SCCT plants can be converted to combined cycle units.
Several CCCT plants, including Idaho Power's Langley Gulch project, are planed in the region due to
recently declining natural gas prices, the need for baseload energy, and additional operating reserves
needed to integrate wind resources. While there is no curent shortage of natual gas, fuel supply is a
critical component of the long-term operation ofa CCCT. Ifnatural gas supplies become constrained,
efforts will have to be made to identify additional regional sources or off shore sources through the
construction of liquefied natural gas. terminals.
Simple-Cycle Combustion Turbines
Simple-cycle natural gas turbine technology involves pressurizing air which is then heated by buring
gas in fuel combustors. The hot pressurized air is expanded through the blades of the turbine which is
connected by a shaft to the electric generator. Designs range from larger industrial machines at 80-
200 MW to smaller machines derived from aircraft technology. SCCTs have a lower thermal efficiency
than CCCT resources and are not typically economical to operate other than to meet peak-hour load
requirements.
Several natural gas-fired SCCTs have been brought on-line in the region in recent years primarly in
response to the regional energy crisis of 2000-200 i. High electricity prices combined with persistent
drought conditions during the 2000-2001 time period as well as continued sumertime peak load
growth created interest in generation resources with low capital costs and relatively short constrction
lead times.
20091RP Page 67
6. Supply-Side Resources Idaho Power Company
Idaho Power curently has approximately 430 MW of SCCT resources. Peak sumertime electricity
demand continues to grow significantly within Idaho Power's service area, and SCCT generating
resources have been constructed to meet peak load during the critical high demand times when the
transmission system has reached full import capacity. The plants may also be dispatched for financial
reasons during times when regional energy prices are at their highest. Like CCCTs, feasible sites and gas
supply curently exist for futue SCCT development. The SCCT resources studied in the 2009 IRP are
assumed to be located in southwestern Idaho in close proximity to the mainline fuel supply and near
Idaho Power's main load center in the Treasure Valley. Furhermore, in the 2009 IRP, natual gas
pipeline capacity is assumed to be available. Given the limits of available natural gas pipeline capacity,
Idaho Power may need to begin acquiring additional transport capacity.
Conventional Coal Resources
Conventional coal-fired generation is a
mature technology and has been the primary
source of commercial power production in
the United States for many decades.
Traditional pulverized coal plants have been
a significant par of Idaho Power's
generation mix since the early 1970s.
Idaho Power curently has over 1,000 MW
of pulverized coal generation in service.
All of Idaho Power's pulverized coal
generation is in neighboring states and is
owned with other regional utilties.
A pulverized coal facility uses coal that is
ground into a dust-like consistency and The Boardman Plant in Oregon provides baseload energy to
burned to heat water and produce steam to Idaho Power customers.
drive a steam tubine and generator. Emission controls at coal plants have become increasingly
important in recent years and many units in the region have been upgraded to include the latest scrubber
and low Nitrous Oxide (NOx) burer technology to help reduce harmful emissions and particulates.
Coal has the highest ratio of carbon-to-hydrogen of all the fossil fuels and signficant research is being
done in hopes of developing carbon captue and sequestration technology that can be economically
added to existing coal facilities.
Even though coal-fired power plants require significant capital commitments to develop, coal resources
take advantage of a low-cost fuel and provide reliable and dispatchable energy. Coal supplies are
abundant in the Intermountain Region and are sufficient to fuel Idaho Power's existing plants for many
years to come.
In 2007, Idaho Power decided to not pursue the development ofa coal-fired resource identified in the
2006 IRP. In addition to considering the cost ofa coal-based resource, the company considered the
uncertinty surounding the regulation of carbon emissions and the abilty to permit a new coal resource.
Idaho Power continues to evaluate other coal-fired resource opportunities, including efficiency
improvements at its jointly owned facilities as well as monitoring the development of clean coal
technologies. However, due to the uncertainty regarding futue carbon regulations, conventional coal
resources were not included in any ofthe portfolios analyzed in the 2009 IRP.
Page 68 20091RP
Idaho Power Company 6. Supply-Side Resources
Advanced Nuclear
The Energy Policy Act of 2005 authorized funds to be appropriated for the development of a
next-generation nuclear power project at the Idaho National Laboratory (INL). The project would
consist of the research and development, design, construction, and operation of a prototype plant,
including a nuclear reactor used to generate electricity, produce hydrogen, or both. The target
completion date for the prototype nuclear reactor is September 202 i. For fiscal years 2006-2015,
$ 1.25 bilion has been authorized for appropriation. In addition, the act authorizes additional
appropriations deemed necessary between fiscal years 2016-2021 to complete the project. Whether
funds wil actually be appropriated to develop the project is unkown at the present time.
The act also establishes tax credits for up to 6,000 MW of new advanced nuclear power development.
Projects must be in service by January 2021 to qualify. Multiple projects in the southeastern states wil
likely make up the next 6,000 MW of development, and therefore qualify for the credits. The first of the
new nuclear projects are expected to be on-line by 2014. Idaho Power wil follow the progress ofthe
projects in the coming years and special attention wil be paid to the issues surounding spent nuclear
fuel disposaL.
In the 2006 IRP, the preferred portfolio included a power purchase agreement (PPA) for a 250 MW
share of the proposed Next Generation Nuclear Plant project beginnng as early as 2022. Recent
discussions with INL suggest the likelihood of the project being located in Idaho is less than when the
2006 IRP was prepared. Although the preferred portfolio for the 2009 IRP does not contain a nuclear
resource, Idaho Power will continue to monitor the progress of the advanced nuclear research and
development efforts as well as new modular nuclear designs that are being proposed and investigated by
others.
Resource Advantages and Disadvantages
Different resource types have specific characteristics that can be either an advantage or a disadvantage.
In order to sumarize the differences between the resource types, Idaho Power has prepared Table 6.1
which shows both the advantages and disadvantages ofthe resources analyzed in the 2009 IRP.
Resource Cost Analysis
The costs of a variety of supply-side and demand-side resources were analyzed for the 2009 IRP.
Cost inputs and operating data used to develop the resource cost analysis were derived from various
sources including, but not limited to, the NPCC, Department of Energy (DOE), independent consultants,
and regional energy project developers. Resource costs are presented as:
· Levelized fixed cost-per-kilowatt (kW) of installed (nameplate) capacity per month, and
· Total levelized cost-per-megawatt hour (MWh) of expected plant output or energy saved,
given assumed capacity factors and other operating assumptions.
The levelized costs for the various supply-side alternatives include the cost of capital, operating and
maintenance (O&M) costs, fuel costs, and other applicable adders and credits. The cost estimates used to
determine the cost of capital for the supply-side resources include engineering development costs,
generating and ancilary equipment purchase costs, installation, applicable balance of plant construction,
and the costs for a generic transmission interconnection to Idaho Power's network system. More detailed
interconnection and transmission system backbone upgrade costs were estimated by Idaho Power's
transmission planing group. The cost of capital also includes Allowance for Funds Used Durng
Constrction (AFUDC-eapitalized interest). The O&M portion of each resource's levelized cost
20091RP Page 69
6. Supply-Side Resources Idaho Power Company
includes general estimates for property taxes and property insurance premiums. The value of renewable
energy credits (RECs) is not included in the levelized cost estimates.
The levelized costs for each of the demand-side resource options include anual administrative and
marketing costs of the program, annual incentive or rebate payments, and anual participant costs.
The demand-side resource costs do not reflect the financial impact to Idaho Power as a result of these
load reduction programs.
Specific resource cost inputs, fuel forecasts, key financing assumptions, and other operating parameters
are shown in Appendix C- Technical Appendix.
Table 6.1 Supply-Side Resources Advantages and DisadvantagesResource Type Advantages Disadvantages
Geothermal · Renewable resource
. No harmful emissions
. Minimum fuel risk (once developed)
. Low, variable operating costs
· Baseload generation (90%+ capacity factor)
. Limited number of sites
. High exploration costs due to drillng risks
. Uncertainty surrounding future tax incentives
Wind . Renewable resource
. No fuel cost
. No harmful emissions
· Low, variable operating costs
. Limited number of good sites in southern Idaho
. Intermittent and non-dispatchable resource
. Ineffcient use of limited firm transmission capacity
. Avian and aesthetic impacts
. Uncertainty surrounding future tax incentives
Hydro . Renewable resource
. No fuel cost
. No harmful emissions
. Low, variable operating costs
. Limited number of sites
. Future development is limited to small sites or at
existing dams without power generation
. Fish and other environmental issues
Solar
(General)
Parabolic Trough
Power Tower
Parabolic Dish
Photovoltaic
· Renewable resource
. No fuel cost
. No harmful emissions
· Low, variable operating costs
· Generation would match well with summer peak
loads.
. More expensive than other resource options
. Poor generation during winter months
. Intermittent and non-dispatchable resource
. Ineffcient use of limited firm transmission capacity
. Limited utilty scale projects exist
. Can be built with thermal storage . Utilty scale production is limited
· By using molten salt, thermal storage can be built
integrally into the system
. Utilty scale production is unproven
. Requires land slope of 1 percent of less
· Off-grid electricity production in remote areas . Not suitable for storage options
. Unproven technology
. Proven & reliable technology
. Suitable for distributed generation
. Cloud cover creates a rapid power drop-off
. Utilty scale projects are only practical up to
10MW
Biomass . Renewable resource
. No harmful emissions
. Minimum fuel risk
· Low, variable operating costs
· Baseload generation (90%+ capacity factor)
. Limited number of sites
. Uncertainty surrounding future tax incentives
. Fuel supply risk
Page 70 20091RP
Idaho Power Company 6. Supply-Side Resources
Resource Type
In-stream
Generation
Advantages
· Renewable resource
· No harmful emissions
. No fuel cost
Disadvantages
. Small size, many sites would be required
. Environmental impact and permitting
. High maintenance cost
Distributed
Generation
· Utilze existing backup generators at customer
sites
· Dispatchable resource
· Provides operating reserves
. More expensive than other resource options
. Limited number of sites
. Fuel price risk and volatiity
. Existing air quality permits may need to be
modified
. Small size, many sites would be required
Natural Gas
Combined-Cycle
Combustion
Turbines (CCCT)
Simple-Cycle
Combustion
Turbines (SCCT)
. Proven and reliable technology
· Dispatchable resource
· Provides operating reserves necessary for
integration of renewable generation
· More effcient than a SCCT
· Greater than 50% reduction in CO2 emissions per
MWh of output compared to conventional
pulverized coal technology
. Fuel price risk and volatilty
. Potential fuel supply and transporttion issues
· Dispatchable resource
· Proven, reliable resource
. Low capital cost
· Short construction lead times
. Ideal for peaking service
. High variable operating cost
. Fuel price risk and volatility
. Less effcient than a CCCT
Coal
Pulverized
Advanced
Technology
· Abundant, low cost fuel
· Less price volatilty than natural gas
· Proven and reliable technology
· Dispatchable resource
· Well suited for baseload operations
. Potential lack of public acceptance
. Significant particulate and gas emissions,
particularly CO2
. Significant capital investment
. Long construction lead times
. Lengthy environmental permitting and siting
processes
· Abundant, low cost fuel
· Potentially lower greenhouse gas emissions if CO2
is sequestered
· Potential for financial incentives
· Oispatchable resource
. New, unproven technologies
. Higher capital costs than pulverized coal
. Long construction lead times
Nuclear · Forecasted low fuel costs
· Forecasted adequate fuel availabilty
. Lack of greenhouse gas emissions
· Potential low cost of production
· Proven technology (existing reactor types)
. Lack of public accptance
. Safety concerns
. Waste disposal
. Construction cost uncertainties and the potential
for construction cost overrns
. Security concerns
20091RP Page 71
6. Supply-Side Resources Idaho Power Company
Emission Adders for Fossil Fuel-Based Resources
All resource alternatives have potential environmental and other social costs that extend beyond just the
capital and operating costs included in the cost of electricity. Fossil fuel-based generating resources are
particularly sensitive to some of the environmental and social costs. It is likely that further emissions
regulations wil be implemented during the period covered in the 2009 IRP.
In the analysis, Idaho Power incorporated estimates for the futue costs of certain emissions into the
overall cost of the various fossil fuel-based resources. Within the resource cost analysis rankng,
the levelized costs for the various fossil fuel-based resources include emission adders for greenhouse
gases (GHG), NOx, and mercur. The additional costs are assumed to begin in 2012. Table 6.2 provides
the emission adder rates assumed in the analysis. Based on the assumptions in Table 62, Table 6.3
provides the emissions costs for the various fossil fuel-based resources that were analyzed.
Table 6.2 Emissions Adder Assumptions
Adder
GHG............................................................................,
NOx..............................................................................
Mercury .......................................................................'
Cost in 2009 U.S. dollars
$43 per ton
2,600 per ton
1 ,443 per ounce
First Year Applied
2012
2012
2012
Annual Escalation
2.50%
2.50%
2.50%
Table 6.3 Emission Adders (lbs/MWh)
Adder
Pulverized Coal...................................................................................................................
IGCC...................................................................................................................................
IGCC with Carbon Sequestration............................................. ...........................................
Distributed Generation Diesel.. ........................................................................... ................
SCCT..................................................................................................................................
CCCT..................................................................................................................................
GHG NOx Hg
1,886 0.44 0.00
1,797 0.21 0.00
309 0.43 0.00
1,540 0.00 0.00
1,127 0.11 0.00
809 0.08 0.00
Production Tax Credits for Renewable Generating Resources
Various federal tax incentives for renewable resources were extended and/or renewed within the
Emergency Economic Stabilization Act of2008. This legislation requires most projects to be on-line by
December 31, 20 i 6, to be eligible for the federal production ta credits (PTCs) identified in Section 45
of the Internal Revenue Code. The credit is eared on power produced by the project during the first
i 0 years of operation. The credit, which is adjusted anually for infation is curently valued at
$2 i per MWh for wind and geothermal resources.
Levelized Capacity (Fixed) Cost
The anual fixed revenue requirement in nominal dollars for each resource were sumed and levelized
over a 30 year operating life and are presented as dollars-per-kW of plant nameplate capacity per month.
Included in these costs were the cost of capital and fixed O&M estimates. Figure 6. i provides a
combined raning of all the various resource options, in order of lowest to highest levelized fixed
cost-per-kW-per-month. The raning shows that distributed generation and natural gas peakng
resources are the lowest capacity cost alternatives. Distributed generation and gas peakng resources do
have high operating costs, but the operating costs are not as important when the resource is only used a
limited number of hours per year to meet peak-hour demand.
Page 72 20091RP
Idaho Power Company 6. Supply-Side Resources
Levelized Cost of Production
Certain resource alternatives carry low-fixed costs and high-variable operating costs while other
alternatives require significantly higher capital investment and fixed operating costs, but have
low-variable operating costs. The levelized cost of production measurement represents the estimated
annual cost-per-MWh in nominal dollars for a resource based on an expected level of energy output
(capacity factor) over a 30-year operating life.
The nominal, levelized cost of production assuming the expected capacity factors for each resource tye
is shown in Figure 6.2. Included in these costs are the cost of capital, non-fuel O&M, fuel, and emission
adders; however, no value for RECs was assumed in this analysis. Resources such as DSM measures,
the Shoshone Falls upgrade, geothermal, wind, and certin types of thermal generation appear to be the
lowest cost for meeting baseload requirements.
20091RP Page 73
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6. Supply-Side Resources Idaho Power Company
This page left blan intentionally.
Page 76 20091RP
Idaho Power Company 7. Transmission Resources
7. TRANSMISSION RESOURCES
High-voltage transmission lines are a key
element in operating Idaho Power's electrical
system and are necessary for reliability, which
makes them an essential part ofIdaho Power's
resource portfolio. In order to keep the electric
power system balanced, generation must match
system load at all times. Regional transmission
interconnections improve reliability by
providing the flexibility to move electricity
between balancing authorities and also provide
economic benefits from the ability to share
operating reserves.
Historically, Idaho Power has been a "sumer
peaking" utility, while most other utilities in
the Pacific Northwest experience system peak
loads during the winter. Because of this, Idaho Power is able to purchase energy from the Mid-Columbia
market to meet peak sumer load and sell excess energy to Pacific Northwest utilities during the winter
and spring. This practice benefits Idaho Power's customers because the construction of additional
peaking resources is avoided and revenue from off-system sales is retured to customers through the
power cost adjustment (PCA).
Transmission Interconnections
High-voltage transmission lines are necessary to
interconnect with other regional utilities.
