20061011Reading exhibits.pdf

EXHIBIT No. 201
Case No. IPC-06-
READING , ICIP
Present position
Education
Professional
and business
history
Don C. Reading
Don C. Reading
Consulting Economist with 8en Johnson Associates, Inc.
, Economics - Utah State University
, Economics - University of Oregon
Ph., Economics - Utah State University
Idaho Public Utilities Commission:
1981-86 Economist/Director of Policy and Administration
Teaching:
1980-81 Associate Professor, University of Hawaii-Hilo
1970-80 Associate and Assistant Professor, Idaho State University
1968-70 Assistant Professor, Middle Tennessee State University
Dr. Reading provides expert testimony concerning economic and
regulatory issues. He has testified on more than 25 occasions before
utility regulatory commissions in Alaska, California, Colorado , the District
of Columbia, Idaho, Nevada, Texas, Utah , and Washington.
His areas of expertise include demand forecasting, long-range planning,
price elasticity, marginal pricing, production-simulation modeling, and
econometric modeling. He has also provided expert testimony in cases
concerning loss of income resulting from wrongful death, injury, or
employment discrimination.
Dr. Reading has more than 30 years experience in the field of economics.
He has participated in the development of indices reflecting economic
trends, GNP growth rates, foreign exchange markets , the money supply,
stockmarket levels, and inflation. He has analyzed such public policy
issues as the minimum wage, federal spending and taxation, and
import/export balances. Dr. Reading is one of four economists providing
yearly forecasts of statewide personal income to the State of Idaho for
purposes of establishing state personal income tax rates.
Dr. Reading s areas of expertise in the field of energy include demand
forecasting, long-range planning, price elasticity, marginal and average
cost pricing, production-simulation modeling, and econometric modeling.
Among his recent cases was an electric rate design analysis for the
Industrial Customers of Idaho Power.
While at Idaho State University, Dr. Reading performed demographic
studies using a cohort/survival model and several economic impact
Don C. Reading
studies using input/output analysis. He has also provided expert
testimony in cases concerning loss of income resulting from wrongful
death, injury, or employment discrimination.
Among Dr. Reading s current projects are a FERC hydropower
relicensing study (for the Skokomish Indian Tribe) and an analysis of
Northern States Power s North Dakota rate design proposals affecting
large industrial customers (for J.R. Simplot Company). Dr. Reading has
also recently completed an analysis for the Idaho Governor s Office of the
impact on the Northwest Power Grid of various plans to increase salmon
runs in the Columbia River Basin.
Publications
The Economic Impact of Steel head Fishing and the Return of Salmon
Fishing in Idaho , Idaho Fish and Wildlife Foundation , September, 1997.
Cost Savings from Nuclear Regulatory Reform , Southern Economic
Journal, March , 1997 , with R. Canterbery and B. Johnson.
A Visitor Analysis for a Birds of Prey Public Attraction, Peregrine Fund
Inc., November, 1988.
Investigation of a Capitalization Rate for Idaho Hydroelectric Projects
Idaho State Tax Commission , June, 1988.
Post-PURPA Views " In Proceedings of the NARUC Biennial Regulatory
Conference , 1983.
An Input-Output Analysis of the Impact from Proposed Mining in the
Challis Area (with R. Davies). Public Policy Research Center, Idaho State
University, February 1980.
Phosphate and Southeast: A Socio Economic Analysis (with J. Eyre, et
al). Government Research Institute of Idaho State University and the
Southeast Idaho Council of Governments, August 1975.
Estimating General Fund Revenues of the State of Idaho (with S.
Ghazanfar and D. Holley). Center for Business and Economic Research
Boise State University, June 1975.
A Note on the Distribution of Federal Expenditures: An Interstate
Comparison, 1933-1939 and 1961-1965." In The American Economist
Vol. XVIII , No.2 (Fall 1974), pp. 125-128.
New Deal Activity and the States, 1933-1939." In Journal of Economic
History, Vol. XXXIII (December 1973), pp. 792-810.
EXHIBIT No. 202
Case No. IPC-06-
READING , ICIP
BARTON L. KLINE ISB #1526
MONICA B. MOEN ISB #5734
Idaho Power Company
O. Box 70
Boise, Idaho 83707
Telephone: [phone]
FAX Telephone: [phone]
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Attorney for Idaho Power Company
Street Address for Express Mail
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR A
CERTIFICATE OF PUBLIC CONVENIENCE)
AND NECESSITY FOR THE RATE BASING
OF THE EV ANDER ANDREWS POWERPLANT.
CASE NO. IPC-06-
IDAHO POWER COMPANY'
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF
IDAHO POWER
COMES NOW, Idaho Power Company ("Idaho Power" or "the Company
and, in response to the First Production Request of the Industrial Customers of Idaho
Power to Idaho Power Company dated June 19, 2006, herewith submits the following
information:
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
REQUEST FOR PRODUCTION NO.1: On page 10 of Greg Said's direct
testimony he states:
Among the actions recommended by the 2004 IRP was the
acquisition of targeted 88 MW simple-cycle, natural gas-fired
combustion turbine. Consistent with the recommendations
of the2004 IRP, the peaking resource RFP requested proposals for an 80
MW- 200 MW turnkey electric generation resources located within
the Company s service territory that would meet anticipated peak
energy demands. The flexibility in plant capacity permitted under the
RFP allowed the developers to respond to the RFP with their most
cost-effective proposals.
Please explain in greater detail how the "flexibility in plant capacity" in the
RFP is consistent with the Company's 20041RP. Please explain why a simple-cycle
resource of nearly twice the size of the 88 MW facility stated in the Near-Term Action Plan
is consistent with the IRP.
RESPONSE TO REQUEST NO.1: The "flexibility in plant capacity" in the
RFP is consistent with the Company s 2004 IRP on several counts.
First, one of the primary goals of the 2004 I RP was to ensure that the
portfolio of resources selected balanced costs , risks and environmental concerns.
Since there was an active secondary market for combustion turbines when the 2004
IRP (and the subsequent peaking RFP) were being prepared, Idaho Power felt that it
was appropriate to provide flexibility in the RFP to provide bidders an opportunity to
propose a variety of standard turbine sizes capable of meeting the identified peaking
need. As a result of the information obtained in the Bennett Mountain RFP , Idaho
Power knew that it was possible to acquire larger frame combustion turbines at
extremely competitive prices on a $/kW basis. By selecting a larger combustion turbine
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 2
Idaho Power has provided additional internal generation resources capable of meeting
system load in the event of transmission outages, forced outages of other generation
units, extreme weather conditions, or greater than expected load growth. In all of these
instances , the risk of curtailment of firm load is reduced by selecting a larger
combustion turbine. Given the competitiveness of the pricing in the Bennett Mountain
RFP , Idaho Power was able to acquire the incremental 85 MW of capacity (173 MW
88 MW = 85 MW) at an extremely competitive price - providing additional generation at
minimal cost while improving reliability for customers.
Second , the idea of specifying a range of turbine sizes in the peaking
resource RFP is discussed on page 75 of the 2004 IRP. Incorporating flexibility in
turbine sizing in the RFP is consistent with the discussion on page 75 of the 2004 IRP.
And finally, by incorporating a range of sizes in the RFP and ultimately
selecting a 173 MW combustion turbine, Idaho Power has an opportunity to defer
additional generation resources in future resource plans. Deferring a large generation
resource, even for one year, could result in substantial savings for customers.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 3
EXHIBIT No. 203
Case No. IPC-06-
READING, ICIP
REQUEST FOR PRODUCTION NO. 23: On page 15 of Mr. Said'
testimony, he states that "(fJorecasted natural gas prices from the 2004 IRP were used in
the bid evaluation." At any time during its evaluation of the various responses to Idaho
Power's RFP , did Idaho Power use an updated forecast of natural gas prices?
RESPONSE TO REQUEST NO. 23: Idaho Power did not use, nor was it
necessary to use , an updated forecast of natural gas prices to evaluate the responses
to the RFP. In bid evaluations, it is only necessary that the same gas price forecast be
used to calculate estimated variable operating costs for all of the bids to allow for a
consistent cost comparison among the bids.
The response to this request was prepared by Randy Henderson
Business Analyst, Idaho Power Company, in consultation with Monica B. Moen
Attorney Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
Page 9
EXHIBIT No. 204
Case No. IPC-06-
READING, ICIP
IDAHO~POWER~
An IDACORP Company
2006 Integrated Resource Plan
2006 Integrated Resource Plan
d8t
An IDACORP Company
Idaho Power Company 1. 2006 Integrated Resource Plan Summary
1. 2006 INTEGRATED
RESOURCE PLAN SUMMARY
ntrod ucti on
The 2006 Integrated Resource Plan (IRP) is
Idaho Power Company s eighth resource plan
prepared to ful:fill the regulatory requirements
and guidelines established by the Idaho Public
Utilities Commission (!PDC) and the Oregon
Public Utility Commission (OPUC).
In developing this plan, Idaho Power worked
with the Integrated Resource Plan Advisory
Council (IRPAC), comprised of major
stakeholders representing the environmental
community, major industrial customers,
inigation customers, state legislators, public
utility commission representatives, the
Governor s office, and others. The IRPAC
meetings served as an open forum for discussion
related to the development of the IRP, and its
members have made significant contributions to
this plan. While input from the IRPAC has been
considered and incorporated into the 2006 IRP
fmal decisions on the content of the plan were
made by Idaho Power. A list ofIRPAC
members can be found in Appendix
Technical Appendix. Idaho Power encourages
IRPAC members to submit comments
expressing their views regarding the 2006 IRP
and the planning process.
The 2006 IRP assumes that during the planning
period (2006-2025), Idaho Power will continue
to be responsible for acquiring resources
sufficient to serve all of its retail customers in
its mandated Idaho and Oregon service areas
and will continue to operate as a vertically-
integrated electric utility.
The two primary goals of Idaho Power s 2006
IRP are to:
1. Identify sufficient resources to reliably
serve the growing demand for energy
within Idaho Power s service area
throughout the 20-year planning period;
and
2. Ensure the portfolio of selected
resources balances costs, risks, and
environmental concerns.
In addition, there are several secondary goals:
1. Give equal and balanced treatment
both supply-side resources and
demand-side measures;
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2006 Integrated Resource Plan Page 1
1. 2006 Integrated Resource Plan Summary Idaho Power Company
2. Involve the public in the planning
process in a meaningful way;
3. Explore transmission alternatives; and
4. Investigate and evaluate advanced coal
technologies.
The nwnber of households in Idaho Power
service area is expected to increase from around
455,000 in 2005 to over 680,000 by the end of
the planning period in 2025. Population growth
in southern Idaho is an inescapable fact, and
Idaho Power will need to add physical resources
to meet the electrical energy demands of its
growing customer base.
Idaho Power, with hydroelectric generation as
the foundation of its energy production, has an
obligation to serve customer loads regardless of
the water conditions which may occur. In light
of public input and regulatory support of the
more conservative planning criteria used in the
2002 IRP, Idaho Power will continue to
emphasize a resource plan based upon a
worse-than-median level of water. In the 2006
IRP, Idaho Power is again emphasizing 70th
percentile water conditions and 70th percentile
average load for energy planning, and the 90th
percentile water conditions and 95th percentile
peak-hour load for capacity planning. A 70th
percentile water condition means Idaho Power
plans generation based on a level of streamflows
that is exceeded in seven out of ten years on
average. Conversely, streamflow conditions are
expected to be worse than the planning criterion
in three out of ten years. This is a more
conservative planning criterion than median
water planning, but less conservative than
critical water planning. Further discussion of
Idaho Power s planning criteria can be found in
Chapter 4.
Idaho Power extended the planning horizon in
the 2006 IRP to 20 years. Recent Idaho Power
IRPs utilized a 10-year pl3nning horizon, but
with the increased need for baseload resources
with long construction lead times along with the
need for a 20-year resource plan to support
PURP A contract negotiations, Idaho Power and
the IRP AC decided to extend the planning
horizon of the 2006 IRP to 20 years.
Potential Resource Portfolios
Idaho Power examined 12 resource portfolios
and several variations of portfolios in preparing
the 2006 IRP. Discussions with the IRP AC led
to the selection of four finalist portfolios for
additional risk analysis-a portfolio that
emphasized thermal resources, a portfolio with a
strong commitment to renewable resources, a
resource portfolio that emphasized regional
transmission, and a modified version of the
2004 IRP preferred portfolio.
Following the risk analysis, a modified version
of the 2004 preferred portfolio was selected as
the preferred portfolio for the 2006 IRP. The
selected portfolio adds supply-side and
demand-side resources capable of providing
091 MW of energy, 1,250 MW of capacity to
meet peak-hour loads, and 285 MW of
additional transmission capacity from the
Pacific Northwest. The selected portfolio also
includes demand-side management (DSM)
programs estimated to reduce loads by 90 iM.W
annually and peak-hour loads by 187 MW.
The preferred portfolio represents resource
acquisition targets. It is important to note the
actual resource portfolio may differ from the
above quantities depending on acquisition or
development opportunities, specific responses to
Idaho Power s Request for Proposals (RFPs),
the business plans of any ownership partners
and the changing needs of Idaho Powersystem.
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 Idaho Power
Page 2 2006 Integrated Resource Plan
5. Potential Resource Portfolios Idaho Power Company
wasted is used to produce additional power
beyond that typically produced by a SCCT. New
CCCT plants could be built or existing simple-
cycle plants could be converted to combined-
cycle units.
The CCCT resources that were studied in the
2006 IRP were assumed to be located in
southwestern Idaho in close proximity to
mainline fuel supply and within 25 miles of
Idaho Power s transmission system. The cost
estimates and operating parameters for CCCT
generation in the 2006 IRP are based on data
from the NWPCC's Fifth Power Plan (2005).
Potential generation studied in each of the
various portfolios ranged from 0 MW up to
250 MW of additional CCCT capacity over the
20-year planning period.
CCCT Advantages
Proven and reliable technology
Operational flexibility
Dispatchable resource
Greater than 50% reduction in CO2
emissions per MWh of output compared
to conventional pulverized coal
technology.
CCCT Disadvantages
Natural gas price volatility
Potential fuel supply and transportation
issues
Simple-Cycle
Combustion Turbines
Several natural gas-fIred SCCTs have been
brought on-line in the region in recent years
primarily in response to the regional energy
crisis of 2000-2001 when electricity prices
spiraled out of control. High electricity prices
combined with persistent drought conditions
during the 2000-2001 time period as well as
continued summertime peak load growth
created interest in generation resources with low
capital costs and relatively short construction
lead times. Idaho Power currently has
approximately 250 MW of SCCT capacity in its
existing resource fleet, and plans to have
another 170 MW on-line by the summer of
2008. Peak summertime electricity demand
continues to grow significantly within Idaho
Power s service area, and SCCT generating
resources have been constructed to meet peak
load during the critical high demand times when
the transmission system has reached full import
capacity. The plants may also be dispatched for
fmancial reasons during times when regional
energy prices are at their highest. Like CCCTs
feasible sites and gas supply currently exist for
future SCCT development.
Simple-cycle natural gas turbine technology
involves pressurizing air which is then heated
by burning gas in fuel combustors. The hot
pressurized air is expanded through the blades
of the turbine which is connected by a shaft to
the electric generator. Designs range from larger
industrial machines at 80-200 MW to smaller
machines derived from aircraft technology.
SCCTs have a lower thermal efficiency than
other fossil fuel-based resources and are not
typically economical to operate other than to
meet peak-hour load requirements.
The SCCT resources that were studied in this
plan are assumed to be located in southwestern
Idaho in close proximity to mainline fuel supply
and within 25 miles of Idaho Power
transmission system. The cost estimates and
operating parameters for seCT generation in
the IRP are based on data from the NWPCC' s
Fifth Power Plan (2005). Potential generation
resources studied in each of the various
portfolios ranged from 0 MW up to 680 MW of
additional SCCT capacity over the 20-year
planning period.
