20060125IPC response Micron 1st request Part I.pdf

IDAHO POWER COMPANY
O. BOX 70
BOISE, IDAHO 83707
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An IDACORP Company
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BARTON L. KLINE
Senior Attorney
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January 24 2006
HAND DELIVERED
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise, Idaho 83720-0074
Re:Case No. IPC-05-
Idaho Power Company s Response to Micron
Technology, Inc.'s First Set of Discovery Requests
Dear Ms. Jewell:
Please find enclosed for filing an original and two (2) copies of the
Company s Response to Micron Technology, Inc.'s First Set of Discovery Requests
regarding the above-described case.
I would appreciate it if you would return a stamped copy of this transmittal
letter to me in the enclosed self-addressed stamped envelope.
(1R~
Barton L. Kline
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Enclosures
Telephone [phone], Fax [phone] E-mail BKlinerBJidahopower.com
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BARTON L. KLINE ISB #1526
MONICA B. MOEN ISB #5734
Idaho Power Company
O. Box 70
Boise, Idaho 83707
Telephone: [phone]
FAX Telephone: [phone]
BKline (g) idahopower.com
MMoen (g) idahopower.com
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Attorneys 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
AUTHORITY TO INCREASE ITS BASE
RATES AND CHARGES FOR ELECTRIC
SERVICE IN THE STATE OF IDAHO
CASE NO. IPC-05-
IDAHO POWER COMPANY'
RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF
MICRON TECHNOLOGY, INC.
COMES NOW, Idaho Power Company ("Idaho Power" or "the Company
and in response to the First Set of Discovery Requests of Micron Technology, Inc. to Idaho
Power Company dated December 27 2005 , herewith submits the following information:
REQUEST NO.1: Please provide all the workpapers , data and
spreadsheets in Excel format for each of the Cost of Service Studies (Traditional COS
Normalized COS , and Non-Weighted COS) prepared for this case.
RESPONSE TO REQUEST NO.1: The requested information was
provided in Idaho Power Company s Response to Request No.6 of the Idaho Irrigation
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page
Pumpers Association s First Data Request. Micron has received a copy of all of the
Irrigators' Data Requests.
The response to this request was prepared by Maggie Brilz , Director of
Pricing, Pricing and Regulatory Services , Idaho Power Company, in consultation with
Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO.2: Please provide complete copies of Idaho Power
Company s 200, 2002, and 2004 IRPs.
RESPONSE TO REQUEST NO.2: Idaho Power Company s IRPs for the
years 2000, 2002 and 2004 are enclosed with this response.
The response to this request was prepared by Gregory W. Said , Director of
Revenue Requirement, Pricing and Regulatory Services , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO.3: Please provide, in Excel format, all the workpapers
data and spreadsheets used to normalize the loads used to develop allocators for the
Normalized COS."
RESPONSE TO REQUEST NO.3: The system coincident demands used
to develop allocators for the "Normalized COS" are contained in the
Demand&EnergyNorm05rc.xls workbook provided in response to the Idaho Irrigation
Pumpers Association s First Production Request, Request No. 12. The group peak
demands (which are non-coincident with the system peak) used to develop normalized
allocators are in the file ClassKWNorm05rc.xls included on the CD labeled "First
Production Request of Micron - Responses" provided with this response. All of these
normalized" demands were calculated using normalized calendar month energy and
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 2
median demand ratios in the D&EMaster05rc.xls workbook provided in response to the
Idaho Irrigation Pumpers Association s First Production Request, Request No.
The median demand ratios used in D&EMaster05rc.xls are determined
from historical ratios as shown in the file MedianFactorsOO-04.xls included on the
enclosed CD labeled "First Production Request of Micron - Responses . The historical
ratios for 2003 and 2004 are based on the hourly customer loads contained in the Excel
workbooks with "hourly" in the file name that were also provided in response to the
Idaho Irrigation Pumpers Association s First Production Request, Request No.9. The
hourly customer loads in Excel format were provided in accordance with the consensus
reached at the cost-of-service workshops. (See Case No. IPC-04-, Order No.
29868.) Hourly loads from prior years are not available in Excel.