While Idaho Power has added generation resources in the recent past to meet load growth, the abilty to
import additional amounts of energy from the Pacific Northwest has been, and continues to be, limited
by constraints on the existing transmission system. Idaho Power's transmission system is shown in
Figure 7.1 and the associated interconnections and capacities are shown in Table 7.1.
The rated capacity of a transmission path may be less than the sum of the individual circuit thermal
capacities. The difference is due to a number of factors, including load distribution, potential outage
impacts, and surounding system limitations. In addition, not all of the transmission capacity identified
in Table 7.1 is available for Idaho Power's use. Reliability reserve margins, ownership rights,
20091RP Page 77
7. Transmission Resources Idaho Power Company
contractual restrictions, and prior obligations commit much of the transmission capacity to other paries.
In addition to the restrictions on interconnection capacities, other internal transmission constraints may
limit Idaho Power's ability to access specific energy markets. The internal transmission paths needed to
import resources from other utilties are shown in Figure 7.1 and Table 7.1. The following sections
provide additional details on Idaho Power's primary interconnections and the constraints on each path.
Idaho Power regularly evaluates transmission improvements, such as the installation of reactive devices,
to prove incremental transmission capacity increases on external interconnections and internal paths.
When determined to be cost effective, Idaho Power commits capital resources to the improvements.
Incremental transmission capacity increases are typically small and do not materially impact the
Integrated Resource Plan (IRP) planng process.
Table 7.1
Transmission
Interconnections
Transmission Interconnections
Capacity
To Idaho From Idaho
Idaho to Northwest 1,090-1,200 MW
Sierra
Eastem Idaho 1
262MW
Utah (Path C)2 775-950 MW
Montana3 79MW
87MW
600MWPacific (Wyoming)
Line or Transformers
2,400 MW Oxbow Lolo 230-kV
Midpoint Summer Lake 500-kV
Hells Canyon Enterprise 230-kV
Quart Tap LaGrande 230-kV
Hines Harney 138/115-kV
500 MW Midpoint Humboldt 345-kV
Kinport Goshen 345-kV
Bridger Goshen 345-kV
Brady Antelope 230-kV
Blackfoot Goshen 161-kV
830-870 MW Borah Ben Lomond 345-kV
Brady Treasureton 230-kV
American Falls Malad 138-kV
58 MW Antelope Anaconda 230-kV
70 MW Jefferson Dilon 161-kV
600 MW Jim Bridger 345/230-kV
Connects to Idaho Power
Avista
Pacific Power
Pacific Power
BPA
BPA
Sierra Pacific Power
Rocky Mountain Power
Rocky Mountain Power
Rocky Mountain Power
Rocky Mountain Power
Rocky Mountain Power
Rocky Mountain Power
Rocky Mountain Power
NorthWestern Energy
NorthWestern Energy
Rocky Mountain Power
Power Transfer Capacity for Idaho Power's Interconnections
1 The Idaho Power-Rocky Mountain Power interconnection total capacities in eastern Idaho and Utah include Jim Bridger resource
integration.
The Path C transmission path also includes the internal Rocky Mountain Power Goshen-Grace 161-kV line and the Three Mile Knoll
345/138-kV transformer.
The direct Idaho Power-Montana Power schedule is through the Brady-Antelope 230-kV line and through the Blackfoot-Goshen 161-kV
line that are listed as an interconnection with Rocky Mountain Power. As a result, Idaho-Montana and Idaho-Utah capacities are not
independent.
Page 78 20091RP
Idaho Power Company 7. Transmission Resources
Figure 7.1 Idaho Power Transmission System Map
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20091RP Page 79
7. Transmission Resources Idaho Power Company
Brownlee-East Path
The Brownlee-East transmission path is on the east side of the Northwest Interconnection shown in
Table 7.1. Brownlee-East is comprised of the 230-kilovolt (kV) and 138-kV lines east of the
Brownlee/Oxbow/Quarz area. When the Midpoint-Sumer Lake 500-kV line is included with the
Brownlee-East path, the path is typically referred to as the Brownlee-East Total path. The constraint on
the Brownlee-East transmission path is within Idaho Power's main transmission grid and located in the
area between Brownee and Boise on the west side of the system.
The Brownlee-East path is most likely to face summer constraints during normal-to-high water years.
The constraints result from a combination of Hells Canyon Complex hydro generation flowing east into
the Treasure Valley, concurent with transmission wheeling obligations and purchases from the
Pacific Northwest. Transmission wheeling obligations also affect southeastern flow into and through
southern Idaho. Significant congestion affecting southeast energy transmission flow from the
Pacific Northwest may also occur durng December. Restrictions on the Brownlee-East path limit the
amount of energy Idaho Power can import from the Hells Canyon Complex, as well as off-system
purchases from the Pacific Northwest.
The Brownlee-East Total constraint is the primary restriction on imports of energy from the
Pacific Northwest durng normal and high water years. If new resources are sited west of the constraint,
additional transmission capacity wil be required to remove the existing Brownlee-East transmission
constraint to deliver the energy to the Boise/Treasure Valley load area. The Boardman to Hemingway
project is a major addition to the Brownlee East Total Path and wil remove the existing Brownee-East
constraint.
Oxbow-North Path
The Oxbow-North path is a par of the Northwest Interconnection and consists ofthe Hells Canyon-
Brownlee and Lolo-xbow 230-kV double-circuit line. The Oxbow-North path is most likely to face
constraints during the sumer months when high northwest-to-southeast energy flows and high hydro
production levels coincide.
Northwest Path
The Idaho to Northwest path consists of the 500-kV Midpoint-Sumer Lake line, the three 230-kV
lines between the Northwest and Brownlee, and the 115-kV interconnection at Harey. The Nortwest
path has different constrains than the Brownlee-East path. Durng sumer months, the Northwest path
is more constrained in low-to-normal water years due to transmission wheeling obligations and
off-system purchases from the Pacific Northwest. The Boardman to Hemingway project is a major
addition to the Idaho to Northwest path and wil relieve constraints on the path.
Montana Path
The Montana path consists of the Antelope-Anaconda 230-kV and Jefferson-Dilon 161-kV
transmission lines. The Montana path is also constrained durng the sumer months. The Antelope-
Anaconda 230-kV transmission line is one segment of the Associated Mountain Power System (AMPS)
project which is owned by Idaho Power, NorthWestern Energy and PacifiCorp, collectively known as
the AMPS paricipants. The AMPS participants have initiated the process to increase the path rating by
installng reactive devices. The transmission capacity increase is subject to formalization of the
agreement between the partners and the WECC rating process. Idaho Power would be allocated a
portion of any capacity increase and plans for the capacity to be used for network and native load
service.
Page 80 20091RP
Idaho Power Company 7. Transmission Resources
Transmission Planning
Idaho Power has discussed possible transmission upgrades linking the company's service area to the
regional energy market in the Pacific Northwest since the 2000 IRP. Idaho Power discussed the
Pacific Northwest transmission upgrades in general terms in both the 2000 and 2002 IRPs and identified
225 megawatts (MW) of capacity on the Boardman to Hemingway path, originally identified as the
McNar to Boise transmission path, in the preferred portfolio of the 2006 Integrated Resource Plan
(IRP). This chapter provides details regarding Idaho Power's existing transmission system, planning
considerations, and proposed transmission projects. Details of the analysis methods and results are
provided later in Chapters 9 and 10.
Transmission Adequacy
Prior to 2000, Idaho Power was able to reasonably plan for the use of short-term power purchases to
meet temporar water related generation deficiencies on its own system. Short-term power purchases
have been successful because Idaho Power is a summer peakng utility while the majority of other
utilities in the Pacific Northwest region experience peak loads during the winter.
The transmission adequacy analysis reflects Idaho Power's contractual obligations to provide wheeling
service to the Bonnevile Power Administration (BPA) loads in southern Idaho. The BPA loads are
typically served with a combination of energy and capacity from the Pacific Northwest and several
Bureau of Reclamation (BOR) projects located in southern Idaho. BPA is a network transmission
customer and Idaho Power's contractual obligations to BPA are detailed in four Network Service
Agreements under the Idaho Power Open Access Transmission Tariff (OATT).
Although Idaho Power has transmission interconnections to the Southwest, the Pacific Northwest market
is the preferred source of purchased power. The Pacific Northwest market has a large number of
participants, high transaction volume, and is very liquid. The accessible power markets south and east of
Idaho Power's system tend to be smaller, less liquid, and have greater transmission distances.
In addition, the markets south and east of Idaho Power's system can be very limited during sumer peak
conditions.
Prior to 2000, Idaho Power's IRPs often emphasized acquisition of energy rather than construction of
generating resources to satisfy load obligations as transmission constraints were not a major impediment
to Idaho Power's purchasing power to meet its service obligations. Transmission constraints began to
place limits on purchased power supply strategies starting with the 2000 IRP. In addition to evaluating
transmission alternatives in the IRP process, Idaho Power paricipates in regional transmission plang
efforts as a member of the Northern Tier Transmission Group (NTTG).
Northern Tier Transmission Group
The NTTG was formed in early 2007 with an overall goal of improving the operation and expansion of
the high-voltage transmission system that delivers power to consumers in seven western states.
In addition to Idaho Power, other members include Deseret Power Electric Cooperative, NortWestern
Energy, Portland General Electric (PGE), Rocky Mountain Power/PacifiCorp and the Utah Associated
Muncipal Power Systems (UAMPS).
Idaho Power is active in regional transmission planing through the NTTG, along with the Western
Electricity Coordinating Council's (WECC) Transmission Expansion Plannng Policy Committee
(TEPPC) and Planing Coordination Committee (PCC). In addition to integrated resource planing
requirements, coordinated regional and sub-regional planing studies are conducted and reviews of
various transmission projects are evaluated through technical studies in the WECC rating process.
20091RP Page 81
7. Transmission Resources Idaho Power Company
Through the NTTG planing process conducted in 2007, along with the 2008-2009 biennial plannng
process, a number of potential transmission projects, including the Boardman to Hemingway and
Gateway West projects, have been identified. The public stakeholder process evaluates transmission
needs as determined by state mandated integrated resource plans and load forecasts, proposed resource
development and generation interconnection queues, and forecast uses of the transmission system by
wholesale transmission customers.
By identifying potential resource areas and load center growth, the required transmission capacity
expansions to safely and reliably provide service to customers are identified. The process considers not
only Idaho Power's obligations to retail customers and network customers, such as BPA, but also
provides for open access interstate wholesale obligations required by FERC's planing requirements
under FERC Order No. 890's Attachment K planing process.
Proposed Transmission Projects
Idaho Power is responsible for providing safe and reliable electrical service to its service area, which
includes most of southern Idaho and a portion of eastern Oregon. In addition to operating under
regulatory oversight of the IPUC and the OPUC, Idaho Power is a public utility under the jurisdiction of
FERC and is obligated to expand its transmission system to provide requested firm transmission service
and to construct and place in service sufficient capacity to reliably deliver electrical resources to
customers.
Because of the potential for renewable resource development in the region and the constraints on the
existing transmission system, Idaho Power has considered two major transmission projects in the
2009 IRP-Boardman to Hemingway and Gateway West. These two projects were also evaluated in
NTTG's regional, biennal planing process along with several other large projects. For the 2009 IRP,
two portfolios requiring Boardman to Hemingway capacity were analyzed for the first 10 years of the
planning horizon (2010-2019). In the second 10 years (2020-2029), the Gateway West project was
included in every portfolio because curent constraints require the addition of new transmission capacity
for resources to be added in southern Idaho, east ofthe Treasure Valley load center. However,
the amount of Gateway West capacity is different in each portfolio depending on other included
resources.
Idaho Power will face increasing demands for transmission capacity in the coming decade. Additional
requirements include the forecast growth of existing network customers, including BPA's southern
Idaho contracts and another 1,000 MW of energy that is expected to be wheeled through Idaho Power's
system to other regional customers. The development of wind and other renewable resources in response
to renewable portfolio stadards (RPS) is anticipated to fuher increase the demand for transmission
capacity between the Intermountain Region and the Pacific Northwest.
The concept of "right sizing" a transmission project, or building the project to an appropriate potential,
has been carefully considered. There are many factors involved in the decision process prior to
proposing a solution to the identified requirements, including planing horizon perspectives.
The Boardman to Hemingway and Gateway West projects have been designed to appropriately size the
transmission line, and allow phased construction to meet Idaho Power's needs as well as satisfy requests
from third paries for capacity on the same path. A more detailed description of each project is presented
in the following sections.
Page 82 20091RP
Idaho Power Company 7. Transmission Resources
Boardman to Hemingway
The Boardman to Hemingway project is a new,
300 mile long, single-circuit, electric transmission
line between northeast Oregon and southwest Idaho.
The new line is intended to provide access to the
Pacific Northwest electric market and is not
intended to deliver energy from the Boardman coal
facility to Idaho Power's service area.
The project is expected to be completed and in
service in 2015. The overhead, 500-kV,
high-voltage transmission line wil connect a
switching yard at the Boardman Power Plant, near
Boardman, Morrow County, Oregon to the
Hemingway Substation, located in Owyhee County,
Idaho. The proposed transmission line wil connect
with other transmission lines on either end of the
project to convey electricity on a regional scale. Figue 7.2 shows a map of the region with the
Boardman and Hemingway substation termination points.
The northern terminal of the project is expected to interconnect with the existing Boardman substation,
which Idaho Power is a par owner. In the 2006 IRP, the new line was anticipated to interconnect at the
McNary substation; however, there is insufficient room at the existing McNary substation for major
transmission expansion options. A northeast Oregon (NEO) substation is also contemplated by a number
of utilities, providing futue interconnectivity of regional projects. The in-service date for the NEO
substation is unown at this time. The proposed Boardman to Hemingway project is not dependent
upon completion of the NEO substation project, or any of the other transmission proposals to satisfy
Idaho Power's need or other existing service requests.
The Boardman to Hemingway project is likely to utilize a bundled conductor design capable of a
thermal continuous rating of about 3,000 MW. However, due to reliability standards and the WECC's
rating process, the initial implementation of the Boardman to Hemingway project along with the
Gateway West project is likely to result in an increased rating of approximately 1,400 MW from east to
west (exports into the Pacific Northwest), and about 850 MW from west to east (imports into
Idaho Power's balancing authority area). The ratings are subject to techncal peer review and wil be
revisited as other regional projects continue to develop. As additional projects reinforce the transmission
network, additional capacity rating increases of the Boardman to Hemingway project may occur.
The Boardman to Hemingway project capacity or sizing considerations and termination locations were
developed in the public review process conducted by the NTTG and the project WECC phase 0 rating
process (the regional planng phase). During the review process, it was determined a 230-kV project
would be unable to meet Idaho Power's overall resource planng requirements and would underutilize
a substantial transmission corridor. A project operating voltage of 500-kV was selected to match the
existing Pacific Northwest transmission grid. A 765-kV line designed with a thermal capacity of
approximately 7,000 MW would not achieve a greater rating that the proposed 500-kV project,
but would be nearly twice the cost. Because of the higher cost, no fuher consideration was given to a
765-kV transmission line.
Public involvement is an important part of determining
the route of proposed transmission lines.
20091RP Page 83
7. Transmission Resources Idaho Power Company
Figure 7.2 Boardman to Hemingway Line Project Map
So~
BiRDMAN TO HEIWNGWAY
,,1/ TRANSMSSN UNl PROJECT
MARCH 200
Mi~Qw~
IlM~~.-o
Q t(l ZO-.
Page 84 20091RP
Idaho Power Company 7. Transmission Resources
Idaho Power has received more than 4,000 MW of requests to commence transmission service between
2005 and 20 I 4 on the Idaho-Northwest transmission path. Of the 4,000 MW of service requests,
only 133 MW were granted up through 2007 due to the limited available transmission capacity of the
existing system. There are curently active transmission service requests being studied that are expected
to commence operations when the proposed Boardman to Hemingway project is completed. In the
2006 IRP, Idaho Power requested 225 MW of energy imports from the Pacific Northwest to
Idaho Power's system. However, the 2009 IRP analyzed various levels of imports.
The Boardman to Hemingway project is important for the development of renewable resources as
northeast Oregon has the potential for both wind and geothermal resource development. Idaho Power
and Horizon Wind Energy recently developed the first phase of the 101 MW Elkhorn Valley Wind
Project in Union County, Oregon. Firm transmission capacity existed for the first 66 MW of the wind
project. The remaining 34 MW of output from the Elkhorn project may face curailment during times of
transmission congestion. Furher renewable resource development in northeast Oregon wil require
additional transmission resources.