Page 54 2006 Integrated Resource Plan
Idaho Power Company 5. Potential Resource Portfolios
SCCT Advantages
Dispatchable resource
. Proven, reliable resource
. Low capital cost
Short construction lead times
Ideal for peaking service
SCCT Disadvantages
High variable operating cost
Typically not economical for baseload
operation
. Low efficiency
Natural gas price volatility
Combined Heat and Power
Opportunities exist in the region to take
advantage of excess heat energy created by
certain industrial processes. Partnerships could
be developed with some industrial customers
and CHP generating units could be installed at
facilities with 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
from the combustion turbine is delivered to the
distribution and transmission system, and the
steam is used to meet the industrial facility
requirements. The steam could either be sold to
the industrial facility or the industrial facility
could own the steam-generating portion of the
plant.
The cost estimates and operating parameters for
CHP generation in the 2006 IRP are based on
data gathered in Idaho Power s 2004 IRP, with
escalation applied at 3 percent. Estimates are
based only on the electrical generation portion
of the facility. The actual plant costs are highly
dependent on the specific plant configuration, as
well as the specific contract and ownership
agreement. The CHP opportunities studied in
the 2006 IRP are assumed to be located in
southern Idaho in close proximity to Idaho
Power s transmission system. The potential
generation studied in each of the various
portfolios ranged from 0 MW up to 200 MW of
additional CHP capacity over the 20-year
planning period.
CHP Advantages
Dual use of fuel
High fuel utilization efficiency
Facilities are often located in close
proximity to the load center
CHP Disadvantages
Natural gas price volatility
Shared ownership and associated
operational concerns
Biomass
Biomass fuels like wood residues, organic
components of municipal solid waste, animal
manure, and wastewater treatment plant gas can
be used to power a steam turbine or
reciprocating engine to produce electricity. Most
of the biomass-generating resources in the
region are small-scale local co-generating
operations. The use of biomass fuels has not
proven to be economic for large-scale
commercial power production. Available fuel
supply can vary as production from the industry
fluctuates. The biomass fuel sources assumed in
the resource cost analysis for the plan are wood
by products from the forest and wood products
industry. The cost estimates and operating
2006 Integrated Resource Plan Page 55
I~aho FbwerCdmpany 7. T en-Year Resource Plan
For the mid-term, Idaho Power expects to add
approximately 150 "NfW of additional wind
generation in 2012, followed by approximately
250"MW of pulverized coal-fired generation in
2013. Idaho Power will need to sign and commit
to agreements for construction in 2007 in order
to meet the projected 2013 on-line date.
In the longer term, the 2006 IRP includes
approximately 250 MW ofIGCC in 2017,
approximately 100 "NfW of additional CHP at
customers ' facilities in 2020, approximately
100 "MW of additional geothermal generation
2021-2022, and approximately 250 M.W of
advanced nuclear generation at the INL in 2023.
Idaho Power anticipates acquiring the energy
from the advanced nuclear project through a
PPA.
Idaho Power prefers that its future coal-fired
facilities be composed of smaller individual
units or percentage ownership shares of larger
units. A smaller unit reduces the amount of
generation at risk due to equipment failure, and
a larger unit will provide economy of scale cost
savings not possible with smaller units.
Spreading the generation over more units in
different locations provides for greater
operational flexibility and reliability. In
addition, the construction timing of more and
smaller generating units may better coincide
with customer load growth in Idaho Power
service area.
Idaho Power will continue to explore the idea of
seasonal ownership, or exchange arrangements
that simulate seasonal ownership, with
interested parties.
Idaho Power faces uncertainty regarding the
future addition of PURP A generation. If the
quantity of Idaho Power s PURPA generation
significantly changes from the 172 aM.W
assumed in the 2006 IRP, the Near-Term and
Ten-Year action plans may need to be revised.
Demand-Side Resources
The 2006 IRP adds several new programs as
well as expanding existing programs. Overall
the prefeITed portfolio adds a set of demand-side
programs that are forecast to reduce average
loads by 90 aMW on an annual basis and reduce
the summertime peak-hour load by 187 MW.
Since summertime loads drive Idaho Power
capacity needs, the DSM programs are designed
to provide significant load reductions during
summertime peak-hour loads.
Renewable Energy
In 2005, Idaho Power hydroelectric generation
supplied 36 percent of the MWh used by Idaho
Power customers under low water conditions.
By 2025, under normal water conditions
hydroelectric generation will continue to supply
about 33 percent of the MWh 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 2005. Other than power purchased
from several small PURPA projects and green
tags acquired to support the Green Energy
Program, Idaho Power had no major non-hydro
renewable energy purchases in 2005. However
in future years Idaho Power anticipates
acquiring a greater amount of non-hydro
renewable energy given the number of PURP A
resources either under contract or in contract
negotiations. Although Idaho Power is required
to purchase the output from qualified PURP A
projects, at present it does not own the green
tags associated with PURP A generation.
Without the green tags, Idaho Power cannot
claim the environmental attributes associated
with the PURP A generation. Furthermore
without obtaining the green tags, Idaho Power
may not be able to count the PURP A generation
toward meeting a future RPS.
2006 Integrated Resource Plan Page 97
7. Ten-Year Resource Plan Idaho Power Company
The prefeITed portfolio includes approximately
250 'MW of wind generation and 150 'MW of
geothermal generation by 2025. These
additions, based on nameplate ratings, result in
non-hydro renewable resources equaling
0 percent of Idaho Power s total generation
resources by 2025. If the nameplate capacity of
existing small hydro, wind, and geothermal
PURP A contracts are considered, renewable
resources would account for 9.8 percent of
Idaho Power s current generation portfolio. If
the same existing PURP A contracts are included
with the 400 'MW identified in the prefeITed
portfolio, renewable resources would account
for 14.1 percent ofIdaho Power s total
generation portfolio by 2025. This figure likely
underestimates the percentage of renewable
resources Idaho Power will have in 2025
because new renewable PURP A resources have
not been estimated or included in the
calculation.
Peaking Resources
The 2006 IRP adds 1 250 'MW of capacity
additions to the resource portfolio. Idaho Power
will add wind, geothermal, and thermal
resources in the near and mid-term. In addition
to the capacity contemplated in the 2006 IRP
Idaho Power has committed to adding the
170 'MW Danskin combustion turbine, which is
scheduled to be on-line in 2008, and the 49 MW
Shoshone Falls upgrade, which is scheduled to
be on-line in 2010. With the addition of the
170 MVV Danskin combustion turbine in 2008
Idaho Power will have 424 MVV 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
has the option to operate the combustion
turbines to meet monthly energy requirements
within the emission limits of the facility permits.
Given current and forecasted 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.
However, Idaho Power anticipates operating the
combustion turbines whenever customer load
exceeds the generation capacity of its other
generation units and the import capacity of the
transmission system.
Market Purchases
Under low water conditions in 2005, Idaho
Power purchased 22 percent of the MWh used
by its customers from the regional energy
markets. By 2025, under normal water and
renewable conditions, purchased power is
expected to supply only 4 percent of the energy
used by Idaho Power s customers. Summertime
on-peak capacity purchases will still be
necessary and Idaho Power expects to continue
to use its full share of the transmission system to
access regional power markets.
Idaho Power s regional trading partners
sometimes offer term market purchases and
exchanges. Idaho Power will continue to
evaluate the regional market purchases and
exchanges on a case-by-case basis.
Transmission Resources
The 2006 IRP includes 285 MVV of transmission
upgrades, significantly improving Idaho
Power s ability to import power from the
Mid-Columbia market in the Pacific Northwest.
Construction of a single conductor, 230 kV
single-circuit line from McNary to Brownlee,
Brownlee to Ontario, and Ontario to the Garnet
and Locust substations will add approximately
225 MVV of additional import capacity. The
other upgrade is to reconductor the 230 kV
single-circuit line from Lolo to Oxbow, which
will add approximately 60 MVV of additional
import capacity.
The planned supply-side resource additions will
require significant upgrades to the backbone
transmission system. Idaho Power has already
begun the process to upgrade the Borah-West
Page 98 2006 Integrated Resource Plan
Idaho Power Company 7. Ten-Year Resource Plan
transmission path as detailed in the 2004 IRP. A
considerable amount of renewable generation is
expected to be located in eastern Idaho which
will require an improved Borah-West
transmission path to reach the Treasure Valley
load center. The Borah-West transmission path
upgrade is scheduled to be completed in May
2007, which will provide a 250 MW increase in
east to west transfer capability on the Borab-
West path. The Borah-West upgrades are
necessary to serve Idaho Power s native load-
either through resources identified in the 2006
IRP or through additional imports from the east
side. Additional upgrades to the Borah-West
and Midpoint-West transmission paths will be
necessary if more resources are added in eastern
Idaho or Wyoming as identified in the 2006
Integrated Resource Plan.
The coal-fIred resource scheduled for 2013 will
also require significant transmission upgrades to
deliver the energy to the Treasure Valley.
Because the specific site of the coal-fIred
resource has not been identified, the required
transmission upgrades are unknown and a
generic cost estimate was used in the analysis.
Demand-Side
Management Programs
Idaho Power anticipates increasing the emphasis
on demand-side programs during the planning
period. By 2025, Idaho Power anticipates that
the energy efficiency programs initiated in the
2004 IRP, combined with the programs
identified in the 2006 IRP, will reduce energy
demand by 108 aMW. Figure 7-1 shows Idaho
Power s estimated energy sources in 2007 and
2025 , assuming normal water and weather
conditions.
Figure 7-1. Idaho Power Energy Sources in 2007 and 2025
2007
Ii! DSM Hydro iii Purchased Power
2025
. Non-Hydro Renewable Thermal
2006 Integrated Resource Plan Page 99
EXHIBIT No. 205
Case No. IPC-06-
READING, ICIP
Idaho Power Company Draft (8/1/06)Table of Contents
TABLE OF CONTENTS
Table of Contents ........................................................... ................................................ .............................. i
List of Tables......................... ....................................
."."""".."'..."'"
......................................................... v
List of Figures ............................................................................................................................................ vi
List of Appendices ..................................................................................................................................... vi
Glossary of Terms ................................................................... ................................................... ............... vii
1. Integrated Resource Plan Summary ........................................................................................................
2. Idaho Power Company Today ................................................................................................................
Customer and Load Growth...................................................................................................................
Supply-Side Resources ..................................................................................................................... .....
Hydro Resources ................... ....................................... ........................................................ ............
General Hells Canyon Complex Operations....................................................................................
Brownlee Reservoir Seasonal Operations........................................................................................
Federal Energy Regulatory Commission Relicensing Process........................................................
Environmental Analysis .
.................................................................. ........................ ...... ..................
Hydroelectric Relicensing Uncertainties .........................................................................................
Baseload Thermal Resources...........................................................................................................
Jim Bridger................ ........................................................................ ............................. ............
Valmy ................... ................... ................................ ......................................................... ..........
Boardman...................................................................................................................................
Peaking Thermal Resources ..................................................................................... ........................
Danskin ... ......................... .......... ................
................................................... .............................
Bennett Mountain.......................................................................................................................
Salmon Diesel............................................................................................................................
Public Utility Regulatory Policies Act (pURP A) ...................................................... ............ ........1 0
Idaho Projects.. ............ .............................................. .................................... ...........................1 0
Oregon Projects........................................................................................................................
Cogeneration and Small Power Producers (CSPP)..................................................................
Purchased Power """'.....".""..".'."""."'.'."""""""""...................................................................
Transmission Interconnections ............................................................................................................
Description
".,...,.,."""""",.., ........................................... .................. ..... ....................... .................
Capacity and Constraints ...............................................................................................................
Brownlee-East .Path............................................................. ............................... .....................
2006 Integrated Resource Plan Page i
5. Potential Resource Portfolios Draft (8/1/06)Idaho Power Company
The CCCT resources that were studied in the
2006 IRP were assumed to be located in
southwestern Idaho in close proximity to
mainline fuel supply and within 25 miles of
Idaho Power s transmission system. The cost
estimates and operating parameters for CCCT
generation in the IRP are based on data from the
Northwest Power and Conservation Council'
Fifth Power Plan (2005). Potential generation
that was studied in each of the various portfolios
ranged from 0 MW up to 250 MW of additional
CCCT capacity over the 20-year planning
period.
CCCT Advantages
Proven and reliable technology
Operational flexibility
Dispatchable resource
Less greenhouse emissions than coal
CCCT Disadvantages
Natural gas price volatility
Potential fuel supply issues
Simple Cycle Combustion
Turbines (SSCT)
Several natural gas-fIred simple cycle
combustion turbines (SSCTs) have been brought
online in the region in recent years primarily in
response to the regional energy crisis of2000-
2001 when electricity prices spiraled out of
control. High electricity prices combined with
persistent drought conditions during the 2000-
2001 time period as well as continued
summertime peak. load growth created interest
in generation resources with low capital costs
and relatively short construction lead times.
Idaho Power currently has approximately
250 MW of SSCT capacity in its existing
resource fleet, and plans to have another
160 MW online by the summer of 2008. Peak.
summertime electricity demand continues to
grow significantly within Idaho Power s service
area, and SSCT generating resources have been
constructed to meet peak. load during the critical
high demand times when the transmission
system has reached full import capacity. The
plants may also be dispatched for financial
reasons during times when regional energy
prices are at their highest. Like CCCTs, feasible
sites and gas supply currently exist for future
SSCT development. However, the forecasted
trend of high natural gas prices has reduced
interest in future SSCT generation plants.
Simple cycle natural gas turbine technology
involves pressurizing air which is then heated
by burning gas in fuel combustors. The hot
pressurized air is expanded through the blades
of the turbine which is connected by a shaft to
the electric generator. Designs range from larger
industrial machines at 80-200 MW to smaller
machines derived from aircraft technology.
SSCTs have a lower thermal efficiency than
other fossil fuel based resources and are not
typically economical to operate other than to
meet peak load requirements.
The SSCT resources that were studied in this
plan are assumed to be located in southwestern
Idaho in close proximity to mainline fuel supply
and within 25 miles of Idaho Power
transmission system. The cost estimates and
operating parameters for SSCT generation in the
IRP are based on data from the Northwest
Power and Conservation Council's Fifth Power
Plan (2005). Potential generation resources
studied in each of the various portfolios ranged
from 0 MW up to 680 MW of additional SSCT
capacity over the 20-year planning period.
SSCT Advantages
Dispatchable resource
. Proven, reliable resource
Low capital cost
Page 46 2006 Integrated Resource Plan
Idaho Power Company Draft (8/1/06)5. Potential Resource Portfolios
Short construction lead times
Ideal for peaking service
SSCT Disadvantages
Very high variable operating cost so not
economic for baseload operations
Low efficiency
Natural gas price volatility
Combined Heat and Power (CHP)
Opportunities exist in the region to take
advantage of excess heat energy that is created
by certain industrial processes. Partnerships
could be developed with some industrial
customers and combined heat and power (CHP)
generating units could be installed at 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
from the combustion turbine is delivered to the
distribution and transmission system and the
steam is used to meet the industrial facility
requirements. The steam could either be sold to
the industrial facility or the industrial facility
could own the steam generating portion of the
plant.
The cost estimates and operating parameters for
CHP o-eneration in the IRP are based on data
o-athered in the Idaho Power 2004 IRP, with
escalation applied at 3 percent. Estimates are
based only on the electrical generation portion
of the facility. The actual plant costs are highly
dependent on the specific plant configuration as
well as the specific contract and ownership
agreement. The CHP opportunities that were
studied in the 2006 IRP are assumed to be
located in southern Idaho in close proximity to
Idaho Power s transmission system. The
potential generation that was studied in each of
the various portfolios ranged from 0 MW up to
200 MW of additional CHP capacity over the
20-year planning period.