The energy values used as allocators for both the "Traditional" and the
Normalized" Class Cost-of-Service studies are the normalized calendar month energy
usages adjusted for losses. A description of the process used to derive the normalized
values for 2005 has been provided in response to the Idaho Irrigation Pumpers
Association s First Production Request, Request No. 24. Ms. Schwendiman
workpapers , pages 142 - 144, detail the progression of the normalized energy values
from the normalized billed data (Table I , workpaper page 142), to the normalized billed
data converted into calendar months (Table II , workpaper page 143), to the normalized
calendar month data adjusted for losses (Table III , workpaper page 144). The calendar
month data adjusted for losses is the basis for the derivation of the energy-related
allocation factors used in the cost-of-service studies as detailed on Exhibit No. 41 and
Exhibit No. 46.
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 3
The model used to determine the normalized billed energy values is
written in Oracle Express and is not available in Excel. However, the file named
Normalized MWh - 2005 vs Normalized MWh - 2004.xls included on the enclosed CD
labeled "First Production Request of Micron - Responses" shows the output from the
normalization model. The worksheets with the wording "Text Paste" in their names
detail the output from the normalization model. The worksheets named "Normalized
2005 MWh" and "Normalized 2004 MWh" show in presentation format the normalized
billed energy by month and customer class for each respective year found in the "Text
Paste" files. The worksheet named "Norm. 2005 MWh - Norm. 2004 MWh" details the
difference in normalized billed energy between 2005 and 2004. Finally, the worksheet
named "Norm. 2005 MWh - Norm. 2004 MWh% details the difference in normalized
billed energy between 2005 and 2004 in percentage terms.
The response to this requestwas prepared by Paul Werner, Load
Research Team Leader, Idaho Power Company, and Barr Smith , Planning Analyst
Idaho Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho
Power Company.
REQUEST NO.4: Please provide in numerical format the monthly energy
and peak hour surplus/deficiency data by year used to generate Figures 6 and 7 for the
2004 IRP and reproduced in Ms. Brilz s workpapers in Page 67.
RESPONSE TO REQUEST NO.4: Included on the enclosed CD labeled
First Production Request of Micron - Responses" is a spreadsheet containing data
used to produce Figure 6 and Figure 7 for the 2004 IRP as reproduced in Ms. Brilz
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 4
workpapers. Figure 6 data was not used in the Marginal Cost Analysis , but is provided
as requested.
The response to this request was prepared by Patricia S. Nichols, Senior
Pricing Analyst , Idaho Power Company, in consultation with Barton L. Kline , Senior
Attorney, Idaho Power Company.
REQUEST NO.5: Please provide similar monthly energy and peak hour
surplus/deficiency data to that requested in Request No.4 for the 2000 and 2002 IRPs.
RESPONSE TO REQUEST NO.5: Included on the attached CD is a
spreadsheet containing data used to produce Figure 7 for the 2002 IRP. The Company
has been unable to locate the file containing the data used to produce Figure 6 in the
2002 IRP.
The information contained in Figures 6 and 7 of the 2002 and 2004 IRP'
was not presented in the 2000 IRP.
The response to this request was prepared by Patricia S. Nichols , Senior
Pricing Analyst, Idaho Power Company, in consultation with Barton L. Kline, Senior
Attorney, Idaho Power Company.
REQUEST NO.6: Please provide all workpapers, data and spreadsheets
used to develop normalized revenues , kWh sales , and customers by month for the 2005
test period as used in the COS studies.
RESPONSE TO REQUEST NO.6: The spreadsheet included on the
enclosed CD labeled "First Production Request of Micron - Responses" details the
derivation of the normalized revenue and non-energy billing components such as the
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 5
Demand, the Basic Load Capacity, and the number of bills. Data used to determine the
normalized kWh sales has been provided in the Response to Request No.
The response to this request was prepared by Maggie Brilz, Director of
Pricing, Pricing and Regulatory Services, Idaho Power Company, in consultation with
Barton L. Kline , Senior Attorney, Idaho Power Company.
REQUEST NO.7: Please provide all workpapers , data, spreadsheets and
other model output, including Aurora or other model output, used to develop the monthly
peak hour surplus/deficiencies included in the 2004 IRP in Figures 6 and 7.
RESPONSE TO REQUEST NO.7: The requested information that is
deemed to be non-confidential is included on the CD labeled "First Production Request
of Micron - Responses" provided with this response. The requested information that is
deemed to be confidential has been provided only to those parties that have signed the
Protective Order. The confidential information is included on the CD labeled
Confidential - First Production Request of Micron - Responses" provided with this
request.