Idaho Power is committed to working with communities to identify proposed and alternate routes for the
Boardman to Hemingway project. The initial process of identifying a route began in late 2007 when
Idaho Power submitted documents to the Bureau of Land Management (BLM), the U.S. Forest Service
(USFS), and the Oregon Department of Energy (DOE).
Following public scoping meetings held in October 2008, the agencies received public input requesting
Idaho Power to conduct more extensive outreach as par of identifying a route for the new transmission
line. In response, Idaho Power initiated the Community Advisory Process (CAP) to engage communities
from Boardman, Oregon to Melba, Idaho in siting the Boardman to Hemingway project. The CAP
enlists project advisory team members in three geographic regions within the project area. The members
are familiar with the local areas and issues; the topography, recreation, wildlife and view shed issues;
and work collaboratively with Idaho Power to identify and recommend potential line routes.
Idaho Power has been working with communities in the CAP since spring 2009 and the process is
expected to be completed in early 2010.
The results of the 2009 IRP analysis indicate the Boardman to Hemingway transmission line wil be a
well used resource that benefits customers and generators in both the Pacific Northwest and the
Intermountain Region. The capital cost of the Boardman to Hemingway project, as measured on a
dollar per kW of capacity basis, is estimated to be well below the capital cost of any supply-side
resource alternative. Additional information about the Boardman to Hemingway project can be found at
ww.boardmantohemingway.gov.
Gateway West
The Gateway West transmission line project is a joint project between Idaho Power and
Rocky Mountain Power to build and operate approximately 1,150 miles of new transmission lines from
the planed Windstar substation near Glenrock, Wyoming to the Hemingway substation near Melba,
Idaho. The project is being designed such that multiple construction phases can provide transmission
segments as needs materialize. Some segments of the Gateway West project are planned to be in service
as early as 2014.
The two transmission projects, Boardman to Hemingway and Gateway West, are complementary and
will provide an upgraded transmission path from the Pacific Northwest across Idaho and into eastern
Wyoming with an additional transmission connection to the population center along the Wasatch Front
in Utah.
20091RP Page 85
7. Transmission Resources Idaho Power Company
Significant resource development potential exists in Wyoming and southern and eastern Idaho.
Idaho Power's transmission system is curently limited in the ability to transmit energy from new
resources from the east to the major load centers in Idaho. Gateway West wil provide new transmission
capacity to integrate and deliver any such selected resources, in addition to meeting third-party
transmission service requests under Idaho Power's Open Access Transmission Tariff (OATT).
The Gateway West project is currently undergoing a public involvement process regarding route
selection, environmental studies, and permitting. The project as proposed in Idaho includes two separate
500-kV lines between the Populus substation in southeast Idaho, and the Hemingway substation in
southwestern Idaho, with connections in central Idaho at the Midpoint and proposed Cedar Hil
substations.
Phase 1 is expected to provide between 700 MW and 1,500 MW of additional transfer capacity across
Idaho. The fully completed project would provide an additional 3,000 MW of transfer capacity.
Similarly, the project extending east from Populus substation into eastern Wyoming is expected to
provide Phase 1 capacity improvements of approximately 700 to 1,500 MW, with the full build out
capacity increase being greater than 2,000 MW east of Jim Bridger, and 3,000 MW between the Populus
substation and Jim Bridger.
The project cost and capacity is expected to be shared between Idaho Power and Rocky Mountain Power
based upon load service requirements and third-party transmission service request obligations.
Additional information about the Gateway West project can be found at ww.gatewaywestproject.com.
Page 86 20091RP
Idaho Power Company 8. Planning Criteria and Portolio Selection
8. PLANNING CRITERIA AND PORTFOLIO SELECTION
Many utilities plan to median, or expected, conditions and then include a reserve margin to cover the
50 percent of the time when conditions are less favorable than median. Idaho Power discussed planing
criteria with commission staff members and the public criteria as par of the 2002 Integrated Resource
Plan (IRP). Out ofthese discussions came the company's practice of using more stringent planning
criteria than median conditions. The planing criteria and planning scenarios are discussed in the
following section.
Planning Scenarios and Criteria
The timing and necessity of future generation resources are based on a 20-year forecast of surluses and
deficiencies for monthly average load and peak-hour load. The 20-year forecast is fuher divided into
two 10-year periods that coincide with the near-term action plan and the long-term action plan.
The planng criteria for monthly average load plannng are 70th percentile water and 70th percentile
average load conditions. For peak-hour load conditions, the planng criteria used are 90th percentile
water and 95th percentile peak-hour load. The peak-hoUr analysis is coupled with Idaho Power's ability
to import additional energy on its transmission system. Peak-hour load planning criteria are more
stringent than average-load plannng criteria because Idaho Power's ability to import additional energy
is tyically limited durng peak load periods. The median forecast is no longer used for resource
planning although the median forecast is used to set retail rates and avoided cost rates durng regulatory
proceedings.
Load and Resource Balance
Idaho Power has adopted the practice of assuming drier-than-median water conditions and
higher-than-median load conditions in its resource planing process. Targeting a balanced position
between load and resources, while using the conservative water and load conditions, is considered
comparable to requiring capacity margin in excess of load while using median load and water
conditions. Both approaches are designed to result in a system having generating capacity in reserve for
meeting day-to-day operating reserve requirements.
In order to identify the need and timing of future resources, Idaho Power prepares a load and resource
balance which accounts for generation from all of the company's existing resources and planed
purchases. The updated load and resource balance showing Idaho Power's existing and committed
resources for average energy and peak-hour load are shown in Appendix C-Technical Appendix.
20091RP Page 87
8. Planning Criteria and Portfolio Selection Idaho Power Company
Average Monthly Energy Planning
Average energy surluses and deficiencies are determined using 70th percentile water and 70th percentile
average load conditions, coupled with Idaho Power's ability to import energy from firm market
purchases using reserved network capacity. Figure 8. i shows the monthly average energy surluses and
deficits with existing resources. The energy positions shown in Figure 8. i include the forecast impact of
existing demand-side management (DSM) programs, coal curailment, the curent level of Public
Utilities Regulatory Act (PURPA) development, existing power purchase agreements (PPAs),
firm Pacific Northwest import capability, and gas peaking unit output. Figure 8.1 ilustrates that monthly
average deficit positions grow steadily in magnitude and number of months affected. By 2014,
four months are affected with deficits reaching nearly 400 aMW for the most deficit month and, near
the end of the plannng period, energy deficits become substatial as generation from Idaho Power's
coal facilities is totally curtailed.
Figure 8.1 Monthl~ Average Energy Surpluses and Deficits with Existing Resources (70th Percentile Water
and 70t Percentile Load)
1,600
1,400
1,200
1,000
800
600
400
$: 200:E 0II (200)
(400)
(600)
(800)
(1,000)
(1,200)
(1,400)
(1.600)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
ii ijJ~~
-.
iu~l~I.1
Resource deficits are substantially improved as shown in Figure 8.2 with the addition of committed
resources from the 2006 IRP and the new DSM programs proposed in the 2009 IRP. The commtted
resources supply-side include the Langley Gulch combined-cycle combustion turbine (CCCT),
the 2012 Wind Request for Proposal (RFP), and geothermal projects.
Figure 8.2 Monthly Average Energy Surpluses and Deficits with Existing and Committed Resources and
New DSM (70th Percentile Water and 70th Percentile Load)
1,600
1,400
1,200
1,000
800
600
400
$: 200:E 0II (200)
(400)
(600)
(800)
(1,000)
(1,200)
(1,400)
(1,600)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Page 88 20091RP
Idaho Power Company 8. Planning Criteria and Portolio Selection
By design, the inclusion of generating and transmission resources in the 2009 IRP preferred portfolio
substantially eliminates all energy deficits. Figure 8.3 shows the resulting positions for monthly average
energy. The surpluses shown in Figure 8.3 are a result of the assumption that all resources are
dispatched and operating.
Figure 8.3 Monthly Average Energy Surpluses and Deficits with 2009 IRP Resources (70th Percentile
Water and 70th Percentile Load)
1,600
1,400
1,200
1,000
800
600
400
:5 200~ 0ni (200)
(400)
(600)
(800)
(1,000)
(1,200)
(1,400)
(1.600)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
As shown in Figure 8.1, energy deficits of approximately 200 average megawatts (aMW) exist in
July 2012 without the addition of the Langley Gulch project and the 2012 Wind RFP. As shown in
Figure 8.2, with the addition of these two resources, deficiencies do not appear again until the 2014 to
2015 timeframe. Portfolios for the 2009 IRP were designed to eliminate the remaining deficits which
were accomplished as shown in Figure 8.3. Additional details regarding the selection of the preferred
portfolio are presented in Chapter 10.
Peak-Hour Planning
Peak-hour load deficiencies are determined using 90th percentile water and 95th percentile peak-hour load
conditions, coupled with Idaho Power's ability to import additional energy on its transmission system to
reduce any deficits. Monthly peak-hour deficits with existing resources are ilustrated in Figure 8.4.
Figure 8.4 ilustrates considerable peak-hour deficits reaching in excess of 500 MW by 2012,
and continuing to grow through the remainder of the 20-year planing period.
Figure 8.4 Peak-Hour Deficits with Existing Resources (90th Percentile Water and 95th Percentile Load)
o
(200) i
(400)
(600)
(800)
(1,000)
:; (1,200)
:I (1,400)
(1,600)
(1.800)
(2,000)
(2,200)
(2,400)
(2,600)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
II'~ æ:3 ~lUIBll1l I
-l ~:j tj
~l:
20091RP Page 89
8. Planning Criteria and Portolio Selection Idaho Power Company
Peak-hour positions are substantially improved as shown in Figure 8.5 with the addition of committed
resources from the 2006 IRP and the new demand response programs proposed in the 2009 IRP.
The committed supply-side resources include the Langley Gulch CCCT, the 2012 Wind RFP,
and geothermal projects.
Figure 8.5 Peak-Hour Deficits with Existing and Committed Resources and New DSM (90th Percentile
Water and 95th Percentile Load)
o
(200)
(400)
(600)
(800)
(1,000)
:š (1,200)
::(1,400)
(1,600)
(1,800)
(2,000)
(2,200)
(2,400)
(2,600)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
I.I III
~
:g ~~m:-lI-- -l -l---l -l,
Again by design, the inclusion of generation and transmission resources in the 2009 IRP preferred
portfolio substantially eliminates all peak-hour deficits. Figure 8.6 shows the resulting monthly positions
for peak-hour planning.
Figure 8.6 Peak-Hour Deficits with 2009 IRP Resources (90th Percentile Water and 95th Percentile Load)
o
(200)
(400)
(600)
(800)
(1,000)
:š (1,200)
:: (1,400)
(1,600)
(1,800)
(2,000)
(2,200)
(2,400)
(2,600)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
.I
Peak-hour load deficiencies are determined using 90th percentile water and 95th percentile peak-hour
load conditions. In addition to these criteria, 70th percentile average load conditions are assumed, but the
hydrologic and peak-hour load criteria are the major factors in determining peak-hour load deficiencies.
Peak-hour load planng 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.
The deficits shown in Figure 8.5 account for the updated sales and load forecast, forecast performance
of DSM programs, adjustments to the hydro generation forecast, the curent level of PURP A
development, the Langley Gulch CCCT, the 2012 Wind RFP and Idaho Power's natual gas-fired
peaking resources. Similar to the deficits shown for average energy, the peak-hour analysis shows
deficits beginning in 2014. With the addition ofthe 2009 IRP preferred portfoJio, these deficits are
Page 90 20091RP
Idaho Power Company 8. Planning Criteria and Portolio Selection
substantially eliminated as shown in Figure 8.6. Additional details regarding the selection ofthe
preferred portfolio are presented in Chapter 10.
Idaho Power's customers reach a maximum energy demand in the sumer. Idaho Power's existing and
committed resources are insufficient to meet the projected peak-hour growth, and the company's
customers in Oregon and Idaho face signficant capacity deficits in the summer months if additional
resources are not added.
At times of peak summer load, Idaho Power is fully using all available transmission capacity from the
Pacific Northwest. If Idaho Power were to face a significant outage at one of its main generation
facilities, or a transmission interrption on one of the main import paths, the company would fail to meet
reserve requirement standards. If Idaho Power is unable to meet reserve requirements, then the company
is required to shed load by initiating rolling blackouts. Although infrequent, Idaho Power has initiated
rolling blackouts in the past durng emergencies. Idaho Power has committed to a build program,
including demand-side programs, generation, and transmission resources, to reliably meet customer
demand and minimize the likelihood of events that would require the implementation of rollng
blackouts.
Portfolio Design and Selection
The 2009 IRP portfolio development strategy divides the study period into two 10-year periods; 2010-
through 2019, and 2020 through 2029. Resource portfolios in each ID-year period are designed to
satisfy the energy and peak-hour deficits shown in the load and resource balance. Idaho Power also
believes a federal renewable electricity standard (RES) will be enacted in the near future, and each
portfolio is designed to substatially comply with the RES provisions contained in the Waxman-Markey
bil.
The Shoshone Falls Upgrade Project has been included in numerous past IRPs as a committed resource.
For the 2009 IRP, the project was included in all the portfolios analyzed. However, in order to quantify
the value ofthe project, the preferred portfolio was also analyzed without including the Shoshone Falls
upgrade project. The results of this analysis are presented in Chapter 10. A sumar of the resource
portfolios analyzed for the first 10 years of the planning horizon is shown below in Figure 8.7.
Figure 8.7 Initial Resource Portolios (2010-2019)
2012
1-1 Solar 1-2 Gas Peaker 1-3 Gas Peaker & B2H'1-4 B2H
Resource MW Resource MW Resource MW Resource MW
Wind*150 Wind*150 Wind*150 Wind*150
CCCT(LangleyGulch)* 300 CCCT (Langley Gulch)* 300 CCCT(LangleyGulch)* 300 CCCT (Langley Gulch)* 300
Geothermal*20 Geothermal*20 Geothermal*20 Geothermal*20
Shoshone Falls 49 Shoshone Falls 49 Shoshone Falls 49 Shos hone Falls 49
SCCT (Large Aero)200 SCCT (Frame Peaker)170 B2H 250 B2H 250
Geothermal*20 Geothermal*20 Geothermal*20 Geothermal*20
Solar PT wiSt 100 SCCT (Frame Peaker)170 SCCT (Large Aero)100 B2H 175
Solar PT wiSt 100 SCCT (Large Aero)100
Year
2015
2016
2017
2019
1 B2H-Boardman to Hemingway
*Committed Resource
The first 10-year planng period has significant committed resources which are also shown in
Figure 8.7. The committed resources included in all of the portfolios. The committed resources are not
20091RP Page 91
8. Planning Criteria and Portolio Selection Idaho Power Company
included in the capital cost for comparison between portfolios. The new resources shown are designed to
reduce previously discussed deficiencies and to meet proposed RES requirements. Because the
identified deficiencies are not large and the list of possible resources is limited, it was not necessary to
analyze a large number of portfolios for the first 1 O-year period. The limited number of resource options
results in similar portfolios with regards to fuel and technology. A description of the major differences
between each portfolio is presented below.
· 1-1 Solar-Includes two, 100 MW solar power tower resources
· 1-2 Gas Peaker-Includes two, 170 MW frame peaking units (simple-cycle combustion turbines
(SCCTJ)
· 1-3 Gas Peaker and Boardman to Hemigway-Includes a 250 MW market purchase on the
Boardman to Hemingway transmission line and two, 100 MW aero derivative peaking units
(SCCTs)
· 1-4 Boardman to Hemigway-Includes two market purchases on the Boardman to Hemingway
transmission line (250 MW and 175 MW)
In the second 10-year planning period, Idaho Power analyzed six portfolios and all portfolios were again
designed to substantially meet the proposed RES requirements in the Waxman-Markey bil. In addition,
advanced nuclear and integrated gasification combined cycle (IGCC) were included in separate
portfolios to determine how they would impact portfolio performance. A summary of the resource
portfolios analyzed for the second 10 years of the planning horizon is shown below in Figure 8.8.