CHP Advantages
Dual use of fuel
Facilities are often located in close
proximity to the load center
CHP Disadvantages
Natural gas price volatility
Shared ownership and associated
operational concerns
Biomass
Biomass fuels like wood residues, organic
component of municipal solid waste, animal
manure, and wastewater treatment plant gas can
be used to power a steam turbine generator and
produce electricity. Most of the generating
resources that use biomass in the region are very
small scale local co-generating operations. The
use of biomass fuels has not proven to be
economic for large scale commercial power
production. Available fuel supply can vary as
production from the industry fluctuates. The
biomass fuel sources assumed in the resource
cost analysis for the plan are wood byproducts
from the forest and wood products industry. The
cost estimates and operating parameters for
biomass-fueled generation in the plan are based
on data from the Northwest Power and
Conservation Council's Fifth Power Plan
(2005). No biomass-fueled generation resources
were included in the portfolios analyzed for the
2006 Integrated Resource Plan.
Solar Energy and Photovoltaics
The conversion of solar radiation to electricity is
typically achieved by capturing heat to power a
conventional generating cycle like a steam
2006 Integrated Resource Plan Page 47
Idaho Power Company Draft (8/1106)7. Ten-Year Resource Plan
Idaho Power prefers that its future coal-fIred
facilities be composed of smaller individual
units, or percentage ownership shares of larger
units. While a smaller unit reduces the amount
of generation at risk due to equipment failure
Idaho Power also anticipates a smaller
ownership share of a larger unit will provide
economy of scale cost savings possible with
larger units. Spreading the generation over more
units in different locations provides for greater
operational flexibility and reliability. In
addition, the construction timing of more and
smaller generating units may better coincide
with customer load growth in Idaho Power
service area.
Idaho Power will continue to explore the idea of
seasonal-ownership, or exchange arrangements
that simulate seasonal ownership, with
interested parties.
Idaho Power faces uncertainty regarding the
future addition ofPURPA generation. If the
quantity of Idaho Power PURP A generation
significantly changes from the 172 aMW
assumed in the 2006 IRP, the Near-Term and
Ten-Year action plans may need to be revised.
Demand Side Resources
The 2006 IRP adds several new programs as
well as implementing expansions of existing
programs. Overall, the preferred portfolio adds a
set of demand-side programs that are expected
to reduce loads by approximately 90 aMW and
reduce the system peak-hour load by
approximately 187 MW during the summertime.
Since summertime loads drive Idaho Power
capacity needs, the DSM programs are designed
to provide significant load reductions during
summertime peak-hour loads.
Renewable Energy
In 2005, Idaho Power hydroelectric generation
supplied 36 percent of the MWh used by Idaho
Power customers under low water conditions.
By 2015 , under normal water conditions
hydroelectric generation will continue to supply
about XX percent of the MWh 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 2005. Other than power purchased
from several small PURP A projects and green
tags acquired to support the Green Energy
Program, Idaho Power had no major non-hydro
renewable energy purchases in 2005. However
in future years Idaho Power anticipates
acquiring a greater amount of non-hydro
renewable energy given the number of
renewable PURP A resources which have
recently been contracted. Although Idaho Power
is required to purchase the output from qualified
PURP A projects, at present Idaho Power does
not own the renewable energy credits (RECs) or
Green Tags associated with PURP A generation.
Idaho Power intends to acquire approximately
250 MW of wind generation and 50 MW of
geothermal generation by 2015. By 2015
non-hydro renewable resources will supply :xx
percent of the MWh used by Idaho Power
customers under normal weather and water
conditions. However, ifIdaho Power acquires
the RECs associated with the anticipated
generation from non-hydro renewable PURP A
resources, the percentage of non-hydro
renewable energy will increase to XX percent.
Peaking Resources
The 2006 IRP adds 1 250 MW of generation
capacity additions to the resource portfolio.
Idaho Power will add wind, geothermal, and
thermal resources in the near and mid-term. In
addition to the capacity contemplated in the
2006 IRP, Idaho Power has committed to adding
the 170 MW Danskin combustion turbine which
is scheduled to be online in 2008 and the
64 MW Shoshone Falls upgrade which is
scheduled to be online in 2010. With the
addition of the 170 MW Danskin combustion
2006 Integrated Resource Plan Page 83
7. Ten-Year Resource Plan Draft (8/1/06)Idaho Power Company
turbine in 2008, Idaho Power will have 424 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
has the option to operate the combustion
turbines to meet monthly energy requirements
within the emission limits of the facility permits.
Given current and forecasted 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 anticipates operating the
combustion turbines primarily when customer
load exceeds the generation capacity of its other
generation units and the import capacity of the
transmission system.
Market Purchases
Under low water conditions in 2005, Idaho
Power purchased 22 percent of the MWh used
by its customers from the regional energy
markets. By 2015, under normal water and
renewable conditions, purchased power is
expected to supply only:X percent of the energy
used by Idaho Power customers. Summertime
on-peak capacity purchases will still be
necessary and Idaho Power expects to continue
to use its full share of the transmission system to
access regional power markets.
Idaho Power s regional trading partners
sometimes offer term market purchases and
exchanges. Idaho Power will continue to
evaluate the regional market purchases and
exchanges on a case-by-case basis.
Transmission Resources
The 2006 IRP includes 285 MWoftransmission
upgrades, significantly improving Idaho
Power s ability to import power from the
Mid-Columbia market in the Pacific Northwest
Construction of a single conductor, 230 kV
single circuit line from McNary to Brownlee
Brownlee to Ontario, and Ontario to the Garnet
and Locust substations will add approximately
225 MW of additional import capacity. The
other upgrade is to reconductor the 230 kV
single circuit line from Lolo to Oxbow which
will add approximately 60 MW of additional
import capacity.
The planned supply-side resource additions will
require significant upgrades to the backbone
transmission system. Idaho Power has already
begun the process to upgrade the Borah- West
transmission path. A considerable amount of
renewable generation is expected to be located
in eastern Idaho which will require an improved
Borah-West transmission path to reach the
Treasure valley load center. I~4Wer
~..
:4n
" '
~:Bt.'Pa:1:Ja;aiiJV'
. .
. The Borah-West
upgrades are necessary to serve Idaho Power
native load-either through resources identified
in the 2006 IRP or through additional imports
from the east side. Additional upgrades to the
Borah-West and Midpoint-West transmission
paths will be necessary if more resources are
added in eastern Idaho or Wyoming as
identified in the 2006 Integrated Resource Plan.
It is likely that the coal-fired resource scheduled
for 2013 will also require significant
transmission upgrades. Because the site of the
proposed coal-fired resource has not been
identified, the required transmission upgrades
are unknown and a generic cost estimate was
used in the analysis.
Demand-Side
Management Programs
Idaho Power anticipates increasing the emphasis
on demand-side programs during the planning
period. By 2025, Idaho Power anticipates that
the energy efficiency programs initiated in the
Page 84 2006 Integrated Resource Plan
EXHIBIT No. 206
Case No. IPC-06-
READING, ICIP
REQUEST NO. 96: In Request No.1 of the Commission Staff, Staff
requested a copy of load-resource balance data by month for each of the years 2006-
2026 for six different assumed water and load conditions, with and without the addition
of the proposed Evander Andrews plant. The requested ti~e period was chosen
specifically to correspond to the time period covered by the 2006 IRP. 2006 IRP load-
resource balance deJa has been in use by the Company for several months during the
preparation of the 2006 IRP; consequently, Staff assumed it could also be used to re-
examine the need for the Evander Andrews plant. In the Company s initial response to
this request, Idaho Power provided load-resource balance data for the period 2004-
2013, apparently from the 2004 IRP.
Please provide a response to this request using load-resource balance
data consistent with the data that will be used in the 2006 IRP.
RESPONSE TO REQUEST NO. 96: The requested information is
attached hereto as "Response to Request No. 96.
The response to this request was prepared by Phil DeVol, Planning
Analyst, Idaho Power Company, in consultation with Monica B. Moen , Attorney II , Idaho
Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH
PRODUCTION REQUEST OF COMMISSION STAFF Page 11
IDAHO POWER COMPANY
CASE NO. IPC-O6-
FOURTH PRODUCTION REQUEST
OF COMMISSION STAFF
RESPONSE TO
REQUEST NOS. 96 & 99
\PC-O6-
E"ander Andrews
,~~
~\D~CO!U'~M
Response to IPUC Staff's 4th
production Request
Response to Request No. 96
Response to Request No. 99
, "
EXHIBIT No. 207
Case No. IPC-06-
READING, ICIP
REQUEST NO. 95: A natural gas fired peaking plant was not selected as
part of the preferred portfolio chosen in the Draft 2006 IRP. If 2006 IRP assumptions
are used and the proposed Evander Andrews plant is assumed to be a resource option
instead of part of Idaho Power s existing generation fleet, would the Evander Andrews
plant be chosen as part of the preferred portfolio?
RESPONSE TO REQUEST NO. 95: If 2006 IRP assumptions are used
and the proposed Evander Andrews plant is assumed to be a resource option instead of
part of Idaho Power's existing generation fleet, it is almost certain that the peaking
resource Idaho Power is proposing to add to the Evander Andrews would have been
selected as a part of the preferred portfolio. With the continued growth in summertime
peak-hour loads , Idaho Power needs either generation resources internal to its system
or additional firm transmission capacity to markets with availability of firm summertime
peak-hour energy.
The 2006 IRP predicts the 2007 summertime peak-hour deficit to be
approximately 115 MW. Summertime peak-hour deficits are forecasted to grow to 204
MW by the summer of 2009. Given the planning criteria to meet the peak-hour load
under a 90th percentile water condition and a 95th percentile peak-hour load , a peaking
resource capable of being constructed and placed on-line quickly, such as the proposed
Evander Andrews plant, would have most likely been included in the 2006 IRP'
preferred portfolio had it not been regarded as part of the Company s existing fleet.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Operations and Planning, Idaho Power Company, in
consultation with Monica B. Moen, Attorney II, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH
PRODUCTION REQUEST OF COMMISSION STAFF Page 10
EXHIBIT No. 208
Case No. IPC-06-
READING, ICIP
REQUEST NO. 26: Provide estimates by month for the period June 2007
through December 2027 of the number of hours the Evander Andrews plant will be
expected to operate to serve Idaho Power's load.
RESPONSE TO REQUEST NO. 26: The number of hours that the
Evander Andrews plant will be expected to operate will depend on a number of factors
including the ability to purchase and import energy via the existing transmission
system, non-weather related economic conditions that could drive load growth to higher
than expected levels , the performance of existing generation units, performance of
demand side management and energy efficiency programs , potential usage for load
following (possibly needed to support wind generation and compensate for potential
loss of operational flexibility of the Hells Canyon Complex) and the timing of future
resource additions. Since the new Evander Andrews unit is expected to have a lower
heat rate than either of the existing Evander Andrews units or the Bennett Mountain
unit, it would typically be dispatched first. As a result, the new Evander Andrews unit
will most likely operate for more hours than Idaho Power's other combustion turbines.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST
PRODUCTION REQUEST OF COMMISSION STAFF Page 8
EXHIBIT No. 209
Case No. IPC-06-
READING , ICIP
REQUEST NO.1 00: Staff Request No. 26 asked for monthly estimates
for the period June 2007-December 2027 of the number of hours the Evander Andrews
plant will be expected to operate to serve Idaho Power's load. Idaho Power did not
provide any estimate of expected operating hours. For the purposes of answering this
request, Staff assumed that the Evander Andrews plant would be added to Idaho
Power's portfolio and dispatched in an AURORA simulation using the portfolio selected
in the 2006 IRP. Please provide monthly estimates as requested, or if this cannot be
done please explain why.
RESPONSE TO REQUEST NO. 100: As requested , Idaho Power has
added the new Evander Andrews plant to its existing portfolio. The resulting portfolio
including the new Evander Andrews plant and the portfolio selected in the 2006 IRP
was dispatched in an Aurora simulation from 2007 through 2032. This Aurora
simulation utilized 50th percentile water and average load conditions and 90th percentile
peak-hour loads for the Idaho South "bubble , the other WECC zones utilized default
Epis load and water conditions, which represent an average or median water and load
condition. The new Evander Andrews plant's operating hours as determined by the
Aurora simulation are attached hereto as "Response to Request No.1 00." The inputs
to the Aurora analysis will have a significant impact on of the number of hours that any
of the combustion turbines (CTs) are dispatched. In a simulation that utilizes 50th
percentile water and average load conditions and 90th percentile peak-hour loads
conditions for the Idaho South "bubble" and average or median conditions for the
remainder of the WECC, CT operation will be limited. Under more severe conditions for
the Idaho South "bubble" and the remainder of the WECC zones, such as 90
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH
PRODUCTION REQUEST OF COMM ISSION STAFF Page 17
percentile water and 95th percentile peak-hour loads , the CTs are expected to dispatch
more frequently.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Operations and Planning, Idaho Power Company and
Rick Haener, Planning Analyst, Idaho Power Company, in consultation with Monica B.
Moen, Attorney II , Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH
PRODUCTION REQUEST OF COMMISSION STAFF Page 18
IDAHO POWER COMPANY
CASE NO. IPC-06-
FOURTH PRODUCTION REQUEST
OF COMMISSION STAFF
RESPONSE TO
REQUEST NO. 100
Response to Request No. 100
!Evander Andrew #1 007
iEvand~~-Andrew #1 12008
!Evander Andrew #1 12009
tEvander Andrew #1 12010
jEvander Andrew #1 011
!Evander A drew #1 012
iEvander Andrew #1 013
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iEvander Andrew #1 014
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jEvander Andrew #1 '2015
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iEvander Andrew #1 12016
!E;a~der Andrew #1 ~017
!Evander Andrew #1 018
!EVande ~ndr~~ #1
12019iEvander Andrew #1 12020
!Evander Andr w #1 ~021
/Evande And~~w #1 ~022
---
jEvander Andrew #1 12023r--_.
------
fEvander Andrew #1 2024---1!Evander Andrew #1 12025
iEvander An rew #1 12026
iEvander Andrew #1 12027
;-----
jEva~er Andrew #1
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iEvander Andrew #1 \2032
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7342 I -----...1121813 17145 ~951
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--------1
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EXHIBIT No. 210
Case No. IPC-06-
D. Reading, ICIP
REQUEST NO. 68: Please provide an update on the status of the
negotiation with the cogenerator referred to on page 6, lines 17-20 of Greg Said's direct
testimony. How much capacity and energy does Idaho Power expect will be made
available if the contract with the cogenerator is executed? If the contract is executed
how will it change Idaho Power's load resource balance and need for power?
RESPONSE TO REQUEST NO. 68:
Negotiations continue between Idaho Power and this proposed
cogeneration project. The project has proposed sizes ranging from 35 MW up to 110
MW for this project coupled with continuous 24 hour-a-day operations or fully
dispatchable operations.
Both Idaho Power and the proposed project have expended significant
effort in these negotiations. However, at this time it would be premature to speculate on
the final outcome of these negotiations and the actual impact the resource may have on
Idaho Power s energy needs.
The response to this request was prepared by Randy C. Allphin, CSPP
Contract Administrator, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST
PRODUCTION REQUEST OF COMMISSION STAFF Page 34
EXHIBIT No. 21
Case No. IPC-06-
READING , ICIP
REQUEST FOR PRODUCTION NO. 13: In response to a question at the
bottom of page 13 of his direct testimony about the decision to delay the peaking project
by one year, Mr. Said states that "the Company evaluated the most prudent use of its
resources and determined that other short-term altematives other than this project could
meet the projected peak energy needs for the summer of 2007." Please provide copies of
the reverenced evaluation(s) and determination(s). Include any work papers, studies
AURORA model runs and economic evaluations.
RESPONSE TO REQUEST NO. 13: A copy of the analysis that examined
expected changes in Idaho Power's forecast surplus/deficit position and a memorandum
summarizing the analysis are attached hereto as "Response to Request No. 13.
" -.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 15
IDAHO POWER COMPANY
CASE NO. IPC-O6-
FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO.
EXHIBIT No. 214
Case No. IPC-06-
READING, ICIP
REQUEST FOR PRODUCTION NO. 19: What is the retail rate impact of
Mr. Said's request at page 20 for the Commission to approve inclusion of the total project
investment in the Company s rate base for ratemaking purposes? Assume for purposes of
answering this question that the total project investment includes 60 million dollars for the
generating plant and 22.8 million dollars for associated transmission and substation
improvements. Please provide supporting work papers.