The response to this request was prepared by Karl Bokenkamp, General
Manager, Power Supply Planning, Idaho Power Company, in consultation with Barton L.
Kline , Senior Attorney, Idaho Power Company.
REQUEST NO.8: Please provide actual and normalized customer counts
by month for the 2005 test period.
RESPONSE TO REQUEST NO 8: The number of bills for each customer
class for each month of the 2005 test year are included in the file provided in the
Response to Request No., under the tab labeled "New Bills . The number of bills for
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 6
each month for each customer class were used to determine the average annual
number of customers as shown in column Q of this file by dividing the total number of
bills for the test year by twelve. For all customer classes except Small General Service
(Schedule 7) and Large General Service (Schedule 9), the average annual number of
customers calculated in the file is included on page 1 of Mr. Pengilly s Exhibit No. 50
Column 2.
The Company s proposed rate design for Schedule 7 and Schedule 9
Secondary Service Level , requires the transfer of some customers from Schedule 7 to
Schedule 9. Pages 3 and 4 of Exhibit No. 50 detail the change in the total number of
bills for Schedule 7 and Schedule 9 as a result of the proposed rate design. The
resultant total number of bills for Schedule 7 and Schedule 9 are then divided by twelve
to derive the average annual number of customers as shown on page 1 of Exhibit
No. 50.
The Company does not normalize customer counts.
The response to this request was prepared by Maggie Brilz, Director of
Pricing, Pricing and Regulatory Services, Idaho Power Company and Peter Pengilly,
Senior Pricing Analyst, Idaho Power Company in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO.9: Please provide all workpapers , data and spreadsheets
in Excel format, used to develop the monthly growth based weights to seasonalized
transmission demands and allocators discussed at page 22 , line 24, through page 23
line 4 of Ms. Brilz s testimony, as used in the COS studies.
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 7
RESPONSE TO REQUEST NO. 9: The requested information is included
in the Response to Request No.1 O.
The response to this request was prepared by Patricia S. Nichols, Senior
Pricing Analyst, Idaho Power Company, in consultation with Barton L. Kline, Senior
Attorney, Idaho Power Company.
REQUEST NO.1 0: Please provide all data, workpapers and
spreadsheets, in Excel format, and the output of other models, including the Aurora
model , used to develop monthly marginal costs in the 2005 Marginal Cost Study
included in Ms. Brilz s workpapers , and used to develop weighted allocators in the COS
studies.
RESPONSE TO REQUEST NO.0: The requested data is included on
the enclosed CD labeled "First Production Request of Micron - Responses" in the file
named Marginal Cost Template G & T 2005 Analysis.xls. This spreadsheet, which
includes schedules and workpapers, is the marginal cost analysis used to produce the
schedules contained in the 2005 Marginal Cost Analysis included in Ms. Brilz
workpapers.
The 2004 Integrated Resource Plan (IRP) serves as the primary source of
data for the analysis. Data from the IRP used in the Marginal Cost Analysis is identified
as such in the spreadsheet (a copy of the 2004 IRP has been provided in the Response
to Request No 2). Historic data from the FERC Form 1 is also used in the analysis , and
is identified as such. Test year data for 2005 is also used, and is identified. Finally,
forecast plant investment for the period 2006 through 2010 is used and is summarized
in the spreadsheet.
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 8
Output from the Aurora model was used to produce the marginal energy
costs shown on Schedule 1 of the analysis. This output has been provided in response
to the First Production Request of the Industrial Customers of Idaho Power to Idaho
Power Company, Request No 4.
The response to this request was prepared by Patricia S. Nichols , Senior
Pricing Analyst, Idaho Power Company, in consultation with Barton L. Kline, Senior
Attorney, Idaho Power Company.
REQUEST NO. 11: Please provide all LOLP or other capacity risk or load
loss studies performed by or for Idaho Power Company during the last three years.
RESPONSE TO REQUEST NO. 11: Idaho Power has not performed any
LOLP or other capacity risk or load loss studies , nor has it had these studies performed
for it, during the last three years.
The response to this request was prepared by Karl Bokenkamp, General
Manager , Power Supply Planning, Idaho Power Company, in consultation with Barton L.
Kline , Senior Attorney, Idaho Power Company.
