200408272004IRP.pdf

2004 INTEGRATED RESOURCE PLAN
Providing a foundation for a bright future.

2004 INTEGRATED RESOURCE PLAN
July 2004

Idaho Power Company

2004 Integrated Resource Plan

August 2004

Idaho Power Company

2004 Integrated Resource Plan

Table of Contents

1. Integrated Resource Plan Summary ........................................................................................1
Introduction .............................................................................................................................................1
Potential Resource Portfolios.................................................................................................................2
Risk Management....................................................................................................................................2
Near-Term Action Plan...........................................................................................................................3
2. Idaho Power Company Today ..................................................................................................7
Customer and Load Growth ..................................................................................................................7
Supply-Side Resources............................................................................................................................9
Transmission Interconnections ............................................................................................................18
Off-System Purchases, Sales, and Load-Following Agreements.......................................................24
Demand-Side Management ..................................................................................................................25
3. Planning Period Forecasts .....................................................................................................29
Load Forecast ........................................................................................................................................29
Hydro Forecast ......................................................................................................................................33
Generation Forecast..............................................................................................................................35
Transmission Forecast ..........................................................................................................................35
Fuel Price Forecasts ..............................................................................................................................36
4. Future Requirements..............................................................................................................39
Water Planning Criteria for Resource Adequacy ..............................................................................40
Planning Scenarios................................................................................................................................41
5. Potential Resource Portfolios.................................................................................................49
Resource Cost Analysis.........................................................................................................................49
Supply-Side Resource Options.............................................................................................................52
Demand-Side Management and Pricing Options ...............................................................................56
Social Costs ............................................................................................................................................59
Resource Portfolios ...............................................................................................................................60
Portfolio Selection .................................................................................................................................61
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6. Risk Analysis...........................................................................................................................63
Capital Risk ...........................................................................................................................................67
Production Tax Credit Risk .................................................................................................................69
Natural Gas Price Risk .........................................................................................................................70
Carbon Tax Risk ...................................................................................................................................71
Market Risk ...........................................................................................................................................73
Risk Analysis Summary........................................................................................................................74
7. Ten-Year Resource Plan.........................................................................................................77
Introduction ...........................................................................................................................................77
Market Purchases..................................................................................................................................80
Transmission Resources .......................................................................................................................80
Demand-Side Management and Pricing Options ...............................................................................81
8. Near-Term Action Plan ..........................................................................................................83
Introduction ...........................................................................................................................................83
Near-Term Action Plan.........................................................................................................................83
Generation Resources ...........................................................................................................................84
Renewable Energy.................................................................................................................................85
Transmission Resources .......................................................................................................................86
Demand-Side Management and Pricing Options ...............................................................................86
Risk Mitigation ......................................................................................................................................87

Appendices:
Appendix A 2004 Economic Forecast
Appendix B 2004 Sales and Load Forecast
Appendix C 2004 Demand Side Management Annual Report
Technical Appendix

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Glossary of Acronyms

A/C – Air Conditioning
AEO – Annual Energy Outlook
AIR – Additional Information Requests
aMW or MWa – Average Megawatt
BPA – Bonneville Power Administration
CCCT – Combined-Cycle Combustion Turbine
CHP – Combined Heat and Power
CO2 – Carbon Dioxide
CT – Combustion Turbine
DOE – Department of Energy
DG – Distributed Generation
DSM – Demand-Side Management
EA – Environmental Assessment
EEAG – Energy Efficiency Advisory Group
EIA – Energy Information Administration
EIS – Environmental Impact Statement
ESA – Endangered Species Act
FERC – Federal Energy Regulatory Commission
IOU – Investor-Owned Utility
IPC – Idaho Power Company
IPUC – Idaho Public Utilities Commission
IRP – Integrated Resource Plan
IRPAC – Integrated Resource Plan Advisory Council
kV – Kilovolt
kW – Kilowatt
kWh – Kilowatt hour
LIWA – Low-Income Weatherization Assistance
MAF – Million Acre Feet
MMBTU – Million British Thermal Units
MW – Megawatt
MWh – Megawatt hour
NEEA – Northwest Energy Efficiency Alliance
NWPCC – Northwest Power and Conservation Council
NOx – Nitrogen Oxides
OPUC – Oregon Public Utility Commission
PM&E – Protection, Mitigation and Enhancement
PTC – Production Tax Credit
QF – Qualifying Facility
RFP – Request for Proposal
RTO – Regional Transmission Organization
SO2 – Sulfur Dioxide
WACC – Weighted Average Cost of Capital
WECC – Western Electricity Coordinating Council
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Idaho Power Company 2004 Integrated Resource Plan

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1. Integrated Resource Plan Summary

Introduction
The 2004 Integrated Resource Plan (IRP) is Idaho Power Company’s (IPC or the
Company) seventh resource plan prepared to fulfill the regulatory requirements and guidelines
established by the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility
Commission (OPUC).
Idaho Power Company worked with representatives of major stakeholders to develop
the 2004 Integrated Resource Plan. Members of the environmental community, major
industrial customers, irrigation representatives, state legislators, PUC representatives, the
Governor’s office, and others formed the Integrated Resource Plan Advisory Council
(IRPAC) and made significant contributions to this plan. The 2004 IRP reflects the combined
knowledge and input from the representatives and some of the IRPAC members may submit
separate documents and letters expressing their views regarding the 2004 IRP and the
planning process.
Based on legislative actions in Oregon and Idaho, the 2004 Integrated Resource Plan
assumes that during the planning period, from 2004 through 2013, Idaho Power will continue
to be responsible for acquiring resources sufficient to serve all of its retail customers in its
Idaho and Oregon certificated service areas and will continue to operate as a vertically-
integrated electric utility.
The two primary goals of the 2004 Integrated Resource Plan are to:
1. Identify sufficient resources to reliably serve the growing demand for energy service
within the Idaho Power Company service territory throughout the 10-year planning
period.
2. Ensure that the portfolio of resources selected balances cost, risk, and environmental
concerns.
In addition, there are two secondary goals:
a. To give equal and balanced treatment to both supply-side resources and demand side
measures
b. To involve the public in the planning process in a meaningful way.
The number of households in the Idaho Power Company service territory is expected
to increase from around 320,000 today to over 380,000 by the end of the planning period in
2013. Population growth in Southern Idaho is an inescapable fact, and IPC will need physical
resources to meet the electrical energy demands of the additional customers.
Idaho Power Company has an obligation to serve customer loads regardless of the
water conditions that may occur. In light of the public input and regulatory support of the
2002 IRP planning criteria, IPC will continue to emphasize a resource plan based upon a
worse-than-median level of water. In the 2004 Integrated Resource Plan, IPC is again
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emphasizing the 70th percentile water conditions and 70th percentile load conditions for
resource planning. The water-planning criteria are discussed further in Chapter 4.
Potential Resource Portfolios
Idaho Power Company examined 12 resource portfolios as part of the 2004 Integrated
Resource Plan. Idaho Power Company initially presented eight resource portfolios.
Discussions with the IRP Advisory Council led to four additional resource portfolios. Of the
12 portfolios, the top five were selected for additional risk analysis – a portfolio that
emphasized coal-fired generation, a portfolio with a wind generation emphasis and a natural
gas-fired generation backup, and three diversified portfolios. Following the risk analysis, a
diversified portfolio with nearly equal amounts of renewable generation and traditional
thermal generation was selected as the preferred resource portfolio.
The selected portfolio will increase Idaho Power Company’s power supply by
approximately 800 aMW and increase the capacity of the system by almost 940 MW over the
planning horizon. The balanced portfolio selected for this plan is composed of:
− 76 MW Demand Response Programs (DSM)
− 48 MW Energy Efficiency Programs (DSM)
− 350 MW Wind-Powered Generation
− 100 MW Geothermal-Powered Generation
− 48 MW Combined Heat and Power at Customer Facilities
− 88 MW Simple-Cycle Natural Gas Fired Combustion Turbines
− 62 MW Combustion Turbine, Distributed Generation, or Market Purchases
− 500 MW Coal-Fired Generation
The proposed resource portfolio represents resource acquisition targets. It is important to note
that the actual resource portfolio may differ from the above quantities depending on the
response to Idaho Power Company’s requests for proposals.
Risk Management
Idaho Power, in conjunction with the IPUC staff and interested customer groups,
developed a risk management policy during 2001 to protect against severe movements in the
Company’s power supply costs. The risk management policy is primarily aimed at managing
short-term market purchases and hedging strategies with a typical time horizon of 18 months
or less. The risk management policy is intended to supplement the existing IRP process.
Whereas the IRP is the forum for making long-term resource decisions, the risk
management policy addresses the short-term resource decisions that arise as resources, loads,
costs of service, market conditions, and weather vary. The Risk Management Committee
oversees both the implementation of the risk management policy and the Integrated Resource
Plan to ensure a consistent and coordinated approach.
Idaho Power intends to issue requests for proposals (RFPs) and acquire a variety of
resource types including, renewable, thermal, demand-side programs, and combined heat and
Chapter 1 Plan Summary

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power early in the planning period. Should any of these resources differ from the expected
levels of production and reliability, Idaho Power will be able to adjust the resource
proportions in later resource plans. In addition, should market or policy conditions
dramatically change, the customers of Idaho Power Company will have the protection of a
diverse resource portfolio.
Near-Term Action Plan
Customer growth is the primary driving force behind Idaho Power Company’s need
for additional resources. Population growth throughout Southern Idaho – specifically, in the
Treasure Valley – requires additional resources to meet both instantaneous peak and sustained
energy needs. The Company’s data, projections, and analyses show that a blended approach
based on a diversified portfolio of resources is the most cost-effective, least-risk, and
environmentally responsible method to address the increasing energy demands of Idaho
Power customers.
Idaho Power has selected a balanced portfolio containing renewable resources,
demand-side measures, and thermal generation to meet the projected electric demands over
the next ten years. The 2004 Integrated Resource Plan identifies specific actions to be taken
by Idaho Power Company prior to the next IRP in 2006:
Fall 2004
− Issue the RFP for 200 MW wind resource
− Issue the RFP for the combustion turbine peaking resource.
− Proceed with the Borah-West transmission upgrade
− File a supplement to the 2004 IRP presenting the results of the ongoing demand-side
management studies
− File for an energy efficiency tariff rider with the Oregon PUC
2005
− Design demand-side measures in coordination with the Energy Efficiency Advisory
Group and the Public Utility Commissions
− Issue RFP for 12 MW CHP
− Issue the RFP for 100 MW geothermal resource
Idaho Power intends to issue various requests for proposals starting in the fall of
2004. Actual size and configuration of the resources and demand-side programs may vary
depending on the specific vendor responses to the requests for proposals. In the event that
bidders are not responsive or if the pricing is not competitive, the resource portfolio identified
in the IRP may have to be adjusted. In addition, should bidders propose especially attractive
responses to the RFPs, Idaho Power Company may alter the resource proportions.
Renewable Resource Education, Research, and Development
Idaho Power Company’s resource portfolio has always emphasized renewable
resources. The Company’s foundation was the Swan Falls Dam on the Snake River – a
Chapter 1 Plan Summary

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renewable resource that is still in operation today nearly 100 years later. Idaho Power
Company continues to support renewable resource education, research, and development.
Idaho Power will continue its commitment to fund educational and demonstration energy
projects with up to $100,000 of support for the following near-term research, education, and
demonstration projects:
1. Idaho Power Company will support the Foothills Environmental Learning Center to be
built near Hull’s Gulch on the north side of Boise including the installation of a 4.6
kW fuel cell and a 2.0 kW solar panel at the center.
2. Idaho Power Company will repair and upgrade the 15 kW demonstration solar energy
project on the roof of the Idaho Power Corporate headquarters in downtown Boise.
Idaho Power Company’s most significant commitment to renewable resources is the intention
to add approximately 450 MW of renewable energy resources to the Company’s generation
portfolio.
Portfolio Composition
In 2013, after the projects identified in the 2004 Integrated Resource Plan preferred
portfolio are completed, Idaho Power Company’s resource portfolio will contain
approximately:
− 1,800 MW Hydro
− 1,520 MW Coal-Fired Generation
− 350 MW Wind Powered Generation
− 340 MW Natural Gas Combustion Turbines
− 100 MW Geothermal Powered Generation
− 48 MW Combined Heat and Power
− 124 MW Demand-Side Progams

The diversified resource portfolio will allow Idaho Power Company to continue to serve its
customers while balancing cost, risk, and environmentally concern.
Chapter 1 Plan Summary

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IRP Methodology
A brief outline of the IRP methodology is as follows:
1. Assess the present and future conditions
− Develop the load forecast
− Develop the hydrologic forecast
− Develop generation and transmission forecasts
− Determine energy surplus and deficiency on a monthly basis
− Develop a peak-hour transmission analysis to estimate transmission deficiencies
− Determine energy (monthly) and capacity (peak hour) targets
2. Inventory the potential resource and DSM program options and select a portfolio
− Estimate the costs of potential supply-side resources and demand-side programs
− Construct practical portfolios based on supply-side resource and demand-side
program costs and estimates
− Analyze the generation performance and financial costs of the different portfolios
− Rank the portfolios and select the top five portfolios for further risk analysis
3. Test the top five portfolios to identify a preferred portfolio
− Refine the transmission analysis for the top five portfolios
− Perform financial risk analysis
− Perform policy risk analysis
− Perform market risk analysis
− Discuss the qualitative risks
− Identify the preferred portfolio
4. Develop the action plans based on the preferred portfolio
− Develop the ten-year action plan
− Develop the near-term action plan

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Chapter 1 Plan Summary

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2. Idaho Power Company Today
Customer and Load Growth
In 1990, Idaho Power Company had almost 290,000 general business customers.
Today, Idaho Power Company serves almost 425,000 general business customers in Idaho
and Oregon. Firm peak load has increased from less than 2,100 MW in 1990 to nearly 3,000
MW in the summers of 2002 and 2003. Average firm load has increased from 1,200 aMW in
1990 to 1,660 aMW today. Summaries of Idaho Power load and customer data are shown in
Table 1 and Figure 1.

Table 1 Idaho Power Company Historical Data (1990 through 2003)
Year
Total Nameplate
Generation (MW)
Peak Firm Load
(MW)
Average Firm Load
(aMW) Customers
1990 2,635 2,052 1,206 289,398
1991 2,635 1,972 1,207 295,670
1992 2,694 2,164 1,282 303,962
1993 2,644 1,935 1,274 314,255
1994 2,661 2,245 1,375 325,988
1995 2,703 2,224 1,325 336,795
1996 2,703 2,437 1,439 348,188
1997 2,728 2,352 1,458 358,938
1998 2,738 2,578 1,487 369,803
1999 2,738 2,689 1,503 381,311
2000 2,738 2,765 1,654 390,851
2001 2,851 2,500 1,576 400,724
2002 2,912 2,963 1,623 411,555
2003 2,912 2,944 1,658 423,167
More detailed information is included in the Technical Appendix to the 2004 Integrated Resource Plan.
Simple calculations using the data in Table 1 suggest that each new customer adds
over 6 kW to the peak load and over 3 kW to the average load. In actuality, residential,
commercial, and irrigation customers generally contribute more to the peak load, whereas
industrial customers contribute more to the average load. Industrial customers generally have
a flatter load shape whereas residential, commercial, and irrigation customers have a load
shape with greater variation.
Since 1990, Idaho Power Company total nameplate generation has increased by
277 MW – or 277,000 kW – to slightly over 2,900 MW. Total nameplate generation is the
rated output of all generation facilities. Actual generation is lower than total nameplate
generation due to factors such as hydrological conditions, fuel purity, maintenance, and
facility wear and tear. The 277 MW increase in capacity represents enough generation to
serve about 46,000 customers at peak times and represents the average energy requirements of
Chapter 2 7 Idaho Power Company Today

Figure 1 Historical Data (1990 through 2003)
0
500
1000
1500
2000
2500
3000
3500
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Year
Ge
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a
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o
r

L
o
a
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(
M
W
)
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
Cu
s
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s
Number of Customers
Total Nameplate Generation
Peak Firm Load
Average Firm Load
about 92,000 customers. Idaho Power Company generation upgrades, including the removal
of the Wood River turbine, are shown in Table 2.
Since 1990, Idaho Power Company has added 135,000 new customers, which equals
the combined population of Nampa and Meridian. The simple peak and average energy
calculations mentioned earlier suggest that the additional 135,000 customers require over 800
additional MW of on-peak capacity and over 400 MW of average energy.
Idaho Power Company anticipates adding over 10,000 customers each year
throughout the 10-year planning period. The same simple calculations suggest that peak load
requirements are expected to grow at over 60 MW per year and average energy is forecast to
grow at over 30 aMW per year. More detailed customer and load forecasts are discussed in
Chapter 3 of this Integrated Resource Plan, and in the Sales and Load Forecast appendix to
the 2004 IRP.
The simple peak energy calculations indicate that Idaho Power Company will need to
add peaking capacity equivalent to the 90 MW Danskin Plant every 18 months or peaking
capacity equivalent to the 162 MW Bennett Mountain Plant every two and a half years,
throughout the entire planning period. The actual energy plans to meet the requirements of
the new customers are discussed in Chapters 7 and 8.

Chapter 2 8 Idaho Power Company Today

Table 2 Idaho Power Company Generation Upgrades
Resource Type Capacity (MW) Year
Milner (addition) Hydro 60 1992
Swan Falls (upgrade) Hydro 15 1994, 1995
Twin Falls (upgrade) Hydro 44 1995
Jim Bridger (upgrade) Thermal 92 1997, 1998, 2002
Boardman (upgrade) Thermal 3 1997
Valmy (upgrade) Thermal 23 2001
Danskin (addition) Thermal 90 2001
Wood River Turbine (removal) Thermal -50 1993

Supply-Side Resources
Idaho Power Company has over 2900 MW of installed generation including over
1200 MW of thermal generation (nameplate capacity). In 2003, hydroelectric generation
supplied 37 percent of the customers’ energy needs, thermal generation supplied 42 percent,
and purchased power supplied the remaining 21 percent of the customers’ energy needs.
Hydro Resources
Idaho Power operates 17 hydroelectric generating plants located on the Snake River
and its tributaries. Together, these hydroelectric facilities provide a total nameplate capacity
of 1,707 MW and annual generation equal to approximately 1,057 aMW, or 9.3 million MWh,
annually under median water conditions. The Idaho Power Company supply-side resources
are listed in Table 3.
The backbone of Idaho Power Company’s hydroelectric system is the Hells Canyon
Complex in the Hells Canyon reach of the middle Snake River. The Hells Canyon Complex
consists of the Brownlee, Oxbow, and Hells Canyon dams and the associated generating
facilities. The three plants provide approximately 70 percent of Idaho Power Company’s
annual hydroelectric generation and nearly 40 percent of the total energy generation. The
Hells Canyon Complex alone annually generates approximately 6.2 million MWh, or
708 aMW, of energy under median water conditions. Water storage in the Brownlee reservoir
also enables the Hells Canyon Complex to provide the major portion of Idaho Power
Company’s peaking and load-following capability.
Idaho Power’s hydroelectric facilities upstream from Hells Canyon include the
American Falls, Milner, Twin Falls, Shoshone Falls, Clear Lake, Thousand Springs, Upper
and Lower Malad, Upper and Lower Salmon, Bliss, CJ Strike, Swan Falls and Cascade
generating plants. Although the mid-Snake projects (Upper and Lower Salmon, Bliss, and
CJ Strike) typically follow run-of-river operations, the Lower Salmon, Bliss, and CJ Strike
plants do provide a limited amount of peaking and load following. When possible, the
schedules at these plants are adjusted within the FERC license requirements to coincide with
the daily system peak demand. All of the other upstream plants utilize run-of-river
streamflow for generation.
Chapter 2 9 Idaho Power Company Today

Table 3 Idaho Power Company Supply-Side Resources
Resource Type Capacity (MW) Location
American Falls Hydro 92 Upper Snake
Bliss Hydro 75 Mid-Snake
Brownlee Hydro 585 Hells Canyon
Cascade Hydro 12 N Fork Payette
Clear Lake Hydro 3 S Central Idaho
Hells Canyon Hydro 392 Hells Canyon
Lower Malad Hydro 14 S Central Idaho
Upper Malad Hydro 8 S Central Idaho
Milner Hydro 59 Upper Snake
Oxbow Hydro 190 Hells Canyon
Shoshone Falls Hydro 13 Upper Snake
Lower Salmon Hydro 60 Mid-Snake
Upper Salmon Hydro 35 Mid-Snake
CJ Strike Hydro 83 Mid-Snake
Swan Falls Hydro 25 Mid-Snake
Thousand Springs Hydro 9 S Central Idaho
Twin Falls Hydro 53 Mid-Snake
Boardman Thermal (Coal) 56 N Central Oregon
Jim Bridger Thermal (Coal) 771 SW Wyoming
Valmy Thermal (Coal) 284 N Central Nevada
Bennett Mountain (2005) Thermal (Natural Gas) 261 SW Idaho
Danskin Thermal (Natural Gas) 90 SW Idaho
Salmon Thermal (Diesel) 5 E Idaho