RESPONSE TO REQUEST NO. 19: There is no current retail rate impact
associated with the Company s application for a Certificate of Convenience and
Necessity. The actual incremental revenue requirement to be requested by the
Company will depend upon circumstances that exist at the time of an application for
recognition of the Evander Andrews project in the Company s rate base, revenue
requirement and rates. The earliest a future retail rate impact would occur would
probably be in 2008 once the Evander Andrews power plant is in service.
application to change the Company s rates in 2008 to reflect the Evander Andrews
power plant could either be a part of a general rate case or a single issue rate case as
was the case for inclusion of the Bennett Mountain power plant costs.
In that case, the Company identified $50.3 million of power plant costs and
$7.7 million of transmission and interconnection facilities costs for a total of $58.0 million
in total project costs. The Company quantified the associated incremental revenue
requirement associated with the Bennett Mountain project at $13.5 million. This
quantification included expenses such as property taxes, property insurance and
depreciation expenses, but excluded expenses such as operating and maintenance
expenses. Power supply expense impacts were likewise not included, but were
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 21
ultimately captured in PCA computations. The Company has not quantified the
incremental revenue requirement associated with the Evander Andrews project.
However, assuming the ratio of incremental revenue requirement to total project costs
($13.5 million / $58 million = 23.3 percent) from the Bennett Mountain application might
be similar in an Evander Andrews application, an estimated incremental revenue
requirement for an $82.8 million project would be $19.3 million.
The response to this request was prepared by Gregory W. Said , Manager
of Revenue Requirement, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
DATED at Boise, Idaho, this 11 th day of July 2006.
rP-
MONICA B. MOEN
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 22
EXHIBIT No. 21
Case No. IPC-06-
READING, ICIP
"- ."-'
An Assessment of the
Feasibility of Emergency
Electrical Generation Units
to Serve System Load
Req uirements
By.
Alex Albertine
August 17 2001
Northwest Power Planning Council
Executive Summary
Over the past year a growing power crisis has emerged across the western states.
Recent developments in power management in California have raised particular concerns
as the Northwest region both plans and reacts to possible power shortages or extreme
price increases. Our heavy reliance on electrical power has left millions of Americans
vulnerable to severe consequences of power loss. In order to avoid the California
experience of rolling blackouts or the effects of higher wholesale power increases, we
must look for creative and innovative ways to both produce greater supplies of electric
power, provide incentives for conservation and balance environmental needs
simultaneously. Many debates have taken place as to what can be done to improve this
situation. Some alternative proposals have been considered. One proposal encourages
the use of emergency generators, already installed in a variety of buildings, be used to
increase power generation.
This study, which is based upon the need to explore the feasibility of power
generation from relatively small generators in individual buildings, is limited in size and
scope. Interviews were conducted over an eight-week period with building operators and
managers in the city of Portland, Oregon who own or manage emergency generating
units. Additional interviews were conducted with personnel from local electric utilities.
This study sought first to detennine the availability of erpergency generators and the
amount of power that could be generated. Owners and managers of buildings were
questioned as to whether and how they would support using private generation in
cooperation with utilities. Issues explored included economic, technical and legal ones
relating to the practical use of emergency generators and the incentives and problems in
establishing a workable program.
This study found that emergency generators are available in a variety of
commercial and industrial buildings as well as hospitals, high schools, colleges, jails, and
public safety facilities. According to industry infonnation Washington, Oregon, Idaho,
and Montana have just over 26 000 generators within their borders. This study contacted
70 facilities or approximately 10% of the total available in the city of Portland.
Federal, state and local jurisdictions govern the use of emergency generators.
Agencies such as the federal Environmental Protection Agency and state agencies such as
the Oregon Department of Environmental Quality have specific requirements and
environmental codes that must be met. At the local level, emergency generators are
subject to local structural, mechanical and electrical regulations.
From the infonnation gathered 71 % of the industrial and commercial building
owners or managers indicated that they would be interested or likely interested in
contracting with a utility to supply energy to the power grid using their emergency
generating capacity. This level of support was qualified by the desire of respondents for
support from utility companies and clear economic incentives to participate.
The results of interviews with utility personnel as well as additional research
indicated that local utilities are supportive to the idea of using emergency generating
capacity to augment present power production. Most utilities are considering innovative
programs to increase the power supply, and see the use of emergency generation as a
possible option. Some utilities are beginning to develop specific program parameters and
consider legal and contract infonnation that would mutually benefit both the owners of
emergency generators as well as the utilities. Further, some program elements have
specific environmental benefits.
Emergency generators may be used up to 200 hours per year during peak power
needs. In exchange for use of the emergency generators, utilities would supply support
maintenance, fuel and equipment to fully maintain the generators as well as build a
centralized and parallel power supply. Building owners would be secure in knowing that
they have guaranteed, dependable and non-interruptable power from well-maintained and
tested emergency generators.
If the results of this survey are extrapolated region-wide there is significant
generating capacity available using the capacity in emergency generators. An estimated
7 gigawatts of generating capacity is believed to be available. This additional power
provided at reasonable cost, both economically and environmentally offer an important
opportunity to meet the power needs of a growing region.
Pages 1-
Page 3
Pages 4-
Table of Contents
Executive Summary
Table of Contents
Introduction
Evaluating conditions of emergency generation facilities
Pages 5-
Analysis of Feasibility
Pages 13-
Types of Emergency Generator Units
Where Generators are Found
Detennining Generator location, Type and Capacity
How Much Power is Possible?
Other Necessary Equipment
Codes and Requirements
Support From Building Owner and Tenants
Support From Utilities
Environmental Feasibility
Conclusions and Recommendations
Pages 17-
Appendices
Pages 19-
Page 21
Page 22- 23
Page 24
Page 25
Page 26
Page 27
Conclusions and Recommendations
Appendix 1 Facilities Director s Questionnaire
Appendix 2 Government Agency Questionnaire
Appendix 3 Utility Questionnaire
Appendix 4 Caterpillar
Appendix 4 Cummins
Appendix 4 Detroit Diesel
Appendix 4 Deutz
An Assessment of the Feasibility of Emergency
Electrical Generation Units to Serve System Load
Requirements
Millions of Americans, often without thought, rely on our complex electrical
power system to meet their daily needs. Without electrical power modern life and the
completion of simple daily tasks becomes impossible. Electrical power is the essential
backbone of America s culture. Unfortunately, this reliance has left citizens vulnerable
to the power system and the negative effects when it does not work properly. Presently
the northwestern part of the United States is experiencing a lessening in availability of
electrical power. Prices of wholesale power are increasing dramatically. These prices are
predicted to continue to be high throughout the next several years. Economic and
population growth, poor water conditions, lack of customer incentives to conserve, high
natural gas prices and a dysfunctional deregulated power industry in California has
resulted in the deterioration of the electrical power system. This situation must be
improved to continue the high standard of living Americans enjoy.
Many debates have taken place in a search for ways to improve this situation. No
single clear answer IRs been found, but many alternative proposals have been considered.
One idea, the focus of this study, is the use of emergency generation units to produce the
demanded amount of power that the utilities are unable to provide. Many commercial and
industrial facilities are already equipped with emergency power generation units. These
units, which run on diesel fuel, are installed and are used in case of an emergency when
the grid that usually provides the electrical power is temporarily out of service. It has
been proposed that these emergency generating units also be put in operation to supply
power during times of peak demand. The question of whether it is feasible to use these
units as part-time power generators is the objective of this study proposed by the
Northwest Power Planning Council.
The Northwest Power Planning Council is an interstate compact agency
responsible for the assessment of electric power and fish and wildlife issues affecting the
states of Idaho, Montana, Oregon and Washington. The Council makes policy
recommendations at the request of the governors, legislators, congressional delegation
and the Bonneville Power Administration.
This study is based on interviews of facilities operators who own emergency
generating units and the utilities that support the power grid. The first goal of the study is
to evaluate the current conditions of the emergency power generators. For example
where generators are located, amount of generating capacity, who controls their use, and
under what circumstan::es generators are currently employed, are all questions addressed
by the study. Since little was known about the emergency generating units, finding
current infonnation about these generators was essential in finding out how they might be
used to offset the power demand. .
The second goal ofthe study is to analyze the feasibility of employing emergency
generators fulltime or on a part-time basis as needed. In question is the economic
viability of keeping generators running for a longer than normal period of time. The study
examines the impact on the utility, and if it is economically feasible for the utility
company to pay for extra equipment, contracts, and servicing for emergency generators.
The study also addresses the environmental quality issues that appear when the
generators are in use. They are noisy and release large amounts of particle waste into the
air. The generators also require fuel onsite for their operation, which, when running the
generators more often, will result in the need for more onsite diesel fuel.
Other complications may also arise. Health and safety issues may offer
challenges. There are also several laws, regulations and institutional constraints on use of
emergency generators. It is important to take into account these regulations and the
actions necessary to modify regulations that prohibit the use of generators as power
producers. At present, the primary purpose of these units is to provide electricity to the
customer in case of service interruption. If emergency generators were to be used to
augment system loads, as addressed in this study, the generators would no longer be
considered emergency generators, but power generators and be subject to a different level
of federal and state requirements.
Electricity is provided by the power producer, passed to the utility, and then to the
consumer. In an ideal circumstance this is how the power industry would work on a
simplified level. The current problem is that it now costs the utility too much to buy the
power from the producer due to increased demand and impacts from additional economic
factors and unpredicted events. Because the utility must supply energy to consumers, it
will look for other options to produce power more efficiently. As shown in figure one
below, demand tends to increase during mid-day. Ifthe utility is only able to fulfill part
of their demand during mid-day the result would be blackouts. This study will review the
use of emergency generators by the utility to fulfill the demanded amount of power as
shown below.
Daily Building Load (KW vs. Time)
The generator is able to fill
the demanded amount of
power.
9;OOam 12:00 3:00pm . TIME
Typical load profile showl"'9 use of
engine genet'ator ckring peak periods.
This beginning study seeks to gather baseline data in regards to emergency power
generation use. Conclusions are preliminary and based on limited data and estimated
numbers. Yet, this information can provide groundwork for even more future research. It
is clear that if the full extent of emergency generation s potential is to be realized, a more
in-depth and broader study must be perfonned. However, it is my intention to provide
the most recent and exact infonnatibn possible. With this infonnation gathered an
estimate of generation potential has been made. Hopefully with this new infonnation
producers, utilities and consumers will begin to prepare for innovative changes in the
power industry.
Evaluating Conditions of Emergency
Generation Facilities
Types of Emergency Generator Units
Emergency generators come in a variety of types and have varying amounts of
kilowatt (kW or 1000 watt) capacity. The main manufacturers of emergency generators
are Caterpillar, Cummins, Detroit Diesel, Perkins, and Deutz. Photos of the different
generators, except Perkins, are included in appendices four, five, six and seven
respectively. The average commercial grade generator will produce anywhere from 150
kW to 800 kW. This is the standard range for generators installed in commercial
buildings to support emergency equipment, such as lighting or elevators. For smaller
buildings or those who only need generation for emergency lighting there are smaller
generators available ranging from 50 to 150 kW. Buildings with tenants that require
larger generation, or industrial plants, may use generators producing 800 kW to 4
megawatts (MW or 1000 kW). Any generator larger than 4 MW is considered to be a
power plant in itself.
Generators are a huge investment for a building owner. A standard 200 kW
generator costs around $21 000. 400 kW generators cost about three times as much.
There are also added expenditures such as an auto start panel, the auto-transfer switches
fuel tanks, various pennits, installation and shipping. This does not include maintenance
which is estimated to be ten to twenty thousand dollars a year for an 800 kW generator.
This maintenance figure also includes the amount spent on periodic testing.
Where Generators are Found
Human safety is the number-one reason for the installation of emergency
generation units into office buildings. Federal law mandates the existence of emergency
lighting in any commercial, industrial or public facility. Emergency lighting can be
supplied two different ways. First, a facility may install emergency batteries to supply
lighting during a power failure. Batteries are cheaper for the owners to purchase. They
are also more environmentally friendly. Emergency battery systems recharge themselves
when power is on and do not use any excess fossil fuels, leave any discharge or any
particle waste when running. One drawback of emergency battery systems is that they are
not as powerful since each can only produce approximately 50 kW. However, batteries
can be stacked to reach higher capacities. Also, they are unable to support the building
needs for more than a day or so at peak load.
The second fonn of emergency lighting is through emergency generation units.
These units come in all fonns and sizes and can produce up to 4 MW of electrical energy.
The benefit of an emergency generator is that it can be used to supply emergency
lighting, backup the elevator system, run the computer system, or in an industrial building
the generator can run the equipment needed to continue produ::tion. Generator use has
flexibility and can be set up to run any electrical device during an outage. Even though
emergency generators cost several thousands of dollars more than battery systems, their
ability to continue to run building systems can save tenants lost revenue. In many cases
generators can pay for their purchase and operation costs in a few years by the amount of
revenue produced from not having to stop production during a power outage.
Emergency generators can be found in hospitals, office buildings, high schools
colleges and universities, jails, public safety facilities (Police, fire, emergency rescue),
military facilities, airports, seaports, ski resorts, industrial production facilities
telecommunication facilities, or anywhere else tlRt may need back up power to continue
work.
Determining Generator Location, Type and Capacity
One of the goals of this study is to calculate the number, type and capacity of
emergency generators available for electrical production in the Northwest. From those
numbers I hoped to estimate the generation potential in kilowatts. Originally it was
thought that by contacting building managers in buildings with known emergency
generators I would be able to find the information necessary for the study. I also mped to
gather information from previous building studies, which along with my survey
information of the city of Portland area, would be used to determine the number of
generators within the four states of the Northwest Power Planning Council'region. The
previous building studies would show me how to extrapolate my generator information
from Portland to include all of the four states.
Initially I had no idea as to how we would be able to get the names and phone
numbers of so many building managers for tie many different types of buildings in
Portland. But after contacting the Building Owners and Managers Association (BOMA),
they provided me with a list of building managers and their phone numbers. I then
contacted the building managers and interviewed trem using the questionnaire I
produced. (See Appendix 1) Unfortunately, several problems arose. First the list provided
by BOMA only included commercial buildings, and it was necessary for me to contact all
types of buildings. Secondly, the list did not indicate information on who had emergency
generation capabilities. Out of the seven hundred buildings listed for Downtown Portland
I had no idea how many or who specifically had the generators.
In my survey I interviewed managers in 70 buildings. (10% oftre 700available.
Since buildings are not legally required to have generators (See codes and requirements
p. 9) I found that only about 20 percent of the buildings I surveyed owned generators.
This small of number was too small to be statistically used to estimate generation
kilowatt capacity in the four northwestern states.
Other errors also appeared. The previous building studies I had hoped to use were
at least ten years old. Numbers from these old studies made their use for estimation
inaccurate and unusable.
In the interest of determining a more accurate number of generators, I requested
from Caterpillar Inc. a list or number of generators installed around the four states. I
knew Caterpillar periodically prepared a list of domestic generating units installed around
the world. Caterpillar s list was last updated Fall 2000 and holds the most accurate data
as to how many generators are installed in Washington, Oregon, Idaho, and Montana.
Caterpillar uses the list to enable its regional dealers to identify maintenance
opportunities. The list is a comprehensive list, in that the list includes not only
Caterpillar brand equipment, but also generating sets manufactured by other companies.
The data provided by Caterpillar is presented below in table 1.
Numbers refer to the amounts of generators of a particular kilowatt production size
installed in a state.
$(J4+~rc
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143
699
321
547
710
058
553
494
621
726
811
400
122
222
2555
.~,
Table 1 shows that at last count, the state of Oregon had as many as 2 143
individua 1 small generating units, posting a capacity rating of between 50 and 70
kilowatts. The total number of standby generation sets rises to 8 148 when we take into
account units of a size ranging from 50 to 2000+ kW.
Obviously, not all of the generating units identified in Table 1 are available for
delivering electricity into the grid. Some may not be operable; others may be used on
remote sites. Further, the data in Table 1 may not be completely accurate, even though
the data is based on an actual count of generator units as opposed to my original plan.