REQUEST NO. 12: Please provide all requests for proposals for firm
energy purchases , including all terms and conditions , issued by Idaho Power Company
during the last three years.
RESPONSE TO REQUEST NO. 12: Idaho Power has issued only one
request for proposals (RFP) for firm energy purchases within the last three years.
copy of the RFP is attached to this response.
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 9
The response to this request was prepared by Karl Bokenkamp, General
Manager, Power Supply Planning, Idaho Power Company, in consultation with Barton L.
Kline , Senior Attorney, Idaho Power Company.
REQUEST NO. 13: Please provide monthly generation amounts for all
Idaho Power Company owned resources by resource and month for the last three
years.
RESPONSE TO REQUEST NO. 13: The requested information is
included on the CD labeled "First Production Request of Micron - Responses" provided
with this response.
The response to this request was prepared by David Bean , Controller
Power Supply, Idaho Power Company, in consultation with Barton L. Kline , Senior
Attorney, Idaho Power Company.
REQUEST NO. 14: Please provide monthly firm purchased energy
amounts for all energy purchased by supplier and month for the last three years.
RESPONSE TO REQUEST NO. 14: The requested information is
included on the CD labeled "First Production Request of Micron - Responses" provided
with this response.
The response to this request was prepared by David Bean, Controller
Power Supply, Idaho Power Company, in consultation with Barton L. Kline , Senior
Attorney, Idaho Power Company.
REQUEST NO. 15: Please provide a copy of any draft Integrated
Resource Plan for Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY , INC.Page 1 0
RESPONSE TO REQUEST NO. 15: Idaho Power does not yet have a
draft of the 2006 IRP.
The response to this request was prepared by Karl Bokenkamp, General
Manager, Power Supply Planning, Idaho Power Company, in consultation with Barton L.
Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 16: Please provide copies of all materials previously
submitted to the Commission Staff or other parties in connection with this rate case.
You need not include discovery responses or other material already served on Micron
representatives.
RESPONSE TO REQUEST NO. 16: Idaho Power has provided Micron
with copies of its responses to all production requests from all parties , including the
Commission Staff.
Since the case was filed , as a part of its statutory audit function, Staff has
reviewed portions of the Company s books and records and Idaho Power has provided
copies of data and information supporting the information contained in those books and
records. The information that has been provided to Staff for its audit review is
voluminous. Upon request, Idaho Power will make this information available for
inspection in a Discovery Room at the Company s Corporate Headquarters. Please
contact Myrna Aasheim at 388-2558 to arrange a time to review the information.
Portions of the audit information are confidential and will only be made available to
persons having executed the Protective Agreement. Much of the audit information is in
electronic form , and , therefore, a laptop computer will be required to view this
information.
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 11
The response to this request was prepared by Barton L. Kline , Senior
Attorney, Idaho Power Company.
DATED this 24th day of January, 2006.
~t1
BARTON L. KLINE
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO FIRST SET OF
DISCOVERY REQUESTS OF MICRON TECHNOLOGY, INC.Page 12
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 24th day of January, 2006 , I served a
true and correct copy of the within and foregoing IDAHO POWER COMPANY'
RESPONSE TO FIRST SET OF DISCOVERY REQUESTS OF MICRON
TECHNOLOGY, INC. upon the following named parties by the method indicated below
and addressed to the following:
Donald L. Howell , II
Cecelia A. Gassner
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise, Idaho 83720-0074
don.howell (g) puc.idaho.qov
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Overnight Mail
FAX [phone]
E-mail
Randall C. Budge
Eric L. Olsen
Racine, Olson , Nye , Budge & Bailey
O. Box 1391; 201 E. Center
Pocatello , ID 83204-1391
rcb(g) racinelaw.net
elo
(g)
racinelaw. net
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E-mail
Anthony Yankel
29814 Lake Road
Bay Village, OH 44140
yankel
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attbi.com
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E-mail
Peter J. Richardson
Richardson & O'Leary
515 N. 27th Street
O. Box 7218
Boise,. ID 83702
peter(g) richardsonandolearv.com
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Dr. Don Reading
Ben Johnson Associates
6070 Hill Road
Boise, ID 83703
dreadinq (g) mindsprinq.com
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Lawrence A. Gollomp
Assistant General Counsel
United States Dept. of Energy
1000 Independence Avenue , SW
Washington , D.C. 20585
Lawrence.Gollomp(g) hq.doe.qov
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Dennis Goins
Potomac Management Group
5801 Westchester Street
O. Box 30225
Alexandria , VA 22310-1149
dqoinsPMG
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aol.com
Conley E. Ward
Givens, Pursley LLP
601 W. Bannock Street
O. Box 2720
Boise, ID 83701-2720
cew (g) qivenspursleY.com
Dennis E. Peseau , Ph.D.