Idaho Power has entered into a Settlement Agreement with the US Fish and Wildlife
Service that provides for a study of Endangered Species Act (ESA) listed snails and their
habitat. The objective of the research study is to determine the impact of peaking operations
on the Bliss Rapids snail and the Idaho Spring snail. The study requires that Idaho Power
operate the Bliss and Lower Salmon facilities following run-of-the-river flows during two of
the next five years. Run-of-the-river operations will serve as the baseline, or control, for the
study. The first year of the run-of-the-river operation is 2004.
General Hells Canyon Complex Operations
Idaho Power Company 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 arrangements are the fall
chinook plan voluntarily adopted by Idaho Power Company in 1991 to protect spawning and
incubation of fall chinook below Hells Canyon Dam, a species that is listed as threatened
under the Endangered Species Act, and the cooperative arrangement that Idaho Power
Company had with federal interests between 1995 and 2001 to implement portions of the
Federal Columbia River Power System (FCRPS) biological opinion flow augmentation
program, a reasonable and prudent alternative (RPA) under the biological opinion intended to
Chapter 2 10 Idaho Power Company Today

avoid jeopardy to ESA-listed anadromous species as a result of FCRPS operations below the
Hells Canyon Complex.
Brownlee Reservoir is the only one of the three Hells Canyon Complex reservoirs –
and Idaho Power Company’s only reservoir – with significant water storage. Brownlee
Reservoir has 101 vertical feet of active storage capacity, which equals approximately
one million 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.
Brownlee Reservoir Seasonal Operations
Brownlee Reservoir is a multiple-use, year-round resource for Idaho Power Company
and the Northwest. Although the primary purpose is to provide a stable power source,
Brownlee Reservoir is also used to control flooding, to benefit fish and wildlife resources, and
to benefit recreation.
Brownlee Dam is one of several Northwest dams that are coordinated to provide
springtime flood control on the lower Columbia River. Between 1995 and 2001, Brownlee
Reservoir, along with several other Northwest dams, was used to augment flows in the lower
Snake River consistent with the FCRPS biological opinion. For flood control, Idaho Power
Company operates the reservoir cooperatively with the U.S. Army Corps of Engineers
(ACOE) North Pacific Division, according to Article 42 of the existing license.
After the flood-control requirements have been met in early summer, Idaho Power
Company attempts to refill the reservoir to meet peak summer electricity demands and
provide suitable habitat for spawning bass and crappie. The full reservoir also offers optimal
recreational opportunities through the Fourth of July holiday.
The US Bureau of Reclamation (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 migrate past the FCRPS projects as part of the flow-augmentation
implemented by the 2000 FCRPS biological opinions. From 1995 through the summer of
2001, Idaho Power Company cooperated with the BOR and other federal interests by shaping
(or pre-releasing) water from Brownlee Reservoir (and later refilling the drafted reservoir
space with water released by the BOR from the upper Snake River reservoirs) and by
occasionally contributing water from Brownlee Reservoir to the flow-augmentation efforts.
In 1996, the Bonneville Power Administration (BPA) entered into an energy
exchange agreement with Idaho Power Company to facilitate Idaho Power Company’s
cooperation with the FCRPS flow-augmentation RPA, and in recognition of the federal
responsibility for the flow augmentation program. The BPA energy exchange agreement
expired in April 2001 and although Idaho Power Company has expressed a willingness to
continue to participate in the FCRPS flow-augmentation program through a similar
arrangement, the BPA has chosen not to renew the agreement. For the summer of 2004,
Idaho Power Company and the BPA have negotiated an agreement that provides the BPA an
option to call on Idaho Power Company to release 100,000 acre-feet of water to augment
Snake River flows during July. Idaho Power Company and the BPA continue to explore the
possibility of a negotiated longer-term shaping agreement.
Chapter 2 11 Idaho Power Company Today

Brownlee Reservoir’s releases are managed to maintain constant flows below
Hells Canyon Dam in the fall. The constant flow requirements are based on the voluntary fall
chinook plan that Idaho Power Company adopted in 1991, as well as the minimum flow
required by Article 43 of the existing license. The constant flow helps ensure sufficient water
levels to protect fall chinook spawning nests, or redds.
After the fall chinook spawn, Idaho Power Company attempts to have a full reservoir
by the first week of December to meet winter peak demands. However, the fall spawning
flows are maintained as the minimum flow below Hells Canyon Dam throughout the winter
until the fall chinook fry emerge in the spring.
Maintaining constant flows to protect the fall Chinook spawning contributes to the
need for additional resources during the fall months. The fall chinook operations result in
lower reservoir elevations in Brownlee Reservoir and correspondingly lower the power
production capability of the plant. The reduced power production may require Idaho Power
Company to acquire power from other sources if the customer load cannot be met due to the
loss of net head at the reservoir.

Federal Energy Regulatory Commission Relicensing Process
Idaho Power Company’s hydroelectric facilities, with the exception of the Clear Lake
and Thousand Springs plants, operate under federal licenses regulated by the Federal Energy
Regulatory Commission (FERC). The process of relicensing Idaho Power’s hydroelectric
projects at the end of their initial 50-year license periods is well under way and the
hydropower project relicensing schedule is shown in Table 4. A license renewal was granted
by FERC in 1991 for the Twin Falls project.
Applications to relicense Idaho Power Company’s three mid-Snake facilities (Upper
Salmon, Lower Salmon, and Bliss) were submitted to FERC in December 1995. The
application to relicense the Shoshone Falls project was filed in May 1997. The application to
relicense the CJ Strike project was filed in November 1998. The FERC issued the licenses for
Upper Salmon, Lower Salmon, Bliss, CJ Strike, and Shoshone Falls in August 2004.
The application to relicense the Upper and Lower Malad project was filed in July of
2002. The application to relicense the Hells Canyon Complex was filed in July 2003. The
relicensing application for the Swan Falls project will be prepared and submitted in 2008.
Failure to relicense existing hydropower projects at a reasonable cost will create
upward pressure on the current low rates for 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) imposed as a condition for relicensing.
Idaho Power Company’s goal throughout the relicensing process is to maintain the low cost of
generation at the hydroelectric facilities while implementing non-power measures designed to
protect and enhance the river environment. No reduction of the available capacity or
operational flexibility of the hydroelectric plants to be relicensed has been assumed as part of
the 2004 Integrated Resource Plan. If capacity reductions or reductions in operational
flexibility do occur as a result of the relicensing process, then Idaho Power Company will
Chapter 2 12 Idaho Power Company Today

Table 4 Idaho Power Company Hydropower Project Relicensing Schedule
FERC Nameplate Current File FERC
Project License Capacity License License
Number (MW) Expires Application
Bliss 1975 75 Dec 1997 Dec 1995
Lower Salmon 2061 60 Dec 1997 Dec 1995
Upper Salmon 2777 34.5 Dec 1997 Dec 1995
Shoshone Falls 2778 12.5 May 1999 May 1997
CJ Strike 2055 82.8 Nov 2000 Nov 1998
Upper/Lower Malad 2726 21.8 July 2004 July 2002
Hells Canyon Complex 1971 1,166.9 July 2005 July 2003
Swan Falls 503 25 June 2010 June 2008
adjust future resource plans to reflect the need for additional capacity resources in order to
maintain the existing level of reliability.
Environmental Analysis
The National Environmental Policy Act requires that the FERC perform an
environmental assessment (EA) of each hydropower license application to determine whether
federal action will significantly impact the quality of the natural environment. If so, then an
environmental impact statement (EIS) must be prepared prior to granting a new license.
As part of the EA for Idaho Power’s mid-Snake and Shoshone Falls applications, the
FERC visited Idaho during July 1997 to receive public and agency input through scoping
meetings. The FERC issued additional information requests (AIRs) in 1998 for the
mid-Snake Projects. The FERC also visited Idaho to receive public and agency input at a
scoping meeting held in September 1999. The FERC issued AIRs for the CJ Strike project in
1999. A draft EIS was issued on the mid-Snake projects in January 2002, and the FERC was
in Idaho again in February 2002 to receive public and agency comment. The FERC issued a
Final EIS document for the mid-Snake projects in July 2002 and the Final EIS for the CJ
Strike project in October 2002. The FERC is currently in the process of preparing the draft
EIS for the Hells Canyon Complex. The draft Hells Canyon EIS is expected to be released in
2005.
The FERC is currently developing an approach to a cumulative environmental
analysis of the Snake River from Shoshone Falls through the Hells Canyon Complex. Once
the analysis is complete, the FERC will consider recommendations from affected state and
federal agencies and issue license orders for the affected projects, including required PM&E
measures. New licenses are anticipated from the FERC for the Shoshone Falls, Upper
Salmon, Lower Salmon, Bliss, and CJ Strike projects in late-2004. Opportunity for additional
public comment on the draft EIS and final EIS for the Hells Canyon Complex will occur
before the license order is issued. If a project’s current license expires before a new license
Chapter 2 13 Idaho Power Company Today

has been issued, annual operating licenses are issued by the FERC pending completion of the
licensing process.

Hydroelectric Relicensing Uncertainties
Idaho Power Company is optimistic that the hydro project relicensing will be
completed in a timely fashion. However, prior experience indicates that the relicensing
process will probably result in an increase in the costs of generation from the relicensed
projects. The increased costs are usually associated with the requirements imposed on the
projects as a condition of relicensing. At this time, Idaho Power cannot reasonably estimate
the impact of the relicensing process on the generating capability or operating costs of the
relicensed projects. At the time of the 2006 IRP, Idaho Power will have better information
regarding the power generation impacts of relicensing.

Baseload Thermal Resources
Jim Bridger
Idaho Power Company 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 generating capacity of the Jim Bridger plant
currently stands at 707 MW. After adjustment for scheduled maintenance periods and
estimated forced outages and de-ratings, the annual energy-generating capability of Idaho
Power’s share of the Jim Bridger plant is approximately 627 aMW.
Valmy
Idaho Power Company owns a 50 percent share, or approximately 261 MW of
capacity of the 521 MW Valmy plant located east of Winnemucca, Nevada. The plant, which
consists of one 254 MW unit and one 267 MW unit, is owned jointly with Sierra Pacific
Power Company. After adjustment for scheduled maintenance periods and estimated forced
outages and de-ratings, the annual energy-generating capability of Idaho Power’s share of the
Valmy plant is approximately 231 aMW.
Boardman
Idaho Power owns a 10 percent share of the 552 MW coal-fired plant near Boardman,
Oregon, operated by Portland General Electric Company. After adjustment for scheduled
maintenance periods and estimated forced outages and de-ratings, the annual energy-
generating capability of Idaho Power’s share of the Boardman plant is approximately
47 aMW.
Chapter 2 14 Idaho Power Company Today

Peaking Thermal Resources
Danskin
In addition to the three coal-fired steam-generating plants, Idaho Power owns and
operates the Danskin Plant, a 90 MW natural gas-fired combustion turbine plant and the
associated switchyard. The plant consists of two 45 MW Siemens-Westinghouse W251B12A
combustion turbines. The 12-acre facility, constructed during the summer of 2001, is located
northwest of Mountain Home, Idaho. The Danskin Plant operates as needed to support
system load.
Bennett Mountain
During the spring and summer of 2003 Idaho Power Company conducted a
competitive bidding process to acquire additional peaking generation. The 2003 Request for
Proposals stated on page 4:

PRODUCT
A generating resource, located inside the Idaho Power Company control area,
providing fully dispatchable, first call, non-recallable, physically delivered
electrical capacity during June, July, August, November and December.

QUANTITY
Idaho Power Company anticipates acquiring between 85 and 200 MW of
delivered energy under summer conditions (90°F) at the elevation of the site or
sites identified in the proposal. Idaho Power Company may combine proposals
to meet the 85 MW minimum capacity requirement.

Idaho Power Company selected Mountain View Power (now identified as TR2) to construct a
162 MW Siemens-Westinghouse 501F simple cycle, natural gas fired, combustion turbine in
Mountain Home, Idaho. The Idaho PUC issued a Certificate of Public Convenience and
Necessity in Orders 29410 and 29422 in January 2004. The Bennett Mountain plant is
expected to be constructed, fully commissioned, and on line by June 1, 2005 and will operate
on an as-needed basis to support customer load.
Salmon Diesel
Idaho Power owns and operates two diesel generation units located at Salmon, Idaho.
The Salmon diesels produce 5.5 MW and are primarily operated during emergency
conditions.
PURPA (Public Utility Regulatory Policy Act)
In 1978 the US Congress passed the Public Utility Regulatory Policy Act (PURPA)
requiring utilities such as Idaho Power to purchase the energy from Qualifying Facilities
Chapter 2 15 Idaho Power Company Today

(QF). Qualifying Facilities are privately owned small renewable generation projects or small
cogeneration projects. The individual states were given the task of establishing the terms and
conditions, including price, that each state’s utilities would be required to pay as part of the
PURPA agreements.
The Idaho Public Utilities Commission established two pricing concepts for PURPA
projects. IPUC Order 29124, dated September 26, 2002 is the most recent IPUC order
establishing the PURPA pricing concepts. The same order also made available 20-year
contract terms. PURPA projects are split into two categories – small projects less than
10 MW and large projects 10 MW and over.
For projects greater than 10 MW there is a separate regulatory procedure to set the
rates for each individual PURPA project. In general, the rates are based on Idaho Power
Company’s avoided cost as determined using a methodology outlined by the Idaho PUC.
For projects less than 10 MW, the IPUC is currently making use of a PURPA
Published Avoided Cost model to create an individual price for each Idaho utility. The goal
of the avoided-cost model is to create a price of the utility’s additional resource that was
avoided due to the addition of a PURPA project. Currently, it is assumed that a natural gas
combined cycle turbine will be the selected resource that Idaho utilities would avoid and the
avoided-cost model uses the cost of a combined cycle turbine in the avoided-cost estimates.
The avoided-cost model requires numerous estimated and forecasted inputs including
expected plant life, estimated plant cost, expected year of plant construction, estimated fixed
O&M costs, estimated variable O&M cost, estimated cost escalation rates, estimated fuel cost
and associated escalation rate, and assumed plant heat rates. Of the inputs, fuel cost and the
associated escalation rate have the most significant influence on the resulting price.
Additionally, fuel cost and the associated escalation rate are the most volatile inputs and are
the most difficult to estimate.
In IPUC Order 29124 the IPUC adopted using the Northwest Power and Conservation
Council’s medium natural gas price forecast for the fuel cost input and to update the PURPA
Published Avoided Cost when new forecasts from the Northwest Power and Conservation
Council become available. The Northwest Power and Conservation Council is expected to
update the natural gas price forecast once a year.
IPUC Order 29391, dated December 5, 2003, established the PURPA Published
Avoided Cost for Idaho Power to be 54.03 Mills per kWh (levelized rate, online in 2004,
20-year contract term).
Cogeneration and Small Power Producers (CSPP)
Idaho Power Company has over 70 contracts with independent power producers for
over 200 aMW of nameplate capacity. Most of the projects are low-head hydro projects on
various irrigation canals, cogeneration projects at industrial facilities, and various small
renewable power projects. Idaho Power Company purchases approximately 100 MW of
power from cogeneration and small power producers. Idaho Power Company is required to
take the energy from these projects and Idaho Power Company does not consider the CSPP
projects to be dispatchable. The Public Utility Regulatory Policy Act and various Idaho and
Chapter 2 16 Idaho Power Company Today

Figure 2 Idaho Power Company 2003 Energy Sources
Thermal
42%
Hydro
37%
Purchased Power
21%

Oregon PUC orders govern the rates, rules, and requirements for independent power
producers.
Purchased Power
Idaho Power Company relies on regional markets to supply a significant portion of
energy and capacity. Idaho Power Company’s is especially dependent on the regional
markets during peak periods. Reliance on regional markets has benefited Idaho Power
customers during times of low prices and Idaho Power Company has a mechanism, the Power
Cost Adjustment, to return these benefits to the customers. However, the reliance on regional
markets can be costly in times of high prices such as during the summer of 2001. As part of
the 2002 IRP process, the public, the Idaho Public Utilities Commission, and the Idaho
legislature all suggested that the time had come for Idaho Power to reduce the reliance on
regional market purchases. Greater planning reserve margins or the use of more conservative
water planning criteria were suggested as methods requiring IPC to acquire more firm
resources and reduce the likelihood of market purchases. Idaho Power Company adopted
more conservative water planning criteria in the 2002 IRP.
Figure 2 shows the 2003 actual utilization of Idaho Power Company energy resources
to serve customer load. As recently as 1998, the proportion of hydro generation exceeded
50 percent and purchased power was only 15 percent of the resource portfolio. Customer
growth combined with below normal water lowered the proportion of hydro to 37 percent and
increased purchased power to 21 percent of the portfolio in 2003.

Chapter 2 17 Idaho Power Company Today

Transmission Interconnections
Description
The Idaho Power transmission system is a key element serving the needs of the Idaho
Power Company retail customers. The 230 kilovolt (kV) and higher voltage main grid system
is essential for the delivery of bulk power supply. Figure 3 shows the principal grid elements
of Idaho Power’s high-voltage transmission system.
Capacity and Constraints
Idaho Power Company’s transmission connections with regional utilities provide
paths over which off-system purchases and sales are made. The transmission interconnections
and the associated power transfer capacities are identified in Table 5. The capacity of a
transmission path may be less than the sum of the individual circuit capacities. The difference
is due to a number of factors, including load distribution, potential outage impacts, and
surrounding system limitations. In addition to the restrictions on interconnection capacities,
there are other internal transmission constraints that may limit IPC’s ability to access specific
energy markets. The internal transmission paths needed to import resources from other
utilities and their respective potential constraints are shown in Figure 3 and Table 5.
Brownlee-East Path
The Brownlee-East transmission path is on the east side of the Northwest
Interconnection shown in Table 5. Brownlee-East is comprised of the 230 kV and 138 kV
lines east of the Brownlee/Oxbow/Quartz area and the Summer Lake-Midpoint 500 kV line.
The constraint on the Brownlee-East transmission path is within Idaho Power’s main
transmission grid and located in the area between Brownlee 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, concurrent with transmission wheeling
obligations and purchases from the Pacific Northwest. Transmission wheeling obligations
also affect southeast flow into and through Southern Idaho. Significant congestion affecting
southeast energy transmission flow from the Pacific Northwest may also occur during the
month of December. Restrictions on the Brownlee-East limit the amount of energy that Idaho
Power Company can import from the Hells Canyon Project as well as limit the off-system
purchases from the Pacific Northwest.
The Brownlee-East constraint is the primary restriction on imports of energy from the
Pacific Northwest during normal and high water years. If new resources are sited west of this
constraint, additional transmission capacity will be required to remove the existing Brownlee-
East transmission constraint and deliver the energy from the additional resources to the
Boise/Treasure Valley load area.
The new 10-mile transmission line between Brownlee and Oxbow identified as the
Oxbow-Brownlee Number Two 230 kV line was designed to relieve the operating limitations
associated with the coincident generation at Oxbow and Hells Canyon. The transmission
Chapter 2 18 Idaho Power Company Today

upgrade increased the Brownlee-East capacity by approximately 100 MW, thereby increasing
IPC’s ability to import additional energy from the Pacific Northwest for native load use. The
transmission upgrade was identified as part of the 2002 Integrated Resource Plan and has
been completed and is now in service.
Oxbow-North Path
The Oxbow-North path is a part of the Northwest Interconnection and consists of the
Hells Canyon-Brownlee and Lolo-Oxbow 230 kV double circuit line. The Oxbow-North path
is most likely to face constraints during the summer months when high northwest-to-southeast
energy flows and high hydro production levels coincide. Congestion on the Oxbow-North
path also occurs during the winter months of November and December due to winter peak
conditions throughout the region.
Northwest Path
The Northwest path consists of the 500 kV Summer Lake-Midpoint line, the three
230 kV lines between the Northwest and Brownlee, and the 115 kV interconnection at
Harney. Deliveries of purchased power from the Pacific Northwest often flow over these
lines. During low water conditions, total purchased power needs may exceed the capability of
the Northwest Path. If new resources are sited west of this constraint, additional transmission
capability will be needed to transmit the energy into the IPC control area.
Borah-West Path
The Borah-West transmission path is within Idaho Power’s main grid transmission
system located west of the Eastern Idaho, Utah Path C, Montana and Pacific (Wyoming)
interconnections shown in Table 5. The Borah-West path consists of the 345 kV and 138 kV
lines west of the Borah/Brady/Kinport area. The Borah-West path will be of increasing
concern because the capacity of this path is fully utilized by existing wheeling obligations.
There is a strong probability that many of the generation alternatives considered in
this IRP will be sited east of the Borah-West transmission path. Transmission improvements
will be required to transfer this new generation through the Borah-West transmission path to
serve load growth in the Boise area. Idaho Power Company has filed to increase the transfer
capacity of the Borah-West Path. The first transmission project that would increase the east
to west transmission capability by 150 MW is moving forward, and an additional 100 MW
project is being considered. If both projects proceed, an additional 250 MW of transmission
capability would be available to serve Idaho Power’s native load requirements from the new
generating resources identified in the Ten-Year Action Plan and the Near-Term Action plan
discussed in Chapters 7 and 8. The appropriate transmission costs have been allocated to each
of the new generating resources.
Midpoint-West Path
The Midpoint-West path is another transmission constraint that exists just west of the
Midpoint area. The Midpoint-West constraint is slightly less restrictive than the Borah-West
constraint at the present time. However, relatively small improvements on the Borah-West
constraint may result in the Midpoint-West constraint limiting east to west transfers. Any
Chapter 2 19 Idaho Power Company Today

significant improvement in the east to west transfers will probably require considerable
upgrades to both the Borah-West and Midpoint-West paths. The transmission projects
mentioned in the Borah-West section also include the necessary improvements to transfer the
output of the proposed new generation resources through the Midpoint-West transmission
path.
Chapter 2 20 Idaho Power Company Today