However, I was assured by the manufacturer that the vast majority of these generators are
serving as emergency generators standing ready to operate when the local distribution
grid stops delivering electricity to a customer location. Typically such calls for
emergency generation occur when there is a distribution fault or when rolling blackouts
have been implemented.
How much power is possible?
Finding out exactly how much emergency generation power or capacity is
available is one of the main goals of the study. Assuming that we get full cooperation
from building managers and do not run into any regulatory problems the total generation
power becomes the maximum power available from emergency generation. In the table
below I evaluate the total production capacity of the generation units indicated in Table 1.
To calculate total production capacity for the units in each of the first six columns, I have
taken the midpoint of the range and assigned that number to the column as the capacity.
For the last column, with generator capacity in excess of 2000 kW, I have used 3000 kW
as the average capacity of this column. It is then simple multiplication. For instance
Oregon s 2 143 generators producing 50- 70 kW results in 2 143 x 60 = 128 580 kilowatts
or about 129 megawatts. Based on this evaluation method, there are 9 528 megawatts or
5 gigawatts of electrical distributed generation installed in the four northwestern states.
5 gigawatts are the maximum amount of electrical capacity from emergency generators
available in the northwestern states. This number is high enough to cover the expected
amount of power generation needed in the Northwest throughout the next several years.
9500 MW is about a quarter of the present utility generating capacity in the Northwest.
The numbers refer to the amount of production capacity at each generator size.
C n
893
118
1513
870
139
1589
M~I1~!Ia
Totai' ,
" - '
739
Other Necessary Equipment
Automatic Transfer Switch and Parallel Switching Gear
Tfie Automatic Transfer Switch (A TS) is a key component of any emergency and
standby generator system. It is the device that monitors the sources and transfers the
critical load from the preferred or normal source, to the alternate, or emergency source.
Automatic Transfer Switches can switch between alternative and normal power sources
with only a thousandth of a second interruption. The interruption is so small the tenant
rarely notices it. If a company, such as a microchip fabrication plant needed switching
gear they would need to be on parallel gear already. Because of its importance, it is
imperative that generator owners be aware of the many transfer scenarios and the
solutions to the various standby power applications. Automatic transfer switches are a
vital but expensive part of an emergency generation system. Without the switching gear
personnel from the building where the generator is located would have to turn on the
generator manually. A model of the automatic switching gear is shown below.
EXHIBIT No. -219
Case No. IPC-06-
READING , ICIP
Portland General Electric: Products & Services: Dispatchable Standby Generation
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Dispatchable Standby Generation
Capture enhanced reliability and operational savings from your backup elec
generation system.
If your business requires standby electric generation to ensure vital production or
performance, you know the daily reality: constant maintenance of your backup sy~
hope that it will perform when you need it.
For most of the year, however, the only thi
backup system generates is a stream of
and maintenance expenses.
PGE's Dispatchable Standby Generation ~
your standby generators to work for up to .
annually to meet peak power demands
picks up all your maintenance and fuel ex~
Your generator is always available to back
facility and will operate synchronized and i
with PGE power so there is no service inte
From PGE's control center, a dispatcher can
start any or all of the standby generators
within the system. Up to 100 megawatts of
power can be generated during peak hours.
For the option of running your generators when needed, PGE will:
. Upgrade switchgear and install control and communications hardware at nc
increasing reliability and improving control of your system.
. Assume all maintenance and operation costs for your system, eliminating y
fuel , repairs , tune-ups, oil changes, filter replacements and overhauls.
. Provide additional sound attenuation, if needed, quieting the generator sysl
Provide additional fuel storage, if needed , expanding your operating time dl
weather-related , long-term power outages.
. Test your system at least once a month under full load; frequent full-load te
ensures the generator will operate successfully during an outage and is bel
engine.
A powerful network
PGE equips your standby generator with paralleling switchgear, allowing the unit t
operated in synchronization with the electric distribution system. Qualifying comm
industrial customers (those with standby ger
250 kilowatts and up) are networked with PC:
communications and power control system. .
units can be monitored and dispatched from
control center.
PARALlEUNGSWITCH GEARPCiE Yourp~tr generator
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In case of an outage, the standby generator
it normally would , providing backup power to
for the duration of the outage. However, whe
returns to the grid, your facility moves back t
power without additional interruption.
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Portland General Electric: Products & Services: Dispatchable Standby Generation Page 2 of 2
.....n." ..... nun
Program participants pay standard electric r,
power used, regardless of where it's being generated. PGE pays all the fuel costs
standby generators, even during an outage, adding to the operational savings.
So how does this work?
Read our FAa, which answers common questions about how the program works
offering the DSG program and how your business can take advantage of this savil
opportunity.
Unleash the full potential of your standby generator
Interested? At your request, we will provide a detailed analysis and proposal tailor
business requirements. Please contact your PGE representative or e-mail us . YOI
call Mark Osborn , DSG program manager, at 503-464-8347.
If you are considering purchasing a new generator or upgrading to a larger systerr
generation, PGE provides convenient financing on request. Financing can be add,
monthly electric bill.
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Dispatchable
Generation
FAa
FAQ
Q: Why is PGE offering the Dispatchable Standby
Generation (DSG) program?
. ,...................................."........... .
The tight supply of electricity and resulting high prices
have created new business opportunities for PGE
customers who can simultaneously use power, while
making more power available in PGE's territory. The DSG
program improves a participant's bottom line by having
PGE:
. Cover the operating and maintenance costs of the
DSG power system
Contribute to the customer s standby generator
system installation
PGE benefits by accessing new power resources for all its
customers. By linking many generators to the electric
distribution system and turning them on at peak demand
hours, PGE and program participants are helping keep
the price of power down and the supply up with an
innovative business relationship.
Q: What happens if we need power at the same time PGE is
using the DSG system?
. Your backup generator is always available to serve you
without interruption. Your generator and PGE are
synchronized and operate in parallel , automatically
backing each other up. If one system fails, the other takes
over significantly increasing your reliability.
The DSG system is set up so your facility's loads are
automatically served first and then any excess power you
generate flows into the PGE system. For example, if your
building load is 1 000 kilowatts, and the generator is
putting out 1 500 kilowatts, only 500 kilowatts are serving
other PGE customers.
Q: Will the DSG program put more wear and tear on my
company s generator?
. The DSG program will probably extend the life of your
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backup/emergency power system. The program operators
regularly start up the generators and test them at full load.
More frequent full load runs are better for the diesel
engines. The tests also save the costs of load bank
testing and assure your organization that the equipment
will start up and function properly in a power outage.
Q: Will PGE help pay for new generators? Does PGE help if
m installing new generators?
. The generators themselves are not funded by PGE.
However, whether you are building a new facility with
backup power, adding generators or upgrading your
switch gear, PGE helps fund the installation. PGE
provides most of the cost for the latest generator control
and paralleling circuit breaker technology. Many high-tech
companies are already using this equipment for seamless
transition from generators to the power grid.
Q: Can you assure us that our emergency power system is
maintained to our standards of reliability and quality?
. Yes, your facility's staff and PGE will jointly decide on the
most qualified maintenance provider. This may be your
existing provider, your own staff or a new provider that
best meets your needs. Our agreement with maintenance
providers will include annual performance reviews and if
they are not performing at the levels we expect, we can
agree to change providers.
Q: Who is responsible for maintenance and repair?
. This is another win-win aspect of the program for
participating businesses, institutions and PGE. All regular
maintenance and any repair bills are paid by PGE. The
utility sees this as a reasonable cost to assure that your
generator is available at all times to participate in the
program, and it lowers your cost of doing business. We
estimate that this may easily save $50 000 to $100 000
over a five-year period.
PGE has created the DSG program with the highest
standards. Should your equipment fail to function as
required for your emergency/backup use, the
maintenance provider selected by you and PGE will begin
diagnosing the problem within four hours of notification. If
appropriate, the provider will then repair or replace the
equipment (at PGE's discretion) with comparable items as
required to meet your system s needs.
Q: Who pays for fuel?
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PGE - Large & Industrial Accounts: Dispatchable Generation F
. PGE pays for fuel regardless of whether the fuel was used
only for your needs or to serve the utility distribution
system. We do require the use of transportation grade
low-sulfur, diesel fuel.
Q: Can I still participate if I choose to buy power from an
independent supplier?
. Under Oregon s restructuring law, you can choose to
purchase your power from an independent provide. If you
make this choice, you can still take advantage of the DSG
program. You , PGE and your independent supplier would
negotiate an agreement, which would provide accurate
billing and properly account for the power used by your
facility, even when the generators are operating.
Q: Are there any regulatory or tax issues I should be
aware of?
Participating in the DSG program will not affect your
taxes. Because PGE will own a portion of the system of
which the generators are a part, the output of the
generators will be considered PGE power. PGE will also
handle all power regulation issues related to the operation
of your DSG power system.
Q: Under what circumstances would my organization have
to reimburse PGE for its investment?
. PGE is providing a significant investment to upgrade your
property. PGE is counting on your generation to maintain
an efficient power system and reduce costs. If you cancel
the agreement without cause or without proper notice
most of the equipment would typically remain with you
and you would be responsible for reimbursing PGE for the
value of that equipment.
If PGE cancels the agreement, PGE will remove any PGE
equipment and leave your facility in such condition as will
enable you to operate the generators for your own backup
use. Under these circumstances, no equipment
reimbursement would be required.
Q: Can a business cancel the DSG agreement?
In the unlikely event that PGE fails to maintain or repair
the equipment as required in the agreement, you may
cancel the contract before its normal expiration date. As
mentioned above, the maintenance service provider is
required to begin diagnosing a problem within four hours.
If a problem cannot be fixed within 30 days, you would
have the option to terminate the agreement.
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10/7/2006
PGE - Large & Industrial Accounts: Dispatchable Generation F
Q: What happens if the actual project cost is greater than
PGE's projections because of unforeseen conditions?
In a retrofit installation or for PGE owned equipment, PGE
will be responsible for all cost over-runs related to items
installed under the Dispatchable Generation Agreement.
With a new facility or new generator plant, where you
would have primary responsibility, we would negotiate an
appropriate cost sharing solution.
Q: How is PGE handling the environmental impact of the
DSG program?
. PGE cares a great deal about the environment. We will be
installing oxidation catalysts on all DSG program engine-
generators. These catalysts significantly reduce carbon
monoxide (CO), hydrocarbons (HC) and odor from the
diesel engines. Research is also underway to explore new
ways to reduce nitrogen oxides (NO ) in the engines we
use for the program. PGE is also doing extensive
research on the use of dual fuels. This could create
opportunities to burn natural gas instead of diesel oil in
many generators, significantly reducing emissions into the
air. Every generating system in the program is issued a
permit by the Oregon Department of Environmental
quality, assuring that the engines are operating within
standards.
Q: How can I learn more about PGE's Dispatchable Standby
Generation program?
. Please contact your PGE representative or e-mail
You may also call Mark Osborn, DSG program manager
at 503-464-8347.
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EXHIBIT No. 220
Case No. IPC-06-
READING, ICIP
Portland General Elecuic : Customer News: Power Report Page 1 of 6
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~!:P.~~.................Power Report
August/September 2006 Power Report Newsletter
Articles in this issue:
Motor tips
Oregon ocean power
Power supply: NW utilities compared
Boardman Plant update
PGE's own energy saving
Wind's a winner... when it blows
Hospital goes 100% wind
Standby generators help out in heat wave
Squeezing every dollar: Hydro savings
Upcoming seminars
Motors: Rewind or Replace
When to upgrade to a premium-efficiency model
When you have a motor that fails, you re faced with deciding whether to repair it 0
That decision depends on a number of factors, including repair versus replacemer
efficiency of the existing industrial motor, availability of a new motor and the cost (
If you are ready to replace a motor, it's a good idea to consider
upgrading to a premium-efficiency model. When you install a
qualifying motor, 200 hp or less, you may be eligible for a cash
incentive of $1 O/hp from Energy Trust of Oregon. These
incentives do not require pre-approval , but applications should be
submitted as soon as practical after purchase. (Motors over 200
hp are also eligible for incentives, but they must be approved by
Energy Trust prior to installation.
Bottom line , the incentive can help provide a good payback on
motors that operate a lot, and a premium-efficiency motor can
reduce your monthly energy usage and operation costs.
Even if you don t need to replace motors now, it's a good idea to
plan ahead " says Doug Findlay of PGE Customer Technical
Services. "Look at your applications , identify what you will need
and pencil it out. That way, when replacement time comes, you
can move quickly and feel confident you re making the right
decision.
Energy expert 001
assists customers
with motors.
PGE can help you with this process by looking at your current motor systems to hi
identify ways to maximize energy efficiency. Just contact your PGE representativE
http://www.portlandgeneral. biz/CustomerN ews/powerReport.aspx 10/7 /2006
Portland General Electric: Customer News: Power Report Page 5 of 6
The Clean Wind purchase helps in ~~OO'~'. ,~ u,~u 'OO~ oou",.... ~ ~'~~oo~~,.
Providence Newberg Medical Center's application to become a LEED (Leadershi~
and Environmental Design) Gold certified building. This certification by the U.S. G
Council would make the structure the first LEED Gold hospital in the country. The
presents this award only to those buildings that meet the highest standards of low
environmental impact and energy efficiency.
Building a green structure and using renewable power supports health care indu~
for patient care and healthy workplaces and demonstrates the benefits of environr
friendly practices to the public " says Larry Bowe, chief executive of Providence
Medical Center.
Learn more about the Providence purchase in our News Room. To learn more ab
benefits of Clean Wind power for your organization, talk with your PGE represent"
Standby generation picks up extra load during heat wave
As the demand for power rose with the soaring temperatures on July 24, PGE's D
Standby Generation program rolled into action. PGE called upon a network of star
. generators at companies throughout our service territory to help meet peak demal
We were able to supply 25.5 megawatts of electricity during a period
of peak load requirements " says Mark Osborn, who manages PGE'Dispatchable Standby Generation program. Salem dual-
This innovative distributed resource program helped PGE avoid spot
purchase power costs on the open market, where supplies were
extremely tight and the rising temperatures pushed megawatt prices
into the stratosphere.
The program puts a customer's standby generators to work for up to 400 hours ar
meet peak power demands - and PGE picks up all maintenance and fuel expem
More than 33 generators at 21 organizations are enlisted in the program. Most rec
generators at the Oregon Military Department's new headquarters in Salem becar
dual-fuel (diesel and natural gas) generators in the program. Read more about Di!
Standby Generation
H dro efficiencies help control costs
PGE works hard to control costs and serve customers efficiently. i
few examples of how we are saving money in our hydro operation
Pelton Hydro Plant: New switches speed transformer repairs, save labor CO!
At our Pelton plant, new switches were installed that make it much faster to switc~
transformer to a backup transformer when repairs are needed. The new equipmer
the time-consuming task of having to move the massive transformers around. Thi~
and overtime costs and reduces the amount of generation lost during maintenancI
About $15 000 for each future maintenance event.
Portland Hydro Project:
$2 million savings, plus reliability improvements
In the Bull Run watershed the source of Portland's drinking water - PGE operi
small dams owned by the City of Portland's water bureau. This spring, PGE comp
http://www.portlandgeneral.bizlCustomerNews/powerReport.aspx 10/7/2006
EXHIBIT No. 221
Case No. IPC-E~06-
READING, ICIP
Portland General Electric
2002 Integrated Resource Plan
Final Action Plan Update
Portland General Electric
March 23, 2006
PGE 2002 IRP Final Action Plan Update
objective of the Commission to remove barriers to the development of
distributed generation.
We continue to evaluate these issues, participate in local and regional
forums, and maintain an open dialogue with customers and interested
parties with respect to CHP. By doing so, we hope to increase our
awareness and understanding of the market potential, assess ways to
overcome barriers and seek technically viable and cost-effective CHP
opportunities to help meet our future resource needs.