Figure 8.8 Initial Resource Portolios (2020-2029)
Year
2-1 NulearlGeen 2-2 Giteway West 2-3 IG 2-4 Wind & Peakers 2-6 Umited Curtilment
Resource MW Resource MW Resource MW Resource MW Resource MW
Solar PT wiSt 100 SCCT (Large ,6ro)100
Wind 100 Wind 100 Wind 100
SolarPTw/St 100 Gateway West 200 Solar PT wISt 100 Wind 100 SCCT (Large ,6ro)100
Nuclear 270
Geothermal 52 IGCCw/Seq.600 SCCT (Large ,6ro)200
Solar PT wISt 100 Gateway West 200 Gateway West 100
Wind 100 SCCT (Large ,6ro)200 SCCT (Large ,6ro)100
Geothermal 52 Gateway West 400 Solar PT wISt 100 Wind 400 Wind 200
SCCT (Large ,6ro)100
Nuclear 400 Gateway West 600 SCCT (Large ,6ro)400 SCCT (Large ,6ro)400
Gateway West 250 Solar PT wiSt 100 SCCT (Large ,6ro)500
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
Portfolio 2- i contains an advanced nuclear resource along with a mixture of renewable resources to
meet RES requirements. Portfolio 2-2 relies heavily on market purchases and wind resources.
Portfolio 2-3 includes an IGCC resource combined with solar power tower technology. Portfolio 2-4
relies on wind resources for energy and natural gas peaking units necessary for peak-hour loads and
wind integration, and portfolio 2-5 includes limited curailment ofIdaho Power's coal resources with
wind and natural gas peaking units. A description of each resource portfolio is presented below.
· 2-1 Nuclear/Green-Includes a 270 MW nuclear resource in 2023 and another 400 MW nuclear
resource in 2028. Renewable resources include wind, solar and geothermal
Page 92 20091RP
Idaho Power Company 8. Planning Criteria and Portolio Selection
· 2-2 Market Purchases-Includes 1,400 MW of purchases on the Gateway West transmission line
and wind resources necessary to meet RES requirements
· 2-3 IGCC with Sequestration-Includes 600 MW from an integrated gasification combined-cycle
(IGCC) resource in 2024, 300 MW of solar for RES requirements, and 400 MW of natural gas
peaking units
· 2-4 Wind and Peakers-Includes 500 MW of wind resources and 1,400 MW of natual gas peaking
units
· 2-5 Limited Curtailment-Includes 300 MW of wind resources and 200 MW of natural gas peaking
units. Portfolio 2-5 also includes limited curailment ofIdaho Power's existing coal resources
Chapter 9 provides details on how the portfolios were modeled and the assumptions used in the analysis.
Chapter 10 presents a detailed discussion of the modeling results and risk analysis.
20091RP Page 93
8. Planning Criteria and Portolio Selection Idaho Power Company
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Page 94 20091RP
Idaho Power Company 9. Modeling Approach and Assumptions
9. MODELING ApPROACH AND ASSUMPTIONS
Idaho Power uses the AURORAxmpQ! (AURORA) market model as the primar tool for determining
future resource operations and to estimate the portfolio costs for the 20-year integrated resource plan
(IRP) planning horizon. AURORA uses a long-term (LT) study option to develop a future Western
Electricity Coordinating Council (WECC) resource optimization scenaro. In addition, AURORA
l_ modeling results provide detailed estimates on wholesale energy pricing, resource values under various
market conditions, and electricity pricing and portfolio values.
The AURORA software applies economic principles and dispatch simulation to model the relationships
of supply, transmission, and electricity demand in order to forecast market prices. The operation of
existing and future resources are based on forecasts of key fundamental elements such as demand,
fuel prices, hydro conditions, and operating characteristics of new resources. Various mathematical
algorithms are used in unit dispatch, unit commitment, pool pricing logic, and in the long-term capacity
expansion capability. The algorithms simulate the regional electrical system to determine how utility
generation and transmission resources operate to serve load.
Multiple electricity markets, zones, hubs, and operating pools can be modeled using AURORA.
Idaho Power models the entire WECC when evaluating the various resource portfolios. Idaho Power
does not maintain detailed data on all WECC resources in the AURORA model and the company relies
on a database maintained and updated by EPIS, Inc. Idaho Power evaluates the AURORA database and
makes changes based on available information prior to modeling the IRP portfolios.
Future WECC resources are determined in a two step process. The first step uses the AURORA LT
module to optimize the WECC future resources per the AURORA L T process. Since the AURORA L T
process does not account for state renewable portfolio standards (RPS), Idaho Power estimates RPS
requirements for futue years on a state-by-state basis and replaces some AURORA LT resources in the
database with RPS qualifying resources. Enough RPS resources are added for compliance with the
anticipated state requirements.
20091RP Page 95
9. Modeling Approach and Risk Assumptions Idaho Power Company
AURORA Setup Enhancements
Idaho Power incorporated several changes to the AURORA database which are designed to increase
AURORA's operational modeling realism. The Idaho Power changes to the database generally add
additional hourly operational detail and move away from flat generation output, de-rates, and fixed
capacity factors over the term of the study. The 2009 IRP also incorporates detailed generating resource
scheduling which results in a model that is more deterministic in character, and provides a more specific
operational view of the WECC.
Several other enhancements to the L T model are included to incorporate the effects of legislated
renewable energy requirements and specific WECC planed resources. The WECC resources are
determined from the 2007 WECC Long Term Resource Adequacy study.
Carbon Modeling Approach
Idaho Power's 2009 IRP analyzes the potential cost of carbon emissions differently than has been done
in previous IRPs. Historically, a carbon adder, or tax, has been used to account for the social costs of
emitting carbon or other combustion byproducts. The purose of a carbon tax is to account for all of the
costs in the price of energy produced by carbon-emitting resources. Both the Waxman-Markey bil
(H.R. 2454) and the Boxer-Kerr bil (S. 1733) propose a cap-and-trade system for reducing carbon
emissions and Idaho Power considers the implementation of a cap-and-trade system to be more likely
than a carbon tax.
Although Idaho Power believes a cap-and-trade system is more likely, regulatory requirements dictate
the analysis be performed using a carbon adder, which Idaho Power has also done. However, the
primary discussion in the 2009 IRP regarding carbon emissions is related to Idaho Power's attempt to
model a cap-and-trade scenario under the provisions of the Waxman-Markey bil. To model the
cap-and-trade scenaro, Idaho Power has reduced the output from its coal facilities based on the number
of allowances that are expected to be allocated to the company. The cost of resource portfolios with
emissions in excess of the allocated amount are increased by purchasing additional allowances.
Idaho Power has also analyzed the effects of carbon legislation by modeling a $43 per ton carbon ta.
The carbon tax analysis suggests that the $43 carbon adder significantly increases the portfolio costs,
and increases the retail energy rates, but does not create a significant decrease in carbon emissions.
The carbon tax appears to be less effective than the proposed cap-and-trade legislation.
In addition, the carbon adder approach does not appear to promote resource dispatch decisions that result
in reduced emissions from existing resources. Coal curailment forces the resource plan to replace the
coal generation and quantifies the cost implications of the resource replacement. Figure 9.1 shows
anual average megawatt (aMW) coal output under the existing operations and the anual aMW of
coal-fired generation under the coal curailment scenario. In this scenario, coal-fired generation is
completely curailed by the end of the plannng period in 2029.
The emissions tagets used to define the new total coal-fired generation are based on the limits proposed
in the Waxman-Markey bilL. The legislation was passed by the House of Representatives in June 2009,
but has not yet been debated in the Senate. The assumed coal curtailment is the primary reason behind
the resource needs in the second 10-year planning period. For additional details on the AURORA
modeling comparisons, refer to the carbon allowance determination section of Appendix C- Technical
Appendix.
Page 96 20091RP
Idaho Power Company 9. Modeling Approach and Assumptions
Figure 9.1 Average Annual Generation from Coal Resources
1,000
900 --I800'-
700 ..'-~600 ~
~500~m -400
300 -
200
100
0 ..~.
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028
- Current Operation -CurtailmentScenario
An alternative to full coal curailment is evaluated in Portfolio 2-5. Portfolio 2-5 reduces coal unit output
to comply with 2020 target levels of emissions and then holds the 2020 carbon emission levels constant
for years 2021-2029. In Portfolio 2-5, Idaho Power operates coal resources at the 2020 emission levels
and acquires the necessar carbon emission allowances from the market. The required carbon emission
allowances are valued at the price cap proposed in the Boxer-Kerry legislation. The total price of the
coal curtailment portfolio 2-4 and the partial coal curilment portfolio 2-5 are roughy equivalent
assuming that the necessary carbon emission allowances can be acquired at costs equal to the proposed
price cap.
The three distinct carbon futues are modeled in AURORA for all ofthe resource portfolios;
I) coal curailment (as described above), 2) a $43 carbon adder without coal curailment, and
3) continuation of present operations with no carbon adder and no coal curtailment. The results of the
analysis are shown in Appendix C-Technical Appendix in the carbon futures comparison section.
Renewable Energy Credits
The 2009 IRP considers the proposed federal renewable electricity standard (RES) legislation and the
resource plan includes the resources necessary to meet the proposed requirements. In addition, some
neighboring states such as Washington, Oregon, Colorado, and Californa have already enacted
significant RPS requirements. The state legislation has prompted the construction of renewable energy
projects throughout the west even in states like Idaho without specific RPS requirements. Even if the
renewable energy is not delivered to the specific state, the renewable energy credits (REC) have value
and can be traded in a regional market.
Idaho does not have RPS and Idaho Power can meet the requirements of the Oregon RPS with a portion
of the RECs from the Elkhorn Valley Wind Project. Idaho Power has not included defined RES planning
criteria in previous resource plans. However, the increasing likelihood of a federal RES led Idaho Power
to develop a formal plan to satisfy the expected future federal requirements. The plannng goal in the
2009 IRP is to substantially satisfy the proposed federal RES targets with existing or new portfolio
resources. Figure 9.2 shows the expected quantity ofRECs Idaho Power would need under the
Waxman-Markey bil along with the number ofRECs each resource portfolio would provide. The
20091RP Page 97
9. Modeling Approach and Risk Assumptions Idaho Power Company
resource portfolios analyzed for the 2009 IRP meet the requirements in the first i 0 years and
substantially meet the requirements in the second 10-year period.
Figure 9.2 Waxman-Markey RES Requirements and Portfolio RECs
450
400
350
§'300:æ~
"C 250~
'StT 200Q)0:tiu 150w0:
100
50 ~
.. .._-~-~
.
2012 2014 2016 2018
. Waxman-Markey (H.R 2454) RES
-1-2 Gas Peaker-1-482H
-2-2 Gateway West
-2-4Wind &Peakers
Transmission and Market Purchases
The need for additional power from either new
resources or market purchases wil require
additional transmission. Idaho Power faces severe
transmission constraints when evaluating additional
supply-side resources. Transmission constraints
have been a major factor in evaluating each new
supply-side resource; Bennett Mountain, Danskin i,
the Elkhorn Valley Wind Project, Langley Gulch,
and the 2012 Wind Request for Proposals (RFP).
2020 2022 2024 2026 2028
_1-1 Solar
-1-3 Gas Peaker & 82H
- 2-1 Nuclear/Green-2-3IGCC
-2-5 Limited Coal Curtailment
Two categories of transmission are accounted for in
the IRP. The first is backbone transmission which
integrates resources and allows energy to flow from
the gen
eration project to the load centers within a utility's
own control area or service territory. Backbone transmission has a designated generating resource and is
usually lower voltage and within the service terrtory. An example of backbone transmission is the
transmission lines that deliver generation from the Hells Canyon Complex to the load center in the
Treasure Valley.
Interstate transmission is the second transmission type and is generally higher voltage and covers greater
distances. Interstate transmission is planed on a regional basis to meet the needs of electric utilties and
the needs of third parties requesting transmission service. Very little interstate transmission has been
constructed in the last 30 years. Examples of interstate transmission include the proposed Gateway West
and Boardman to Hemingway projects.
High-voltage transmission lines are an important
part of delivering energy to customers.
Page 98 20091RP
Idaho Power Company 9. Modeling Approach and Assumptions
The portfolios with market purchases in the first 10 years and all of the second i O-year portfolios
include proposed interstate transmission projects. The Northern Tier Transmission Group (NTTG) is one
entity that coordinates regional transmission plans in the Pacific Northwest. The NTTG anual report is
the basis of the interstate transmission alternatives discussed in Idaho Power's 2009 IRP.
The transmission planing scenarios used in the 2009 IRP are taken from NTTG's 2008-2009 Biennial
Plan Final Report-DRAFT dated November 2, 2009.
Transmission costs are evaluated on an annual Network Transmission Revenue Requirement basis.
The calculation is similar to the revenue requirement calculations used in Idaho Power's FERC formula
rate. In determining the annual revenue requirement, the new transmission investment is calculated in
two parts. The first part is based on a percentage of the total cost of an interstate transmission project
subscribed to and the second par is the cost of backbone upgrades for planed new resources for each
portfolio. The two parts are then added to arrive at the total transmission revenue requirement, which is
included in the anual cost of a portfolio. Additional details showing the calculations can be found in
Appendix C-Technical Appendix.
Regional Transmission Planning (from the NTTG Plan)
NTTG's 2008-2009 biennial plan was produced through public processes in conjunction with related
activities of the NTTG Cost Allocation Committee and the NTTG Transmission Use Committee.
Techncal studies have demonstrated the resulting plan to be capable of reliably meeting the identified
regional transmission needs established in the study plan.
Planning is an iterative process and must work in concert with local transmission plans and IRPs, where
they exist. The NTTG transmission plan is a result of a bottom-up load service process to ensure that the
transmission planned for the NTTG footprint can reliably serve forecasted load growth and conditions
established by data submittls and stakeholder input during the process. There may be broader regional
needs outside of the NTTG footprint unmet by this plan. These unet needs are expected to be
addressed as par of regional, interconnection-wide efforts reconciling bottom-up and top-down study
efforts.
The NTTG plan establishes the baseline main grid transmission configuration for the NTTG footprint
for the planing horizon ending in 20 18. The planned transmission should be used as a base plan to
inform other planning processes. While Idaho Power cannot assure the NTTG regional plan wil be
implemented as designed, the plan represents the best information available during the curent planning
cycle. Changing needs or new information will be accommodated through appropriate data submittals
during the next planing cycle.
The NTTG plan identifies a number of specific projects. However, the techncal analysis was performed
on the premise that the entire transmission plan is in service in 2018. Path and project ratings are
determined separately though Western Electricity Coordinating Council (WECC) processes and are the
responsibility of the projects' sponsors. Commercial subscription and capacity commitments are
administered by each Transmission Provider under their Open Access Transmission Tariff (OATT).
Idaho Power evaluates both the Boardman to Hemingway project for the first 10-year period, and the
Gateway West project for the second 10-year period. Figure 9.3 ilustrates the identified transmission
path upgrades for a variety of interstate transmission projects in the Pacific Northwest and Intermountain
Region. The transmission paths shown in Figure 9.3 are for reference only. Actual transmission paths
are being determines through public processes involving federal and state agencies and the general
public.
20091RP Page 99
9. Modeling Approach and Risk Assumptions Idaho Power Company
Figure 9.3 Northern Tier Transmission Group Planned Transmission Additions
1'.............-.--............---.".......................--..--.....r............--."....,.......-----"."... ......_._-_...........-.-....._...._-"....._-
1- , ~ .. Townsend Hughes Transmissi n &i..., WASHINGTON Wallula waiia. t' alia 7 Wyodak South Proj cts
I \ MCNaix~ - ~ Basin Electrici ~,,/"'13~" Walla W a . Black Hils Power & Ught! McNa 0
¡Bethel JuniperFla PacifCorI 7 OREGON WyodaI CascadeCrossing IDAHO
Portland General
= 345kVDoubieCircuit
i
It----
I
IJa~ Hemingwply-
Captain .Jack
PacifiCorp
NearDav
Johnston
Legend
-230kV
= 230kVDoubieCircuit
-345kV
Gate ay TerminalCen al ~Pacifi orp ~
Mona
~
COLORADO i
I
l = 500kVDoubieCircuit
Crystal\ ~\ ~"
NEVADA Gateway
South
PacifCorp
-500kV
\
i
I~
I
NEW MEXICOARIZONA
L
Market Purchase Assumptions
The 2009 integrated resource plan uses different transmission assumptions for each of the 10-year
periods. The assumption in the first 10-year period is that transmission capacity is increased only to the
extent identified in each resource portfolio. Idaho Power has adopted a conservative approach for the
first 10 years and only includes market energy purchases when the market need is specifically identified
in a resource portfolio.