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Chapter 2 21 Idaho Power Company Today

Table 5 Idaho Power Company Transmission Interconnections
Transmission
Interconnections
Capacity
to Idaho
Capacity
from Idaho
Line or Transformer Connects Idaho Power To
Northwest 1,090 to 2,400 MW Oxbow-Lolo 230 kV Washington Water Power
1,200 MW Midpoint-Summer
Lake 500 kV
PacifiCorp (PPL Division)
Hells Canyon-
Enterprise 230 kV
PacifiCorp (PPL Division)
Quartz Tap-LaGrande
230 kV
Bonneville Power
Administration
Hines-Harney
138/115 kV
Bonneville Power
Administration

Sierra 262 MW 500 MW Midpoint-Humboldt
345 kV
Sierra Pacific Power

Eastern Idaho1 Kinport-Goshen
345 kV
PacifiCorp (UPL Division)
Bridger-Goshen
345 kV
PacifiCorp (UPL Division)
Brady-Antelope
230 kV
PacifiCorp (UPL Division)
Blackfoot-Goshen
161 kV
PacifiCorp (UPL Division)

Utah (Path C)2 775 to 830 to Borah-Ben Lomond
345 kV
PacifiCorp (UPL Division)
950 MW 870 MW Brady-Treasureton
230 kV
PacifiCorp (UPL Division)
American Falls-Malad
138 kV
PacifiCorp (UPL Division)

Montana3 79 MW 79 MW Antelope-Anaconda
230 kV
NorthWestern Energy
87 MW 87 MW Jefferson-Dillon
161 kV
NorthWestern Energy

Pacific (Wyoming) 600 MW 600 MW Jim Bridger 345/230kV PacifiCorp (Wyoming
Division)
Power Transfer Capacity for Idaho Power Company Interconnections
1 The Idaho Power-PacifiCorp interconnection total capacities in Eastern Idaho and Utah include Jim Bridger resource
integration. 2 The Path C transmission path also includes the internal PacifiCorp Goshen-Grace 161 kV line. 3 The direct Idaho Power-Montana Power schedule is through the Brady-Antelope 230kV line and through the Blackfoot-Goshen 161 kV line
that are listed as an interconnection with PacifiCorp. As a result, Idaho-Montana and Idaho-Utah capacities are not independent.
Chapter 2 22 Idaho Power Company Today

Chapter 2 23 Idaho Power Company Today

Transmission Uncertainties
Open Access Transmission Service (FERC Order 888)
Since 1996 Idaho Power has been providing transmission service to qualified
wholesale customers under its Open Access Transmission Tariff. Because of the geographic
location of the Idaho Power transmission facilities, Idaho Power receives numerous requests
for transmission capacity on the Idaho Power main grid transmission system to transport
power between the Pacific Northwest and the Desert Southwest. Because the tariff is
explicitly open access, Idaho Power cannot deny service to qualified wholesale customers
when there is sufficient transmission capacity available to satisfy the customer’s request.
Also, the tariff provides that Idaho Power will construct additional transmission facilities to
increase capacity if the party seeking to use the increased capacity pays the cost of adding the
capacity. The consequence is that planning for Idaho Power’s own use of its transmission
system must take into account that there may be competing uses and that new wholesale
customers have enforceable access rights.
Regional Transmission Organizations
In 1999 the FERC issued Order 2000 to encourage voluntary membership in regional
transmission organizations (RTO). FERC Order 2000 precipitated considerable activity
within the northwest focused on the decisions about whether to create an RTO and how an
RTO should operate. Transmission restructuring activity is continuing and Idaho Power
Company has been an active participant in efforts to determine an appropriate structure for
provision of transmission service within the Pacific Northwest.
The essence of the RTO initiative was that all utilities owning high-voltage
transmission facilities in the region would turn over operational control of their transmission
systems to a single, independent regional operator. RTO formation would also establish
organized markets for generation services such as the generation adjustments needed for
managing transmission loading. While the proposed restructuring changes will not alter the
physical capability of the transmission system, any operational changes will likely affect
Idaho Power's use of its transmission system. The changes are intended to be beneficial,
giving Idaho Power easier access to more efficient markets thus helping manage operation of
the portfolio of resources that serve native load. However, significant uncertainties exist
because the operating principals of a potential northwest RTO are largely undeveloped and
controversial.
Western Electricity Coordinating Council Operating Transfer Capability Process
Since the large-scale transmission outages in the western US during the summer of
1996, transmission system capabilities have come under increasing scrutiny. The Western
Electricity Coordinating Council (WECC) has reevaluated the transfer capability on many
transmission lines. The net result of the WECC efforts to reevaluate the regional transfer
capability is that a transmission operator no longer has the assurance that all of the historical
line capability will be fully usable in the future. New interactions with other existing
transmission paths, previously unidentified, can force reductions in existing transmission
capability. Uncertainty surrounding the transfer capability presents real challenges to
resource planning. Transmission system capability to handle multiple contingences was an
issue that factored into the eastern US Interconnection outage of August 14, 2003.
Recommendations to address the issues are not fully developed and there is considerable
uncertainty regarding how any national recommendations will affect the WECC and the
western US.
Off-System Purchases, Sales, and Load-Following Agreements
Idaho Power currently has three term off-system sales contracts. The three contracts
were entered into in the late 1980s and early 1990s when Idaho Power had an energy and
capacity surplus. The contracts, expiration dates, and average sales amounts are shown in
Table 8 in Chapter 3.
The City of Weiser in SW Idaho has a full-requirements term sales contract with
Idaho Power. Under the full-requirements contract, Idaho Power is responsible for supplying
the entire load of the city. The City of Weiser is located entirely within Idaho Power’s load-
control area.
A term sales contract with Raft River Rural Electric Cooperative Inc. was established
as a full-requirements contract after being approved by the Federal Energy Regulatory
Commission (FERC) and the Public Utilities Commission of Nevada. Raft River Rural
Electric Cooperative Inc. is the electric distribution utility serving Idaho Power’s former
customers in the State of Nevada. Idaho Power sold the transmission and distribution
facilities, along with the rights-of-way that serve about 1,250 customers in Northern Nevada
and 90 customers in southern Owyhee County, to Raft River Rural Electric Cooperative Inc.
The closing date of the transaction was April 2, 2001. The area sold to Raft River Rural
Electric Cooperative Inc. is located entirely within Idaho Power’s load-control area.
Idaho Power Company’s third term sales contract is with the City of Colton in
Southern California. In May 2002, Idaho Power Company notified the City of Colton that
Idaho Power Company intended to terminate the contract with Colton at the end of May 2005.
The contract termination required a three-year advance notification and could have been
initiated by either party.
Idaho Power Company and Montana’s NorthWestern Energy have negotiated a load-
following agreement in which Idaho Power Company provides NorthWestern Energy with
30 MW of load-following service. The agreement includes provisions that allow Idaho Power
Company to receive energy from NorthWestern Energy on the east side of the system during
summer months. Idaho Power Company anticipates that the load following agreement with
NorthWestern will be renewed throughout the IRP planning period. Idaho Power Company
also has a load following agreement with NorthWestern for serving the Idaho Power
Company load in Salmon, Idaho. Salmon, Idaho is located in the NorthWestern load control
area.
Idaho Power Company has negotiated a purchase agreement with PPL Montana for
83 MW during heavy load hours in June, July, and August (heavy load hours are from hour
ending 8:00 am to hour ending 11:00 pm, Monday through Saturday, Mountain Time). The
Chapter 2 24 Idaho Power Company Today

purchase agreement expires in 2009, although Idaho Power Company assumes that the
purchase agreement will be renewed.
Idaho Power Company has an exchange contract with the City of Anaheim,
California. Idaho Power receives 10 MW energy during the months of April through August
at Mona, Utah, and receives 20 MW of energy during November, 35 MW during December,
and 25 MW during January. The November through January energy is delivered to Idaho
Power Company at Mid-Columbia. Idaho Power Company delivers 20 MW of energy to the
City of Anaheim during the months of October through March at the Valmy plant in Nevada.
The contract is set to expire in March 2005 and renewal is uncertain.
Demand-Side Management
Idaho Power operates demand response, energy efficiency, market transformation,
low income, public purpose and education programs with funding from a variety of sources.
In response to IPUC Order 29026, issued in May 2002, Idaho Power initiated an energy
efficiency tariff rider and receives approximately $2.7 million annually for demand-side
management (DSM) programs. At the same time in 2002, an Energy Efficiency Advisory
Group (EEAG) including customer, public, and private representatives was organized to
provide advice and guidance to Idaho Power for administration of rider-funded programs.
Idaho Power Company intends to file for a similar energy efficiency tariff rider with the
Oregon PUC before the end of 2004.
The 2002 IRP indicated a need for near-term summer peak reduction. The primary
focus of programs funded by the rider has been demand response, demand reduction and
energy efficiency during summer peak periods.
Idaho Power is a participant of the Bonneville Power Administration Conservation
and Renewable Energy Discount program devoting up to $525,000 per year to programs for
lower-income residential customers. Additional funding for market transformation programs
as well as low income and public purpose programs, are included in general operating
expenses of the Company. Idaho Power completed a 2003–2005 Demand-Side Management
Plan that outlines the management philosophy and direction for DSM.
In 2003, Idaho Power realized savings of 5,912 MWh and 189 kW of summer peak
demand reduction from its energy efficiency and demand response programs. Savings from
market transformation programs is reported below.
Demand Response Programs
Demand response is a term used broadly to refer to customer-chosen reductions or
shifts in electricity use. In March 2003, the Idaho Public Utilities Commission issued Order
29207 and approved a request by Idaho Power to conduct a two-year Air Conditioning
Cycling Pilot Program. The program enables Idaho Power to directly address summer
peaking requirements by reducing some of the air conditioning load. Air conditioning load is
one of the primary contributors to the summer peak.
Idaho Power’s primary goal of the A/C Cycling Pilot Program is to assess the
effectiveness of air conditioning controls for reducing peak load. Specific objectives include
assessing the effect of control on customer satisfaction and comfort and retention, developing
Chapter 2 25 Idaho Power Company Today

an analysis model for measuring peak load reduction, gaining operating experience in
managing the program, and testing equipment.
Approximately 200 households participated in the summer of 2003 and 300 more
households will be added in 2004. A final analysis of the A/C Cycling Program will be
completed by the end of 2004.
In February 2004 Idaho Power filed an application with the Idaho PUC to conduct an
Irrigation Peak Clipping Pilot program to be conducted during the summer of 2004. The
Idaho PUC accepted the irrigation pilot and it is anticipated that a report analyzing the
feasibility of a full-scale irrigation peak reduction program will be completed by the end of
2004.
Energy Efficiency and Peak Reduction Programs
Idaho Power works with the Energy Efficiency Advisory Group to select new DSM
programs that consider resource needs and customer service characteristics. In 2003, Idaho
Power completed a Compact Fluorescent Lamp Coupon Program, and launched four new full-
scale DSM programs. The four DSM programs are:
1. Energy Efficient Manufactured Home Incentives (January 2003)
2. Manufactured Home Energy Checkups (Late 2003)
3. Industrial Efficiency Program (October 2003)
4. Irrigation Efficiency Program (September 2003)
Additionally, Idaho Power initiated or operated several DSM research pilot programs.
The purposes of the pilot programs are to provide information to Idaho Power for assessing
the viability of full-scale programs or to provide a trial period to fine-tune program
parameters. The pilot programs include:
− Energy Star Homes Northwest “Quick Start”
− Trade In, Trade Up to Energy Star Pilot
− AirCare Plus Pilot
− Distribution Efficiency Initiative Pilot
Market Transformation Efforts
Idaho Power funds market transformation programs in the service territory through
the Northwest Energy Efficiency Alliance (NEEA) and coordinating NEEA activities in
Idaho. The Northwest Energy Efficiency Alliance is a regional group whose mission is to
catalyze the Northwest marketplace to embrace energy-efficient products and services.
In Idaho, funding for the Idaho Power’s participation in the NEEA was authorized
through 2004 by Order 28333 in Case IPC-E-99-13. The Oregon PUC approved the
company’s expenditures for the NEEA for 2003.
Preliminary estimates reported by the NEEA indicate that Idaho Power’s share of
regional market transformation kWh savings for 2003 is between 1.9 and 2.5 aMW. Idaho
Chapter 2 26 Idaho Power Company Today

Power relies on the NEEA to report the energy savings and other benefits of the NEEA
regional portfolio of initiatives.
Low Income and Public Purpose Programs
Low-Income Weatherization Assistance
Low-Income Weatherization Assistance (LIWA) is a public-purpose program to make
weatherization services more affordable for low-income customers. Authorized annual
payments up to $1.2 million are made to local non-profit agencies participating in state-run
weatherization programs in Idaho and Oregon to supplement federal funding. In Idaho, the
provisions and payments are currently being negotiated with the community action agencies.
In Oregon, all dwellings must be electrically heated and all measures must provide cost-
effective electricity savings to be eligible for funding. Idaho Power typically contributes 50
percent of the cost for qualifying measures, plus a $75 administration fee, per dwelling. The
program also funds weatherization of buildings occupied by tax-exempt organizations.

Oregon Commercial Audit Program
The Oregon Commercial Audit Program is a statutory program specifying that all
commercial building customers be notified every year that information regarding energy-
saving operations and maintenance measures is available and that commercial energy-audit
services can be provided. The audit services are normally provided at no charge to the
customer. Customers using more than 4,000 kWh per month may receive a more detailed
audit but may be required to pay a portion of the cost.

Oregon Residential Weatherization
The Oregon Residential Weatherization Program is a statutory requirement program
specifying annual notification to all residential customers informing them how to obtain
energy audits and financing for energy conservation measures. To qualify for an Idaho Power
audit or financing, customers must have electric space heat.

Small Project and Education Funds
Idaho Power, with support of the Energy Efficiency Advisory Group, set aside two
funds – the Small Project Fund and the Education Fund. Each was initially funded with two
percent of the Idaho DSM rider funding which results in approximately $54,000 available for
each fund. The funds are designed to support research requests, educational opportunities and
worthwhile small projects that are not eligible under other programs.

Chapter 2 27 Idaho Power Company Today

Chapter 2 28 Idaho Power Company Today

3. Planning Period Forecasts
Load Forecast
Future demand for electricity by customers in Idaho Power Company’s service
territory is defined by a series of six load forecasts, reflecting a range of load uncertainty
resulting from differing economic growth and weather-related assumptions.
Table 6 summarizes three forecasts that represent Idaho Power’s estimate of the
boundaries of Idaho Power’s annual total load growth over the planning period considering
economic and demographic impacts on the load forecast – normal weather is assumed. There
is a 90 percent probability that Idaho Power’s load growth will exceed the Low Load Growth
Forecast, a 50 percent probability of load growth exceeding the Expected Load Growth
Forecast, and a 10 percent probability that load growth will exceed the High Load Growth
Forecast. The projected 10-year average annual compound growth rate in the expected load
forecast is 2.2 percent. Idaho Power believes that the Expected Load Growth Forecast is the
most likely forecast and uses this forecast as the basis for further analysis of weather related
uncertainties presented in Table 7.
Table 7 summarizes three forecasts that represent Idaho Power’s estimate of Idaho
Power’s annual total load growth over the planning period considering normal, 70th percentile
and 90th percentile weather impacts (explained in more detail below) on the Expected Load
Growth Forecast (from Table 6). Idaho Power uses the 70th percentile forecast as the basis for
resource planning. The 70th percentile forecast is referenced throughout the IRP.
Expected Load Forecast – Economic Impacts
The expected load forecast represents the most probable projection of service territory
load growth during the planning period. The forecast for total load growth is determined by
summing the load forecasts for individual classes of service, as described in Appendix B, 2004
Sales and Load Forecast. For example, the expected total load growth of 2.2 percent is
comprised of residential load growth of 1.9 percent, commercial load growth of 3.2 percent,
irrigation load growth of 0.2 percent, industrial load growth of 3.0 percent, and additional
firm load growth of 1.9 percent.
Economic growth assumptions influence the individual customer-class forecasts. The
number of service area households and various employment projections, along with customer
consumption patterns, are used to form load projections. Economic growth information for
Idaho and its counties can be found in Appendix A, 2004 Economic Forecast.
The number of households in the State of Idaho is projected to grow at an annual
average rate of 1.7 percent during the 10-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 household forecasts. Growth in the number of households within the Idaho Power
service territory, combined with estimated consumption per household, results in the
previously mentioned 1.9 percent residential load growth rate.
Chapter 3 29 Planning Period Forecasts

Table 6 Load Forecast Probability Boundaries (Average Megawatts, aMW)
Year Low Load Growth
Forecast
Expected Load
Growth Forecast
High Load Growth
Forecast
2004 1,640 1,678 1,727
2005 1,662 1,720 1,787
2006 1,687 1,760 1,845
2007 1,716 1,803 1,902
2008 1,747 1,846 1,960
2009 1,777 1,889 2,016
2010 1,807 1,930 2,071
2011 1,836 1,970 2,124
2012
2013
1,864
1,893
2,008
2,049
2,176
2,228

Growth Rate
(2004 through 2013) 1.6% 2.2% 2.9%

The number of households in the Idaho Power Company service territory is expected
to increase from around 320,500 at the end of 2003 to nearly 383,600 by the end of the
planning period in 2013.
Expected Load Forecast – Weather Impacts
The expected case load forecast assumes median temperatures and median
precipitation meaning that there is a 50 percent chance that loads will be higher or lower than
the expected case load forecast due to colder-than-median or hotter-than-median temperatures
or wetter-than-median or drier-than-median precipitation.
Since actual customer loads can vary significantly depending upon weather
conditions, two alternative scenarios were considered that address load variability due to
weather. Idaho Power Company has generated load forecasts for 70th percentile weather and
90th percentile weather. Seventieth percentile weather means that in seven out of 10 years, the
load is expected to be less than the forecast and in three out of 10 years, the load is expected
to exceed the forecast. Ninetieth percentile load has a similar definition.
Cold winter days create high heating load. Hot, dry summers create both high-
cooling and high-irrigation loads. Heating degree-days, cooling degree-days, and growing
degree-days are used to quantify the weather and estimate a load forecast. In the winter,
maximum load occurs with the highest recorded levels of heating degree-days (HDD). In the
summer, maximum load occurs with highest recorded levels of cooling and growing degree-
days (CDD and GDD).
For example, at the Boise Weather Service Office, the median number of HDD in
December over the 1948–2003 time period is 1,040 HDD. The coldest December over the
same time period was December 1985 when there were 1,619 HDD recorded at Boise.
For December, the 70th percentile HDD is 1,068 HDD. The 70th percentile value is
likely to be exceeded in three out of 10 years on average. The 90th percentile HDD is
1,194 HDD and is likely to be exceeded in one out of 10 years on average. Percentile
Chapter 3 30 Planning Period Forecasts

Table 7 Range of Total Load Growth Forecasts in Average Megawatts

Year

Median

70th Percentile

90th Percentile

2004 1,678 1,720 1,788
2005 1,720 1,762 1,831
2006 1,760 1,803 1,873
2007 1,803 1,845 1,917
2008 1,846 1,889 1,962
2009 1,889 1,932 2,006
2010 1,930 1,974 2,048
2011 1,970 2,014 2,090
2012 2,008 2,053 2,130
2013 2,049 2,094 2,171

Growth Rate
(2004 through 2013)

2.2%

2.2%

2.2%

calculations were used in each month throughout the year for the weather-sensitive customer
classes – residential, commercial, and irrigation – to forecast load.
In the 70th percentile residential and commercial load forecasts, temperatures in each
month were assumed to be at the 70th percentile of HDD in winter and at the 70th percentile of
CDD in the summer. In the 70th percentile irrigation load forecast, GDD were assumed at the
70th percentile and precipitation was assumed to be at the 70th percentile, reflecting weather
that is both hotter and drier than median weather. The 90th percentile irrigation load forecast
was similarly constructed using weather values measured at the 90th percentile.
Idaho Power loads are highly dependent upon weather. The three scenarios allow
careful examination of load variability and how the load variability may impact resource
requirements. It is important to understand that the probabilities associated with the load
forecasts apply to any given month and that 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 weekly,
monthly, and seasonal time horizon. Economic and demographic conditions affect the load
forecast in the long-term horizon.
Astaris
The Astaris elemental phosphorous plant, located on the western edge of Pocatello,
Idaho, ceased large-scale production in mid-December of 2001. Four months later, in April
2002, the special contract between Astaris and Idaho Power Company was terminated. Since
then, Astaris (now FMC Corporation) has been billed for electric service as a Schedule 19
customer. Therefore, Astaris load since May 1, 2002 as a special contract customer is zero.
Astaris had been the Company’s largest individual customer and in some past years had
averaged nearly 200 average megawatts of load. Today, the Astaris load is less than 4 MW.
Chapter 3 31 Planning Period Forecasts

Table 8 Firm Sales Contracts
Contract Expiration 2004 Average Load

City of Weiser (Idaho) December, 31 2004 6 aMW
City of Colton (California) May 31, 2005 3 aMW
Raft River Rural Electric Cooperative (Nevada) September 30, 2006 6 aMW
Total Firm Sales 15 aMW

Micron Technology
Micron Technology has replaced Astaris as the Company’s largest individual
customer. In the 2004 IRP forecast, electricity sales to Micron Technology are expected to
steadily rise throughout the forecast period. The primary driver of long-term electricity sales
growth at Micron Technology is employment growth in the Electronic Equipment sector as
provided by the 2004 Economic Forecast. The Micron contract allows for capacity expansion
up to 100 megawatts. Presently the Micron load is around 80 aMW.