Dispatchable Standby Generation
In the 2002 IRP we listed Dispatchable Standby Generation (DSG) as one
of our capacity resources. 1 As part of our acknowledged action items, we
committed to developing a 30 MW "virtual peaking plant" by the winter
of 2006-07. By the end of 2005 we had 29 MW on line and available for
dispatch. We have another 16 MW signed or under construction, for a
total of 45 MW of dispatchable standby generation available by the end of
2007.
We have found that customer enthusiasm and adoption rates for this
program have been higher than we originally anticipated. The high
levels of customer interest and participation have allowed PGE to
establish one of the most successful customer-based capacity programs of
its kind. This option, because of its distributed nature, also provides
reliability benefits for PGE and the host customers.
DSG is a high quality, cost-effective capacity resource that also serves as
reserve capacity. The projects pursued were either new installations or
major rehabilitations that represented lost opportunities if the
construction window was missed.
Since we have received inquiries and further interest from customers
beyond our current implementation, we believe that the DSG program
could potentially be expanded to help meet more of PGE's future capacity
needs. Ultimately, we may be able to develop as much as 100 MW,
depending on future economics and customer adoption rates.
Because this resource relies on the operation of diesel-fueled, back-up
generators at non-residential customer sites, we are limited in the number
of hours per year that we can operate each plant. However, this
limitation does not impair the effectiveness of DSG as a capacity option
1 See Appendix K, p. 179.
PGE 2002 IRP Final Action Plan Update
as we only intend to dispatch the resource during infrequent super-peak
events and to meet PGE and customer reliability needs.
Energy Trust of Oregon Master Service Agreement
In 2005 PGE executed a Master Funding Agreement with the ETa that
will expedite our acquisition of future renewables projects. The
agreement designated ETa funds to assist PGE in acquiring new
renewable energy resources by subsidizing any above-market costs. The
agreement also outlines all key terms and conditions for requesting,
securing and administering subsidy funds for such projects.
Joint Letter to Oregon s Delegation
We participated in a joint letter to Oregon s federal congressional
delegation urging the renewal of the PTC for renewables. Both u.S.
Senators voted for the subsequent extension. The other co-signers
included: Puget Sound Energy; PacifiCorp; NorthWestern Corporation;
Citizens' Utility Board of Oregon; and the Washington State Office of
Community, Trade and Economic Development (see appendix).
We joined the Legislative Committee of the American Wind Energy
Association (A WEA) in early 2005 and worked with them and other
members to secure PTC extension. We also visited our Congressional
delegation on the Ways and Means Committee twice in Washington, D.
to discuss these issues.
EXHIBIT No. 222
Case No. IPC-06-
READING, ICIP
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.
REQUEST FOR PRODUCTION NO. 46: Please describe any efforts Idaho
Power has made to look into the use of emergency generators (i.e. emergency back-up
generation installed throughout the region in commercial or industrial facilities) to meet or
reduce peak loads. Please provide any relevant analyses, documentation , and
correspondence.
RESPONSE TO REQUEST NO. 46:
During the energy crisis in 2001 , Idaho Power made customer inquiries
regarding the installation of back-up generators installed in our service territory.
However, no documentation of these inquiries has been retained.
During this same time period, Idaho Power implemented the Energy Buy
Back program (Schedule 22) that allowed commercial and industrial customers an
opportunity to voluntarily reduce their electric loads in exchange for payment from the
Company. Schedule 22 was available to customers who were able to reduce their
electric load by at least 1 000 kW at one metering point. Eligible customers who were
known to have back-up generation were targeted for program participation. The
program expired in March 2002. A copy of the Program Performance Report filed with
the Commission in May 2002 is attached hereto as "Response to Request No. 46.
The response to this request was prepared by Maggie Brilz
, .
Manager
Rate Design, Idaho Power Company, in consultation with Monica Moen , Attorney
Idaho Power Company
DATED at Boise, Idaho, this 22nd day of September 2006.
MONICA B. MOEN
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
Page 2
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 22nd day of September 2006, I served a true and
COITect copy of the within and foregoing IDAHO POWER COMPANY'S RESPONSE TOTHE THIRD PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO
POWER upon the following named parties by the method indicated below, and addressed to thefollowing:
Commission Staff -X-Hand Delivered
Donovan Walker US. Mail
Deputy Attorney General Overnight Mail
Idaho Public Utilities CoITlIIllssion FAX472 W. Washington (83702)-X.Email Donovan.walker(g)puc.idaho.govO. Box 83720
Boise, Idaho 83720-0074
Industrial Customers of Idaho Power Hand Delivered
Peter J. Richardson, Esq.-X-US. Mail
Richardson & O'Leary Overnight Mail
515 N. 27th Street FAX
O. Box 7218 -X. Email peter(g)richardsonandolearv.comBoise, Idaho 83702
Don Reading Hand Delivered
Ben Johnson Associates -X-US. Mail
6070 Hill Road Overnight Mail
Boise, Idaho 83702 FAX
-X.Email dreading(g)mindspring.com
~(b.
Monica B. Moen
CERTIFICATE OF SERVICE, Page
IDAHO POWER COMPANY
CASE NO. IPC-O6-
THIRD PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO. 46
An IDAEORP Company
Idaho Power Energy Exchange
Schedule 22
Program Performance Report
May 2002
Background
On February 12, 2001, Idaho Power Company ("Company ) filed anapplication (Case No. IPC-E-01-04) with the Idaho Public Utilities Commission ("IPUC"requesting approval of Tariff Schedule 22, Energy Buy Back Temporary Program
("Energy Exchange ). The IPUC approved Schedule 22 in Order No. 28707 dated April, 2001.
The Energy Exchange was a voluntary load reduction program for commercial
industrial or large irrigation customers. Through this program , Idaho Power Companywould credit a customers account for reducing electrical load during specific hours. The
goal of this program was to reduce Idaho Powers system peak(s) and to reduce the
amount of high priced wholesale power the Company purchased. The Energy Exchangewas intended to benefit the Company and the participating . customers, as well as all
Idaho Power customers.
The Energy Exchange was modeled after similar successful programs at otherutilities in the Northwest and across the country. Through the Idaho Power Energy
Exchange, an interactive website, Idaho Power would declare an Exchange Event. An
Exchange Event was a set of hours during which Idaho Power would ask participants to
reduce their electric load during specific hours on specific days in exchange for a credit
on their bill. Hourly prices would be approximately one-half of wholesale market prices.
Exchange Events would be announced for the day of, day ahead, or two days ahead of
an Event. Participating customers could then specify through the Idaho Power Energy
Exchange which hours and days that they wished to reduce their load. Idaho Power
could then accept or reject the offer of load reduction. Exchange Events were
guaranteed to be a minimum of two consecutive hours and if they participated
customers would commit to a load reduction for at least two consecutive hours.
Participating customers were required to be able to reduce their electrical load by
000 kW at each meter point, have Internet access, and have interval meters.
Participants were encouraged to keep their load reduction within 15% of the amount
they committed to reduce. The Tariff stipulated that Idaho Power would credit
customers for up to 115% of the committed reduction but penalize them for reducing
their load by less than 85% of the committed reduction.
May 2002
- 1 -
Results
Idaho Power has chosen not to request an extension of Tariff Schedule 22. A
series of events in the western wholesale energy market, a lack of participation, and the
costs of continuing the Idaho Power Energy Exchange have made this programeconomically impractical to continue.
To facilitate the Energy Exchange Idaho Power contracted with a third partyservice provider, Apogee Interactive, to design and administer the Idaho Power EnergyExchange website. Idaho Power and Apogee Interactive finalized a services agreement
on June 11 , 2001. The Idaho Power Energy Exchange became active on June 15, 2001.
On June 19, 2001 the Federal Energy Regulatory Commission (FERC) approved
the west-wide mitigation plan for wholesale electric markets. In this plan FERC cappedwestern wholesale electric prices at a level based on the market clearing prices in
California during stage 1 emergencies. This price cap was and still is approximately $91
per megawatt hour. In the Energy Exchange, Idaho Power anticipated offering
customers hourly bid prices equal to approximately one-half of wholesale market price
during Exchange Events. Within this bid price framework, the western price cap of $91
per megawatt hour resulted in a maximum bid price of about $45 per megawatt hour.
This price was too low to make it economically feasible for participating customers to
reduce their load. While the approval of the western price caps lowered western
wholesale electric prices, overall energy conservation in the Northwest and other load
reduction programs reduced demand for wholesale power. These events helped make
the Idaho Power Energy Exchange unnecessary as a price and load reduction tool.
To market the Energy Exchange, Idaho Power's delivery service representatives
identified the 35 eligible customers most likely to participate and solicited their
participation in this optional program. Representatives from Idaho Power gave formal
Energy Exchange presentations to three special contract customers and several large
power users. The goal for the Company was to have ten meter points active in the
Idaho Power Energy Exchange.
Two companies signed agreements to participate in the Idaho Power Energy
Exchange. Between these two customers, there were three service points in Idaho and
two in Oregon. These five service points had the combined potential of providing a
maximum of approximately 13 MW of load reduction. The level of reduction is an
approximation based on historic hourly load levels and the customer's reduction
projections.
While marketing this program, Idaho Power found that unlike some of the other
utilities that had initiated successful energy exchanges, the characteristics of Idaho
Power's customer base make voluntary load reduction for short periods of a few hours
per day difficult and usually not economically viable. Many of Idaho Power's large power
users are food processors. These companies have spoilage issues, cold storage capacity
limitations, inflexible shipping and delivery schedules, and maintenance schedules that
prohibit them from participation in this type of program. The Company found that most
May 2002
- 2-
. .
of the large power users in Idaho Power's service territory do not have any load
monitoring equipment, a fact that made accurate load reduction difficult Several
companies required earlier notification of Exchange Events, as well as, reduction of
loads for longer periods to allow more time for ramping loads up or down than the
design of the Energy Exchange provided. Some companies hesitated to participatebecause of labor management challenges during periods of load reduction. Others
expressed the view that the electric energy component was such a small part of their
overall cost of production that compensation for load reduction generally did not make
good economic sense.
Idaho Power paid Apogee Interactive $23 500 to design, program, and
administer the Idaho Power Energy Exchange for the first year. For this initial fee, Idaho
Power could have up ten customers (meter points). active in the Energy Exchange and
could have up to ten Exchange Events per customer without additional fees. The
contract with Apogee Interactive ended May 1, 2002. The cost to Idaho Power to keep
the Idaho Power Energy Exchange in 'warm stand-' mode until May 1 , 2003 would
have been $10 000. Warm stand-by would have kept the Idaho Power Energy Exchange
website accessible but not interactive. The cost for Idaho Power to activate the Energy
Exchange during the contract year would have been $10;000 in additional fees.
Considering the results of the first year of the Energy Exchange, Idaho Power did not
believe it prudent to renew this contract.
When Idaho Power Company filed its application, the below-normal stream
flows in the Snake River and its tributaries, coupled with the volatile wholesale energy
market in the western United States, had created a situation where Idaho Power
believed it would be cost-effective for the Company tQ undertake this program. Because
of changes in wholesale electridty market conditions, the western price caps, and the
composition of Idaho Power's customers , Idaho Power found that the Energy Exchange
was not useful method of load reduction.
Idaho Power Company did gain valuable knowledge and experience in
administering and managing load reduction programs like the Energy Exchange. If the
wholesale electricity market conditions were to change and if the Company deemed it .
necessaryl electric load reduction agreements could be established with individual
customers with regulatory approval as has been done in the past. Considering the fact
that few customers would be interested in or capable of this type of load reduction
agreement, an interactive website would not be essential and the load reduction could
be adminiStered with normally available resources.
May 2002
- 3-
EXHIBIT No. 224
Case No. IPC-06-
READING, ICIP
. ,
BARTON L. KLINE ISB #1526
MONICA B. MOEN ISB #5734
Idaho Power Company
O. Box 70
Boise, Idaho 83707
Phone: [phone]
FAX: [phone]
bkline ~ idahopower.com
mmoen ~ idahopower.com
g:;,;::
"rl:::c:?ll\
' ';--.,' ! --"..-",: \"'
I!!)
11'1 I! i' f
U u ~JIBY
Attorneys for Idaho Power Company
Express Mail Address
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION OF
IDAHO POWER COMPANY FOR
MODIFICATION OFTHE LOAD
GROWTH ADJUSTMENT RATE WITHIN THE POWER COST
ADJUSTMENT METHODOLOGY
CASE NO. IPC-06-
IDAHO POWER COMPANY'
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF NW
ENERGY COALITION TO IDAHO
POWER COMPANY
GGMES-NGW--Idahe Power Company ("Idaho Power" or "the Company ) and , in
response to the First Production Requests of NW Energy Coalition to Idaho Power
Company dated August 8, 2006, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 1
REQUEST FOR PRODUCTION NO.
Please state Idaho Power company s IJormalized system loads for each year
starting with year 1995 through 2005.
RESPONSE TO REQUEST FOR PRODUCTION NO.
Idaho Power company s normalized system loads for 1995 through 2005 in MWh'
are as follows:
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
14656029
15141574
15180588
14758836
15240817
15837958
15759779
14276689
14193837
14536634
14819152
The response to this request was prepared by Gregory W. Said, Manager of
Revenue Requirement, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 2
REQUEST FOR PRODUCTION NO.
Please state Idaho Power Company s total amount of spending on demand-side
management ("DSM") programs or initiatives (including payments to the Northwest
Energy Efficiency Alliance ("NEEA") for each year starting with year 1995 through 2005.
RESPONSE TO REQUEST FOR PRODUCTION NO.
The following table details Idaho Power Company s total amount of spending on
demand-side management ("DSM") programs or initiatives (including payments to the
Northwest Energy Efficiency Alliance ("the Alliance )) for each year starting with year 1995
through 2005 as provided in the Company's respective DSM Annual Reports (previously
termed Conservation Plan) filed with the Commission.
Total System
(nominal $)
1995 186 558
1996 $4 350 128
1997 $3 189 173
1998 $2 681 668
1999 $2 127 840
2000 $1 609 217
2001 $1 694 314
2002 $2 143 103
2003 $2,482 972
2004 $3 707 280
2005 $6 700 973
Notes:
Expenses are reported on a cash basis.
-- .----------.- .
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 5
EXHIBIT No. 225
Case No. IPC-06-
READING, ICIP
REQUEST FOR PRODUCTION NO.
Please state the total amount of estimated energy savings (expressed as average
megawatts) Idaho Power Company and its customers have achieved as a result of DSM
programs (including any savingsj achieved as a result of NEEA programs) for each year
starting with year 1995 through 2005.
RESPONSE TO REQUEST FOR PRODUCTION NO.
The following table details the total amount of estimated energy savings
(expressed as average megawatts) Idaho Power Company and its customers have
achieved as a result of DSM programs (including any savings achieved as a result of
Alliance programs) for each year starting with year 1995 through 2005 as provided in the
company s respective DSM Annual Reports (previously termed Conservation Plan) filed
with the Commission.
Year
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
005
Annual Energy
Savings
excluding
Alliance
(Mwa
2.42
Alliance
Reported
Energy
Savings *
(Mwa)
29**
Total
Annual
Energy
Savings
(Mwa)
Notes:
* Alliance Savings not available prior to 2004. The Alliance savings based on regional load allocation
percentage of 6.5%.
Preliminary estimate from the Alliance, February 24, 2006
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 9
The response to this request was prepared by Tim Tatum , Senior Analyst , Idaho
Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 10
EXHIBIT No. 226
Case No. IPC-06-
READING , ICIP
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J
QUANTUM
CONSULTING
IDAHO POWER DEMAND-SIDE MANAGEMENT
POTENTIAL STUDY
FINAL
Prepared for
Darlene Nemnich
Project Leader
Customer Relations and Research Department
Idaho Power
1221 West Idaho Street
Boise, Idaho 83702
Prepared by
QUANTUM CONSULTING INc.
2001 Addison Street, Suite 300
Berkeley, CA 94704
510-540- 7200
with assistance from
KEMA-XENERGY, Inc.