The second 10-year period increases the transmission based on the projects identified in the NTTG
report discussed earlier. The uncertainty of the entire NTTG transmission expansion plan being
completed as proposed is significant. Resource plans that rely heavily on market purchases over
transmission that is beyond the reasonable scope of Idaho Power parcipation or control may not be
prudent. The transmission risk is discussed further in Chapter 10.
The transmission upgrades modeled for the 2010-2019 period only increase the transmission capacity to
the northwest (Boardman to Hemmingway). Idaho Power subscription on the Boardman to Hemingway
project is determined by the capacity and timing of market purchases identified in each resource
portfolio.
Page 100 20091RP
Idaho Power Company 9. Modeling Approach and Assumptions
Transmission is expanded even fuher in the second ID-year period, 2020-2029 with the Gateway West
project. As mentioned earlier, the 2020-2029 transmission expansion is defined by the NTTG plan.
The results from the two time periods are evaluated independently.
The degree of Idaho Power's investment participation differs between the portfolios and the costs are
included according to the transmission subscription in each resource portfolio. Each transmission
subscription represents an Idaho Power equity investment in the project. Each equity investment
translates into a revenue requirement and the revenue requirements for the transmission investments are
estimated and included in the portfolio total cost comparisons. Idaho Power's investment defines the
revenue requirement and the net present value (NPV) of the revenue requirement is included as part of
the expected-case cost of each resource portfolio. The NPV of any possible transmission capacity sales
to third parties are included in the risk analysis as project benefits.
Economic Evaluation Components and Assumptions
The evaluation of the different resource portfolios incorporates the NPV of the items listed below.
· AURORA Modelig (Total Portfolio Costing)-Idaho Power uses the AURORA model to evaluate
the variable cost of production for existing and committed resources along with any new resources
proposed in the portfolios. Operational constraints are approximated along with energy purchases
and sales in the regional market. Idaho Power used a base inflation rate of 3 percent per year
discounted to 2010 dollars.
· Capital Cost-Idaho Power uses an internal financial analysis model to evaluate the capital cost of
new resources and to estimate the associated revenue requirements. Estimated construction costs,
including Allowance for Funds Used During Construction (AFUDC), have been escalated at the base
inflation rate of 3 percent per year and included in the P- Worth ModeL. The estimated capital costs
are translated into an anual revenue requirement which corresponds to the size and timing of the
estimated dollar investment for each resource. The anual revenue requirement for each resource
portfolio is then discounted and sumed. The anual revenue requirement analysis has the benefit of
matching the anual revenue requirements with the corresponding annual energy benefits.
The anual revenue requirement analysis eliminates the need to estimate resource values beyond the
study period because resource capital costs and resource benefits are matched annually within the
study period.
· Carbon Allowances-Anual carbon emissions surluses and deficits from 2012 onward are valued
at the Boxer-Kerr allowance cap rate. As previously mentioned, each resource portfolio is designed
to substatially comply with the proposed federal legislation. The annual allowance surlus or deficit
is valued at the proposed legislative price cap and the total value is discounted and sumed for the
analysis.
· Renewable Energy Credits-Anual REC surluses and deficits from 2012 forward are valued at
the expected REC value. The annual value of the REC surlus or deficit is discounted and sumed
for the analysis.
· Transmission Cost-Idaho Power estimated the total transmission costs for each resource portfolio
and the estimated transmission costs are used to determine the anual transmission revenue
requirement. The NPV of the transmission revenue requirements are included in the portfolio
evaluation. A more detailed presentation of the transmission assumptions for each portfolio can be
found in Appendix C- Technical Appendix.
· Financial Assumptions and Interest Rates-A list of the IRP financial assumptions and interest
rates is shown in Table 9.1.
20091RP Page 101
9. Modeling Approach and Risk Assumptions Idaho Power Company
30 Years
6.98%
39.10%
35.00%
3.00%
2.50%
0.29%
3.00%
0.31%
2.00%
7.00%
3.00%
Page 102 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
10. MODELING RESULTS AND RISK ANALYSIS
The AURORA modeling results form the basis for evaluating the operational and quantitative risk
characteristics of the various resource portfolios. The portfolio resources include Idaho Power's existing
and committed resources along with the new resources identified in the specific portfolio.
The AURORA portfolio results are aggregated by the two i O-year time periods covered.
Portfolio Modeling Results
Table 10.1 sumarizes the market sales, market purchases, portfolio value, and capital costs used in the
evaluation of the portfolios for the first 1O-year period. The figues in Table 10.1 represent the results of
the AURORA analysis, and total transmission and generation capital costs.
Table 10.1 AURORA Results and Capital Costs Used in Portolio Evaluation (2010-2019)
Year 1-10 Portolio 1-1 Solar 1-2 Gas Peaker 1.3 Gas Peaker & B2H'
AURORA Nominal ($000)
Market Purchases...........................................
Market Sales..................................................
Portolio Value
Total...............................................................
$478,000
(1,264,000)
3,436,000
2,650,000
1-4 B2H
$511,000
(1,210,000)
3,485,000
2,786,000
$507,000
(1,229,000)
3,473,000
2,751,000
$510,000
(1,209,000)
3,483,000
2,784,000
AURORA NPV ($000)
Market Purchases.. .......... ................ ...............
Market Sales..................................................
Resource Total...............................................
Total...............................................................
Capital Costs (2009 Dollars)
Transmission Capital Costs ............................ 27,000,000
Generation Capital Costs ............................... 1,264,000,000
'B2A Boaroman to Aemingway
361,000
(926,000)
2,528,000
1,963,000
382,000
(890,000)
2,562,000
2,054,000
378,000
(905,000)
2,549,000
2,022,000
381,000
(889,000)
2,561,000
2,053,000
22,000,000
267,000,000
87,000,000
250,000,000
111,000,000
97,000,000
The second 1 O-year planning period begins where Portfolio 1-4 ends in 2020. Portfolio 1-4 showed
promise early on in the evaluation process as being a low-cost alternative, therefore Portfolio 1-4 was
selected as the basis for designng the second-period portfolios. The load forecast for the second period
is relatively flat. The primar driver for new resources in the second period is the carbon emission
reduction to be compliant with the carbon allowance limits identified in the Waxman-Markey bil
20091RP
~~~
Page 103
10. Modeling Results and Risk Analysis Idaho Power Company
(H.R. 2454). In fact, the base case assumption is that by the end of the integrated resource plan (IRP)
planing period, virtually all ofIdaho Power's existing coal resources are replaced with lower, or zero,
carbon-emitting resources, or market purchases.
Portfolios 2- I and 2-3 are the most capital intensive; each having over $5 bilion dollars in generation
resources and approximately $ 1.35 and $1.23 bilion in transmission capital costs respectively
(2009 dollars). Less costly, but stil significant, is Portfolio 2-4 with almost $2 bilion in new generating
resources and $800 milion in transmission projects. The least costly of the regular portfolios is
portfolio 2-2 with $356 milion in new resources and $2.25 bilion in new transmission. Portfolio 2-5
(Limited Coal Curilment) has $762 milion in generating resources and $337 milion in transmission
projects. Portfolio 2-5 maintains, and continues to operate, the company's coal plants with limited
curailment.
The operational costs are included in the evaluation in addition to the generation and transmission
capital costs. Operational value includes variable costs of operating the resources along with the net
contribution of portfolio market purchases and sales. The net operational costs can be either negative or
positive depending on the quantity of off-system market sales.
To a significant degree, an inverse correlation exists between the capital cost and the operational costs of
the resource portfolios. The relationship is dependent on the exposure to market prices in both energy
purchases and energy sales. For example, Portfolio 2-1 has the lowest portfolio operating cost of
$2.3 bilion (nominal dollars), but Portfolio 2-1 also has the most market sales at $2.2 bilion. Because
of the large quantity of market sales, portfolio 2-1 has the greatest market price risk.
Portfolio 2-2 has the highest total operating cost at $4.1 bilion with over one-third of the total
($1.5 bilion) being market purchases. The $1.5 bilion gives Portfolio 2-1 a significant market
purchases price risk. Table 10.2 sumarizes the AURORA results and capital costs used in the portfolio
evaluation.
Table 10.2 AURORA Results and Capital Costs Used in Portolio Evaluation (2020-2029)
2-1 2-2 Gateway 2-4 Wind & 2-5 Limited CoalYear 11-20 Portolio Nuclear/Green West 2-3IGCC Peakers Curtilment
AURORA Nominal ($000)
Market Purchases........................$540,000 $1,503,000 $631,000 $1,162,000
Market Sales..............................(2,232,000)(1,174,000)(2,204,000)(1,221,000)
Portolio Value............................,4,050,000 3,758,000 4,309,000 4,003,000
Total............................................2,358,000 4,087,000 2,736,000 3,944,000
AURORA NPV ($000)
Market Purchases........................214,000 527,000 250,000 423,000
Market Sales .............................."(823,000)(473,000)(818,000)(484,000)
Portolio Value.............................1,559,000 1,465,000 1,644,000 1,540,000
Total...........................................,950,000 1,519,000 1,076,000 1,479,000
Capital Costs (2009 Dollars)
Transmission Capital Costs .........1,354,000,000 2,247,000,000 1,227,000,000 799,000,000
Generation Capital Costs.............5,834,000,000 356,000,000 5,123,000,000 1,957,000,000
$840,000
(1,818,000)
4,574,000
3,596,000
323,000
(669,000)
1,717,000
1,371,000
338,000,000
762,000,000
Page 104 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
Risk Analysis and Results
Idaho Power evaluated all of the resource portfolios identified in the 2009 IRP for both quantitative and
qualitative risks. The objective of risk analysis is to identify resource portfolios that perform well in a
variety of possible future scenarios and to reduce total risk.
One of the major risks is load growth uncertainty associated with the present economic conditions.
Economic growth has slowed considerably in Idaho Power's service area and there has been extensive
speculation regarding the duration of the economic downtur. A quick return to the economic growth
rates of the past 20 years wil require additional generation resources to meet load. The present load
forecast projects a relatively long period of diminished economic growth.
The other factor affecting the load growth is the effectiveness of Idaho Power's demand-side
management (DSM) programs. Idaho Power is projecting continued success with DSM programs,
but the success is dependent on overall economic conditions as well as program fuding and consumer
preferences. A lower realization factor for DSM programs wil increase load and require additional
generation resources.
Electric vehicles are another factor that has the potential to increase load. Idaho Power estimates that the
total load from electric vehicles during the early par of the forecast period will not exceed
100 megawatt (MW) and that the load will occur primarily during off-peak-hours. Idaho Power
determined the 100 MW estimate by assuming that each vehicle wil be charged from a typical 220-volt
residential circuit which creates approximately 3 kilowatt (kW) of load. It would take approximately
30,000 electric vehicles charging simultaneously to increase load by 100 MW. Electric vehicles may
become a significant load affecting subsequent resource plans.
Many of the other risk factors are regulatory in nature. The electric utility industry, including
Idaho Power, faces considerable regulatory risks. Idaho Power proposes to utilize the Boardman to
Hemingway transmission line to meet par of its load. However, committed subscription to the
Boardman to Hemingway line is not in place which creates uncertainty concerning allocation of the
project costs.
In addition, Idaho Power faces regulatory uncertainty associated with carbon regulation and a federal
RES. Idaho Power is planning for a resource futue that restricts the quantity of carbon that can be
released into the earh's atmosphere. The proposed carbon legislation is anticipated to restrict the
quantity of carbon emissions and increase the price of renewable energy credits (REC). Limited, or
ineffective, carbon legislation could lead Idaho Power and other utilities to continue to generate from
traditional fossil-fueled plants.
Natual gas prices are primarily affected by supply and demand; however, economic growth, load
growth, carbon legislation, and transmission availability wil also influence prices. Presently natual gas
prices are relatively low. However, Idaho Power analyzed the portfolio costs under a scenario where
natural gas is considerably more expensive.
Quantitative Risk Analysis
For the 2009 IRP, Idaho Power quantitatively analyzed the risk associated with third par transmission
subscription, high REC prices, high natual gas prices, high carbon emissions costs, high load growth,
and low conservation. The change in expected cost for each portfolio forms the baseline for the risk
comparison. Each portfolio is analyzed for the quantitative risk factors mentioned above, and the
boundary costs are estimated for each scenario. The results of the quantitative risk analyses are
presented in terms of net present value (NPV) resulting in a side-by-side comparison of the expected
cost and range of potential risk for each resource portfolio.
20091RP Page 105
10. Modeling Results and Risk Analysis Idaho Power Company
Transmission Subscription by Third Parties
Interstate transmission projects are generally too expensive for a single utility to construct and regional
utilities often form parnerships for large-scale transmission projects. Multiple paries commit to fud a
portion of the project costs in return for a firm reservation of transfer capacity on the transmission line.
Prior to signing the actual agreements, multi-party subscription to new transmission capacity creates
significant uncertainty in evaluating actual project costs. At the present time, subscription to both the
Boardman to Hemingway and the Gateway West transmission projects has not been determined.
Transmission subscription is expected to be better defined in 20 i 0 and will be discussed in the
201 i IRP.
When calculating the expected cost of a portfolio that includes new transmission, the bi-directional
transfer capacity of the transmission project is included in the portfolio and is accounted for in the
expected cost. For example, Idaho Power intends to use the Boardman to Hemingway transmission line
to import energy into Idaho Power's system. Idaho Power's ability to sell transfer capacity from Idaho
to the Pacific Northwest represents a possible cost reduction for any portfolio, which includes the
Boardman to Hemingway transmission project. The risk analysis estimates that sellng all of the unused
transmission capacity would reduce the total expected portfolio cost by $46 milion (NPV) in
Portfolio 1-4 Boardman to Hemingway and by $16.7 milion (NVP) in Portfolio 1-3 Gas Peaker and
Boardman to Hemingway. Figure 10.5 in the quantitative risk analysis summar (2010-2019) section of
this chapter shows the risk associated with third-pary transmission subscription in all of the resource
portfolios.
Renewable Energy Credit Prices
All the portfolios analyzed in the 2009 IRP are designed to comply with the RES proposed in the
Waxman-Markey bil (H.R. 2454). For any given year, the amount ofRECs in the resource portfolio is
valued based on the projected forward price curve for RECs. For the risk analysis, a high REC price
scenario was analyzed using the price cap included in the Boxer-Kerry bil. Portfolios exceeding the
Waxman-Markey REC requirement have lower total risk because a high REC price adds additional
value to the portfolio. Likewise, portfolios with insuffcient RECs are subject to additional REC price
risk. Figure 10.1 shows the two REC forward price cures used in the 2009 IRP.
Figure 10.1 REC-Forward Price Curve
$60
$50
$40
.£l
fa
~
$30
$20
$10
$0
2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029
-IPC Expected Case -IPC High Case
Page 106 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
As shown in Figure 9.2 in Chapter 9, all of the resource portfolios considered in the 2009 IRP exceed
the Waxman-Markey RES requirements for the first 10-year period. Portfolio I-i Solar generates the
most RECs. Figure 10.5 shows the REC price risk for each of the portfolios.
During the second 10-year period, all of the proposed resource portfolios substatially meet the
Waxman-Markey RES requirements. Portfolio 2-1 Nuclear/Green generates the most RECs durng the
second 10-year time period. Figures 10.5 and 10.6 show the REC price risk for each of the resource
portfolios.
High Natural Gas Prices
The effects of high natural gas prices were analyzed by subtracting the total portfolio cost determined
with the expected natural gas prices from the total portfolio cost using high natural gas prices.
Figure 10.2 shows the natual gas prices used for the analysis.
Figure 10.2 Natural Gas Price Forecast
14
13
12
11
10
9
8
7
6 l'"
5
4
3
2
1
o
2010
- --- - - --.. ..
- -- -- --..
16c:
'Eo~
..-----~~---~- -.-------- ------~-
as:i
~
2012 2014 2016 2018 2020 2022 2024 2026 2028
- Sumas Delivered (Expected)- - Sumas Delivered (High)- Sumas Delivered (Low)
High natural gas prices tend to increase the total portfolio value for Idaho Power. During much of the
year, natural gas generation is the marginal resource in the Pacific Northwest and natual gas prices
indirectly set electricity prices in the regional market. Even though Idaho Power uses natural gas fuel for
a portion of its generation, the entire generation output is valued at market cost, and market cost is
determined substantially by natual gas generation. High natural gas prices increase the portfolio value
for all of the Idaho Power resource portfolios.