Simplot Fertilizer
In August of 2002, Simplot Fertilizer closed its ammonia production facility near
Pocatello. The ammonia plant represented about 11 MW, or about one-third of the entire
Simplot load. The ammonia is now being purchased on contract from an outside supplier.
Offsetting the decline is the equipment required to unload and store the ammonia, which
consists of an additional 3 or 4 MW. The total load at Simplot Fertilizer is around 16 aMW
and the peak demand is around 25 MW.
Idaho National Engineering and Environmental Laboratory
The Idaho National Engineering and Environmental Laboratory (INEEL) is the
Department of Energy research facility located in Eastern Idaho northwest of Pocatello. The
INEEL is operated for the Department of Energy by Bechtel BWXT Idaho, LLC. Members
of the LLC are Bechtel National Inc., BWX Technologies Inc., and a consortium of eight
regional universities. The laboratory employs about 8,000 people. Historically, INEEL has
operated several experimental nuclear reactors and generated a significant portion of its
energy needs. Today, the laboratory is a special contract customer of Idaho Power Company
with an average load of around 15 aMW. Peak demand can be nearly 35 MW.
Firm Sales Contracts
Idaho Power currently has three firm sales contracts. The contracts, expiration dates,
and 2004 average load are shown in Table 8.
Chapter 3 32 Planning Period Forecasts

Although Table 8 shows expiration dates for the City of Weiser and the Raft River
Rural Electric Cooperative contracts, it is anticipated that both of the contracts will be
renewed with updated provisions prior to the expiration date. Idaho Power will continue to
evaluate the value of firm sales contracts, but with the exceptions of the City of Weiser and
Raft River Rural Electric Cooperative Inc., Idaho Power has not included the renewal of any
term off-system sales contracts in its load projections.

Hydro Forecast
Hydrologic Baseflow
The representative hydrologic conditions used for analysis within the 2004 IRP (the
50th, 70th, and 90th percentiles) are based on a computed hydrologic record for the Snake River
Basin dating back to 1928. The historical record has been developed by the Idaho
Department of Water Resources (IDWR) for the purpose of obtaining a hydrologic period of
record of sufficient length to validate probability-based decisions. For example, a median
(50th percentile) hydrologic condition based on a 75-year hydrologic period of record is
generally considered more representative of true median conditions than the condition derived
from a 50-year period of record. Table 9 shows the April through July Brownlee inflow
history since 1993. The data reported in Table 9 indicate that in four of the recent years the
Brownlee inflow was less than the 70th percentile planning criterion, and in two of those
years, 1994 and 2001, the flows were less than the 90th percentile planning criterion.
Water management facilities, irrigation facilities, and operations in the Snake River
Basin changed greatly during the 20th century. Therefore, for a hydrologic record to be
meaningful from a planning perspective, the hydrologic record should reflect the current level
of development in the Basin. The process followed by IDWR in developing the hydrologic
record involves modifying the actual historical record to account for development, present
baseflow, current system operations and existing facilities. For example, prior to the late
1940s the primary mechanism for irrigation was flood surface water irrigation. As the
agricultural surface water system, including reservoirs for storage, was developed from the
late 1800s to its height in the 1930s and 1940s, more water was diverted leaving less water in
the Snake River. Over the past 50 years there has been significant conversion from flood
irrigation to sprinkler irrigation, and from surface supplied irrigation to groundwater supplied
irrigation. There has also been a significant additional amount of groundwater irrigated land
put into production over the past 50 years resulting in reduced spring fed contributions to the
river. As a result of these changes over the years, the natural flow hydrograph has been
altered. The timing and volume of the natural flow, in the river and from the springs, has
changed. The changes are built into the historical record to reflect today’s system. IPC uses
the IDWR standardized hydrologic record in the hydro generation modeling performed for the
Company’s Integrated Resource Plan.
Chapter 3 33 Planning Period Forecasts

Table 9 Recent Brownlee Inflow History
Year
April - July
Brownlee Inflow
(MAF)
Rank
Worse than 70th
Percentile Planning
Criterion
Worse than 90th
Percentile Planning
Criterion
1993 6.1 0.40
1994 2.6 0.93 X X
1995 6.8 0.33
1996 8.4 0.16
1997 9.9 0.07
1998 9.0 0.13
1999 8.0 0.20
2000 4.4 0.60
2001 2.4 0.95 X X
2002 3.2 0.81 X
2003 3.6 0.76 X

Part of the process by which the historical record is standardized involves adjusting
the actual flows to a level of baseflow that is representative of the conditions existing today.
Baseflow is defined as that portion of streamflow derived primarily from groundwater
seepage into the stream channel. Observed records suggest that baseflow in the Snake River,
particularly between the Company’s Twin Falls and Swan Falls projects, has been in decline
for several decades. The yearly average flow measured below Swan Falls declined at an
average rate of 43 cubic feet per second (cfs) per year (43 cfs/year) during the period 1960-
2003, and observed streamflow gains between Twin Falls and Lower Salmon Falls, which are
largely attributed to baseflow contribution, declined at a rate of 27 cfs/year over the same
period. A decrease of 43 cfs per year represents the loss of over 31,000 acre-feet of water per
year. The streamflow decline of 43 cfs per year represents a hydro generation loss of
approximately 140 aMW in 2003 as compared to 1960. If the trend continues, the reduction
in hydro generation may reach 170 aMW by 2013.
The observed decline, which continues today, is due to consumptive groundwater
withdrawals and is influenced by extended drought conditions. IDWR has not updated the
standardized hydrologic record since 1992. The implication is that the computed hydrologic
record, on which the representative hydrologic conditions are based, overstates the level of
baseflow existing today and expected in the future. Consequently, the representative
hydrologic conditions used for the Idaho Power Company 2004 Integrated Resource Plan may
also be overstated.
IDWR is in the process of updating the computed hydrologic record. It is anticipated
that the updated record will more accurately reflect the decreased baseflow existing in the
system today and expected in the future. However, depending on the extent to which
baseflow continues to decline and the accuracy of the updated record, it will be necessary in
the future to adjust the level of needed generation to account for this reduction in flow.
Chapter 3 34 Planning Period Forecasts

Generation Forecast
The generation forecast includes existing and committed resources. The output from
the two committed resources, Bennett Mountain (162 MW available in 2005) and the
Shoshone Falls upgrade (60 MW available in 2008) are included in the Idaho Power
Company generation forecast.
Scheduled and forced outages are incorporated in the forecast using historical data.
Idaho Power Company used planned maintenance and traditional maintenance schedules to
estimate scheduled outages. Forced outages were estimated using observed forced outage
rates at the various facilities randomly assigned throughout the planning period. The hydro
facility generation is directly related to the hydro forecast discussed earlier.
Transmission Forecast
Transmission constraints are an important factor in Idaho Power Company’s ability to
reliably serve peak load conditions. Off-system market purchases are the last resort the
Company employs when its own generating resources and firm purchases are inadequate to
meet the load requirements. The transmission constraints on the IPCo system limit the
Company’s ability to employ off-system market purchases for many timeframes and system
conditions.
The transmission analysis requires hourly forecasts for the entire 10-year planning
period for loads and generation levels on the IPCo system. The hourly transmission analysis
is used to quantify the magnitude of off-system market purchases that may be required to
serve the load, and determine if there will be adequate transmission capacity available to
deliver the off-system purchases to the load centers.
From the hourly load and generation forecasts, a determination can be made regarding
the need for, and magnitude of, off-system market purchases needed to serve the loads. The
projected off-system market purchases are summed with all other committed transmission
obligations to determine if the resulting transmission load will exceed the operational limits of
the IPCo transmission constraints.
The analysis assumes all off-system market purchases will come from the Pacific
Northwest. Historically, during Idaho Power Company peak load periods, off-system market
purchases from other areas have often times proven to be unavailable or very expensive.
Many of the utilities to the east and south of Idaho Power Company also experience a summer
peak, and the weather conditions that drive the summer peak are often similar across the
Intermountain and Rocky Mountain West. Because Idaho Power has not been able to rely on
the Rocky Mountain and Intermountain power markets for market purchases, Idaho Power
Company believes that it would not be prudent to rely on imports from the Rocky Mountain
region for planning purposes.
Three different hydro generation/load scenarios are considered in the transmission
analysis:

Chapter 3 35 Planning Period Forecasts

1. Median water/median load
2. Seventieth percentile water and 70th percentile load
3. Ninetieth percentile water and 70th percentile load
The results of the 90th percentile water and 70th percentile load case are given the
most weight in the transmission adequacy analysis, since using the transmission system to
bring in off-system market purchases is the last option available when system conditions are
worse than anticipated.
One difficulty with transmission planning is that while transmission resources are
owned by a specific entity, the transmission resources can be utilized by other parties due to
the open access requirements. Idaho Power Company must reserve the use of its own
transmission resources under open access as well. Often, the Snake River spring water
forecasts are unknown until May or June. By that time it is too late to acquire transmission
with a firm reservation. An additional concern is that the peak time for Idaho Power
Company is July, which coincides with high energy demand in the markets to the east and
south of the Idaho Power Company service territory. Idaho Power Company has experienced
difficulty purchasing energy and acquiring transmission from the south and east during the
July peak period. Based on these concerns, Idaho Power Company believes that the 90th
percentile planning criteria are appropriate for the critical transmission resources.
The 90th percentile planning criteria mean that there is a one-in-ten chance that Idaho
Power Company will face more drastic measures such as curtailing load if attempts to acquire
energy and transmission access from the east and south markets are unsuccessful. Unusual
weather conditions and failures in the California energy market led to extremely high energy
prices throughout the western US during the summer of 2001. Idaho consumers directly felt
the effects of the high prices and Idaho Power initiated an irrigation curtailment program in
response.
The results of the 90th percentile water and 70th percentile load scenario were used to
establish a capacity target for planning purposes. The capacity target identifies the amount of
internal generation or DSM that must be added to the Idaho Power Company system to avoid
transmission overloads.
Fuel Price Forecasts
Coal Price Forecast
The IRP expected coal price forecast is an average of Idaho Power’s spot coal
forecasts for its Valmy and Boardman thermal plants. The plant forecasts are created using
current coal and rail transportation market information and then escalated based on the 2003
Department of Labor Bureau of Labor Statistics forecasts along with the Global Insight 2003
US Power Outlook report. The resulting costs in dollars per MMBtu represent the delivered
cost of coal, including rail costs, coal costs, and use taxes.
Natural Gas Price Forecast
Idaho Power Company does not directly forecast natural gas prices; instead Idaho
Power Company combines industry forecasts. The IRP expected gas price forecast is derived
Chapter 3 36 Planning Period Forecasts

from public and private source forecasts including IGI Resources, NYMEX, PIRA, CERA,
EIA, NWPPC, and US Power Outlook. All source forecasts are converted to nominal dollars
and converted to a Sumas equivalent dollars per MMBtu. Each source forecast is given a
weight and included in a total weighted average to forecast Sumas dollars per MMBtu.
Transportation costs are then added to the weighted average price to develop a delivered
Sumas price in dollars per MMBtu. The transportation costs include Northwest Pipeline fixed
and volumetric charges as well as fuel gas.
The IRP high and low Henry Hub equivalent gas price forecasts were derived using a
private source forecast. The private forecast bracketed a reference case with both a high and a
low gas value. The annual differential was calculated for 2004–2018 and the 2004–2018
trend was used to forecast prices through 2034. The forecasted annual differential was then
applied to the IPCo Henry Hub equivalent gas forecast to generate the high and low forecast
values.
Fuel forecast values are included in the Technical Appendix.
Chapter 3 37 Planning Period Forecasts

Chapter 3 38 Planning Period Forecasts

4. Future Requirements
Beginning with the 2002 IRP, Idaho Power specified a resource adequacy criterion
requiring that new resources be acquired at the time that the resources are needed to meet
forecast energy growth, assuming a water condition at the 70th percentile for hydroelectric
generation.
The 70th percentile means that Idaho Power plans generation based on streamflows
that occur in seven out of ten years on average. Streamflow conditions are expected to be
worse than the planning criteria 30 percent of the time.
In the past, the Western Electricity Coordinating Council resource planning reserve
required Idaho Power to maintain 330 MW of reserves above the forecast peak load to cover
its worst single planning contingency which was defined to be an unexpected loss equal to
Idaho power’s share of two Bridger generation units. At present, WECC has dropped the
planning reserve requirements. The National Electric Reliability Council recently approved
measures requiring the WECC to reinstate some form of planning reserve requirements.
Idaho Power will continue meeting the historical WECC planning reserve requirements under
any planning scenario until replacement planning requirements are in place. Idaho Power’s
current peak load is approximately 3,000 MW, meaning that the 330 MW reserve translates
into a reserve margin of approximately 11 percent.
A 70th percentile monthly water planning differentiates Idaho Power from other
Northwest utilities, which typically plan resources based upon having annual generating
capability sufficient to meet forecast annual energy requirements under critical water
conditions. Critical water conditions are generally defined to be the worst, or nearly worst,
annual water conditions based on historical streamflow records. A summary of other
Northwest utility planning criteria is included in the Technical Appendix.
Using the 70th percentile water-planning criterion produces surpluses whenever
streamflows are greater than the 70th percentile. Temporary off-system sales of surplus
energy and capacity provide additional revenue and reduce the costs to IPC customers.
During months when Idaho Power faces an energy or capacity deficit because of low
streamflow, excessive demand, or for any other reason, Idaho Power plans to purchase off-
system energy and capacity on a short-term basis to meet system requirements.
Low-water (90th percentile) scenarios have been evaluated and included in the 2004
Integrated Resource Plan to demonstrate the viability of IPC’s plan to serve peak and energy
loads under low-water conditions. The evaluations include consideration of IPC’s
transmission capability at times of lower streamflows.
The 90th percentile water and 70th percentile load conditions are used in the
transmission analysis to establish the timing and magnitude of future peaking resources.
Impact of Salmon Recovery Program on Resource Adequacy
The December 1994 Amendments to the Northwest Power Planning Council’s fish
and wildlife program and the biological opinions issued under the Endangered Species Act
(ESA) for the four lower Snake River federal hydroelectric projects call for 427,000 acre-feet
of water to be acquired by the federal government from willing lessors upstream of Brownlee
Chapter 4 39 Future Requirements

Reservoir. The acquired water is then to be released during the spring and summer months to
assist ESA-listed juvenile salmonids (spring, summer, fall Chinook and steelhead) migrating
past the four federal hydroelectric projects on the lower Snake River. In the past, water
releases from Idaho Power’s hydroelectric generating plants have been modified to cooperate
with the federal efforts. Idaho Power also adjusts flows in the late fall of each year to assist
with the spawning of fall Chinook below the Hells Canyon Complex.
Because of the practical, physical, and legal constraints that federal interests must
deal with in moving 427,000 acre-feet of water out of Idaho, Idaho Power has pre-released, or
shaped, a portion of the acquired water with water from Brownlee Reservoir and later refilled
the reservoir with water leased under the federal program. At times, Idaho Power has also
contributed water from Brownlee to assist with the federal efforts to improve salmonid
migration past the lower Snake federal projects.