Utility Resources , Inc.
1500 Liberty Street S., Suite 250
Salem , OR 97302
dpeseau (g) excite.com
William M. Eddie
Advocates for the West
1320 W. Franklin Street
O. Box 1612
Boise, ID 83701
billeddie
(g)
rmci. net
Ken Miller
NW Energy Coalition
5400 W. Franklin , Suite G
Boise, ID 83705
kenmiller1 (g)cableone.net
Michael L. Kurtz
Kurt J. Boehm
Boehm, Kurtz & Lowry
36 East Seventh Street, Suite 1510
Cincinnati, Ohio 45202
mkurtz (g) bkllawfirm.com
kboehm (g) bkllawfirm.com
CERTIFICATE OF SERVICE , Page 2
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(lt2JuBARTON L. KLINE
IDAHO POWER COMPANY
CASE NO. IPC-O5-
FIRST DISCOVERY REQUESTS
OF MICRON TECHNOLOGY, INC.
TT A CHMENT TO
RESPO NSE TO
REQUEST NO.
Idaho Power Company
2000 Integrated Resource Plan
June, 2000
Idaho Power Company
2000 Integrated Resource Plan
Table of Contents
Chapter 1........
....... .... ............. ........ ...... ......... ..... ........... ....... ........ ........ ... ...... ........ ......... ......... ...
Introduction and Executive Summary
.......................................................................................
Introduction ..................................................... ..................................................................................
Load Forecast .....................................................................................................................................
Resource Adeq uacy ............................................................................................................................
Resource Options ...............................................................................................................................
Least-Cost Plan ..................................................................................................................................
Near-Term Action Plan......................................................
...............................................................
Chapter 2....... ........ .... ........ ........ .....
.................. ......... ............... .......... ....................... ... ...
........... 5
Loads....
............. ....... ...... ............. .... ... ...... ......... ...... ......... ......... .... .............. ...... ... ..........
............ 5
Load Growth ......................................................................................................................................
Regional Conservation/DSM............................................................................................................. 7
Pu blic- Purposes Programs ................................................................................................................. 8
Term Off-System Sales.......................................................................................................................
Chapter 3... .................. .......
.......................... ....... ......... ....... ................................. ............... .....
Existing Resources....
.............. ....... ...... ............ ......... ..... ............ ........... ........ .................. .........
Hydroelectric Generating Resources ...............................................................................................
Thermal Generating Resources .......................................................................................................
Purchased & Exchanged Generating Resources .............................................................................
Transmission Resources ............................ .......................................................................................
Chapter 4...................... ........................... ............ .................... ...... ........
........ ..................... ......
Future Adequacy of Existing Resources
..................................................................................
Introd uction ............................................................................ .........................................................
Median Water, Expected Load Growth (Energy) ...........................................................................
Median Water, Expected Load Growth (Peak) ............................................................................... 22
Low Water, Expected Load Growth (Energy) ................................................................................
Low Water, Expected Load Growth (Peak) ....................................................................................
Median Water, High Load Growth (Energy) ..................................................................................
Low Water, High Load Growth (Energy) .......................................................................................
Planning Criteria for Resource Adequacy ......................................................................................
Chapter 5............... ......... ...................... ................... ....... ................... ............... ..... ..... .............. 35
Future Resource Options
.........................................................................................................
Introduction .....................................................................................................................................
Purchased and Exchanged Generation............................................................................................
Generating Resources ......................................................................................................................
Hydroelectric Generating Resources ...............................................................................................
Thermal Generating Resources ....................................................................................................... 41
Summary of Options ........................................................................................................................
Societal Costs ............................. .........................
..................................................................... .........
Chapter 6....... ....... .......... ...... ...
.................. ........... ................. .... .............. .....
........ ....... ............. 49
Ten- Year Resource Plan
..........................................................................................................
Overview...................................................... .....................