P1992
November 2004
Section
TABLE OF CONTENTS
EXECUTIVE SUMMARY
INTRODUCTION
ENERGY EFFICIENCY METHODS
2.4
3.4
Characterizing the Energy-Efficiency Resource
Overview of Energy Efficiency Forecasting Method
Baseline and Measure Data Development
Estimation of Technical Potential and Development Energy-
Efficiency Supply Curves
Estimation of Economic Potential
Estimation of Maximum Achievable, Program, and Naturally
Occurring Potentials
DEMAND RESPONSE POTENTIAL METHODS
Overview of Demand Response Forecasting Methods
DR Data Development
Estimation of "Economic" Potential for Demand Response
Forecasting Program Impacts
ENERGY EFFICIENCY PEAK DEMAND AND ENERGY SAVINGS
POTENTIAL RESULTS
Technical and Economic Potential
Energy Efficiency Supply Curves
Forecasts of Achievable Program Potential Scenarios
Page
ES-
DEMAND RESPONSE POTENTIAL RESULTS
Economic Potential
Forecast Scenarios
DISCUSSION OF UNCERTAINTY
Quantum Consulting Inc.Table of Contents
4. ENERGY EFFICIENCY PEAK DEMAND AND ENERGY SAVINGS POTENTIAL RESULTS
In this section we present summary results of the Idaho Power energy efficiency potential
analysis for the residential and commercial sectors. First, economic and technical potential are
discussed. Next, we present summary energy efficiency supply curves, which are an alternative
method of presenting forecasted potentials. Finally, we present scenario forecasts for achievable
energy efficiency potential. Definitions of the different types of energy efficiency potential and
methods used to develop them are provided in Section 2 of this report. Section 2 also presents
the baseline estimates used in our analyses.
At the outset of this study, the primary focus was on peak demand reduction and the scope was
limited to measures with impacts on summer peak. In a later, second phase, the scope was
expanded to look at all measures with the potential to provide cost-effective energy savings.
Where possible, the figures in this section delineate the peak demand and energy savings
associated with the two phases. In cases where there is no distinction, the figures represent the
results of the second phase. Because the results of the first phase were provided to the resource-
planning group at IPCo, identical graphs based only on the results of the initial phase are
provided separately in Appendix G.
TECHNICAL AND ECONOMIC POTENTIAL
In Exhibits 4-1 and 4-2 we present our overall estimates of total technical and economic
potential for peak demand and electrical energy in the residential and commercial sectors in the
Idaho Power territory. Technical potential represents the sum of all savings achieved if all
measures analyzed in this study were implemented in applications where they are deemed
applicable and physically feasible. As described in Section 2, economic potential is based on
efficiency measures that are cost-effective based on the total resource cost (TRC) test, a benefit-
cost test used to compare the value of avoided energy production and power plant construction
to the costs of energy-efficiency measures and program activities necessary to deliver them. The
value of both energy savings and peak demand reductions are incorporated into the TRC test.
Overall and by Sector
If all measures analyzed in this study were implemented where technically feasible, we estimate
that overall technical demand savings would be roughly 551 MW, about 33 percent of projected
combined residential and commercial peak demand in 2013. If all measures that pass the TRC
test were implemented, economic potential savings would be 384 MW, about 23 percent of total
residential and commercial demand in 2013. Technical energy savings potential is estimated to
be roughly 1 917 GWh, about 21 percent of total residential and commercial energy usage
projected in 2013. Economic energy savings are estimated at 1 107 GWh, about 12 percent of
base residential and commercial usage. The technical and economic potential estimates are
shown by sector and vintage (existing stock versus new construction) in Exhibits 4-3 through 4-
5. The largest share of both technical and economic savings is in the residential existing stock.
Quantum Consulting Inc.Efficiency Potential Results
Exhibit
Technical and Economic Potential (2013)
Peak Demand Savings-
Exhibit
Technical and Economic Potential (2013)
Energy Savings-GWh per Year
600 500
100
. Phase
- - - - - - - - - - - -
liE Phase I 000
--------- --------------
500
500
-------
400
~ 1 500
-"" 300t'CICIIc..C) 1 000
200
Technical Economic Technical Economic
Exhibit
Technical and Economic Potential by Sector and Vintage, Peak Demand Savings (2013)
350
-------------------------------
. Phase
WI Phase I300
250
-------------- --- ---------- ----------------- -.-------
5 200
.:.:
ItI
~ 150
100
-----
Tech. Econ-
Residential
Existing
Tech. Econ-
Residential
New
Tech- Econ-
Commercial
Existing
Tech. Econ.
Commercial
New
Quantum Consulting Inc.Efficiency Potential Results
Exhibit
Technical and Economic Potential by Sector and Vintage, Energy Savings (2013)
1200 =::J
. Phase II
EiI Phase I
200
-.-----------------------------..----
1000
800
..r=
co 600
0:(
400
Tech. Econ.
Residential
Existing
Tech. Econ.
Residential
New
Tech. Econ.
Commercial
Existing
Tech. Econ.
Commercial
New
Exhibit 4-
Phase II Technical and Economic Potential Estimates
GWh
Sector and Vintage Technical Economic Technical Economic
Residential - Existing 299 201 102 554
Residential - New 139 102 373 235
Commercial - Existing 373 252
Commercial - New
Total 551 384 917 107
Quantum Consulting Inc.Efficiency Potential Results
Exhibit 4-
Phase Technical and Economic Potential Estimates
-c ~
GWh
Sector and Vintage Technical Economic Technical Economic
Residential - Existing 237 189 520 444
Residential - New 117 216 173
Commercial - Existing 265 179
Commercial - New
Total 442 337 060 851
End Use Potential
Residential economic potential is presented by key end use in Exhibit 4-6. Lighting, cooling,
and clothes washing dominate economic energy savings, while cooling makes up the vast
majority of peak demand impacts. Exhibit 4-7 shows commercial sector economic potential
estimates by end use. Lighting is the largest contributor in terms of both energy savings
potential and peak demand savings potential, cooling is the second largest contributor to
commercial economic peak demand savings.
Potential by Building Type
Exhibit 4-8 displays residential economic potential by building type. Single':'family homes
account for the vast majority of potentiaL Commercial sector economic potential is displayed
by building type in Exhibit 4-9. The largest contributors to both GWh and peak MW potential
are small offices, food stores, retail establishments, hospital/health care facilities, and
miscellaneous" buildings.
ENERGY EFFICIENCY SUPPL CURVES
Energy efficiency supply curves for energy and peak demand savings are shown in Exhibits 4-
10 and 4-11, respectively. The supply curves show the distribution of measure-level potentials
by relative cost. Energy supply curve summary data are presented Exhibits 4-12 through 4-
for the residential existing, residential new construction, commercialuex:isting and commercial
new construction vintages. Note that these values are aggregated across market segments and
that individual segment results can vary significantly from the average values shown.
addition, it is important to recognize that cost-effectiveness, as defined by the TRC test, cannot
be determined exclusively from these curves because the value of both energy and demand
savings must be integrated when comparing to supply side alternatives. Measure-level TRC
estimates are provided in Appendix E.
Quantum Consulting Inc.Efficiency Potential Results
EXHIBIT No. 228
Case No. IPC-06-
READING, ICIP
\Juarterly ReVIew August 2006 Page 1 of 4
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iii.
"'-'
.tiJf.uf
..
Corp.
Welcome to Avista Corp.
providing energy and energy-related services
Corporate News
Knight
Investor Update
Director Jessie Knight steps down from Avista
board
In June, Jessie Knight resigned from Avista Corp.'s board of directors
following accepting a position as an executive officer of Sempra Energy
(NYSE: SRE).
Jessie served on the board for seven years and was a great asset during
some difficult times,said Avista Corp. Chairman and Chief Executive Officer
Gary Ely. "Although we are sorry to see him go, we wish Jessie the greatest
success at Sempra and in all of his future endeavors."
A replacement has not yet been selected for Mr. Knight's seat on Avista
board.
Read more about this.
Q2 2006 and Year-to-Date Earnings on track
For the second quarter of 2006, Avista Corp. reported net income of
$13.5 million, or $0.27 per diluted share, a decrease over the same
period last year. Year-to-date for the six months ended June 30, 2006
the company posted net income of $45.0 million, or $0.91 per diluted
share, an increase of $16.2 million, or $0.32 per diluted share, over
results in the same period of 2005.
We are on track for a good year in 2006 due to
improved year-to-date earnings from Avista
Utilities and the continued trend of earnings
growth from Advantage IQ: said Avista
Chairman and Chief Executive Officer Gary G.
Ely.
We are satisfied with Avista Energy
operations, which are on track for the year as
measured on an economic basis. However, its
reported results continue to differ from economic
results due to the required accounting for certain
contracts and assets under management " Ely
added.
Ely
Improved stream flows and hydro electric generation during the first two
http://www.avistacorp.com!email/comm/quarteriy/index.htmi
Financial Resources
) Avista Corp. Q2 2006
Income Statement
) Avista Corp.Q2 2006
Balance Sheet
) Avista Corp. Q2 2006
Financial and Operating
Highlights
) Avista Corp. Stock
Quote/Chart
) Avista Corp. 2005
Summary Annual Report
Avista Corp.
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10/7/2006
Quarterly Review August 2006 Page 3 of 4
We believe the modified ERM better balances the interests of the
company and our customers," said Scott Morris, president and chief
operating officer of Avista Corp. "This will also help reduce the volatility in
our earnings that has been caused by variations in the prices for fuel and
purchased power, as well as the availability of hydro generation.
Monis
Calls for conservation keep power flowing
Spokane, Wash.
As is proving true throughout the country, this
has been a hot summer in Avista Utilities
service territory.
On July 24, after several days of extremely high
temperatures in eastern Washington and
northern Idaho, Avista s retail native load
peaked at 1 642 MW, an all-time high for the
utility's summer load. Due to the high loads
coupled with some short-term plant outages,
unplanned power purchases in the wholesale
market were needed. Short-term prices were
extremely high, as electrical supplies were
stretched across the West due to the record
high temperatures and strong demand.
To minimize the amount of unplanned purchases, Avista reached out to customers through personal contact
and the media and requested their voluntary conservation of energy on both July 24 and 25. Customers
responded quickly and effectively, cutting load by approximately 30 megawatts. The reduction in loads not
only contributed to our ability to continue to provide reliable service to our customers; it also reduced the
overall cost of providing power during this time period.
If you are not yet a subscriber to this newsletter and would like to receive it via e-mail, please contact Avista
News
This quarterly review contains forward-looking statements, including statements regarding the company s current
expectations for future financial performance and cash flows, capital expenditures, the company s current plans
or objectives for future operations, future hydroelectric generation projections and other factors, which may affect
the company in the future. Such statements are subject to variety of risks, uncertainties and other factors, most
of which are beyond the companys control and many of which could have significant impact on the company
operations, results of operations, financial condition or cash flows and could cause actual results to differ
materially from the those anticipated in such statements.
The following are among the important factors that could cause actual results to differ materially from the
forward-looking statements: weather conditions, including the effect of precipitation and temperatures on the
availability of hydroelectric resources and the effect of temperatures on customer demand; changes in wholesale
energy prices that can affect, among other things, cash requirements to purchase electricity natural gas for retail
customers and natural gas fuel for electric generation, as well as the market value of derivative assets and
liabilities and unrealized gains and losses; volatility and illiquidity in wholesale energy markets, including the
availability and prices of purchased energy and demand for energy sales; the effect of state and federal
regulatory decisions affecting the ability of the Company to recover its costs and/or earn reasonable retum
including, but not limited to, the disallowance of previously deferred costs; the outcome of pending regulatory and
http://www.avistacorp.com!email/commlquarteriy/index.htmi 10/7/2006
_-.
EXHIBIT No. 229
Case No. IPC-06-
READING, ICIP
REQUEST FOR PRODUCTION NO. 38: With regard to the "Gogen and
Small Power Forecast (aMW)" referred to above in Request for Production No. 40 (sic 37),
please explain fully why the document shows no increase in Cogen and Small Power
generation after 2004. Additionally, please explain whether the Company forecasts any
increase in Cogen and Small Power generation after 2006 and beyond.
RESPONSE TO REQUEST NO. 38: The Gogen and Small Power
Production (CSPP) forecast is revised, at a minimum , annually. Because Idaho Power
has no control over the development and operation of CSPP projects, forecasting of the
actual energy output and monthly shape of the energy delivery from these facilities is
very difficult. In fact, in the case new CSPP resources under contract with Idaho Power
but not yet constructed , the actual online dates of these projects tend to vary
tremendously from their estimated online dates which makes it virtually impossible to
depend on any generation from these projects until such time as they have actually
come online and established some monthly generation history. As a result, the
Company only includes the estimated output from projects with signed and I PUC-
approved agreements in the GSPP forecast at the time the forecast is prepared.
Idaho Power currently has over 200 MW of nameplate rating of new GSPP
projects under contract that have not yet been constructed. The majority of these
projects are wind projects. , Thus, after applying an optimistic capacity factor of 30% to
this 200 MW of nameplate rating, the amount of generation anticipated from these
resources is approximately 60 MW on an annual average basis.
The majority of these projects estimate online dates in late 2007. Thus, in
the current forecast provided in response to Request No. 37, the additional generation
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
is forecasted to appear in calendar year 2008. However, it is important to note that
since Idaho Power has no control over the construction or operation of these or any
additional PURPA projects , this forecast will most likely change numerous times prior to
these projects coming online and after actual operation history has been established for
these projects.
The response to this request was prepared by Randy C. Allphin , CSPP
Contract Administrator, Idaho Power Company, in consultation with Monica Moen
Attorney Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
EXHIBIT No. 230
Case No. IPC-06-
READING , ICIP
REQUEST FOR PRODUCTION NO. 37: In Idaho Power's Response to
Staff's Request No. 81 , Idaho Power provided a copy of the Company s 2003 evaluation
manual for the peaking resource RFP. Page 29 of that document sets forth a "Cogen and
Small Power Forecast (aMW)." Please provide a copy of the Company s current "Cogen
and Small Power Forecast (aMW)." If one is not available, please fully explain why, and
how the Company s decisions with regard to the 2005 RFP took into account the
generation the Company would receive from Cogen and Small Power Producers.
RESPONSE TO REQUEST NO. 37: Please refer to the document
attached hereto as "Response to Request for Production No. 37.
The response to this request was prepared by Randy C. Allphin , CSPP
Contract Administrator, Idaho Power Company, in consultation with Monica Moen
Attorney II , Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 1 0
IDAHO POWER COMPANY
CASE NO. IPC- E-O6-
THIRD PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS
RESPONSE TO
REQUEST NO. 37
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REQUEST FOR PRODUCTION NO. 18: Should the Commission deny
Idaho Power's request for a certificate of public convenience and necessity, what supply or
demand reduction alternative options would the Company turn to in the summer of 2007
(sic )(2008)?
RESPONSE TO REQUEST NO. 18: Please refer to the Response to
Request No. 13. If the Commission denies Idaho Power s request for a certificate of
public convenience and necessity, Idaho Power would most likely consider several
alternatives to meet peak-hour loads during the summer of 2008. These alternatives
include: (1) additional firm market purchases and the associated transmission necessary
to deliver the energy to the east side of Idaho Power's system , (2) transmission system
expansions to increase import capacity, (3) expansion of the Irrigation Peak Rewards
program (which is already being investigated), (4) developing advertising messages that
ask consumers to reduce their peak-hour consumption, and (5) utilizing diesel or other
temporary gensets.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Planning and Operations, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST
OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 20
EXHIBIT No. 232
Case No. IPC-06-
READING , ICIP
REQUEST FOR PRODUCTION NO. 40: In response to ICIP Request for
Production No. 18 , Idaho Power describes five alternatives for meeting peak demand that
it would consider if the Commission denies its request for a certificate of public
convenience and necessity for the Evander Andrews plant. Please describe what efforts
the Company has made to determine the costs of those alternatives and any estimates the
Company has developed of the costs for implementing these alternatives instead of
constructing the Evander Andrews plant.