Water Planning Criteria for Resource Adequacy
Idaho Power Company has an obligation to serve customer loads regardless of the
water conditions that may occur. In the past, when water conditions were at low streamflow
levels, IPC relied on market purchases to serve customer loads. Historically, the Idaho Power
Company plan was to acquire or construct resources that would eliminate expected energy
deficiencies in every month of the forecast period whenever median or better water conditions
existed, recognizing that when water levels were below median, Idaho Power Company
would rely on market purchases to meet any deficits. When water levels were greater than
median, Idaho Power Company would sell the surplus power in the regional markets.
In connection with the market price movements to historical highs during the energy
crisis of 2000 and 2001, Idaho Power Company reevaluated the planning criteria as part of the
2002 IRP. The public, the Idaho Public Utilities Commission, and the Idaho legislature all
suggested that Idaho Power placed too great a reliance on market purchases based upon the
IRP planning criteria. Greater planning reserve margins or the use of more conservative water
planning criteria were suggested as methods requiring Idaho Power to acquire more firm
resources and reduce the likelihood of market purchases.
Due to the public input to the planning process, Idaho Power Company developed a
resource plan based upon a lower-than-median level of water. Beginning with the 2002
resource plan, Idaho Power Company began using the 70th percentile water conditions and
load conditions for resource planning. The 2004 Integrated Resource Plan is the second
resource plan wherein Idaho Power Company is using the 70th percentile water and load
conditions.
Historically, Idaho Power has been able to reasonably plan for the use of short-term
power purchases to meet temporary water-related generation deficiencies on its own system.
Short-term power purchases have been successful because Idaho Power customers typically
have summer peaking requirements while the other utilities in the Pacific Northwest region
have winter peaking requirements
Although Idaho Power has transmission interconnections to the Southwest, the
Northwest market is the preferred source of purchased power. The Northwest market has a
Chapter 4 40 Future Requirements

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. The markets south and east of the Idaho Power system
can be very limited during summer peak conditions.
Under the low water and high-load conditions, projected peak-hour loads are likely to
cause peak-hour transmission overloads from the Pacific Northwest and the transmission
overloads may present significant difficulties as early as the summer of 2007 (transmission
adequacy is discussed later in this chapter). Based on the low-water analyses, Idaho Power
Company believes that it will be difficult to acquire and deliver short-term resources from the
Pacific Northwest in amounts sufficient to satisfy peak-hour deficiencies during low-water
conditions.
Recent experiences indicate that, even when Northwest power is available, the short-
term prices can be quite high and volatile. The price risk has led to the development of the
Risk Management Policy discussed in the Introduction. The Risk Management Policy
represents collaboration of Idaho Power, the IPUC staff, and interested customers in
Commission Case IPC-E-01-16.
The primary uncertainties associated with planned short-term power purchases are the
availability of adequate Northwest to Idaho transmission capacity to allow imports at the
times when needed, and uncertainty concerning the market prices of the purchases.
Planning Scenarios
70th Percentile Water, 70th Percentile Load (Energy)
The main planning scenario for determining the need for energy resources assumes
70th percentile water and 70th percentile load conditions. In purely statistical terms, if the two
probabilities are independent, then one of the two conditions, either poor water conditions or
high load conditions, can be expected in about half of the years (0.7 * 0.7 = 0.49).
During the summer peak periods, low water conditions are more problematic than are
high load conditions. The variability around the summer peak load is considerably less than
the variability associated with water conditions. For example, April through July Brownlee
inflow can range from under 2 million acre-feet to nearly 13 million acre-feet. The summer
high temperature ranges from 98 to 111, meaning that hot summer temperatures are more
certain than are water conditions. Low water conditions are likely to be the more significant
planning factor.
Idaho Power Company makes resource planning decisions based on the 70th
percentile forecasts. Alternative forecasts are included in the 2004 Integrated Resource Plan
to help understand the boundaries of the main forecast. Idaho Power presents a 90th percentile
hydrological forecast to suggest what might happen in extremely dry years. A median water
and median load forecast is also included. The primary purpose for including median forecast
is to allow a historical comparison of the 2004 Integrated Resource Plan with earlier Idaho
Power Company resource plans. The median forecast is no longer used for resource planning,
although the median forecast is used to set retail rates and avoided-cost rates during
regulatory proceedings.
Chapter 4 41 Future Requirements

Figure 4 indicates that when 70th percentile water and 70th percentile load conditions
occur, energy deficiencies begin in December 2009. The initial deficiencies are
approximately 6 aMW and increase to approximately 163 aMW by December 2013. Summer
deficiencies in July are expected to increase from approximately 7 aMW in 2004 to
approximately 340 aMW in 2011.
70th Percentile Water, 70th Percentile Load (Peak)
Figure 5 provides the peak load deficiencies corresponding to the 70th percentile
water and 70th percentile load scenario, which is primarily used to identify the need for energy
resource acquisition. With 70th percentile water and 70th percentile load conditions, summer
peak-hour energy deficiencies occur starting in June 2004 at 280 MW and increase to 976
MW in July 2013. Winter peak-hour deficiencies occur beginning in December 2004 at 86
MW and increase to 463 MW in December 2013. By 2008, peak-hour deficiencies occur in
seven months – May through September, and November and December. The peak-hour
deficiencies continue to increase throughout the planning period reaching a maximum of
nearly 1,000 MW in July 2013.
90th Percentile Water, 70th Percentile Load (Energy)
Figure 6 illustrates that under the 90th percentile water, 70th percentile load scenario,
summer energy deficiencies occur in all years starting in May 2004, with 10 aMW, and
increasing to 529 aMW in July 2013. Winter energy deficiencies occur in most years starting
in December 2004 at 55 aMW and increasing to 261 aMW by December 2013. By 2008,
deficiencies occur in 7 of 12 months; by 2011, all months are deficit under 90th percentile
water conditions.
90th Percentile Water, 70th Percentile Load (Peak)
The primary scenario for determining the need for peak-hour, or capacity, resources is
the 90th percentile water and 70th percentile load scenario. The pattern of deficiencies for the
90th percentile water, 70th percentile load scenario is similar to the pattern of deficiencies for
the 70th percentile water, 70th percentile load scenario, only more severe. Peak-hour
deficiencies in the peak months are typically 40 to 60 MW greater because of changes in
water conditions. Monthly peak-hour surpluses and deficiencies for the 90th percentile water,
70th percentile load growth are shown in Figure 7.
Chapter 4 42 Future Requirements

Figure 4 Monthly Energy Surplus / Deficiency
70th Percentile Water and Load, Existing and Committed Resources

-600
-400
-200
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W

Figure 5 Monthly Peak-hour Surplus / Deficiency
70th Percentile Water and Load, Existing and Committed Resources
-1400
-1200
-1000
-800
-600
-400
-200
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW

Chapter 4 43 Future Requirements

Figure 6 Monthly Energy Surplus / Deficiency
90th Percentile Water, 70th Percentile Load, Existing and Committed Resources

-600
-400
-200
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W

Figure 7 Monthly Peak-hour Surplus / Deficiency
90th Percentile Water, 70th Percentile Load, Existing and Committed Resources
-1400
-1200
-1000
-800
-600
-400
-200
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW

Chapter 4 44 Future Requirements

Figure 8 Monthly Energy Surplus / Deficiency
Median Water, Median Load, Existing and Committed Resources

-600
-400
-200
0
200
400
600
800
1000
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
aM
W

Figure 9 Monthly Peak-hour Surplus / Deficiency
Median Water, Median Load, Existing and Committed Resources

-1400
-1200
-1000
-800
-600
-400
-200
0
200
400
600
800
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW

Chapter 4 45 Future Requirements

Transmission Adequacy
Prior to 2000, Integrated Resource Plans often emphasized acquisition of energy
rather than construction of generating resources to satisfy load obligations. Transmission
limitations were not a major impediment to Idaho Power’s purchasing power to meet its
service obligations. Idaho Power Company recognized that transmission constraints began to
place limits on purchased power supply strategies starting with the 2000 Integrated Resource
Plan. To better assess the adequacy of the power supply and the transmission system, Idaho
Power Company analyzed transmission conditions for all hours of the ten-year planning
period as part of the 2004 Integrated Resource Plan.
The transmission adequacy analysis reflects Idaho Power Company’s contractual
transmission obligations to provide wheeling service to the BPA loads in Southern Idaho.
The BPA loads are typically served with a combination of energy and capacity from the
Pacific Northwest and several United States Bureau of Reclamation projects located in
Southern Idaho. The contractual transmission obligations are detailed in four Network
Service Agreements under the Idaho Power Open Access Transmission Tariff.
Analyzing the transmission limitations during the peak hour of each month allows
Idaho Power to assess the adequacy of the transmission system to serve Idaho Power and the
BPA customers with energy from the Pacific Northwest. The BPA loads in July 2004 were
forecast to be approximately 325 MW. The BPA loads were modeled as being served by a
combination of approximately 55 MW of Southern Idaho USBR generation and
approximately 270 MW of wheeled power from the Pacific Northwest.
The results of the transmission analyses indicate that the Northwest to Idaho path is
most likely to face transmission constraints in low water years. The Brownlee-East path is
most likely to face constraints during normal to high water years. The transmission analysis
shows monthly peak-hour transmission deficiencies when the Idaho Power resource
deficiencies are met by energy purchases from the Pacific Northwest at the same time the
transmission system is delivering energy to the BPA customers in Southern Idaho.
Figure 10 represents the monthly peak-hour transmission deficiencies for a median
water and median load condition. Assuming that Bennett Mountain is available in June 2005,
the first peak-hour transmission deficiency from the Pacific Northwest occurs in July of 2007
and has a magnitude of approximately 80 MW. July peak transmission deficiencies for
subsequent years typically increase by approximately 90 MW per year.
Figure 11 represents the monthly peak-hour transmission deficiencies for a 70th
percentile water and 70th percentile load condition. The magnitude of the transmission
deficiency is 75 MW in July 2007. Transmission deficiencies for subsequent July peaks
typically increase by approximately 80 MW per year. By 2013, transmission deficiencies
begin to appear in May.
Figure 12 represents the monthly peak-hour transmission deficiencies for a 90th
percentile water and 70th percentile load condition – the conditions used in transmission
planning. The 90th percentile water and 70th percentile load conditions presented in Figure 12
are used to establish the timing and magnitude of future peaking resources. The magnitude of
the transmission deficiencies is 54 MW in July 2004. Assuming that the Bennett Mountain
Chapter 4 46 Future Requirements

Plant is available in June 2005, the July peak-hour deficiency is reduced to 3 MW.
Transmission deficiencies for subsequent July peak conditions increase by approximately 90
MW per year. By 2013 transmission deficiencies occur from May through September and
reach nearly 800 MW.
Figure 10 Monthly Peak-hour NW Transmission Deficit
Median Water / Median Load
-1000
-800
-600
-400
-200
0
200
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW

Chapter 4 47 Future Requirements

Figure 11 Monthly Peak-hour NW Transmission Deficit
70th Percentile Water, 70th Percentile Load, Existing and Committed Resources
-1000
-800
-600
-400
-200
0
200
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW

Figure 12 Monthly Peak-hour NW Transmission Deficit
90th Percentile Water, 70th Percentile Load, Existing and Committed Resources
-1000
-800
-600
-400
-200
0
200
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW

Chapter 4 48 Future Requirements

5. Potential Resource Portfolios
Resource Cost Analysis
The individual costs of a variety of potential supply-side and demand-side resources
were analyzed to develop potential resource portfolios. The results of the resource cost
analysis were used to analyze different resource combinations that could satisfy Idaho
Power’s energy needs. The results of the resource cost analysis are shown in Figure 13 and
14. The levelized costs shown for each resource represent the estimated annual revenue
requirement the utility would require to construct and operate an energy resource over a
period of 30 years. Resource costs are presented as:
− Levelized fixed cost per kilowatt per month of installed capacity, and
− Overall levelized cost per megawatt hour of expected plant or program output, given
assumed capacity factors.
The general economic parameters used in the resource cost analysis are
1. An O&M escalation rate of 2.52 percent, based on an annual trend of consumer price
inflation.
2. A discount rate of 7.20 percent based on Idaho Power’s weighted average cost of
capital at the end of 2003 and rate of return on common equity requested by the
company in the 2003 general rate case filing with the Idaho Public Utility
Commission.
3. An assumed 30-year book life for all supply-side resources, and a 30-year program life
for each demand-side resource.
Since completing the portfolio financial analysis, Idaho Power has received Order
29505 from the Idaho Public Utilities Commission. Order 29505 calls for an allowed return
on common equity (ROE) of 10.25 percent, down from 11.2 percent the company proposed in
the filing within the Commission. The resulting after-tax discount rate is 6.7 percent using the
10.25 percent return on common equity. Idaho Power Company analyzed the lower discount
rate and recognized that the lower rate will have an equal effect on all the resource portfolios
and the lower discount rate will not affect the portfolio ranking.

Chapter 5 49 Potential Resource Portfolios

Figure 13 Supply-Side Resources and Demand-Side Programs
30-Year Nominal Levelized Fixed Costs
0 5 10 15 20 25 30 35 40
Idaho - Geothermal (50 MW)
Valmy Unit 3 (130 MW)
Industrial Efficiency (12 MW)
Commercial Efficiency Existing (16
Residential Efficiency Existing (20 MW)
Idaho Pulverized Coal (500 MW)
Commercial Efficiency New (4 MW)
Idaho Wind (100 MW)
Combined Heat & Power (5.5 MW)
Danskin CC Conversion ( 69 MW)
Residential Efficiency New (9 MW)
Irrigation Efficiency (29 MW)
Idaho CCCT (540 MW)
Danskin Adv CT 3rd Unit (43.7 MW)
A/C Demand Response (45 MW)
Bennett Mtn CT 2nd Unit (162 MW)
Irrigation Demand Response (30 MW)
$/kW/Mo
Capacity Fixed O&M

Figure 14 Supply-Side Resources 30-Year Nominal Levelized Cost of Production
0 10 20 30 40 50 60 70 80 90 100
Bennett Mtn CT 2nd Unit (162 MW)
Danskin Adv CT 3rd Unit (43.7 MW)
Danskin CC Conversion ( 69 MW)
Commercial Efficiency New (4 MW)
Idaho CCCT (540 MW)
Valmy Unit 3 (130 MW)
Idaho Pulverized Coal (500 MW)
Residential Efficiency New (9 MW)
Residential Efficiency Existing (20 MW)
Combined Heat & Pow er (5.5 MW)
Idaho - Geothermal (50 MW)
Irrigation Efficiency (29 MW)
Commercial Efficiency Existing (16 MW)
Idaho Wind (100 MW)
Industrial Efficiency (12 MW)
$/MWh
Capacity Fixed & Variable O&M Fuel Emission Adders

Chapter 5 50 Potential Resource Portfolios

Idaho Power’s resource needs change throughout the planning period. Peaking
resources are needed early in the planning period to serve summertime peak loads. As the
customer load continues to grow, and resources to supply that load growth are needed for
more and more hours of the year, it becomes more cost effective for Idaho Power Company to
add baseload resources.
Resource cost inputs, gas and coal forecasts, and other significant financing and
operating assumptions are shown in the Technical Appendix.
30-Year Levelized Fixed Cost per Kilowatt per Month
The capacity cost portion of a supply-side resource levelized fixed cost includes the
components of cost of capital, depreciation, and state and federal income taxes. The
construction cost figures used to calculate annual resource capacity charges include estimated
transmission infrastructure and upgrade costs based on the sites Idaho Power considered to be
likely locations for each resource. Supply-side resource construction costs also include
Allowance for Funds used During Construction (AFUDC – capitalized interest). The non-fuel
operation and maintenance (O&M) portion of each supply-side resource’s levelized fixed cost
includes estimates for property taxes and property insurance premiums.
The levelized cost for each of the demand-side resource options includes annual
administrative and marketing costs of the program, annual incentive or rebate payments (for
the demand-response programs), and annual participant costs (for the energy-efficiency
programs). The annual fixed cost streams for each supply-side and demand-side resource are
summed and levelized over an assumed 30-year life. The levelized costs are presented as
dollars per kilowatt of plant capacity per month. Figure 13 provides a combined ranking of
all of the supply-side and demand side resource options, in order of lowest levelized fixed
cost per kilowatt per month.
30-Year Levelized Cost of Production
The levelized cost of production figures presented for the supply-side resources
contain the same carrying cost, and non-fuel O&M components listed in the nominally
levelized fixed cost of operation analysis detailed previously. In addition, the levelized
variable cost components including fuel and variable O&M expenses for each supply-side
resource are included in the estimates. Estimated capacity factors, based on generation
technology and other known engineering factors, are applied to the estimated generation
output of each supply-side resource to determine the annual overall MWh output.
The annual MWh output (energy savings) for each of the demand-side resource
options is determined by multiplying its annual peak MW capacity by the total number of
hours in the year the resource is expected to provide the energy savings. The program costs
are presented as levelized on an annual basis for the sake of comparison. Both fixed and
variable annual cost streams for each supply-side and demand-side resource are summed and
levelized over an assumed 30-year life. The levelized costs are presented as dollars per
annual megawatt hour of resource output for supply side resources, or program savings for
demand-side resources. Figure 14 shows the combined ranking of all of the supply-side and
demand-side resource options ranked by the levelized cost of production.
Chapter 5 51 Potential Resource Portfolios

Supply-Side Resource Costs
The fixed-costs of production are shown in Figure 13. Figure 14 shows the 30-year
supply-side nominally levelized costs for the same resources. Based on the 30-year costs of
production, Idaho wind is the leading baseload supply-side resource. For an energy resource,
Idaho wind also appears quite favorable when the fixed costs are considered as shown in
Figure 13. Coal-fired generation falls in the middle of the list when considering either fixed-
cost or operating costs.
Simple-cycle combustion turbines similar to Idaho Power Company’s Danskin and
Bennett Mountain plants are the lowest cost peaking resource based upon low fixed costs.
The simple-cycle combustion turbines do have high operating costs, but the operating costs
are not as important when the resource is only used a few hours per year to meet peak
demand.

Supply-Side Resource Options
Included below are brief descriptions of the supply-side resources considered in the
2004 Integrated Resource Plan. The estimated power supply costs for each resource listed
below were analyzed and tested using the Aurora Electric Market model. In addition, the
demand-side resource options described later in this chapter were also considered in the
power supply costs analysis.
Bennett Mountain CT 2nd Unit
The costs for the second Bennett Mountain unit are based on a 162 MW, simple cycle
combustion turbine generator identical to Bennett Mountain Unit 1. The gas delivery
infrastructure planned for Bennett Mountain Unit 1 can be expanded for one additional unit of
similar size. Transmission modifications and the fuel expansion would be required and are
included in the cost estimates.
Danskin CT Advanced CT Additional Units
The costs for additional units at the Danskin Plant are based on 43.7 MW, aero-
derivative combustion turbines operating in simple cycle mode. The existing natural gas
delivery infrastructure at Danskin is adequate for two additional units. Transmission
modifications and expansion would be required and are included in the cost estimates.
Danskin CC Expansion – Incremental
Expanding the Danskin generating facility to include a heat recovery steam generator
(HRSG) connected to the steam turbine-generator to take advantage of the exhaust heat from
the two existing Danskin combustion turbines. The expansion would increase the Danskin
facility capacity by 69 MW and would permit the facility to operate as a baseload plant. The
existing natural gas delivery infrastructure at Danskin is adequate for the addition.
Transmission modifications and expansion would be required and are included in the costs.
Chapter 5 52 Potential Resource Portfolios

Combustion Turbine Advantages and Disadvantages
Combustion Turbine Advantages
− Low capital cost
− Proven technology
− Short construction period
− Modular, can be built in incremental units
− Relatively low CO2 emissions for a thermal resource
− Well-suited to peaking operations
Combustion Turbine Disadvantages
− Expensive to operate
− High fuel price volatility
− Poorly suited to baseload operation

Combined Heat & Power
Idaho Power Company can form a partnership with some industrial customers by
installing Combined Heat & Power (CHP) generating units at industrial facilities that have
existing steam requirements. A common type of CHP system uses a combustion turbine
generator to produce electrical power and also produces steam by installing a heat recovery
steam generator in the exhaust path of the combustion turbine. The electrical power would be
delivered through the Idaho Power distribution and transmission system and the steam would
be used to meet the industrial facility requirements. The cost for combined heat and power
units are based only on the electrical generating portion of the facility. It is undetermined
whether the steam would be sold to the industrial facility or if the industrial facility would
own the steam-generating portion. The cost estimates for combined heat and power reflect a
typical project. Actual costs are highly dependent on the actual plant configuration as well as
the contract and ownership agreements.
Combined Heat and Power Advantages
− Increases overall efficiency of generation system
− Fuel is already used by the industrial processes
− Typically close to load centers requiring fewer transmission upgrades
− Shared operation with customers
Combined Heat and Power Disadvantages
− Subject to natural gas price volatility
− Shared operation with customers
− Actual costs and ownership arrangements are unknown
Chapter 5 53 Potential Resource Portfolios

Geothermal
Idaho Power Company has received inquiries to construct geothermal generating
plants located within, or near to, the Idaho Power service territory. The costs are based on
figures provided as estimates from two Idaho-based geothermal development companies. The
costs include electrical transmission necessary to interconnect the facility to the Idaho Power
transmission system. The most promising geothermal resources are located in Eastern Idaho
and it is assumed a geothermal generating plant would be located in Eastern Idaho.
Delivering the energy to the Idaho Power Company load center in the Treasure Valley will
require significant upgrades to the Borah-West and Midpoint-West transmission paths.
Geothermal Advantages
− Renewable resource
− No CO2 emissions
− Possible production tax credits
Geothermal Disadvantages
− Unproven resource in Idaho
− Unknown operating cost
− Toxic compounds dissolved in water may require disposal

Valmy Unit 3
Idaho Power Company can expand the generation capacity at the Valmy plant in
Northern Nevada by installing a third generating unit. The costs for an additional coal-fired
generating unit at Valmy are based on Idaho Power Company 50 percent ownership of a 260
MW generator. It is assumed the other half of the unit ownership would be assigned to Sierra
Pacific Power Company – the operator of the Valmy project. The costs include the
substantial electrical transmission expansion required to deliver 130 MW to the Idaho Power
system. The Valmy plant infrastructure was designed for potential expansion.
Pulverized Coal
Idaho Power could construct a new 500 MW pulverized-coal fired generating facility
somewhere within the Idaho Power Company service territory. Costs for the coal-fired
generating unit are based on internally generated cost estimates based on industry quotes and
the US Department of Energy Annual Energy Outlook. The costs include a substantial
electrical transmission expansion. It is assumed that the coal will be delivered to the plant by
rail.
Chapter 5 54 Potential Resource Portfolios

Coal Advantages and Disadvantages
Coal Advantages
− Low fuel cost
− Low fuel price volatility when compared to natural gas
− Low operating cost
− Proven technology
− Well-suited to baseload operations
Coal Disadvantages
− High CO2 emissions
− High capital cost
− Community acceptance can be an issue
− Poorly-suited to peaking operations
Wind
Idaho Power Company could construct a wind based generating plant located near the
Idaho Power service territory. Wind cost estimates are based on data provided in the DOE
Annual Energy Outlook, data from the Northwest Power and Conservation Council, data
provided by wind developers, as well as internal Idaho Power estimates. The costs include
electrical transmission necessary to connect the facility to the Idaho Power transmission
system. The most promising wind resources are located in Eastern Idaho and it is assumed
the wind turbines would be located in Eastern Idaho. Delivering the energy to the Idaho
Power Company load center in the Treasure Valley will require significant upgrades to the
Borah-West and Midpoint-West transmission paths.
Wind is an intermittent seasonal resource in many areas including the prospects in
Eastern Idaho. To estimate wind resource output, Idaho Power used a combination of data
from wind developers and the Northwest Power and Conservation Council. Wind output was
estimated for three time periods; annual, monthly, and hourly during peak hours in July. The
estimate used for annual energy output is a 35 percent capacity factor. The 35 percent
capacity factor means that a wind project with a nameplate capacity of 100 MW will produce
an average of 35 MW over the course of a year. Monthly energy output was derived from the
normalized monthly wind energy distribution for areas characterized as Basin and Range
(which includes southern Idaho) in the Northwest Power and Conservation Council’s wind
resource characterization paper. The NWPC distribution is included as part of the Technical
Appendix.
Wind output during peak hours in July was based on actual data provided by a wind
developer for a specific project. The data indicate that, during July between the hours of 4:00
PM and 8:00 PM, a 100 MW wind project will produce 5 MW or more 70 percent of the time.
Chapter 5 55 Potential Resource Portfolios

However, the wind data also indicate that the project will produce 5 MW or less 30 percent of
the time. Based on the wind data, Idaho Power assumes that a 100 MW wind project would
provide 5 MW of capacity during summer peak hours.
If a number of wind projects are developed with sufficient geographic dispersion,
then it is possible that the amount of peak-hour summertime capacity provided by projects
may increase due to the geographic dispersion. Wind capacity values will be revisited when
actual wind project data become available.