During the first 10 years, risk analysis for high gas prices showed that Portfolio 1-3 Gas Peaker and
Boardman to Hemingway had the least reduction in expected portfolio costs with portfolios 1-1 Solar,
1-2 Gas Peaker and 1-3 Gas Peaker and Boardman to Hemingway being very similar. Figue 10.5 shows
the risk of high gas prices for each of the portfolios.
The risk analysis for the second i 0 years showed that high gas prices would increase the expected
portfolio cost for Portfolio 2-2 Gateway West and Portfolio 2-4 Wind and Peakers, with the
Gateway West portfolio being exposed to market purchases and the Wind and Peakers portfolio
containing a significant amount of natural gas resources. Portfolio 2- i Nuclear/Green, Portfolio 2-3 and
Portfolio 2-5 would benefit high gas prices and the resulting high energy prices because these portfolios
20091RP Page 107
10. Modeling Results and Risk Analysis Idaho Power Company
do not rely on a significant amount of natural gas resources. Figure 10.6 shows the risk of high gas
prices in all of the portfolios.
CO2 Allowance Prices
The IRP base case curtails coal production to closely meet the carbon allowances Idaho Power would
expect to receive under the Waxman-Markey bil (RR. 2454). The Boxer-Kerr price cap proposal also
sets a price cap on the cost of carbon allowances. Emissions associated with each of the resource
portfolios were valued using the Boxer-Kerry price cap cure.
It is important to also understand the portfolio risk with high emission allowance prices. Idaho Power
performed a risk analysis to estimate the effect of a $43 per ton carbon tax added to the Boxer-Kerry
price cap cure. Figure 10.3 shows the expected case allowance price (Boxer-Kerry cap) and the high
price case used for the risk analysis.
Figure 10.3 Boxer-Kerry Carbon Allowance Price Cap and High Case Scenario
$140
$120
$100
$80
c:0
~$60~0Cl
$40
$20
$0 i
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032
- Hig h Case Scenario - Boxer-Kerry
As expected, the high price case risk analysis resulted in a cost increase in all of the resource portfolios.
During the first 10 years, Portfolio 1-3 Gas Peaker and Boardman to Hemingway had the greatest
increase in costs and Portfolio 1-1 Solar had the lowest increase. Figure 10.5 shows the risk of high
carbon allowance prices in all of the portfolios.
In the second 10 years, Portfolio 2-5 Limited Coal Curailment showed the greatest cost increase and
Portfolio 2-1 Nuclear/Green showed the lowest increase. Figure 10.6 shows the risk of high carbon
allowance prices in all of the portfolios.
High Load Growth
The curent load growth forecast departs signficantly from the historical trend line. The general
consensus during the company's IRP Advisory Council (IRPAC) meetings was that Idaho Power faces
the risk that loads may be higher than forecast. Figure 10.4 shows the various load forecasts used in the
2009 IRP, including the high load growth case used to assess the load forecast risk.
Page 108 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
Figure 10.4 Average Monthly Load Growth Forecast
2,400
2,300
2,200
2,100
2,000
~1,900
Rl
1,800
1,700
1,600
1,500
1,400
2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029
-WeatherAdjustedActual -50th Percentile -70th Percentile -90th Percentile
High load growth increased the costs in all resource portfolios as additional energy purchases were
required to meet customer load. During the first 10 years, Portfolio 1-3 Gas Peaker and Boardman to
Hemingway had the highest increase in costs and Portfolio 1-2 Gas Peaker had the lowest increase.
Figure 10.5 shows the risk of high load growth in all of the portfolios.
In the second i 0 years, Portfolio 2-4 Wind and Peaker had the highest increase in costs with
Portfolio 2-5 Limited Coal Curtailment having the lowest increase. Figure 10.6 shows the risk of high
load growth in all of the portfolios.
Low Conservation
Energy efficiency, conservation, and demand response programs are forecast to signficantly reduce the
need for future generation resources. However, there is some uncertainty and risk associated with the
forecast if the expected level of DSM is not achieved. Idaho Power evaluated a low conservation case
where only 50 percent of the forecast DSM program performance is achieved to assess the DSM
program realization risk.
The low conservation risk analysis showed an increase in costs to all of the portfolios which is similar to
the high load growt analysis presented above. During the first 10 years, Portfolio 1-3 Gas Peaker
and Boardman to Hemingway had the highest increase in costs and Portfolio 1-2 Gas Peaker had the
lowest increase. Figure 10.5 shows the risk of low conservation in all of the portfolios.
In the second 10 years, Portfolio 2-4 Wind and Peakers had the highest increase in costs with
Portfolio 2-5 Limited Coal Curailment having the lowest increase in costs. Figure 10.6 shows the risk of
low conservation in all of the portfolios.
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10. Modeling Results and Risk Analysis Idaho Power Company
Quantitative Risk Analysis Summary (2010-2019)
The sumary conclusions of the quantitative risk analyses are:
· The high load growth and low conservation analyses do not provide signficant differentiation
between the different resource portfolios, but do quantify the potential for increased costs.
· Additional generation benefits some portfolios due to additional operational flexibility.
· Natual gas prices are correlated with market power prices and high gas prices increase the value of
Idaho Power's existing portfolio.
· Portfolios that include the Boardman to Hemingway transmission project have the potential to cost
less depending on actual third-party subscription.
. Carbon risk is a significant factor if emission costs exceed the anticipated allowance allocations.
Portfolio 1-4 Boardman to Hemingway has the lowest expected portfolio cost and the potential for the
lowest risk. Figure i 0.5 shows the expected total portfolio cost and the cumulative risk for each portfolio
analyzed for the 2010-2019 time period.
Figure 10.5 Cumulative Portfolio Risk (2010-2019)
-3rd Part Transnission
-RECPrice
-High GasPrice
-C02 Risk
- Low Conservtion
- High Load Growth
1-4B2H
1-3Gas
Peaker&
B2H
1-2Gas
Peaker
1-1 Solar
$2.0 $2.1 $2.2 $2.3 $2.4 $2.5 $2.6 $2.7 $2.8 $2.9 $3.0
. Expected Portolio Cost (Billions ofDollars)
Quantitative Risk Analysis Summary (2020-2029)
The 2009 IRP considered several assumptions when analyzing the quantitative risk analysis for years
2020 through 2029. Portfolio 1-4 was used to define the 2010-2019 resources for the second io-year
modeling period. Another assumption that had a substantial effect on total portfolio costs is the addition
of the Gateway West transmission project. Additional quantitative risk factors with significant portfolio
differentiation include natural gas price effects ranging from $0-$ i, i 40 milion and the expected carbon
allowance price with a $43 increase ranging between $296 to $749 milion.
Portfolio 2-5 Limited Coal Curailment has the lowest expected portfolio cost, but has the highest carbon
risk of all the portfolios. The carbon risk in Portfolio 2-5 could be even greater than the estimate should
the carbon allowance price caps be adjusted upward. Portfolio 2-1 Nuclear/Green has the highest
expected portfolio cost, but has the least risk because of the limited exposure to the carbon price risk.
Page 110 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
Figure 10.6 shows the expected total portfolio cost and the cumulative risk for each portfolio analyzed
for the 2020-2029 time period.
Figure 10.6 Cumulative Portolio Risk(~a~~a=2029)
2-3IGCC
.RECPrice
II High Gas Price
.C02Risk
. Low Co nservtion
. High Load Growth
2-5 Limited Coal Curtailment
2-4 Wind & Peakers
2-2 Gateway West
.-2-1 Nuclear/Green
$2.0 $2.5 $3.0 $3.5 $4.0 $4.5 $5.0
Expected Portfolio Cost (Billions of Dollars)
Qualitative Risk Analysis
The qualitative risks associated with the four 2010-2019 resource portfolios and the five 2020-2029
resource portfolios are more difficult to assess. Qualitative analysis preferences are chosen through
judgment and do not lend themselves to the deterministic quantitative metrics. Many of the qualitative
factors are considered in public forus like the IRPAC meetings as well as in regulatory workshops and
proceedings. For the 2009 IRP, Idaho Power qualitatively analyzed the risk associated with carbon
regulation, technology, and resource siting.
Carbon Regulation
Congress is embarking on the most comprehensive energy legislation in many years. Whle the
Waxman-Markey bil (H.R. 2454) has emerged from the House with an extensive section on carbon
regulation, at the time of this IRP, the form of carbon regulation from a Senate bil is stil uncertin.
Carbon regulation has become a contentious point in the Senate. Idaho Power has analyzed the
Waxman-Markey bil and developed portfolios to comply with proposed carbon regulations. If the
Senate were to pass an energy bil, the bil would then go to conference with the House of
Representatives. Major components could be changed, paricularly carbon regulation. In addition,
political analysts and Washington D.C. insiders have speculated that due to the record federal deficit and
continued high unemployment in the economy, President Obama could ask Congress to drop the carbon
emission cap-and-trade provisions from the energy bil. If cap-and-trade was removed, carbon regulation
could become an independent piece of legislation separate from any energy bil. Given the energy
legislation uncertainty, Idaho Power believes that it is important to select a resource portfolio that has
the flexibilty to adapt to carbon regulation changes.
Technology
Technology risk primarly occurs during the second 10-year period of the forecast. The principal area in
which technology risk is considered in this resource plan is the uncertainty associated with developing
20091RP Page 111
10. Modeling Results and Risk Analysis Idaho Power Company
new advanced nuclear and coal technologies, such as integrated gasification combined cycle (IGCC).
IGCC resources provide increased effciency, reduced emissions, and the ability to captue and
potentially sequester CO2 emissions at reduced costs. However, IGCC plants have higher capital costs
and there is uncertainty regarding the performance of the proposed technology.
While there are certain risks associated with each type of generation resource, Idaho Power is
specifically concerned about the technology risk associated with IGCC projects. IGCC projects have
received a considerable amount of attention in the press recently. Idaho Power is supportive ofIGCC
technology and believes that the technology may playa significant role in meeting the nation's future
energy needs. However, Idaho Power also believes that there is considerable technology risk associated
with developing an IGCC project for use with western coals. With only two operating IGCC projects in
the entire United States, much of the electric industry, including Idaho Power, does not consider IGCC
to be a proven technology.
Considering Idaho Power's modest size and the significant cost of an IGCC project, Idaho Power
believes it would be imprudent for the company to assume the IGCC development risk alone.
Idaho Power is more comfortable tang a lesser share in a jointly-owned regional IGCC project and the
company believes that an ownership share is the appropriate way for Idaho Power to allocate the IGCC
technology risk if a future joint development opportunity becomes available.
Market Risk
All market paricipants, including Idaho Power, face price risks when buying or selling in the market.
The magnitude of the risk depends on the characteristics of the portfolio of power supply resources.
Portfolios with a large quantity of either market sales or market purchases have greater exposure to
changes in market prices. Additional factors to consider in the market price risk faced by each portfolio
are the quantity and timing, e.g., spring, sumer, daytime or nighttime of renewable resource
generation, the quantity of natural gas-fired resources, and the seasonal cost of natural gas.
Idaho Power's current resource base consists primarily oflow, marginal-cost coal and hydroelectric
resources. Idaho Power's customers have historically benefited because the company can sell excess
capacity to the market on a short-term basis durng periods of high prices. To a lesser degree,
Idaho Power can buy from the market during low-price periods and curail existing resources, thereby
shifting fuel (water and coal) use to more valuable hours. However, both opportties are limited by
existing transmission constraints.
In the 2009 IRP, Idaho Power's excess capacity is eventually consumed by load growth and the base
case assumption of coal resource curilment. These assumptions reduce seasonal excess capacity and
limit the opportities to capitalize on market price volatility. Tables 10.3 and 10.4 show the amount of
market purchases and sales for each portfolio. "Resource Total" represents the total generation from
existing resources and the new resources in each portfolio. "Native Load" represents the amount of
generation required to serve customers.
As shown in Table 10.3, Portfolio 1-1 has the least exposure to market purchases and the greatest
exposure to market sales, thus leaving it more exposed to a futue of low prices when selling power in
the wholesale electric market. On the other hand, Portfolio 1-2 has the least amount of market sales and
the greatest amount of market purchases, leaving it more exposed to the risk of high market prices.
Although there are differences between each of the portfolios in the amount of market purchases and
sales, the differences are minor. The relatively small difference between the portfolios highlights the fact
that Idaho Power is able to use market purchases and sales to increase the total value of any portfolio.
Compared to the first ten-year period, the second ten-year period shows a more significant variation
between portfolios. The portfolios with large base-load units that are not impaired by carbon legislation
(Portfolios 2- i, 2-2 and 2-5) show greater exposure to low market prices. The remaining portfolios (2-2
Page 112 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
and 2-4) are significantly more exposed to high market prices due to a reliance on market purchases.
Figure 10.4 shows the results of the analysis for the second ten-year period.
Table 10.3 Market Purchases and Sales Summary (2010-2019)
MWh (000)
Market Purchases.......... .....................................................
Market Sales ............ ......... ........... ........ ......... ... ... ................
Resource Total....................................................................
Native Load. ............... .................................. ........ ...............
Diff Market Purchases to Lowest.... ....... ........... .................
Diff Market Sales to Lowest....... .............. ..........................
iB2A Boardman to Hemingway
1-1 Solar
8,312
(26,395)
187,614
169,531
(1,220)
Table 10.4 Market Purchases and Sales Summary (2020-2029)
MWh (000)
Market Purchases..........................................
Market Sales.................................... .......... ....
Resource Total...............................................
Native Load........... ................ .........................
Diff Market Purchases to Lowest..................
Diff Market Sales to Lowest...........................
2-1
Nuclear/Green
7,186
(34,372)
204,869
177,683
2-2 Gateway
West
19,629
(18,645)
176,698
177,683
12,440
(15,727)
1-2 Gas Peaker
8,861
(25,175)
185,845
169,531
549
2-3IGCC
8,475
(34,170)
203,378
177,683
1,289
(15,525)
1-3 Gas
Peaker & B2H'
8,771
(25,722)
186,482
169,531
459
(547)
2-4 Wind &
Peakers
15,566
(19,246)
181,363
177,683
8,380
(601)
1-4 B2H
8,828
(25,178)
185,881
169,531
516
(3)
2-5 Limited
Coal
Curtilment
11,135
(28,063)
194,610
177,683
3,949
(9,418)
Resource Siting
Time delays and cost increases associated with resource siting and public acceptance are risks that
Idaho Power considers when developing generation and transmission resources. Resource siting
becomes even more critical when attempting to locate a generation resource close to an existing load
center. In addition to the permitting requirements associated with developing generation resources,
Idaho Power must also ensure that the public supports the project and that the project will remain
productive throughout its useful life.
The problems that Alternate Energy Holdings, Inc has encountered durng the past several years with a
proposed nuclear generation plant near Brueau, Idaho, and the difficulties MidAmerican Nuclear
Energy Company, LLC faced with a proposed nuclear generation plant in Payette County are indicative
of the risks associated with resource siting and public acceptance. Presently, Idaho Power recognzes
there are siting concerns with portions of the Boardman to Hemingway transmission line and the
company is working with the local communities and regulatory agencies to develop the project in
appropriate areas. Resource siting is a potential issue with any of the generation and transmission
resources identified in the IRP.
Qualitative Risk Analysis Summary
Generation resources represent significant capital expenditures and resource development entails
considerable risk. The public recognizes the risk and electric utilities are regulated to insure that the
risks are prudent. One part of the risk assessment is the public involvement when developing long-term
resource plans. A second part of the risk assessment is regular periodic review of the company's
long-term resource strategy. Idaho Power develops its IRP on a biennial schedule to address the
20091RP Page 113
10. Modeling Results and Risk Analysis Idaho Power Company
changing economic, regulatory, and technology risks. Idaho Power recognizes the capital risk in
developing generation resources and understands that a diverse resource portfolio of a variety of
supply-side, demand-side, and regional transmission resources will allow the company to maintain
operational flexibility, minimize risk, and adapt to future economic, demographic, and regulatory
conditions.
Preferred Portfolio Selection
2010-2019 (Portolio 1-4 Boardman to Hemingway)
The selection Portfolio 1-4 Boardman to Hemingway is based primarily on the portfolio having the
lowest expected portfolio cost. The low cost is a result of the portfolio having a relatively low new
resource capital cost and low AURORA portfolio cost. Portfolio 1-4 has the highest transmission cost
with a 37 percent stake in the Boardman to Hemingway project.