~.................
.............................................. 49
Resource Strategies ..........................................................................................................................
Least-cost Resource Plan .................................................................................................................
Chapter 7. .........
.............. ....... ..... .......
............... ........... ......... ...... ............... ....... ........ ............ .... 61
N ear- Term Action Plan.....
.................. .... ....... ............... ....... ............ .......... ......... .......
.............. 61
Purchase Seasonal Energy and Capacity As Needed To Meet System Load.................................. 61
Initiate Request For Proposals To Purchase Energy and Capacity................................................ 61
Support the Idaho Power Hydro Relicensing Process..................................................................... 62
Participate in RTO Discussions .......................................................................................................
Participate in Regional Conservation and Pu bUc Purpose Programs ............................................ 62
Investigate Potential Cost-Effective Distributed Generation Resources ........................................
Appendices:
Appendix A 2000 Economic Forecast
Appendix B Sales & Load Forecast
Appendix C 2000 Conservation Plan
Technical Appendix
Glossary of Acronyms
AEO - Annual Energy Outlook
AIR - additional information requests
aMW - average megawatts
APS - Arizona Public Service
BP A - Bonneville Power Administration
CCCT - combined-cycle combustion turbine
CO2 - Carbon Dioxide
CT - combustion turbine
DOE - Department of Energy
DG - distributed generation
DSM - demand-side management
EA - environmental assessment
EIA - Energy Information Administration
FERC - Federal Energy Regulatory Commission
HP /IP - high pressure/intermediate pressure
IOU - Investor-Owned Utility
IPUC - Idaho Public Utilities Commission
IRP - Integrated Resource Plan
kV - kilovolt
kWh - kilowatt hours
LIW A - Low-Income Weatherization Assistance
MW - megawatt
NEEA - Northwest Energy Efficiency Alliance
NOx - Nitrogen Oxide
NYMEX - New York Mercantile Exchange
OPUC - Public Utility Commission of Oregon
PM&E - protection, mitigation and enhancement
PV - photovoltaic
QFs - qualifying facilities
RFP - request for proposals
RTOs - regional transmission organizations
SCCT - simple-cycle combustion turbine
SO2 - Sulfer Dioxide
SWIP - Southwest Intertie Project
TSP - Total Suspended Particulate
W ACC - weighted average cost of capital
WE FA - Wharton Econometrics Forecast Associates
WSCC - Western System Coordinating Council
Chapter
Introduction and Executive Summary
Introduction
The 2000 Integrated Resource Plan (IRP)
is Idaho Power fifth resource plan
prepared to fulfill the regulatory
requirements and guidelines established by
the Idaho Public Utilities Commission
(IPUC) and the Public Utility Commission
of Oregon (OPUC).
Prior to submission of the 2000
Integrated Resource Plan to the public
utility commissims, two public meetings
were held and written comments were
solicited on a draft version of the plan
which had been distributed to the public
and the staffs of the IPUC and OPuc.
Comments received at the public meetings
and written comments received thereafter
were used in preparing the final plan.
list of the people and organizations from
which comments on the draft plan were
solicited is included in pages 65 through68 of the Technical Appendix which
accompanies this plan.
The 1997 Integrated Resource Plan
was prepared in the midst of considerable
uncertainty concerning the potential
impacts of the restructuring of the electric
utility industry. In response to that
uncertainty, the Idaho Public Utilities
Commission and Oregon Public Utility
Commission allowed Idaho Power to delay
the filing of the Integrated Resource Plan
from 1999 to 2000. As a result of the one
year delay Idaho Power has prepared this
2000 Integrated Resource Plan with the
benefit of additional information that
would not have been available in 1999.
For example, SB 1149 is now law in the
state of Oregon. SB 1149 provides an
initial framework for electric industry
restructuring in the state of Oregon. SB
1149 conditionally exempts Idaho Power
from restructuring in its Oregon service
territory.
In 1999 the Idaho Legislature also
considered electric industry restructuring.
In the end, the Idaho legislature decided to
defer further consideration of restructuring
legislation and indicated a preference for a
cautious approach to ela:tric industry
restructuring in Idaho.