Wind Advantages
− Renewable resource
− No fuel cost
− No CO2 emissions
− Moderate capital cost
− Low operating cost

Wind Disadvantages
− Unproven resource in Idaho
− Uncertain availability
− May require additional capital expense for backup generation
− Costs may be distorted with Production Tax Credits
− Future of Production Tax Credits is unknown

Demand-Side Management and Pricing Options
Idaho Power Company has worked with the Energy Efficiency Advisory Committee
and outside consultants to identify potential demand-side programs that may be cost-effective.
Potential programs were identified in all four major customer classes – residential,
commercial, irrigation, and industrial. Potential DSM programs and the program size in MW
are identified in Table 10.
Idaho Power analyzed a number of DSM options through a pre-screening analysis and
then used the Aurora Electric Market Model to determine how each option impacts the Idaho
Power Company power supply costs. The pre-screening analysis compared estimated
program costs and hourly impacts to a set of alternative hourly costs. The alternative hourly
costs represented both heavy and light load market purchase estimates as well as gas-fired
peaking generation costs. The set of alternative hourly costs was used as a pre-screen in order
to represent the value of summer peaking resources when designing potential DSM resource
options. The pre-screening analysis resulted in eight DSM options – six energy efficiency
options and two demand response – that had benefit to cost ratios greater than 1.0 (static
analysis).
Chapter 5 56 Potential Resource Portfolios

Table 10 Idaho Power Company Potential Demand-Side Programs
Demand Response Programs:
− Irrigation Demand Response (30 MW on peak)
− Air Conditioning Demand Response (45 on peak MW)
Energy Efficiency Programs:
− Commercial Efficiency, Existing Construction (16 MW on peak, 10 aMW energy)
− Commercial Efficiency, New Construction (4 MW on peak, 1 aMW energy)
− Industrial Efficiency (12 MW on peak, 11 aMW energy)
− Residential Efficiency, Existing Construction (20 MW on peak, 10 aMW energy)
− Residential Efficiency, New Construction (9 MW on peak, 2 aMW energy)
− Irrigation Efficiency (29 MW on peak, 7 aMW energy)

The energy and capacity estimates for the demand response programs and energy
efficiency programs outlined in Table 10 identify the expected returns of the fully installed
10-year programs. Since implementation is not planned to start until 2005, there will only be
nine years of program performance included during the 2004-2013 planning period of the
2004 Integrated Resource Plan. The nine-year performance period produces a small
difference between the results expected at the end of the planning period in 2013 and the
results expected after a full 10 years of program operation. The top four energy programs are
expected to provide 48 MW of peak reduction by 2013. The same four programs are expected
to provide an additional 6 MW of peak reduction in 2014, bringing the total peak reduction to
54 MW after ten years of program performance in 2014. Because the 2004 IRP only
addresses the 2004-2013 planning period, the 48 MW of peak reduction achieved by 2013 is
referred to throughout the remainder of the 2004 Integrated Resource Plan.
Idaho Power then constructed a number of resource portfolios containing a
combination of supply and demand side resources that were analyzed with the Aurora model
(dynamic analysis). The purpose of the Aurora analysis was to identify the hourly impacts of
the DSM options on Idaho Power’s simulated power supply costs. Because of the difficulty
of modeling the two demand response options in Aurora, Idaho Power evaluated the impacts
of the two demand response programs outside of the Aurora model – comparing the
program’s capacity costs to those of supply-side peaking resources (Figure 13). Both demand
response options were determined to be cost effective based on their dispatchability and peak
benefits. Each of the six energy efficiency options was analyzed individually to determine the
impact on the present value of power supply costs for a given portfolio. In the analysis, all six
energy efficiency options showed that power supply costs were reduced when each DSM
option was added to the portfolio.
In order to determine which of the six energy efficiency options should be included in
the finalist portfolios, Idaho Power looked at the 30-year present value of the reduction in
Chapter 5 57 Potential Resource Portfolios

power supply costs (benefit), and the present value of the DSM option’s Total Resource Cost
(cost), and developed benefit to cost ratios derived from the Aurora analysis. The resulting
ranking of the six energy efficiency options based on the 30-year benefit to cost ratios is:
1. Commercial New Construction
2. Irrigation Efficiency
3. Industrial Efficiency
4. Residential New Construction Efficiency
5. Commercial Existing Construction Efficiency and
6. Residential Existing Construction Efficiency.
In addition to the two demand response options, Idaho Power Company chose to
include the four highest-ranking energy efficiency options. The top four were selected for
two reasons. First, it was felt that although the two lowest ranking options did have a benefit
to cost ratio over one, that better options may be identified through the ongoing energy
efficiency assessment analysis. The second reason for implementing the top four energy
efficiency programs is that it will be an operational challenge to implement six large programs
in the same year as indicated by the Action Plan. Idaho Power Company believes it would be
prudent to concentrate its efforts on the four top programs. The energy efficiency assessment
analysis, by Quantum Consulting, will be finished this fall and will provide more information
to evaluate the energy efficiency programs. Additional details on the analysis are included in
the Technical Appendix.
The demand-side programs and supply side resources are compared in a combined
resource stack as shown in Figure 13 and Figure 14. Figure 13 and Figure 14 show that
several demand-side programs compare favorably with traditional thermal generation. The
attributes of the programs and resources and their contribution to the resource portfolio are
fully discussed in Chapter 6 as well as the Technical Appendix.
Demand-Side programs reduce demand and energy at the point of consumption.
Transmission and distribution losses are not a factor in DSM programs. In order to accurately
compare DSM programs with supply-side resources, the energy and capacity estimates from
the demand-side programs were increased by 10 percent to account for the losses that would
occur if the energy and capacity were remotely generated by supply-side resources.
Idaho Power Company proposed seasonal rates as part of the 2003 General Rate Case
filed with the Idaho Public Utilities Commission (IPC-E-03-13) because the cost to serve
customers during the summer months is greater than during the remainder of the year and
Idaho Power Company believes that electric rates should reflect the actual cost of service.
Idaho Power Company proposed that the energy rate for residential customers should be
25 percent greater during the summer months than non-summer months. The Idaho PUC
ultimately approved a summer rate 12.6 percent greater than the base rate for all energy
greater than 300 kWh per month (Idaho PUC Order 29505). Seasonal rates are a new pricing
system for Idaho Power customers and the impacts of the seasonal rates have not been
included in the 2004 Integrated Resource Plan. Customer billing data gathered during the
summers of 2004 and 2005 will be used to assess the impact of seasonal rates on
consumption.
Chapter 5 58 Potential Resource Portfolios

Demand-side measures and energy conservation measures are often seen as
synonymous. Unfortunately, generic energy conservation programs are unlikely to be
sufficient to meet the peak deficiencies facing Idaho Power during the near term of this
resource plan. Specific demand-side measures and pricing options that target peak-hour
demand reduction are more likely to address the peak deficiencies facing Idaho Power
Company. Idaho Power Company has analyzed both energy efficiency and peak-reduction
demand-side measures in the 2004 Integrated Resource Plan.
Presently, Idaho Power Company has a pilot residential air conditioning program and
nearly 200 residential customers have voluntarily enrolled in the program. The program will
be expanded to another 300 residential customers this summer. During times of extreme
need, such as during the summer peak, Idaho Power briefly interrupts program participant’s
air conditioners. Interruption periods are commonly 15 minutes or less. Idaho Power
Company has divided the program participants into two groups, and by alternately
interrupting each group, the group air conditioning demand can be reduced by half.
It is interesting to note that Idaho Power Company adds almost 10,000 residential
customers each year and most of these new customers have air conditioning. A simple
analysis suggests that Idaho Power Company would have to enroll 20,000 customers in the air
conditioning cycling program each year to maintain residential air condition demand at the
current level.
Several programs identified by the EEAG appear to have promise. Due to the nature
and timing of the projected peak deficits and transmission overloads, conservation, demand-
side measures, and pricing options must be carefully designed and targeted to cost-effectively
address the projected deficits.
Idaho Power anticipates that some of the energy efficiency and demand-response
programs will be conducted through a competitive process using requests for proposals.
Additionally, Idaho Power intends to have the effectiveness of the programs assessed using an
independent evaluation process, again likely conducted using requests for proposals.
Social Costs
All electric power resources have costs, benefits, and impacts beyond the construction
and operating costs that are included in the price of electricity. The non-internalized costs
include the air pollution and natural resource depletion associated with thermal generation, the
effects on aquatic life and recreation associated with hydroelectric dams, and the aesthetic and
bird mortality issues associated with renewable wind power.
Order 93-695 from the Oregon Public Utility Commission specified costs associated
with the level of carbon dioxide (CO2), nitrogen oxides (NOx), and total suspended particulate
(TSP) emissions from new thermal generating plants. SO2 emission costs are included in the
calculation of direct utility costs through modeling of the emission allowance system
established by the Clean Air Act. The sensitivity of the resource portfolio to the externality
costs specified by the OPUC in Order 93-695 has been investigated as part of the portfolio
analysis (NOx, TSP, and CO2,). The OPUC order specified costs in 1990 dollars and the costs
have been escalated to 2004 dollars for the Integrated Resource Plan.
Chapter 5 59 Potential Resource Portfolios

Table 11 Idaho Power Company
Externality Cost Ranges for Thermal Plant Emissions
Combinations of NOx, TSP, and CO2 Cost Levels in Dollars per Ton
Emission Level 1 Level 2 Level 3 Level 4 Level 5 Level 6
NOx $2,460 $2,460 $2,460 $6,151 $6,151 $6,151
TSP $2,460 $2,460 $2,460 $4,921 $4,921 $4,921
CO2 $12.30 $30.76 $49.21 $12.30 $31.76 $49.21

Table 11 shows the six sets of social cost additions identified in the OPUC order. The
order states that each utility should conduct its sensitivity studies with at least one of these six
combinations of social costs. Idaho Power’s preliminary analysis indicated that the CO2 cost
was the most significant of the three (NOx, TSP, and CO2). Idaho Power conducted
sensitivity studies at three different CO2 cost levels – $0 per ton, $12.30 per ton, and $49.21
per ton, escalating at 2.5 percent per year. TSP and NOx costs were held constant in all three
studies at $2460 per ton and $3000 per ton respectively.

The social costs shown in Table 11 do affect the resource and program choices. Coal-
fired generation is particularly sensitive to externality costs. The CO2 costs in dollars per ton
can be roughly translated into equivalent dollars per MWh. For example, a CO2 cost of $12
per ton would roughly translate into $12 per MWh for a coal-fired plant, $5 per MWh for a
combined cycle plant, and $7 per MWh for a combustion turbine. The values shown in
Figure 13 and Figure 14 indicate that an externality costs have the potential to affect the
relative position of coal-fired generation in the resource portfolio. Coal-fired generation
resources are long-lived assets and Idaho Power and its customers face significant long-term
price uncertainty with respect to social costs. Portfolio risk is presented in Chapter 6.
Additional details on the ranking of the portfolios under the three different CO2 cost scenarios
are presented in the Technical Appendix.
Resource Portfolios
Twelve different portfolios were analyzed as part of the 2004 Integrated Resource
Plan. Each portfolio will fully meet the Idaho Power Company projected monthly energy
needs under the 70th percentile water and 70th percentile load planning criteria. Each portfolio
will eliminate the projected peak-hour transmission overloads from the Pacific Northwest
under the 90th percentile water and 70th percentile load conditions. The resource portfolios
were developed to explore a variety of different resource alternatives and to analyze the costs
and benefits associated with each resource strategy.
The resource portfolios varied from a portfolio consisting entirely of combustion
turbines to a portfolio containing 1,000 MW of wind generation with over 800 MW of
combustion turbines for backup capacity. Other portfolios included a predominately coal-
fired portfolio which included almost no natural gas fired generation, and a number of
Chapter 5 60 Potential Resource Portfolios

diversified portfolios that include varying amounts of wind, geothermal, coal, simple and
combined-cycle combustion turbines, and demand-side resources.
The 30-year portfolio power supply costs include both the carrying and operating
costs of the various additional supply-side and demand-side resources proposed within each
portfolio, as well as the carrying and operating costs of Idaho Power’s existing and committed
resources. Unless otherwise noted, portfolio power supply costs are based on 70th percentile
water condition, 70th percentile load conditions, expected fuel price forecasts, and a CO2
emission cost of $12.30 per ton. All of these costs are stated as a 30-year present value, using
the same financing assumptions as outlined previously in the discussion of the resource cost
analysis.
The capital costs listed for each portfolio have been escalated based on the
construction timing and lead times of the various resources within each portfolio and do not
include any estimates of Allowance for Funds Used During Construction (AFUDC,
capitalized interest). AFUDC was considered in the determination of each portfolio’s
carrying cost.
All the portfolios assume that Idaho Power Company will own and operate the
resources. If the energy and capacity were obtained through Power Purchase Agreements or
other arrangements, the capital costs would be lower and the power supply costs would be
higher. A full listing of the portfolios with additional detail regarding the portfolio costs,
capacity, and resource timing is included in the Technical Appendix.

Portfolio Selection
The twelve original portfolios were analyzed and ranked under four different scenarios:
1. No CO2 tax, expected gas prices, production tax credit (PTC) continues to be renewed
2. CO2 tax at $12.30 per ton beginning in 2008, expected gas prices, PTC continues to be
renewed
3. CO2 tax at $49.21 per ton beginning in 2008, expected gas prices, PTC continues to be
renewed
4. CO2 tax at $12.30 per ton beginning in 2008, expected gas prices, no PTC

The portfolio ranking is reported in Table 12. The Aurora Electric Market Model was used to
calculate the 10-, 20-, and 30-year present value of the portfolio power supply costs for each
of the twelve portfolios, under each of the above four scenarios. Rankings were assigned to
each portfolio based on the present value of its portfolio power supply cost – the lowest cost
portfolio was ranked 1 and the highest cost portfolio was ranked 12. The portfolio rankings
were summed and considered in two separate cases:
a. Sum of rankings – all scenarios, all years
b. Sum of rankings – all scenarios 30 year only

Chapter 5 61 Potential Resource Portfolios

Table 12 Portfolio Comparison
Portfolio Additional Capacity Power Supply
Costs
Capital Costs CO2 Ranking**
Portfolio 0 734 MW $7,870 M $1,211 M 6
Portfolio 1 810 MM $8,513 M $421 M 2
Portfolio 2 750 MW $8,302 M $857 M 7

Portfolio 3* 784 MW $7,982 M $1,690 M 1

Portfolio 4 722 MW $8,187 M $810 M 4
Portfolio 5 794 MW $8,157 M $904 M 11

Portfolio 6* 784 MW $8,031 M $805 M 8
Portfolio 7* 1,084 MW $7,555 M $1,352 M 10
Portfolio 8* 935 MW $7,748 M $912 M 12

Portfolio 9 853 MW $7,961 M $1,143 M 9
Portfolio 10 893 MW $7,971 M $904 M 3

Portfolio 11* 939 MW $7,385 M $1,238 M 5

* Portfolios selected for additional analysis
** CO2 ranking based on PV of carbon costs at $12.31 per ton, 1 = lowest
Case a. and Case b. were analyzed separately. Each of the 12 portfolios received equal
weighting in either case. The results were nearly identical for Case a. and Case b., with
Portfolio 11 receiving the top ranking in either case. Since the resources being considered in
this plan are long-lived assets, Idaho Power decided that Case b., considering only the 30 year
present value of portfolio power supply costs, was the appropriate way to rank the portfolios.
More detail summarizing the portfolio ranking analysis is included in the Technical Appendix.

Chapter 5 62 Potential Resource Portfolios

6. Risk Analysis
Idaho Power Company has identified five of the twelve portfolios for risk analysis.
That does not mean that the other seven portfolios are unacceptable, but the five portfolios
selected for risk analysis dominate the other seven portfolios in the cost analysis. Estimated
transmission costs for the five selected portfolios were refined to reflect acquisition and
integration of the entire resource portfolio. The five selected portfolios are:

Portfolio 3 – Wind + Natural Gas Backup Generation
Acquisition Schedule Description (total MW) Resource Type
2006, 2007, 2008, 2009, 2010 1000 MW Wind (50 MW Capacity) Renewable
2009 50 MW Geothermal Renewable
2007, 2008, 2011, 2012 648 MW Combustion Turbines Thermal
Additional Capacity (2013) 784 MW
PV Portfolio Power Supply Costs $7,712 M
Construction Cost $1,690 M
Carbon Tax (CO2) Ranking 1 – lowest PV of CO2 emission
adders

Portfolio 6 – Balanced Resources

Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
, 2007 200 MW Wind (10 MW Capacity) Renewable
12 MW Combined Heat & Power Thermal
88 MW Combustion Turbines Thermal
50 MW Geothermal Renewable
500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 784 MW
2006
2007
2007
2008
2010
PV Portfolio Power Supply Costs $7,935 M
Construction Cost $805 M
Carbon Tax (CO2) Ranking 8

Chapter 6 63 Risk Analysis

Portfolio 7 – Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006, 2007 200 MW Wind (10 MW Capacity) Renewable
2007 12 MW Combined Heat & Power Thermal
2007 88 MW Combustion Turbines Thermal
2008 100 MW Geothermal Renewable
2010 250 MW Coal Thermal
2013 500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 1084 MW
PV Portfolio Power Supply Costs $7,699 M
Construction Cost $1,352 M
Carbon Tax (CO2) Ranking 10

Portfolio 8 – Balanced Resources with Coal Emphasis
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006 100 MW Wind (5 MW Capacity) Renewable
2006, 2007, 2008 36 MW Combined Heat & Power Thermal
2007 20 MW Geothermal Renewable
2007 250 MW Coal Thermal
2009 500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 935 MW
PV Portfolio Power Supply Costs $7,920 M
Construction Cost $912 M
Carbon Tax (CO2) Ranking 12

Portfolio 11– Balanced Resources
Acquisition Schedule Description (total MW) Resource Type
All years 48 MW DSM Demand-Side
All years 76 MW Demand Response Demand-Side
2006, 2007, 2010 350 MW Wind (18 MW Capacity) Renewable
2007, 2010 48 MW Combined Heat & Power Thermal
2007 88 MW Combustion Turbines Thermal
2008 100 MW Geothermal Renewable
2010 62 MW CT / Distributed Gen Thermal
2011 500 MW Coal (seasonal) Thermal
Additional Capacity (2013) 939 MW
PV Portfolio Power Supply Costs $7,547 M
Construction Cost $1,238 M
Carbon Tax (CO2) Ranking 5

Chapter 6 64 Risk Analysis

Table 13 Risk Categories
Category Risk Type
Quantitative Risk 1. Capital Risk
2. Production Tax Credits (wind)
3. Capacity Risk (wind)
4. Fuel Prices
5. CO2 Taxes

Qualitative Risk 1. Public Policy changes
2. Resource commitment
3. Resource timing
4. Resource siting
5. Public acceptance
6. DSM Implementation Risk