An important consideration in selecting a preferred portfolio is the ability to maintain flexibility in the
face of uncertainty and not to foreclose various resource options. The flexibility to adjust to changes
during the present period of unusually high regulatory uncertainty is very important. To maintain
operational flexibility in some cases means Idaho Power must commit to long lead time resources,
such as the Boardman to Hemingway project.
2020-2029 (Portolio 2-4 Wind and Peakers)
The theme of maintaining resource flexibility continues in the second i O-year period. Portfolio 2-4
focuses on relatively short lead time resources, such as wind projects and natual gas-fired resources.
The coal curtailment assumption in Portfolio 2-4 will require signficant replacement resources during
the last years of the study horizon. In order to accommodate the needed quantity of replacement
resources, a significant share (600 MW) of Gateway West is included in the preferred portfolio.
The Gateway West transmission project enables access to the high-capacity wind regions of Wyoming
(500 MW) as well as access to some energy-rich coal and natual gas deposits in southern Wyoming.
The feasibility and risks of natural gas transport for 1,400 MW of new natural gas generation located
near the load center in the Treasure Valley has not been included in this analysis.
Figues 10.7 and 10.8 show projections for Idaho Power's energy sources by resource type, for 2019 and
2029 respectively, assuming the preferred portfolio for each 10-year period and the carbon regulations
proposed in the Waxman-Markey bil are implemented. The percentages presented in Figures 10.7 and
10.8 are estimates ofIdaho Power's future energy sources and are not a representation ofthe energy
expected to be delivered to customers. An accounting of the energy delivered to customers, by resource
type, is posted on Idaho Power's Web site at ww.idahopower.com.
It is important to note the Waxman-Markey bil presents only one scenario out of many possible futues
for the regulation of carbon emissions. In addition, alternative compliance options implemented as par
of any future carbon regulation may allow the continued operation of Idaho Power's coal resources.
The level of hydroelectric generation presented in Figures 10.7 and 10.8 is based on 50th percentile
or median water conditions. As shown in the figures, the addition of the Langley Gulch combined-cycle
combustion turbine (CCCT) in 2012 increases the amount of natural gas generation in 2019 to
12 percent which increases to 29 percent in 2029 with the addition of the natural gas peaking units
identified in the second 10 years of the planning period. The addition of gas peakng resources is
necessary to integrate the wind resources (500 MW) in the preferred portfolio.
The anual percentage of energy supplied through power purchases is projected to increase from
7 percent in 2019 to 12 percent in 2029. The market purchases component of the power supply portfolio
Page 114 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
includes purchases from non-wind Public Utility Regulatory Policy Act (PURP A) resources and
market-purchased power. Existing PURP A wind generation is accounted for in the wind generation
category.
Figure 10.7 2019 Supply-Side Resources Figure 10.8 2029 Supply-Side Resources
Natural Gas
and Diesel
12%
Market
Purchased
Power 7%
Hydro 42%
Market
Purchased
Power
12%
Hydro
45%
Wind12%
Natural Gas
and Diesel
29%
Figures 10.7 and 10.8 represent Idaho Power's energy resource mix in 2019 and 2029 respectively,
under the assumptions that Idaho Power's coal resources are curtailed as proposed in the Waxman-
Markey bil, and portfolios i -4 Boardman to Hemingway and 2-4 Wind and Peakers are implemented.
Ifthe cost of emitting carbon is less than $30 per ton, it may be more economical for Idaho Power to
continue to operate existing coal resources.
Developing Alternate Portfolios
Idaho Power developed two alternate resource portfolios that identify the resource choices should the
assumptions used to determine the preferred portfolio not materialize. The most likely scenario leading
to selecting an alternative portfolio in the near term is limited third-pary interest in the Boardman to
Hemingway transmission line. Idaho Power anticipates identifying other partners for the Boardman to
Hemingway transmission line by the end of2012. Should there be insufficient interest in the project,
Idaho Power will assess the construction start date in 2013 and possibly delay construction until there is
sufficient committed interest in the project. Idaho Power would likely replace the Boardman to
Hemingway project with a natural gas-fired generation resource and begin the acquisition process for the
natural gas resource with a competitive RFP in 2013. Idaho Power will review the status of the
Boardman to Hemingway project in the 201 i IRP. The preferred and alternate portfolios for the first
1O-year period are shown in Table 10.5.
The alternate portfolio for the second i O-year period assumes Idaho Power curails existing coal
resources based on the Waxman-Markey bil through 2020 with no additional curilment though the
second i 0 years of the planng period. Idaho Power believes this is a likely scenaro and the alternate
portfolio contains additional resources to offset the level of coal curilment. The preferred and alternate
portfolios for the second i O-year period are shown in Table 10.6.
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10. Modeling Results and Risk Analysis Idaho Power Company
Table 10.5 Preferred and Alternate Portfolios (2010-2019)
Preferred Portolio 1-4 Boardman to HemingwayYear Resource MW Year
2010................................. I
2012................................. Wind* I
CCCT (Langley Gulct)*
Geothermal* i
2015................................. Shoshone Falls I
Boardman to HemingLay
2016................................. Geothermal* I
2017................................. Boardman to Heming~ay
~~:~~;t~~~.~~~~~~~.......... I
i
Table 10.6 Preferred and Alternate Portglios (2020-2029)
Preferred Portolio 2-4 Wind & Peaker$
Year Resource MW
1002020................................ SCCT (Large Aero)
2021................................
2022................................ Wind
2023................................
2024................................ SCCT (Large Aero)
2025................................ Gateway West
2026 .................... ............ Large Aero
2027................................ Wind
2028................................ SCCT (Large Aero)
2029................................ SCCT (Large Aero)
100
200
100
200
400
400
500
Alternate Portolio 1-2 Gas Peakers
Resource
150
300
20
49
250
20
175
2010......................................,
2012......................................, Wind*
MW
150
300
20
49
170
20
170
Year Resource MW
100
100
100
200
100
CCCT (Langley Gulch)*
Geothermal*
2015....................................... Shoshone Falls
SCCT (Frame Peaker)
2016......................................, Geothermal*
2017....................................... SCCT (Frame Peaker)
2019......................................"
Alternate Portolio 2-5 Limited Curtilment
2020...................................
2021................................... Wind
2022 ... ........................ ........ SCCT (Large Aero)
2023...................................
2024...................................
2025...................................
2026 .... ............................... SCCT (Large Aero)
2027................................... Wind
SCCT (Large Aero)
2028...................................
2029...................................
Estimated Cost of Proposled Carbon Legislation
Meeting the proposed carbon legislation lis not without cost. As mentioned in Chapter 9, Idaho Power
prepared Portfolio 2-5 where carbon em~ssions are reduced up to 2020 and then held flat at the
2020 level throughout the remainder of t~e planing period. Idaho Power also prepared an additional
resource portfolio, with no carbon emission reductions. The additional portfolio was used to isolate the
estimated costs to comply with the propased carbon legislation. Tables 10.7 and 10.8 compare the
estimated costs of the no curilment poi1folio with the cost estimates for the preferred resource
portfolios 1-4 and 2-4 for both time peri~ds.
IThere are only minor costs of the proposed carbon legislation in the first 10 years of the plannng period
because the carbon legislation does not ~hange Idaho Power's resource choices during the first 10 years.
However, the proposed carbon legislatioh does affect how Idaho Power operates its resources in the first
10 years, but the effects are minor and r~sult from reduced off-system sales.
iThe second 1 O-year period is considerably different. By the 2020-2029 time period, Idaho Power must
replace the generation capacity lost due ~o coal curailment with alternate generation resources. The
analysis estimates the total cost of the carbon legislation to be almost one bilion dollars. The total is
composed of almost $700 milion of gen~ration capital and over $300 milion in lost market sales.
I
Page 116 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
Idaho Power will continue to evaluate the federal carbon emission legislation and the topic wil be
discussed in the 20 i i IRP.
Table 10.7 Carbon Legislation Costs (2010-2019)
1-4 Boardman to
Hemingway
No Coal
Curtilment Difference
Aurora Nominal ($000)
Market Purchases .................................................................."
Market Sales .... ............................ ............ ..... .... ... ..................,
Resources Total.....................................................................,
Total.......................................................................................,
Aurora NPV ($000)
Market Purchases..................................................................,
Market Sales........... ......................... ........... ..... ......................'
Resources Total............................................ .... ............... ......"
Total......................................................................................."
2009 Dollars
Transmission New..................................................................,
Generation Capital Costs. ............ ................ ..........................,
Table 10.8 Carbon Legislation Costs (2020-2029)
Aurora Nominal ($000)
Aurora Nominal ($000)
Market Purchases..............................................................,
Market Sales............... .................................. ......................
Resources Total.... ................................... ...........................
Total....................................................................................
Aurora NPV ($000)
Market Purchases...............................................................
Market Sales .. ... ............... ....... .... ................. ...... .................
Resources Total..................................................................
Total....................................................................................
2009 Dollars
Transmission New...............................................................
Generation Capital Costs....................................................
$510,000
(1,209,000)
3,483,000
2,784,000
381,000
(889,000)
2,561,000
2,053,000
110,870,000
96,951,000
2-4 Wind & Peakers
$1,162,000
(1,221,000)
4,003,000
3,944,000
423,000
(484,000)
1,540,000
1,479,000
799,000,000
1,957,200,000
$495,000
(1,458,000)
3,600,000
2,637,000
$15,000
249,000
(117,000)
147,000
372,000
(1,055,000)
2,631,000
1,948,000
9,000
166,000
(71,000)
104,000
110,870,000
96,951,000
°
°
No Coal
Curtilment Difference
$509,000
(2,600,000)
5,088,000
2,997,000
$653,000
1,379,000
(1,085,000)
947,000
199,000
(953,000)
1,916,000
1,162,000
224,000
469,000
(376,000)
317,000
799,000,000
1,270,500,000
o
686,700,000
An analysis was performed to determine the sensitivity of total portfolio cost to the price of carbon
allowances. The purpose of the analysis was to determine a "tipping point" where the cost of buying
allowances and emitting carbon becomes high enough that coal curlment becomes a lower cost
option. The sensitivity of the total 20-year portfolio costs (AURORA nominal and Capital NPV) of both
the preferred portfolios (1-4 and 2-4) and the no-coal curilment scenario are shown in Figure 10.9.
The results of the analysis indicate at an allowance price of less than $30, the no-coal curailment
scenario is a lower cost option. Ifthe cost of carbon allowances exceeds $30, the coal curailment
scenario becomes the lowest cost option.
20091RP Page 117
10. Modeling Results and Risk Analysis Idaho Power Company
Figure 10.9 Carbon Allowance Cost and Portfolio Costs
$8.5
$8.0
(hi:.Q
~$7.5
'l0U
.Q $7.0~0a.
$6.5
$6.0
$0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50
-Preferred Porfolio w/Coal Curtilment - No Coal Curtailment w/Carbon Allowance Cost
Capacity Planning Margin
Idaho Power discussed planning criteria assumptions with state utility commissions and the public in the
early 2000s before adopting the present planing criteria. Idaho Power's future resource requirements
are not based directly on the need to meet a specified reserve margin. The company's long-term resource
planing is instead driven by the objective to develop resources suffcient to meet higher-than-expected
load conditions, under lower-than-expected water conditions, which effectively provides a reserve
margin.
As par of preparing the 2009 IRP, Idaho Power has calculated the capacity planng margin resulting
from the resource development identified in 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
expected-case (50th percentile) peak-hour load, with the excess resource capacity designated as planing
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 forecasted peak load to
cover the worst single planing contingency. The worst single planing contingency is defined as an
unexpected loss equal to Idaho Power's share of two units at the Jim Bridger coal facility. The reserve
level of 330 MW translates into a reserve margin of approximately 10 percent and the reserved
transmission capacity allows Idaho Power to import energy during an emergency via the Pacific
Northwest Power PooL. A 330 MW reserve margin is also roughly equivalent to a Loss of Load
Expectation (LOLE) of one day in i 0 years, a standard industr measurement. Capacity planing margin
calculations for July of each year through the planng period are shown in Tables 10.9 and 10.10 at the
end of this chapter.
Page 118 20091RP
Idaho Power Company 10. Modeling Results and Risk Analysis
Loss of Load Expectation
Idaho Power used a spreadsheet model3 to calculate the LOLE for the preferred and alternate portfolios
identified in the 2009 IRP. The assessment assumes critical water conditions at the existing hydro
facilities and the planned additions for the preferred and alternate scenarios. As mentioned in the
previous section, Idaho Power uses a Capacity Benefit Margin (CBM) of330 MW in transmission
planng to provide for the necessary reserves for unit contingencies. The CBM capacity is reserved in
the transmission system and sold on a non-firm basis until forced unit outages require use of the
transmission capacity. The 2009 IRP analysis assumes CBM transmission capacity is available to meet
deficits due to forced outages.
The model uses the IRP forecasted hourly load profile, generator/purchase outage rates (EFORd) and
generation and transmission capacities, to compute a LOLE for each hour of the 20-year plannng
horizon. Demand response programs were modeled as a reduction in the hourly load during the
mid-week peak hours rather than as a dispatchable resource due to the limited energy of the demand
response programs. The LOLE analysis is performed on a monthly basis to permit capacity de-rates for
maintenance or lack of fuel (water).
The typical metric used in the utility industry to assess probability-based resource reliability is a LOLE
of 1 day in 10 years. Idaho Power has chosen to calculate LOLE on an hourly basis to evaluate the
reliability at a more granular leveL. The i day in i 0 years metric is roughly equivalent to 2.4 hours/year.
The results of the loss ofload probability analysis are shown in Figure 10.10 and additional data can be
found in Appendix C- Technical Appendix.
Figure 10.10 Loss of Load Expectation
5.00
4.50
4.00
3.50
lõ 3.00
~2.50~::0 2.00:i
1.50
1.00
0.50
0.00
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028
-=Preferred Portfolio (1-4 and 2-4) -Alternate Portfolio (1-2) -Alternate Portflio (2-5)
In performing the analyses, there were several instaces where extending purchases of east-side energy
similar to the purchases contemplated in 2010-2012 were necessary to achieve the results shown in
Figure 10.10. The high value in 2028 indicates that a minor adjustment in the preferred portfolio would
3 Based on Roy Bilinton "Power System Reliability Evaluation" Charer 2&3, Copyright 1970.
20091RP Page 119
10.Modeling Results and Risk Analysis Idaho Power Company
be desirable from a reliability perspective. Moving two of the five lOO-MW units scheduled in 2029 to
an on-line date in 2028 would reduce the spike without changing the results for 2029.
The LOLE analysis indicates there are periods where a consistent capacity-based load and resource
balance was not achieved, in par due to the uneven nature of capacity additions. In future IRPs,
Idaho Power may use the LOLE model during the development ofthe initial resource portfolios to
smooth out capacity additions.