RESPONSE TO REQUEST NO. 40: The Company has not performed a
detailed analysis of the costs associated with the five alternatives described in ICIP
Request for Production No. 18. Preliminary estimates are available for a couple of the
alternatives.
Alternative 1 - Additional firm east side purchases. Idaho Power has
priced , but has not executed, any additional firm east side purchases for heavy load
hours in July 2007. On September 5 2006, the Mid-C to Four Corners price spread for
firm heavy load energy was $16 to $17/MWh. The higher Four Corners price is
representative of the premium Idaho Power may have to pay for an east side purchase.
In addition to the premium relative to Mid-C pricing, the cost to purchase energy
on Idaho Power s east side may require an additional expenditure of $5 - $7 to
compensate for the cost of transmission between Four Corners and Idaho Power s east
side interconnections.
Alternative 2 -Increase transmission system import capacity. Several
alternatives to increase import capacity were investigated in the 2006 I RP. Pages 57
through 62 of the Draft 2006 IRP (IRPAC Draft) discuss these transmission projects.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
Preliminary cost estimates (prepared by Power Engineers) range from $10.8 million to
reconductor the Lolo to Oxbow line to $282 million for the Bridger to Midpoint 500 kV
upgrade.
These upgrades were not originally envisioned as alternatives to replace
the new Evander Andrews combustion turbine. However, if the certificate of public
convenience and necessity for the Evander Andrews plant is denied , the projects
identified in the 2006 IRP are the type of longer-term transmission upgrades that Idaho
Power would consider to increase import capability. Idaho Power has submitted long-
term firm transmission requests to NorthWestern Energy, BPA, Avista, PacifiCorp and
Idaho Power. These requests establish a position in the transmission providers' queue
and initiate the process of determining system impacts and preparation of more detailed
cost estimates. However, with the exception of the Lolo to Oxbow reconductoring
project, Idaho Power does not consider these transmission upgrades a near-term
alternative due to construction lead-time.
Alternative 3 - Expand irrigation peak rewards program. Idaho Power is
currently planning changes to the Irrigation Peak Rewards Program. The Company
anticipates filing those proposed changes with the I PUC later this month. The proposed
program modifications are expected to result in an additional 4.5 MW (including losses)
of cost-effective load reduction during the Company s summer peak. A revised
Demand Credit structure and a reduced horsepower limit are the modifications largely
expected to drive the additional load reduction. Under the revised Demand Credit
structure, it is expected that approximately 13% of the customers currently
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
Page
participating with a one day Interruption Option will shift to a two or three day
Interruption Option.
The revised Demand Credit structure and the reduced horsepower limit
are also expected to improve customer satisfaction among program participants. In the
Company s survey of 2005 program participants , the most frequently recommended
improvement to the program was an increase to the Demand Credits. Improvements in
customer satisfaction is also anticipated among those customers with cumulative
horsepower between 75 and 99 that have wanted to participate in the program in past
years , but were not eligible.
In addition, the Company is considering a shift in the interruption period
from 4:00 p.m. to 8:00 p.m. to 3:00 p.m. to 7:00 p.m. The Company is currently
surveying participants concerning their preferences with respect to timing of daily
interruption periods. Changing the interruption period may increase program participant
satisfaction and possibly increase program participation. It is anticipated that these
changes will increase spending on this program by approximately $300 000 per year.
Alternative 4 - Advertising messages. No efforts to determine costs.
Alternative 5 - Add temporary gensets. No efforts to determine costs.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Operations and Planning, Idaho Power Company, in
consultation with Monica Moen , Attorney II , Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
Page
EXHIBIT No. 233
Case No. IPC-06-
READING, ICIP
Final March 30, 2005
IIlVIO POWER
An IDACORP Company
Idaho Power Company
1221 West Idaho Street
Boise, Idaho 83702
REQUEST FOR PROPOSALS
Peaking Resource
RFP Issue Date-March 30, 2005
Pre-Bid Conference-April 21 , 2005
Mountain Home, Idaho
Notice oflntent Due-May 5 , 2005
Proposals Due-June 2, 2005
RFP Website
IVWW. idahopo wer. com/aboutus/business/rfp/
Final March 30, 2005
Table of Contents
Scope of Request .........................................................................................
Alternative I-Evander AndrewsPower Complex..............................................
Alternative II-Bennett Mountain Power Plant...................................................
Alternative III................... .......... ...
........ .............................................................
General Information ...........................................................................................
RFPWebsite and Communication ................................................................
0 RFP Schedule...............................................................................................
General Proposal Guidelines ........................................................................
Instructions for Submitting a NOI
.....................................................................
Instructions for Submitting a Proposal...............................................................
Confidentiality ..................................................................................................
Minimum Credit Requirements.........................................................................
Limitation of Liability.........................................................................................
General Requirements.....................................................................................
Regulatory Provisions ....................................... .......................... ..................... 13
Environmental and Siting Requirements..........................................................
Reservation of Rights..... .................................................................................. 14
Performance Assurances.................................................................................
0 RFP Response Instructions ........................................................................
Project Information...........................................................................................
Company Information.......................................................................................
Detailed Description of Requested Proposal................................................... 19
Proposal Evaluation Procedure .......................................................................
Non-price attributes............................................... ................. .......... ............... 21
Evander Andrews Power Complex Site Information ...................................
Bennett Mountain Power Plant Site Information..........................................
Transmission and Interconnection Requirements ....................................... 27
DAHO POUVER
An lOACORP Company
Idaho Power Company
Peaking Resource RFP 2005
Page i
Final March 30 2005
Transmission Requirements and Constraints ..................................................
Resource Information Requirements ...............................................................
Transmission and Generation Interconnection Requirements .........................
Electrical Transmission Pricing Information ..................................................... 29
About Idaho Power Company..................................................................... 31
10.Turnkey Pricing Schedule .........................................................................
11.Notice of Intent to Bid Form (NOI)............................................................. 35
EWtO POWER
An IDACORP Company
Idaho Power Company
Peaking Resource RFP 2005
Ps!lEj/i
Final March 30, 2005
Scope of Request
Idaho Power Company (IPe) is seeking to acquire peaking electric generating resources on a
turnkey basis to expand its generation portfolio. IPC issues this Request for Proposals (RFP)
to solicit and screen, for subsequent contract negotiations, competitive proposals that will offer
exceptional value to IPC and its customers. By responding, Respondents are bound by the
terms and conditions of this RFP. IPC will not accept proposals ITom affiliates or subsidiaries
ofIDACORP.
Idaho Power Company identified a need for peaking resource electric generation in the Idaho
Power Company 2004 Integrated Resource Plan (IRP). Specifically, the 2004 IRP indicated
that Idaho Power Company would issue an RFP for 88 MW of peaking resource. Summary
details of this RFP are:
PRODUCT
A turnkey electric generation resource located within Idaho Power Company s service
territory to meet peak energy demands. Upon its completion, legal title of the generating
resource will be conveyed to Idaho Power Company. Power purchase agreements where
legal title of the generating facilities is not conveyed will not be considered in this RFP.
QUANTITY
Idaho Power Company anticipates acquiring 88 MW of delivered capacity under summer
conditions (900P; 20% relative humidity) at the elevation of the site identified in the
proposal. Based on present market conditions of combustion turbines, IPC will consider
acquiring resources ITom 80 MW to 200 MW.
TERM
Provisional Acceptance of the peaking resource must commence no later than April 1
2007.
The primary need for this resource is to provide electricity during peak energy
requirements for the Treasure Valley load center. Idaho Power Company invites
Respondents to offer proposals to locate turnkey generating facilities in the locations
described below.
Alternative I-Evander Andrews Power Complex
Idaho Power Company owns and operates the Evander Andrews Power Complex located
at Mountain Home, Idaho. The power plant has two simple cycle Siemens Westinghouse
W251B12A natural gas combustion turbines located on a 40-acre site. These turbines
have a nominal rating of 42 MW each at 90oP and 20% relative humidity at an elevation
of 3 112 feet above sea level. The power plant consists of an existing control room and
warehouse. Expansion of the existing control room will be required and is the
responsibility of the Respondent. Any expansion of the warehouse will be IPC
responsibility. Specific site information is included in Section 6.
.------.-- -
EWI) POWER
An IDACORP company
Idaho Power Company
Peaking Resource RFP 2005
Page 10'36.
- - - - _
__m
EXHIBIT No. 234
Case No. IPC-06-
READING , ICIP
REQUEST FOR PRODUCTION NO. 41: Please explain what assumptions
the Company is making for the future regarding the Conservation Reserve Enhancement
Program (CREP program), through which farmlands will be set aside , and irrigation pumps
turned off. Specifically, please describe any assumptions the Company is making
regarding decreased peak power requirements as compared to what they would be
without the CREP program. Please explain whether these assumptions affected the
Company s decisions with regard to the 2005 RFP or (the) Evander Andrews power plant.
RESPONSE TO REQUEST NO. 41: For planning purposes, Idaho Power
has not incorporated any specific assumptions in the 2006 IRP regarding the
Conservation Reserve Enhancement Program (CREP). On January 9, 2006 , Idaho
Power announced that it selected a Siemens Power Generation , Inc. proposal to build a
170-megawatt combustion turbine at the utility's Evander Andrews Power Complex
north of Mountain Home , Idaho. CREP was announced four months later in May of
2006. The CREP announcement had no effect on the Company s decision regarding
the 2005 RFP or the Evander Andrews plant.
In a more recent forecast , Idaho Power has incorporated an annual
energy reduction over the next 15 years (2007 through 2021) of approximately 4%
because of CREP.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Operations and Planning, Idaho Power Company, in
consultation with Monica Moen, Attorney II , Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
Page
EXHIBIT No. 235
Case No. IPC-06-
READING , ICIP
REQUEST FOR PRODUCTION NO. 31: In response to ICIP's Production
Request No., Idaho Power stated
Given the competitiveness of the pricing in the Bennett
Mountain RFP, Idaho Power was able to acquire the
incremental 85 MW of capacity (173 MW-88 MW = 85 MW) at
an extremely competitive price providing additional
generation at minimal cost while improving reliability for
customers.
Please explain how the "additional generation" acquired, above the 88 MW
called for in the 2004 IRP, will change IPC's projected need for future resources as set
forth in the 2004 IRP? For example, will the additional generation acquired obviate the
need for any specific RFPs that were called for in the 2004 I RP?
RESPONSE TO REQUEST NO. 31: The additional peaking capacity
acquired above the 88 MW called for in the 2004 IRP will allow Idaho Power to defer the
timing of future resources required to serve peak-hour loads. Although Idaho Power
does not typically assign or correlate changes in its resource plan to specific changes in
inputs such as load forecast, PURPA generation forecast, Snake River base flows, or
resource additions (or losses), the summation of these types of changes are considered
in total in the 2006 IRP.
The summation of changes considered in the 2006 IRP, including the 85
MW of additional peaking capacity provided by the larger Evander Andrews combustion
turbine , have allowed several of the resources selected in the 2004 IRP to be deferred.
First, the 100 MW geothermal resource originally planned to be online in 2008 in the
2004 IRP has been reduced to 50 MW and the online date deferred until 2009. Second
the 62 MW combustion turbine/distributed generation/market purchase resource
originally planned to be online in 2010 in the 2004 IRP has been eliminated altogether
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
Page 2
although market purchases are still anticipated in the 2006 IRP. Finally, the 12 MW of
CHP resources originally planned to be online in 2007 in the 2004 IRP have been
deferred until 2010.
The response to this request was prepared by Karl E. Bokenkamp,
General Manager Power Supply Operations and Planning, Idaho Power Company, in
consultation with Monica Moen, Attorney II , Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER
Page 3
EXHIBIT No. 237
Case No. IPC-06-
READING , ICIP
REQUEST NO. 72: Please elaborate on the highlighted portion of the
following statement from page 17, lines 2-6 of Said's direct testimony: "Although the
transmission system will require additional investment in order to integrate the Project
those improvements will provide capacity during all seasons and improve reliability of
the Company s transmission system." Quantify, if possible, seasonal increases in
transmission capacity and improvements in reliability.
RESPONSE TO REQUEST NO. 72:
The third unit at Evander Andrews is expected to run , for the most part
during the summer and winter peak periods of low-hydro years. The additional
transmission capacity associated with the required transmission improvements will exist
during all hours of all seasons. During those hours that the third unit at Evander
Andrews is not running, the additional transmission capacity is available for other uses
and their associated benefits.
Presently there are three 230 kV transmission lines making up the
Midpoint West transmission system and they all terminate in the vicinity of Boise Bench
substation. The addition of the transmission improvements associated with the Evander
Andrews project will create a fourth 230 kV transmission line from the Mountain Home
area to the Boise area. The addition of a fourth 230 kV line will increase the
redundancy and resulting reliability of the transmission system. Further reliability
improvements are gained by terminating the new line at Mora Substation; a remote
location other than Boise Bench.
IDAHO POWER COMPANY'S RESPONSE TO FIRST
PRODUCTION REQUEST OF COMMISSION STAFF Page 13
The response to this request was prepared by Roger Grim , Engineer
System Planning, Idaho Power Company, in consultation with Barton L. Kline , Senior
Attorney, Idaho Power Company.
DATED at Boise, Idaho, this Ie) day of July 2006.
~tfjj
BART N L. KLINE
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO FIRST
PRODUCTION REQUEST OF COMMISSION STAFF Page 14
EX.HIBIT No. 238
Case No. IPC-06-
READING, ICIP
REQUEST NO. 91: Please explain in detail the transmission
improvements that "will provide capacity during all seasons and improve the reliability of
the Company s transmission system." Please quantify as accurately as possible the
benefits of increased transmission capacity and of improved reliability. If these
attributes cannot be quantified , please explain why.
RESPONSE TO REQUEST NO. 91: The proposed transmission
improvements would be constructed to accommodate the transmission requirements of
the new peaking facility. However, these improvements would also have a positive
impact on the Company s transmission system generally. Presently, three 230kV
transmission lines comprise the Midpoint West transmission system. All three of these
lines terminate in the vicinity of the Boise Bench substation. The addition of the
transmission improvements required for the Evander Andrews power plant project
would create a fourth 230 kV transmission line from the Mountain Home area to the
Boise load center. This additional line would increase redundancy and result in
increased transmission system reliability. Furthermore , the presence of this new
transmission line would make it feasible to add a 230/138 kV transformer in the
Mountain Home area and , thereby, improve local area reliability. System reliability is
enhanced by terminating the new fourth line at the Mora Substation, a location remote
from the Boise Bench substation.
Feasibility Studies for generator interconnections do not attempt to
determine whether excess capacity exists on the transmission system. However, the
Company s impression from performing the Feasibility Study for the interconnection
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH
PRODUCTION REQUEST OF COMMISSION STAFF Page 2
required by the proposed Evander Andrews power plant is that little excess
transmission capacity exists when the new facility would be in full operation.
The response to this request was prepared by Roger Grim, System
Planning Engineer, Idaho Power Company, in consultation with Monica B. Moen
Attorney II , Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FOURTH
PRODUCTION REQUEST OF COMMISSION STAFF Page 3
EXHIBIT No. 239
Case No. IPC-06-
READING, ICIP
REQUEST FOR PRODUCTION NO. 43: Please provide any long-term
transmission planning documents the Company has developed that support any claim by
the Company that it was planning on building any of the transmission facilities that will be
required to bring the proposed Evander Andrews plant output to load regardless of
whether the Evander Andrews plant was built.
RESPONSE TO REQUEST NO. 43: Idaho Power has made no claim that
it was planning on building any of the transmission facilities that will be required to bring
the proposed Evander Andrews plant output to load regardless of whether the Evander
Andrews plant was built. The transmission facilities are required as a result of the
proposal to construct an additional peaking resource at the Evander Andrews Power
Complex. Without that proposed new facility, the associated transmission facilities to
accommodate that project would not be constructed. As a result, Idaho Power has no
documents supporting that claim.
The response to this request was prepared by Roger Grim , System
Planning Engineer, Idaho Power Company, in consultation with Monica Moen, Attorney
, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
EXHIBIT No. 242
Case No. IPC-O6-
D. READING, ICIP
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