The objective of the risk analysis was to identify a portfolio that performs well in a
variety of possible scenarios. Besides the quantitative risk of price fluctuations, Idaho Power
is also interested in the qualitative risks associated with events like policy changes, resource
commitment risk, and environmental risk. The risk categories are presented in Table 13.
Quantitative Risk
Idaho Power has conducted a boundary analysis to assess the quantitative risks. For
example, Idaho Power has analyzed the impacts on the resource portfolios under three CO2 emission tax scenarios – no CO2 tax, a $12.30 per ton tax, and a $49.21 per ton tax. Likewise,
Idaho Power has analyzed each portfolio’s performance if natural gas prices turn out to follow
the low price scenario or the high price scenario. Production Tax Credits have been handled
in a similar fashion. Idaho Power assessed portfolio performance if production tax credits for
wind are allowed to expire, and also if the production tax credits are renewed.
The capacity risk identified for wind is the risk that the resource will not deliver the
contract energy due to resource and technology constraints. The capacity risk for wind
generation was quantified based on weather data collected at potential generation sites and the
wind capacity risk was included in the portfolio analysis. For example, the capacity estimate
for a 100 MW wind generator at the 70th percentile is 5 MW during the summer peak hours.
Wind capacity estimates are discussed in more detail in Chapter 5.
Qualitative Risk
The qualitative risks are more difficult to analyze. The objective is to select a
portfolio that is likely to withstand unforeseen events associated with the qualitative risk.
The DSM implementation risk is the risk that the actual energy savings and peak
reductions from the projected DSM programs will be different than the projected energy
savings and peak reduction targets. Should the actual energy savings and peak reductions be
less than the estimated values, Idaho Power Company will be required to acquire additional
Chapter 6 65 Risk Analysis

supply-side resources to meet the customer load. If the DSM programs exceed the estimated
savings, future supply-side resources may be delayed.
Idaho Power is a regulated utility with an obligation to serve and Idaho Power
Company faces regulatory risk. Idaho Power expects that future resource additions will be
approved for inclusion in rate base and that Idaho Power Company will be allowed to earn a
fair rate of return on its investment. Idaho Power believes that by expanding public
involvement in the IRP process (working with the IRP Advisory Council), and by addressing
several of the Idaho PUC concerns identified in the order acknowledging the 2002 IRP, that
Idaho Power has at least partially addressed the regulatory risk associated this plan.
Significant changes in public policy represent risks that must be considered in a
resource plan involving long-lived assets. In addition to the CO2 emissions tax, another
possible change in public policy that could impact Idaho Power Company and other utilities is
implementation of a renewable portfolio standard. The impacts associated with enactment of
a renewable portfolio standard have been considered in this plan. Although the impacts are
not presented in quantitative terms, the preferred portfolio does position Idaho Power
Company to meet future renewable portfolio standards in the event such standards are
enacted. Once the preferred portfolio in service, nearly ten percent of the Idaho Power
Company generating resources will be non-hydro renewable resources.
Idaho Power Company faces risk in the resource timing and commitment. Idaho
Power has attempted to identify the time periods in which new resources are needed. There
are a number of factors that influence actual timing of resource need. Examples include
economic growth in the service territory, electricity usage patterns, and performance of
existing resources. At the Integrated Resource Plan Advisory Council meetings it was agreed
that early commitment to a large resource might be inadvisable. The Council members
thought that it would be more prudent to pursue a variety of resource types to spread the risk
of policy, siting, and system integration issues. The preferred plan, and most of the finalist
portfolios, addresses the uncertainty by adding resources in smaller increments. The smaller
increments more closely match the projected need for additional capacity.
By utilizing a diverse mix of smaller, short lead-time resources, the preferred plan has
the flexibility to adjust resource timing by either accelerating or deferring actual in-service
dates to more closely match actual load growth. With the exception of the 500 MW coal-fired
plant and the geothermal resources, most of the resources included in the preferred plan have
a fairly short acquisition lead-time. The longer lead-time associated with constructing a coal-
fired plant or a geothermal resource does present a commitment risk. Progress on the
resource acquisition plan and the need to defer or accelerate a future resource will be
addressed every two years in subsequent Integrated Resource Plans.
There are two other qualitative risks that are associated with having a generation
system based on Snake River hydropower. Idaho Power Company has senior water rights on
the Snake River and Idaho Power Company is very concerned about the declining base flows
in the Snake River. The declining base flows have the potential to dramatically lower the
energy output from the Snake River hydropower system. The 2004 Integrated Resource Plan
is based on 70th percentile water conditions as determined by the historical record. If Snake
River streamflows continue to decline, Idaho Power Company will require additional
resources to meet the customer load. The declining Snake River flows has the interest of all
Chapter 6 66 Risk Analysis

parties including the State legislature, the State Department of Water Resources, the water
users, the river naturalists, and Idaho Power Company.
Portfolio 11 proposes adding 350 MW of renewable wind-based generation. One
reason that Idaho Power Company can economically add wind-based generation is that wind-
based generation can be integrated into the hydropower system. Idaho Power Company
intends to use the flexibility of the Snake River hydropower system, especially the operational
flexibility of the Hells Canyon Project, to integrate the wind-based generation. Reductions in
the streamflow flexibility of the Snake River hydropower system may negatively affect the
ability of Idaho Power Company to economically integrate wind-based generation.
The risk analysis presented below combine quantitative risk with a subjective
probability assessment of the boundary conditions. In all of the boundary condition cases,
Idaho Power Company has assigned a probability estimate to the expected, high, and low,
scenarios. The greatest likelihood is assigned to the expected case. For example, under the
discount rate assessment of the capital risk, the expected case is assigned a probability of
80 percent, and the high and low cases are each assigned a probability of ten percent. The
probability assignment may not be symmetric when assessing the other risk categories. The
dollar impact under each scenario is then weighted by the assigned probability to arrive at an
analytical probability assessment. The analytical probability assessments are then used to
summarize the risks at the end of this chapter.
Capital Risk
Capital costs and construction cost of each portfolio represents the capital risk. The
portfolios only consider mature technologies even though some of the resource types are
unproven in Idaho (wind and geothermal). While capital construction costs are generally
known for the various resources, there are always risks associated with any major
construction project including the risk of cost overruns. The impacts associated with a 10
percent cost overrun are shown in the following table:
Construction Costs
Total Construction Costs (No AFUDC)
P3 P6 P7 P8 P11
Portfolio Construction Cost $1,690 $805 $1,352 $912 $1,238
Cost Increase Relative to
Lowest Cost Portfolio $884 $0 $547 $107 $433
Construction Risk
Weight 10%
Weighted Risk $88 $0 $55 $11 $43

Dollars in Millions

Chapter 6 67 Risk Analysis

Capital Costs
PV Power Supply Costs (30 year, CO2 at $12 per ton, includes wind PTC)
P3 P6 P7 P8 P11
Expected Rate (7.2%) $7,982 $8,031 $7,555 $7,748 $7,385
High Rate (9.2%) $6,257 $6,281 $5,989 $6,120 $5,854
Low Rate (5.2%) $10,507 $10,604 $9,823 $10,116 $9,609
Expected relative to
Expected $0 $0 $0 $0 $0
Low relative to Expected $2,525 $2,573 $2,268 $2,368 $2,224
High relative to Expected -$1,725 -$1,750 -$1,566 -$1,628 -$1,531
Weights
Expected 80%
Low 10%
High 10%
Weighted Risk $80 $82 $70 $74 $69

Dollars in Millions

Portfolio 6 has the lowest projected capital cost of the five portfolios and therefore
also has the lowest construction cost risk.
Portfolio 11 is the least sensitive to discount rate changes. However, portfolios 7 and
8 face similar discount rate risks. Each of the other four portfolios is likely to face higher
construction costs than Portfolio 11.
Chapter 6 68 Risk Analysis

Production Tax Credit Risk
The Production Tax Credit for wind generation has expired. There are discussions in
the US Congress of renewing the production tax credit for wind-powered generation. The 30-
year power supply costs under the two production tax credit scenarios is presented below:

PV Power Supply Costs (30 year, CO2 at $12 per ton)
P3 P6 P7 P8 P11
Production Tax Credit $7,712 $7,935 $7,699 $7,920 $7,547
No Production Tax Credit $8,238 $8,059 $7,821 $7,970 $7,735

Expected relative to Expected $0 $0 $0 $0 $0
No PTC relative to Expected $526 $124 $122 $50 $188
Weights
Expected 70%
No PTC 30%
Weighted Risk $158 $37 $37 $15 $53

Dollars in Millions
As expected, the portfolios with the greatest quantities of wind-powered generation derive the
greatest benefit from the production tax credit. Portfolios 3 and 11 have the largest quantity
of wind-powered generation and face the greatest risk to changes in the US Tax Code with
respect to wind-powered generation.

Chapter 6 69 Risk Analysis

Natural Gas Price Risk
Idaho Power Company faces two types of natural gas price risk. Direct risk is the risk
that Idaho Power faces to acquire natural gas to fuel its own resources. Indirect risk is the risk
that Idaho Power Company faces when it acquires power from, or sells power in, the regional
market where natural gas fired resources set power prices. The high prices during the summer
of 2001 were partially the result of indirect risk. Portfolios that rely on market purchases will
face a greater indirect natural gas price risk. The direct and indirect natural gas price risks are
shown below:
Portfolio Fuel Cost Risk
PV Power Supply Costs (30 year, CO2 at $12 per ton, includes wind PTC)
P3 P6 P7 P8 P11
Expected Gas price $7,712 $7,935 $7,699 $7,920 $7,547
Low Gas Price $7,771 $8,026 $7,854 $8,095 $7,658
High Gas Price $7,819 $8,048 $7,520 $7,755 $7,527
Expected relative to Expected $0 $0 $0 $0 $0
Low relative to Expected $59 $91 $155 $175 $111
High relative to Expected $107 $113 -$179 -$165 -$20
Weights
Expected 50%
Low 20%
High 30%
Weighted Risk $44 $52 -$23 -$15 $16

Dollars in Millions

The table shows the portfolio power supply costs under three different gas price
scenarios. The portfolio power supply costs include both the expenses and revenues
associated with all of the portfolio fuel supply costs, surplus sales, and costs associated with
Idaho Power Company’s existing resources. The coal-fired portfolios face price risk because
the size of coal-fired generation necessitates some quantity of surplus sales until customer
loads increase to match the resource size. For engineering design, financial, and construction
reasons, coal-fired generation is generally added in large units with the idea that the excess
generation will be sold at regional market prices for the few years that the Idaho Power
system has surplus power. Like the renewable energy resources, portfolios that rely on coal
face indirect natural gas price risk because the natural gas prices affect the prices at which the
surplus power is sold in the regional market.
Chapter 6 70 Risk Analysis

Carbon Tax Risk
It is likely that carbon dioxide emissions will be regulated within the thirty-year
timeframe addressed in the 2004 IRP. Activity throughout the United States suggests that
carbon dioxide emissions may be regulated in the relatively near future. The Climate
Stewardship Act (S.139), introduced by Senators McCain and Lieberman, received 43 votes
in the Senate in 2003. The bill is likely to be brought to a vote again this year, and a
companion bill has already been introduced in the House.1 At the state level, twenty-eight
states either have or are planning to institute a greenhouse gas emission reduction strategy2
(For example, Washington recently passed a law regulating carbon dioxide from new electric
generation plants, which requires that 20 percent of the carbon dioxide from new plants either
be taxed or be mitigated through offset projects.3 Oregon passed a similar law in 19974).
The magnitude of the CO2 regulation risk faced by IPC and its customers depends on
the carbon intensity of the portfolio. Portfolios with a heavy emphasis on carbon emitting
resources face the risk of increased power supply costs. Accordingly, Idaho Power Company
believes it is prudent to incorporate reasonable estimates for the cost of carbon dioxide
emissions into the IRP resource modeling and analysis, and to thereby actively seek to lessen
the Company’s and customers’ exposure to the financial risk associated with carbon
emissions.
The base case scenario used in the IRP assumes a $12.30 per ton CO2 cost for carbon
emissions, beginning in 2008; scenario analysis was conducted using no cost and $49.21 per
ton CO2 as the boundary conditions. The imputed costs of carbon emissions used in the risk
analysis are derived from Order 93-695 from the Oregon PUC (The OPUC order specified
costs in 1990 dollars and the costs have been escalated to 2004 dollars for the IRP). While the
OPUC order was the starting point for the CO2 analysis, IPC also confirmed that these costs
represent reasonable estimates of the risk that IPC and its customers face due to potential
future regulation of carbon dioxide emissions.
The CO2 costs used in the Idaho Power Company 2004 IRP are consistent with two
other recent analyses in the region. First, in PacifiCorp’s recent Integrated Resource Plan,
PacifiCorp assessed the range of likely future scenarios of regulation of carbon emissions, and
the associated costs of these emissions, and found that $8 per ton of carbon dioxide was a
reasonable value to represent the likely cost of carbon emissions. Second, a recent draft
California PUC report also assessed the range of likely future scenarios of carbon regulation,
and the associated costs, and concluded that a reasonable estimate for carbon costs is a trend
of $5 per ton CO2 in the near term, $12.50 per ton CO2 by 2008, and $17.50 per ton CO2 by
2013.5 Further, this draft report found that the range of carbon costs is from a low of about
zero up to $69 per ton CO2. Thus, both the base case scenario and the high and low scenarios
included in Idaho Power Company 2004 IRP are consistent with these recent analyses.
1 “Bipartisan Group to Unveil House version of McCain-Lieberman Bill”, Energy and Environment Daily,
March 30, 2004. www.eenews.net. 2 “Climate Change Activities in the United States: 2004 Update,” Pew Center for Climate Change, March 2004
(www.pewclimate.org). 3 Washington House Bill 3141, http://access.wa.gov/leg/2004/Apr/n200431_0700.aspx. 4 Oregon House bill 3283, 1997, http://www.energy.state.or.us/siting/co2std.htm. 5 Energy and Environmental Economics and Rocky Mountain Institute, A Forecast of Cost Effectiveness Avoided
Costs and Externality Adders, prepared for the California Public Utilities Commission, January 8, 2004.
Chapter 6 71 Risk Analysis

CO2 Tax Risk
PV Power Supply Costs (30 year, includes wind PTC)
P3 P6 P7 P8 P11
CO2 $0 per ton $6,530 $6,518 $6,213 $6,320 $6,197
CO2 $12 per ton $7,712 $7,935 $7,699 $7,920 $7,547
CO2 $49 per ton $11,256 $12,316 $11,979 $12,521 $11,624

Expected relative to Expected $0 $0 $0 $0 $0
Low relative to Expected -$1,182 -$1,417 -$1,486 -$1,600 -$1,350
High relative to Expected $3,544 $4,381 $4,280 $4,601 $4,077
Weights
CO2 $0 per ton 30%
CO2 $12 per ton 50%
CO2 $49 per ton 20%
Weighted Risk $354 $451 $410 $440 $410

Dollars in Millions

Chapter 6 72 Risk Analysis

Market Risk
Each of the five portfolios was evaluated with respect to its exposure to market sales
and purchases. Each portfolio relies on the regional market for sales when Idaho Power has
surplus energy and for purchases during the times when Idaho Power demand exceeds
generation. The market risk is reported below:
Market Exposure Risk

PV Power Supply Cost (30-year, CO2 at $12 per ton, includes wind PTC)
P3 P6 P7 P8 P11
NPV Base Portfolio Cost $7,712 $7,935 $7,699 $7,920 $7,547
Market Sales ($ millions) -$1,874 -$1,478 -$1,832 -$1,761 -$1,820
Market Purchases ($ millions) $664 $1,030 $537 $707 $659
Net Purchases (Sales) ($ millions)-$1,210 -$448 -$1,295 -$1,054 -$1,161
10% increase in power prices -$121 -$45 -$130 -$105 -$116
10% decrease in power prices $121 $45 $130 $105 $116
Expected relative to Expected $0 $0 $0 $0 $0
Expected relative to 10% increase -$121 -$45 -$130 -$105 -$116
Expected relative to 10% decrease $121 $45 $130 $105 $116
Weights
Expected 50%
Increase in price 30%
Decrease in price 20%
Weighted Risk -$12 -$4 -$13 -$11 -$12

Dollars in Millions

Because the resource planning criteria eliminate the monthly energy deficiencies, under no
portfolios is Idaho Power Company a net importer of power. Under all portfolios, Idaho
Power Company is a net exporter of power and Idaho Power Company and its customers
benefit from regional market sales. Portfolio 7 has the greatest amount of market sales and
therefore faces the greatest market risk. Portfolio 7 also has the most surplus capacity at the
end of the planning period because the seasonal-ownership coal plant is not added until 2013.
Chapter 6 73 Risk Analysis

Risk Analysis Summary
The five types of risk, capital risk, production tax credit risk, natural gas price
exposure, CO2 tax exposure, and market exposure, can be combined into one summary by
adding the five values together. Net market sales are shown as a negative number indicating
that market sales are expected to reduce the portfolio cost. In some cases, fuel price risk is
shown as a negative number indicating a reduction in portfolio power supply costs. The other
three risk categories are expected to increase the portfolio cost. A summary of the five types
of quantitative risk is shown below:
Portfolio 11 dominates the other four portfolios with regard to the quantitative risk
analysis. The Idaho Power Company analysis shows that Portfolio 11 fares the best when the
market risk are combined. Idaho Power Company has selected Portfolio 11 to develop the
Ten-Year and Near-Term action plans.
The Near-Term Action Plan is discussed in Chapter 8, but it is interesting to note that
of the top five resource portfolios, four would have very similar near-term action plans. Three
of the diversified portfolios, and the wind generation with natural gas backup would have very
similar near-term action plans. The near-term action plan for the Portfolio 8, the portfolio that
emphasizes coal-fired generation, would be significantly different. Even so, should coal-fired
generation become more attractive, Portfolio 11 does include coal-fired generation and allows
the proportion of coal-fired generation to be increased in future resource plans.
Risk Analysis Summary

PV Power Supply Cost (CO2 at $12 per ton, includes wind PTC)
P3 P6 P7 P8 P11
Portfolio Power Supply Cost $7,712 $7,935 $7,699 $7,920 $7,547
Discount Rate Sensitivity $80 $82 $70 $74 $69
Construction Risk $88 $0 $55 $11 $43
Weighted CO2 Risk $354 $451 $410 $440 $410
Weighted PTC Risk $158 $37 $37 $15 $56
Weighted Gas Price Risk $44 $52 -$23 -$15 $16
Weighted Market Risk -$12 -$4 -$13 -$11 -$12
Total of Weighted Risk Adjustments $712 $618 $536 $514 $582
Total Risk Adjusted PPSC $8,424 $8,553 $8,235 $8,434 $8,129

Dollars in Millions

Chapter 6 74 Risk Analysis

Figure 15 Load Forecast Risk – High, Expected, and Low Growth Scenarios
-200
0
200
400
600
800
1,000
1,200
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
MW
Expected Case Low Case High Case P11 Capacity

Figure 15 shows the load forecast risk under the high and low load forecasts that will
be faced by adopting Portfolio 11. Portfolio 11 closely matches the energy capacity required
to meet the expected load forecast during the early years of the planning period. As would be
the case with any large resource, adding the 500 MW of coal-fired generation in 2011 leads to
a temporary energy surplus during the time that Idaho Power Company receives the plant
output. Idaho Power prefers that the 500 MW of coal-fired generation be a combination of
smaller units such as two 250 MW units. Having the 500 MW of seasonal-ownership coal-
fired generation be composed of smaller units gives greater online date flexibility as well as
additional flexibility and reduced online risk when the 500 MW facility is fully operational.
Idaho Power Company faced the same generation surplus issues in the past with the Bridger
and Valmy plants and Idaho Power Company entered into term sales contracts until the native
load growth required the plant output.
If actual customer load turns out to be either higher or lower than the expected load
forecast, then the timing and size of the resource RFPs in Portfolio 11 can be adjusted to
accommodate the realized customer load. Idaho Power Company anticipates some flexibility
in both the RFP and the responses for the 88 MW combustion turbine. Idaho Power expects
that the RFP will specify a range of turbine sizes similar to the Bennett Mountain RFP in
2003, perhaps up to 200 MW as in the Bennett Mountain RFP. The RFP flexibility allows the
developers to respond to the RFP with their most cost effective proposals. Idaho Power
Company expects to offer similar flexibility in the DSM and renewable RFPs as well.
Portfolio 11 has a diverse mix of generation resources equally balanced between
renewable resources and traditional thermal resources. The qualitative risks associated with
Chapter 6 75 Risk Analysis

policy changes, resource timing, siting, and public acceptance are difficult to forecast.
However, a diverse portfolio will have less exposure to qualitative risk than will a portfolio
that is concentrated on one resource type or one resource strategy. The risk analysis supports
the conclusion that Portfolio 11, with its blended approach, is well suited to meet the future
resource needs of the Idaho Power Company customers. In summary, the advantages of
Portfolio 11 are:
− Lowest risk-adjusted portfolio power supply costs
− Diversifies Idaho Power Company’s overall resource mix
− Positions Idaho Power Company to meet potential public policy changes (CO2 tax and
renewable portfolio standards)
− Reduces the resource commitment early in the planning period by closely matching
resource additions to capacity needs

It is important to note that the final objective of the risk analysis is not to exactly
quantify the risk associated with a portfolio. Instead, the risk analysis is designed to identify a
portfolio that leads to ten-year and near-term action plans that are resilient to the different
risks. The objective is to arrive at an Integrated Resource Plan that meets the projected needs
of the customers, as well as a plan that can accommodate economic and political changes at
the least cost to the customers and shareowners of Idaho Power Company. The action plans
resulting from selecting Portfolio 11 are discussed in Chapters 7 and 8.