Table 10.9 Capacity Planning Margin (2010-2019)
Load and Resource Balance July-i0 JUIy-ii JUIy-i2 July-i3 July.i4 July-iS Julyi6 July-i7 July-i8 JUIy-i9
Load Forecast (95"'% )-Aug 2009 wiNo DSM (3,296)(3,408)(3,495)(3,596)(3,670)(3,734)(3,796)(3,860)(3,924)(3,990)
Existing DSM (Energy Effciency)17 33 48 64 79 93 107 121 135 149
Load Forecast (95"'% )-w/EE DSM ,(3,279)(3,375)(3,592)(3,641)(3,689)(3,739)(3,790)(3,842)(3M7)(3,533)
Existing DSM (Irngation Timer)8 6 6 6 6 6 6 6 6 6
Existing DSM (AC Cool Credit)51 51 51 51 Q,Q,Q,51 51 51
Total Exsting Demand Response 59 57 57 57 57 57 57 57 57 57
Peak-Hour Load Forecast w/Existing DSM (3,220)(3,318)(3,390)(3,476)(3,535)(3,585)(3,633)(3,63)(3,733)(3,785)
Existing Resources
Coal (w/Curtilment)967 972 978 983 983 982 980 980 977 977
H~ro (50"'%)-HCC 1,134 1,134 1 ,134 1,134 1,134 1,134 1,134 1,134 1,134 1,134
H~ro (50"'%)-Other 254 254 253 252 249 246 245 244 243 243
Sho-Ban Water Lease 42 47 48 48 0 0 0 0 0 0
Totl Hyro 1,431 1,435 1,435 1,434 1,383 1,380 1,379 1,378 1,377 1,377
CSPP (PURPA),133 141 141 141 141 141 141 141 141 141
Power Purchase Agreem ents
Elkhorn Valley Wind 5 5 5 5 5 5 5 5 5 5
Raft Riwr Geothemial 10 10 10 10 10 10 10 10 10 10
Clatskanie Energy Exhange 12 12 12 12 12 12 12 12 12 12
EnergyPlus-Jeffrson (83 MN)83 83 83 83 83 83 83 83 83 83
East Side Purchase (50 MW 50 50 50 50 50 50 50 50 50 50
Mead Purchase 75 75 75 75 75 75 75 75 75 75
Totl Poer Purchase Agreement 235 235 235 235 235 235 235 235 235 235
Fimi Pacific NW Import Capabilty 122 105 97 87 79 71 65 58 54 48
Salmon Diesel 5 5 5 5 5 5 5 5 5 5
Gas Peakers 416 il 416 416 il 416 il 416 il il
Subtotal 3,309 3,309 3,307 3,302 3,243 3,231 3,221 3,214 3,206 3,199
Net Position - Monthly SurpluslDeficit 88 (9)(83)(174)(292)(354)(412)(469)(528)(586)
Planning Margin 2.7%-0.3%-2.4%-5.0%-8.3%-9.9%-11.3%-12.7%-14.1%-15.5%
2006 IR Resources
Wind RFP 0 0 8 8 8 8 8 8 8 8
LangleyGulch 0 0 300 300 300 300 300 300 300 300
Geothemial 0 0 0 20 20 20 20 20 20 20
Geothemial 0 0 0 0 0 0 0 20 20 20
Net Position-Remaining Monthly SurpluslDeficit 88 (9)225 153 35 (26)(84)(122)(180)(238)
Planning Margin 2.7%-0"3%6.6%4.4%1.0%-0.7%-2.3%-3.3%-4.8%-6.3%
20091R DSM Jul-l0 Jul-l1 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jul-19
Commercial (FlexPeak)40 45 57 57 57 57 57 57 57 57
Irrgation Peak Rewards 212 244 254 254 254 254 254 254 254 254
EnergY Effciency Peak Reduction 3 7 12 18 24 31 37 44 51 58
Totl New DSM Peak Reduction 254 '296 '323 '329 '335 '341 '348 '355 '362 '369
Net Position - Remaining Monthly Surplus/Deficit 343 287 547 482 370 315 264 233 182 130
Planning Margin 10.6%8.7%16.1%13.9%10.5%8.8%7.3%6.3%4.9%3.4%
2009 IR Resources Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jul-19
Boardman-Hem ingwayTransm iss ion 250 250 250 250 250
Shoshone Falls Upgrade 0 0 0 0
Boardman-Hem ingwayTransm iss ion 175 175 175
Large Aaro
Wind
Large Aaro
GatewayWest Transm iss ion
Large Aaro
Wind
Large Aaro
Large Aaro
Net Position - Monthly SurpluslDeficit 343 287 547 482 370 565 514 658 607 555
Planning Margin 10.6%8.7%16.1%13.9%10.5%15.8%14.1%17.9%16.2%14.%
Page 120 20091RP
Idaho Power Company 10.Modeling Results and Risk Analysis
Table 10.10 Capacity Planning Margin (2020-2029)
Load and Resource Balance July-20 July-21 July-22 July-23 July-24 July-25 July-26 July-27 July-28 July-29
Load Forecast (95"% )-Aug 2009 wINo DSM ..
(4,271)(4,331)(4,393)(4,434)(4,480)(4,505)(4,058)(4,110)(4,171)(4,231)Eicsting DSM (Energy Effciency)163 177 191 205 219 233 247 261 275 289
Load Forecast (95"% )-/EE DSM ..(3,895)(3,933)(3,980)(4,027)(4,052)(4,098)(4,146)(4,173)(4,204)(4,216)Eicsting DSM(lrrgation TImer)6 6 6 6 6 6 6 6 6 6
Eicsting DSM (AC Cool Credit)51 51 51 51 51 51 51 51 51 51
Tolal Eicsting Demand Response 57 57 57 57 57 57 57 57 57 57Peak-Hour Load Forecast wlEsting DSM (3,839)(3,877)(3,923)(3,970)(3,995)(4,041)(4,089)(4,116)(4,148)(4,159)existing Resources
Coal (w/Curtilment)977 977 977 977 977 977 977 977 0 0
H~rc (50"%) -HCC 1,134 1,134 1,134 1,134 1,134 1,134 1,134 1,134 1,134 1,134
H~rc (50"%)-her 242 241 240 240 239 238 237 236 235 234
Sho-Ban Water Lease 0 0 0 0 0 0 0 0 0 0Total Hyro 1,376 1,375 1,374 1,374 1,373 1,372 1,371 1,370 1,369 1,368
CSPP (PURPA)..141 141 141 141 141 141 141 141 141 141
Power Purchase Agreements
Elkhorn Valley Wind 5 5 5 5 5 5 5 5 5 5
Rail Riwr Geothermal 10 10 10 10 10 10 10 10 10 10
Clatskanie Energy Exchange 12 12 12 12 12 12 0 0 0 0
Energ~lus-Jeffrson (83 MN 83 83 83 83 83 83 83 83 83 83
East Side Purchase (50 MN 50 50 50 50 50 50 50 50 50 50
Mead Purchase 75 75 75 75 75 75 75 75 75 75
Totl Poer Purchase Agreement 235 235 235 235 235 235 223 223 223 223
Firm Pacific NW 1m port Capabilty 41 34 28 23 19 13 6 2 0 0
Salmon Diesel 5 5 5 5 5 5 5 5 5 5
Gas Peakers 416 416 416 416 416 416 416 416 416 416
Subtolal 3,191 3,184 3,177 3,171 3,167 3,160 3,140 3,135 2,155 2,154
Net Position - Monthly Surplus/Deficit (647)(693)(747)(799)(828)(882)(949)(981)(1,993)(2,005)
Planning Margin -16.9%-17.9%-19.0%-20.1%-20.7%-21.8%-23.2%-23.8%-48.1%-48.2%
2006 IR Resources
Wind RFP 8 8 8 8 8 8 8 8 8 8
Langley Gulch 300 300 300 300 300 300 300 300 300 300
Geothermal 20 20 20 20 20 20 20 20 20 20
Geothermal 20 20 20 20 20 20 20 20 20 20
Net Position-Remaining Monthly SurpluslDeficit (300)(346)(399)(452)(481)(534)(602)(634)(1,646)(1,658)
Planning Margin -7.8%-8.9%-10.2%-11.4%-12.0%-13.2%-14.7%-15.4%-39.7%-39.9%2009 RP IlM
Commercial (Fleiceak)57 57 57 57 57 57 57 57 57 57
Irrgation Peak Rewards 254 254 254 254 254 254 254 254 254 254
Energy Effciency Peak Reduction 66 73 80 87 95 103 111 119 127 127
Totl New IlM Peak Reuction 376 383 390 398 406 413 421 429 438 438
Net Position - Rem aining Monthly SurpluslDeficit 76 37 (9)(54)(75)(121)(181)(204)(1,208)(1,220)
Planning Margin 2.0%1.0%-0.2%-1.4%-1.9%-3.0%-4.4%-5.0%-29.1%-29.3%
2009 IRP Resources
Boardman-Hem ingway Transm iss ion 250 250 250 250 250 250 250 250 250 250
Shoshone Falls Upgrade 0 0 0 0 0 0 0 0 0 0
Boardman-Hem ingway Transm iss ion 175 175 175 175 175 175 175 175 175 175
Large Perc 100 100 100 100 100 100 100 100 100 100
Wind 5 5 5 5 5 5 5 5
Large Perc 200 200 200 200 200 200
Gateway West Transm iss ion 100 100 100 100 100
Large Perc 200 200 200 200
Wind 20 20 20
Large Perc 400 400
Large Perc 500
Net Positon - Monthly Surplus/Deficit 601 562 521 476 655 709 849 846 242 730
Planning Margin 15"7%14.5%13.3%12.0%16.4%17.6%20.8%20.5%5.8%17.5%
20091RP Page 121
10. Modeling Results and Risk Analysis Idaho Power Company
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Page 122 20091RP
Idaho Power Company 11. Action Plan
11. ACTION PLAN
Near-Term Action Plan
The near-term action plan describes the actions Idaho Power plans to take over the next 10 years
(2010-2019) as part of implementing the preferred portfolio. Because the near-term time period is so
short, no long lead time generation resources, such as advanced nuclear or integrated gasification
combined cycle (IGCC) are considered in the near-term plan. However, Idaho Power intends to continue
its efforts to explore regional allances and participate in regional utility planing forus as these
technologies develop. Table 11.1 presents a list ofthe actions Idaho Power expects to take in the next
10 years as par of implementing the preferred portfolio.
Table 11.1 Near-Term Action PlanYear Action
2010.................................................................. Present and gain acceptance of 2009 IRP with regulatory commissions
File wind contract resulting from the 2012 Wind RFP with the IPUC
File geothermal contract with the IPUC
Irrigation Peak Rewards program increases from 160 MW to 220 MW
FlexPeak Management program increases from 20 MW to 40 MW
Langley Gulch CCCT construction begins
2011 .................................................................." Wind project construction begins
Langley Gulch CCCT construction continues
Irrigation Peak Rewards program increases from 220 MW to 250 MW
FlexPeak Management program increases from 40 MW to 45 MW
File 2011 IRP with regulatory commissions
2012.................................................................. Wind project on-line (approximately 150 MW)
Langley Gulch CCCT on-line (300 MW)
Geothermal project on-line (approximately 20 MW)
2013................................................................... Boardman to Hemingway construction begins
Shoshone Falls Upgrade Project construction begins
File 2013 IRP with regulatory commissions
2014.................................................................." Shoshone Falls Upgrade Project construction continues
Boardman to Hemingway construction continues
2015................................................................... Shoshone Falls Upgrade Project on-line (49 MW)
Boardman to Hemingway completed (250 MW)
File 2015 IRP with regulatory commissions
2016................................................................... Geothermal project on-line (approximately 20 MW)
2017 ................................................................... Boardman to Hemingway additional capacity for market purchases (175 MW)
File 2017 IRP with regulatory commissions
2018.................................................................., No action
2019.................................................................. File 20191RP with regulatory commissions
Long-Term Action Plan
The long-term action plan describes Idaho Power resource acquisitions during the 2020-2029 time
period. The long-term action plan assumes that the near-term action plan is completed with only minor
variations. The long-term action plan includes a combination of renewable resources and natural
gas-fired resources to firm the output from wind resources. The main event in the long-term action plan
is that Idaho Power continues to curail the output from the coal-fired generation resources in order to
meet the proposed federal carbon legislation. In this potential future, Idaho Power's coal-fired resource
operations wil be limited to seasonal needs in early years until they are fully curailed by the end of the
20091RP Page 123
11. Action Plan Idaho Power Company
planing period. Table 11.2 presents a list of the actions Idaho Power expects to take from 2020 through
2029 as part of implementing the preferred portfolio.
Table 11.2 Long-Term Action Plan
Year Action
2020 ................................................................................................................. Natural gas generation project on-line (approximately 100 MW)
2021 ............................ ............................. .......... .............................................. No action
2022 ................................................................................................................. Wind project on-line (approximately 100 MW)
2023 ................................................................................................................. No action
2024....... .................................................. .............................................. .......... Natural gas generation project on-line (approximately 200 MW)
2025 ................................................................................................................. No action
2026... ......................... ........................................................................... .......... Natural gas generation project on-line (approximately 200 MW)
2027............................ .............................. ................... .................................... Wind project on-line (approximately 400 MW)
2028 ........................................................................................................ ......... Natural gas generation project on-line (approximately 400 MW)
2029............................ .................................. ................................................... Natural gas generation project on-line (approximately 500 MW)
Delayed interest in the Boardman to Hemingway project may result in Idaho Power constructing both a
replacement generation resource as well as constructing the transmission line at a later date.
The alternate resource portfolio may lead to constructing the Boardman to Heming project in the second
10-year period. Idaho Power wil review the status of the Boardman to Hemingway project in the
20 i 1 IRP. Table i 1.3 shows the changes to the near-term action plan if sufficient interest by third parties
in the Boardman to Hemingway project does not materialize.
Table 11.3 Alternate Portolio Near-Term Action Plan
Year Action
2010 ......................................................................................................................... File 20091RP with regulatory commissions
File wind contract (2012 Wind RFP) with the IPUC
File geothermal contract with IPUC
Irrigation Peak Rewards Program increases to 220 MW
FlexPeak Management program increases to 40 MW
Langley Gulch CCCT construction begins
2011 ....................................................................................................."................... Wind project construction begins
Langley Gulch CCCT construction
Irrigation Peak Rewrds Program increases to 250 MW
FlexPeak Management program increases to 45 MW
File 2011 IRP with regulatory commissions
2012............... ................................... ......................................................................" Wind project on line (approximately 150 MW)
Langley Gulch CCCT on-line (300 MW)
Geothermal generation on-line (approximately 20 MW)
Natural gas generation resource one RFP
2013 ....................................................................................................."................... File 2013 IRP with regulatory commissions
2014 ......................................................................................................................... Shoshone Falls upgrade construction
Natural gas generation resource two RFP
2015.............................. ..................................................... ...................................... Shoshone Falls upgrade on-line (50 MW)
Natural gas generation resource one on-line
File 2015 IRP with regulatory commissions
2016........................... ........................... ................................................................... Geothermal Generation on-line (approximately 20 MW)
2017........... ................ ........................................... .................................................." Natural Gas generation resource two on.line
File 2017 IRP with commissions
2018 ......................................................................................................................... No action
2019......................................................................................................................... File 20191RP with commissions
Page 124 20091RP
Idaho Power Company 11. Action Plan
Conclusion
Each Idaho Power Integrated Resource Plan (IRP) builds on the foundation of earlier resource plans and
each plan includes incremental changes due to forecasts of futue events. The 2009 plan is no exception.
However, the 2009 IRP is different in two key aspects.
First, Idaho Power, and other utilities in the west, face major regional transmission decisions.
No significant interstate transmission has been built in the region for many years. Idaho Power's
2009 IRP is the first company resource plan where the company and others in the region, must make a
significant commitment to new interstate transmission projects.
Secondly, Idaho Power, and the nation, face the likelihood of significant carbon legislation. There has
been considerable discussion on aspects of the legislation; however, all recognze the objective of the
proposed legislation is to reduce the quantity of carbon released into the earth's atmosphere. Reducing
carbon emissions will require curailment of certain resources as either demand declines or additional
energy is produced from alternate resources. Idaho Power has chosen to directly face the issue of
curtilment and the 2009 IRP attempts to quantify the impact of proposed carbon legislation.
Idaho Power would like to than the IRP Advisory Council (IRP AC) members and the public for their
contributions to the 2009 IRP. The IRP AC debated these two major issues along with a significant
number of other social topics. Idaho Power's 2009 IRP is better because of the contributions from the
IRP AC members and the public.
In recognition of the amount of time and effort expended by the IRP AC, at the final meeting members
discussed the possibility of including a statement in the IRP indicating the advisory council's support of
the IRP. Because the IRP AC represents such a diverse set of stakeholders, the members determined it
would not be possible for the group to unanimously support all aspects of the IRP. However, the IRPAC
was supportive of the public process and asked Idaho Power to include the following statement in the
2009 IRP: "The members of the IRP Advisory Council support the public process Idaho Power
Company conducted as par of preparing the 2009 IRP."
Idaho Power prepares an integrated resource plan biennially. At the time of the next plan in 2011,
Idaho Power wil have additional information regarding supply-side resources, demand-side
management (DSM) programs, fuel prices, economic conditions, and load growth. In addition,
Idaho Power hopes to have better information regarding potential carbon regulations, the development
of a federal renewable electricity standard (RES), and the feasibility of advanced nuclear, IGCC,
and other technology issues.
One ofthe key strengths ofIdaho Power's planning process is that the IRP is updated every two years.
Frequent planing allows Idaho Power, the IRPAC, the IPUC and the OPUC, and concerned customers
to revisit the resource plan and make periodic adjustments and corrections to reflect changes in
technology, economic conditions, and regulatory requirements. Durng the two years between resource
plan fiings, the public and regulatory oversight of the activities identified in the near term action plan
allows for discussion and adjustment of the IRP as waranted.
20091RP Page 125
11. Action Plan Idaho Power Company
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Page 126 20091RP