Chapter 6 76 Risk Analysis

7. Ten-Year Resource Plan
Introduction
Portfolio 11 consisting of a diversified set of supply side resources plus 76 MW of
demand response and 48 MW of demand-side energy management is selected as the preferred
portfolio. Portfolio 11 adds approximately 800 MW of energy resources and over 900 MW
MW of capacity during the ten-year planning period. The energy and capacity estimates
include the demand-response programs.
Selecting Portfolio 11 provides Idaho Power Company with a schedule of planned
events as outlined in Table 14 and Table 15. Idaho Power expects to use the Request for
Proposals (RFP) process to acquire both supply-side resources and demand-side programs.
RFPs for the first two resource additions, 200 MW of wind power and the 88 MW
combustion turbine expansion will begin this fall. Also, Idaho Power Company intends to
work with the Energy Efficiency Advisory Group (EEAG) to initiate the demand-side
activities. Requests for Proposals for the other resources will follow throughout the early
years of the planning period.
Table 14 Portfolio 11 – Ten-Year Resource Plan

Year Activity

August 2004 1. 2004 Integrated Resource Plan submitted to the
Idaho and Oregon Public Utility Commissions

Fall 2004 1. Idaho Power Company and Utility Commissioners
communicate regarding IRP specifics and concerns
2. RFP issued for 200 MW wind
3. RFP issued for 88 MW peaking resource
4. File DSM results as a supplement to the IRP
5. File energy efficiency tariff rider in Oregon

2005 1. Demand-side measures designed in partnership
with the Energy Efficiency Advisory Group and the
Public Utility Commissions
2. RFP issued for 12 MW CHP
3. RFP issued for 100 MW geothermal
4. Utility partner for seasonal-ownership coal plant
identified

Chapter 7 77 Ten-Year Action Plan

Table 15 Portfolio 11 – Ten-Year Resource Plan (Continued)

Year Activity

2006 1. CHP design work with successful bidders
2. 100 MW of wind generation online
3. 150 MW Borah-West transmission upgrade
complete
4. Ongoing DSM programs
5. RFP issued for 500 MW seasonal-ownership coal-
fired generation
6. 2006 IRP

2007 1. 12 MW CHP online
2. 88 MW Danskin expansion online
3. 100 MW wind generation online
4. 500 MW seasonal coal begin construction
5. RFP issued for 62 MW combined cycle gas turbine
or distributed generation
6. Ongoing DSM programs

2008 1. 100 MW geothermal online
2. 100 MW proposed Borah-West transmission
upgrade complete
3. RFP issued for 36 MW CHP
4. RFP issued for 150 MW wind
5. Ongoing DSM programs
6. 2008 IRP

2009 1. CHP design work with successful bidders
2. Ongoing DSM programs

2010 1. 36 MW CHP online
2. 150 MW wind online
3. 62 MW Combustion Turbine or peaking resource
online
4. Ongoing DSM programs
5. 2010 IRP

2011 1. 500 MW seasonal-ownership coal-fired generation
online
2. Ongoing DSM programs

2012 1. Ongoing DSM programs
2. 2012 IRP

2013 1. Ongoing DSM programs

Chapter 7 78 Ten-Year Action Plan

Supply-Side Resources
The 2004 Integrated Resource Plan identifies approximately 800 MW of energy
additions to the Idaho Power Company supply-side portfolio. Idaho Power Company intends
to add 350 MW of wind generation, 100 MW of geothermal generation, 88 MW combustion
turbine upgrade, and 62 MW of combustion turbines or distributed resources later in the time
period. Idaho Power Company also plans to add 48 MW of generation from combined heat
and power at some of its customer’s facilities.
Idaho Power Company expects to add 500 MW of seasonal-ownership coal-fired
generation later in the planning period in 2011. Idaho Power Company prefers that the
seasonal-ownership coal-fired facility be composed of smaller individual units such as two
250 MW units for greater operational flexibility and reliability. In addition, the construction
timing of a combination of smaller units may better coincide with customer load growth in the
Idaho Power Company service territory.
Idaho Power Company faces some uncertainty regarding future PURPA generation.
Idaho Power Company may need to revise the Ten-Year and Near-Term action plans should
the quantity of PURPA generation significantly change form the 78 aMW assumed in the
2004 Integrated Resource Plan. Idaho Power Company anticipates that some large
developments that may qualify for PURPA negotiations will be submitted as part of the
Company’s generation requests for proposals. Idaho Power Company will revisit the Ten-
Year and Near-Term Action plans in future Integrated Resource Plans.
Renewable Energy
In 2003 Idaho Power Company hydro generation supplied 38 percent of the energy
used by Idaho Power customers under low water conditions. By 2012, under normal water
conditions, hydro generation will continue to supply about 38 percent of the energy used by
Idaho Power customers.
Wind, geothermal, and other non-hydro renewable resources supplied a negligible
amount of energy used by Idaho Power customers in 2003. Other than the Green Energy
Program, Idaho Power had no specific non-hydro renewable energy purchases in 2003. Idaho
Power Company intends to acquire 350 MW of wind generation and 100 MW of geothermal
generation by 2012. By 2012, non-hydro renewable energy will supply 9 percent of the
energy used by Idaho Power customers under normal renewable energy conditions.
Peaking Resources
The 2004 Integrated Resource Plan adds 939 MW of capacity additions to the
resource portfolio. Idaho Power Company will add wind, geothermal, and thermal resources.
The Idaho Power Company peaking capacity will be increased by an 88 MW combustion
turbine upgrade. The most promising site appears to be an upgrade of the Danskin site with
the addition of two combustion turbines, however other sites are also being considered. With
the additional 88 MW, Idaho Power Company will have 338 MW of natural gas fired peaking
generation.
The primary purpose of the combustion turbines is to provide the generation capacity
necessary to meet peak-hour loads. However, Idaho Power Company has the option to
Chapter 7 79 Ten-Year Action Plan

operate the combustion turbines to meet monthly energy requirements within the operating
limits of the facility permits. With the current and forecast natural gas prices, purchasing
energy from the regional markets, up to the limits of the transmission system, will most likely
be more economical than operating the combustion turbines as an energy resource. Idaho
Power Company anticipates mainly operating the combustion turbines when customer load
exceeds the combined capacity of the Company’s other generation units and the transmission
system.
Market Purchases
In 2003, under low water conditions, Idaho Power Company purchased 21 percent of
the energy used by its customers on the regional energy markets. By 2012, under normal
water and renewable conditions, purchased power is expected to supply only 4 percent of the
energy used by Idaho Power Company customers. Summertime on-peak capacity purchases
will still be necessary and Idaho Power expects to continue to use the full capacity of the
transmission system to access regional power markets.
Idaho Power Company is taking steps to reduce the reliance on regional markets for
energy purchases. Our regional trading partners sometimes offer term market purchases and
exchanges and Idaho Power Company will continue to evaluate the regional market purchases
and exchanges on a case-by-case basis. The 2004 Integrated Resource Plan anticipates that
Idaho Power Company will continue to make summertime energy and capacity purchases of
up to several hundred MWs to meet customer load during the early years of the planning
period.
Transmission Resources
The additional generation will require significant upgrades to the backbone
transmission system. Idaho Power Company has already begun the process to upgrade the
Borah-West transmission path. It is anticipated that much of the renewable generation will be
located in Eastern Idaho and that generation will require an improved Borah-West
transmission path. Idaho Power Company intends to increase the capacity of the Borah-West
transmission path by 150 MW in 2006 and Idaho Power Company has applied to increase the
capacity by another 100 MW in 2008. The Borah-West upgrades are necessary to serve Idaho
Power Company native load – either through resources identified in this Integrated Resource
Plan or through additional imports from the east side. Additional upgrades to the Borah-West
and Midpoint-West transmission paths may be necessary if more resources are added in
Eastern Idaho or Wyoming.
The site of the proposed seasonal coal plant has not been identified so the exact
transmission paths are unknown. It is likely that the seasonal coal plant will also require
significant transmission upgrades and even though the exact paths are unknown, transmission
cost estimates for upgrades were included in the analysis.
Chapter 7 80 Ten-Year Action Plan

Demand-Side Management and Pricing Options
Idaho Power Company anticipates increasing the emphasis on demand-side
programs during the planning period. By 2012, Idaho Power Company demand-side and
peak-reduction programs are expected to supply approximately one percent of the customer
energy requirement. The one percent is in addition to the effects of national energy measures.
Figure 16 shows the 2012 energy sources assuming normal water and normal non-hydro
renewable resource conditions.

Figure 16 Idaho Power Company 2012 Energy Sources
Hydro
38%
Thermal
48%
DSM
1%
Purchased Power
4%
Renewable
9%

Chapter 7 81 Ten-Year Action Plan

Chapter 7 82 Ten-Year Action Plan

8. Near-Term Action Plan
Introduction
Customer growth is the primary driving force behind Idaho Power Company’s need
for additional resources. Population growth throughout Southern Idaho, and specifically in
the Treasure Valley, requires additional measures to meet both peak and energy needs.
Over the past 85 years, Idaho Power Company has developed a blended portfolio of
generation resources. IPC believes that a blended approach based on a portfolio of diverse
resources is the most cost-effective and least-risk method to address the increasing energy
demands of our customers.
Supply-side generation resources are likely to be the primary method to meet the
increasing energy demands of Idaho Power Company customers. However, IPC customers
have expressed an interest that all generation resources be financially, environmentally, and
socially responsible. Renewable energy and demand-side measures are significant
contributors to the resource portfolio selected in the 2004 Integrated Resource Plan.
Near-Term Action Plan
The Near-Term Action Plan presented in Table 16 is designed to accommodate
resource uncertainty. During the Integrated Resource Plan Advisory Council meetings,
several participants were concerned that wind resources, geothermal resources, demand-side
measures, and combined heat and power resources may or may not meet the energy and
capacity targets identified in the 2004 IRP. Idaho Power Company intends to acquire
production resources in all four categories early in the resource plan. The energy and capacity
values in future resource plans in 2006 and 2008 may be modified to reflect the actual
production experience that Idaho Power Company gains with wind resources, geothermal
resources, demand-side programs, and combined heat and power projects. Idaho Power
Company intends to take an active role supporting the development of these resource options
by acquiring production energy and capacity with an RFP process as part of the 2004 IRP.
Chapter 8 83 Near-Term Action Plan

Table 16 Portfolio 11– Near-Term Action Plan (Present through 2006)
Year Activity

August 2004

1. 2004 Integrated Resource Plan submitted to the Idaho
and Oregon Public Utility Commissions

Fall 2004 1. Idaho Power Company and Utility Commissioners
communicate regarding IRP specifics and concerns
2. RFP issued for 200 MW wind
3. RFP issued for 88 MW peaking resource
4. File DSM results as a supplement to the IRP
5. File energy efficiency tariff rider in Oregon

2005 1. Demand-side measures designed and funded through
Energy Efficiency Advisory Group and the Public Utility
Commissions
2. RFP issued for 12 MW CHP
3. RFP issued for 100 MW geothermal
4. Utility partner for seasonal-ownership coal plant
identified

2006 1. CHP design work with successful bidders
2. 100 MW of wind generation online
3. 150 MW Borah-West transmission upgrade complete
4. Ongoing DSM programs
5. RFP issued for 500 MW seasonal-ownership coal plant
6. 2006 IRP

Generation Resources
Thermal Generation - Baseload
Idaho Power Company intends to issue an RFP for approximately 12 MW of
combined heat and power projects in early 2005. Various Idaho Power Company industrial
customers have approached Idaho Power Company regarding combined heat and power
projects. Idaho Power expects that design and construction of the projects will occur in 2005
and 2006, and the projects will be online beginning in 2007.
Idaho Power will need additional base-load generation to meet the energy demands of
the new and existing customers. Idaho Power Company has not added a baseload generation
facility since it acquired fifty percent ownership of the Valmy coal-fired generation plant in
the mid 1980s. The 2004 Integrated Resource Plan identifies that the time has come to
acquire additional base-load generation. Idaho Power intends to acquire 500 MW of coal-
fired generation to be online in 2011. Idaho Power Company will explore the interest to share
seasonal ownership of the facility with other utility partners. Idaho Power expects that a
Request for Proposals for the coal-fired generation will be issued in 2006.
Chapter 7 84 Near-Term Action Plan

Thermal Generation - Peaking
Population growth in Southern Idaho is an inescapable fact and air conditioning is a
common feature in most new construction. The Idaho Power Company summer peak
continues to grow at approximately 80 MW per year. Idaho Power Company will need
physical resources, such as the Bennett Mountain and Danskin power plants near Mountain
Home, Idaho, to meet the energy demands of the additional customers. Idaho Power intends
to issue an RFP for an 88 MW simple-cycle combustion turbine peaking resource in late
2004. The simple-cycle combustion turbine was selected because the upgrade provides
additional peaking capacity at low capital cost and because of the short construction lead-
time.
Renewable Energy
Idaho Power will continue its evaluation of renewable energy. In the 2002 IRP Idaho
Power stated, “Idaho Power intends to dedicate up to $50,000 to explore the feasibility of
constructing a pilot anaerobic digester project within the IPC service territory.” In 2003 Idaho
Power Company donated a $50,000 educational grant to the University of Idaho to study the
development of methane digesters within the Idaho Power Company service territory and the
State of Idaho.
Idaho Power will continue to fund education and demonstration energy projects with
up to $100,000 of funding. One of the current projects is to support the Foothills
Environmental Learning Center to be built on the north side of Boise just off 8th Street near
Hull’s Gulch. Support includes the installation of a 4.6 kW fuel cell and a 2.0 kW solar panel
at the center. Other private supporters include Intermountain Gas, Boise Cascade
Corporation, The Nature Conservancy, the Golden Eagle Audubon Society, and United
Water. The 3300 square foot Foothills Environmental Learning Center will provide ongoing
education to improve land management of the Boise foothills and the Boise Parks and
Recreation Department will manage the center. Another planned project is to repair and
upgrade the 15 kW demonstration solar energy project on the roof of the Idaho Power
Corporate headquarters in downtown Boise.
Idaho Power Company’s most significant new commitment to renewable resources is
the intention to add a significant quantity of renewable energy to the company’s generation
portfolio. Idaho Power Company intends to issue Request for Proposals (RFP) for up to 450
MW of renewable resources. If the RFP process is successful, Idaho Power will add
approximately 450 MW of renewable wind and geothermal resources to its generation
portfolio.
Wind Generation
Idaho Power Company intends to issue an RFP for approximately 200 MW of wind
generation in late 2004. The wind generation is expected to come online in 2006 and 2007.
Idaho Power Company recognizes that wind generation has moved beyond the research and
development stage and Idaho Power will incorporate wind energy into the generation
portfolio as a production resource. Wind developers have indicated that there are several
viable wind generation sites in Southern Idaho. Idaho Power Company will acquire wind
Chapter 7 85 Near-Term Action Plan

generation up to a total of approximately 200 MW as part of the near-term action plan and
350 MW of wind generation as part of the ten-year action plant.
Portfolio 3, Wind with Back-up Gas Generation, scored well in the resource analysis.
Depending on the actual performance of the wind generation in production in Southern Idaho,
Idaho Power Company may increase the amount of wind generation in future resource plans.
Geothermal Generation
Idaho Power Company intends to issue an RFP for approximately 100 MW of
geothermal generation in 2005. As with wind, Idaho Power Company recognizes that
geothermal generation has moved beyond the research and development stage and Idaho
Power will incorporate geothermal energy into the generation portfolio as a production
resource. Geothermal developers have indicated that there are several viable geothermal
generation sites in Southern Idaho. Idaho Power Company will acquire geothermal
generation up to a total of approximately 100 MW as part of the near-term action plan. The
100 MW of geothermal generation is expected to be online in 2008. Depending on the
success of the geothermal generation projects, geothermal generation may play a greater role
in future resource portfolios.
Transmission Resources
The new generation resources proposed in the 2004 Integrated Resource Plan will
require additional transmission resources. Idaho Power expects to construct additional
transmission including a 150 MW upgrade to the Borah-West transmission path as part of the
thermal and renewable generation plans presented earlier in this chapter. Idaho Power
Company has filed for an additional 100 MW upgrade to the Borah-West transmission path as
well. The Borah-West upgrades are necessary to serve Idaho Power Company native load
either through additional generation in SE Idaho or additional east-side imports. Idaho Power
Company will evaluate the transmission requirements of the proposed generation projects and
weigh the transmission requirements in the bid evaluation process. However, the planned
Borah-West upgrades that are necessary to integrate generation resources located on the
eastern side of the service territory will also increase Idaho Power Company’s ability to
import power from markets east of Idaho.
Demand-Side Management and Pricing Options
Idaho Power Company intends to work with the Energy Efficiency Advisory Group
and the Public Utility Commissions of Idaho and Oregon in 2005 to design and fund 48 MW
of Demand-Side Management programs and 76 MW of Demand-Response programs. Idaho
Power Company intends to file for an energy efficiency tariff rider with the Oregon PUC
before the end of 2004.
Idaho Power anticipates that some of the Energy Efficiency and Demand-Response
programs will be conducted through a competitive process using Requests for Proposals.
Additionally, Idaho Power intends to have the effectiveness of the programs assessed using an
independent evaluation process, again likely conducted using Requests for Proposals. Idaho
Power Company expects that the energy efficiency and Demand-Response programs will
come online starting in 2005 and continue throughout the planning period. Depending on the
Chapter 7 86 Near-Term Action Plan

success of the DSM and Demand-Response programs, these programs may play a greater role
in future resource portfolios.
Risk Mitigation
The Near-Term Action Plan is specifically designed to mitigate some of the risks
discussed in Chapter 6. The Near-Term Action Plan has RFPs for renewable resources,
combined heat and power, and demand-side programs early in the planning period. Idaho
Power Company also plans to release an RFP for additional natural-gas fired generation in
2004. The RFPs reduce risk by acquiring a diverse mix of resources early in the planning
period.
Although renewable resources and demand-side programs face no fuel price risk,
there are other risks associated with these options. Wind and geothermal resources are
unproven in Idaho. Idaho Power Company has received considerable interest from renewable
resource developers, but until the responses to the RFPs are received, it is difficult to assess
the real potential of the resources. Likewise with demand-side programs – until the responses
to the RFPs are received, it is difficult to assess the real potential of the programs.
RFPs for the renewable resources and demand-side programs are planned for release
in 2004 and 2005. Like the Bennett Mountain RFP in 2003, Idaho Power expects to issue the
RFPs for a range of generation and Idaho Power will entertain flexibility from the developers
for all resource types.
Idaho Power Company believes that it is imprudent to specify the exact the DSM
programs at this time for two reasons:
1. The ongoing study of DSM potential in the Idaho Power service territory is not yet
completed.
2. DSM program developers may indeed propose additional programs or changes to the
programs identified in the DSM study.
Idaho Power Company analysts included DSM programs that represent a variety of customer
segments to estimate the potential DSM savings. The actual quantity of energy savings will
depend on the specific programs proposed as well as the performance of the vendors. Idaho
Power Company believes that the DSM quantities identified in Portfolio 11 are reasonable
targets and Idaho Power Company expects that DSM vendors will perform and meet the
targets.
Idaho Power Company prepares an Integrated Resource Plan every two years. At the
time of the 2006 IRP, Idaho Power Company will have additional information regarding
renewable resources, demand-side programs, fuel prices, economic conditions, and load
growth. The responses to the RFPs in 2004 and 2005 will greatly influence the resource
quantities identified in the 2006 Integrated Resource Plan.

Chapter 7 87 Near-Term Action Plan

Resource planning is a continuous process that Idaho Power Company constantly works to
improve. Idaho Power Company invited outside participation to help develop the 2004
Integrated Resource Plan. Idaho Power Company values the knowledgeable input, comments,
and discussion provided by the Integrated Resource Plan Advisory Council and the comments
provided by concerned citizens and customers. Idaho Power Company prepares and publishes
a resource plan every two years and expects that the experience gained over the next few
years will lead to modifications in the ten-year resource plan presented in this document.
Idaho Power looks forward to continuing the resource planning process with concerned
parties.

Chapter 7 88 Near-Term Action Plan