Based on the legislative actions in
Oregon and Idaho, the 2000 Integrated
Resource Plan assumes that during the
planning period, from 2000 through 2009
Idaho Power will continue to be
responsible for acquiring sufficient
resources to serve all of its customers in its
Idaho and Oregon certificated service
areas as a vertically integrated electric
utility. Idaho Power has attempted to
build sufficient flexibility into the 2000
Integrated Resource Plan so that if
industry restructuring comes sooner than
planned, neither the Company nor its
customers will be disadvantaged by
decisions made in accordance with the
2000 Integrated Resource Plan.
The twin goals of the 2000
Integrated Resource Plan are to (1)
maintain Idaho Power s ability to serve the
growing service territory demand for
electricity for whatever period its role asan exclusive supplier of electricity
continues; and (2) ensure that any
resources acquired for service territory
loads will be cost effective in
competitive market.
Load Forecast
Three load forecasts have been
developed for the 2000 Integrated
Resource Plan. The three forecasts define
a range of possible load growths in the
Idaho Power service territory during the
2000 through 2009 planning peri od. The
expected load growth rate is 1.76 percent
per year over the ten years of the planning
period. This expected growth rate forecast
represents Idaho Power s estimate of the
most probable total load growth during the
planning period.
Low and high load forecasts were
also prepared to recognize the uncertainty
inherent in the forecasting process. The
high load growth forecast of 2.32 percent
per year assumes a load growth rate that is
exceeded by only 10 percent of historic
load growth rates. The low load growth
forecast of 1.21 percent is a growth rate
that was exceeded by 90 percent of the
historic load growth rates. These forecasts
are discussed further in Chapter 2 and in
Appendix B, Sales and Load Forecast.
Resource AdeQuac'l
In the Integrated Resource Plan
modeling process, monthly demand and
energy requirements from the Sales and
Load Forecast are compared throughout
the planning period against the generating
capability of Idaho Power s power supply
system. This comparison reveals Idaho
Power future need for additional
capacity and energy resources.
Idaho Power has determined that
its existing resources (described in Chapter
3) plus market purchases of 250 average
megawatts (aMW) of energy in July and
August, and 200 average megawatts of
energy in November and December are
sufficient to meet expected load growth
until the year 2004. Beginning in 2004
additional resources must be available to
serve expected loads. The adequacy of the
Company resources to meet load
requirements throughout the planning
period is described further in Chapter 4.
Resource Options
Idaho Power s resource options for
the planning period are described in
Chapter 5. To meet the forecast loads at
least cost throughout the ten-year planning
period, Idaho Power considered multiple
resource acquisition strategies. These
strategies include increased monthly
ener-gy and capacity purchases from the
Pacific Northwest power market to meet
seasonal deficiencies and the acquisition
of additional generating capability from a
portfolio of various generation
technologies. From those multiple
resource strategies three strategies were
chosen for final analysis and review: 1) a
market purchase strategy, 2) a combined-
cycle ga&-fired turbine strategy and 3) a
simple-cycle ga&-fired combustion turbine
strategy.
Market Purchases
One of the three resource strategies
selected for further review was increased
reliance on market purchases from the
Pacific Northwest. Seasonal purchases of
energy and capacity was the preferred
strategy selected in the 1997 Integrated
Resource Plan. In the 2000 IRP the
Company plans to use market purchases
from the Pacific Northwest throughout the
planning period to supplement Company
resources in July, August, November and
December. These market purchases are
placed in the resource plan in incrementsof 200 megawatts (MW) and 250
megawatts. Market purchases beyond the
initial 200 megawatts and 250 megawatts
increments were detennined not to be the
optimum strategy because the delivery of
increased market purchases from thePacific Northwest would require
substantial investments in additional
transmission facilities to relieve existing
constraints in Idaho Power s transmissionsystem. Transmission constraints are
discussed more thoroughly in Chapter 3.
Generating Technologies
Seven generic generating resources
using currently-available technologies
including gas-fired and coal-fired thennal
generation, renewable resource generating
technologies such as solar, geothennal
wind power, and generation from fuel cells
were considered to identify the optimal
resource strategy for the 2000 Integrated
Resource Plan. Two of these technologies
a 250-megawatt combined-cycle gas-fired
combustion turbine and a 250-megawatt
simple-cycle gas-fired combustion turbine
were selected as the core resources for the
second and third resource strategies in the
final evaluation.
Fuel cells solar photovoltaic
panels, wind power, geothennal, and solar
thennal generation were also considered
but their relatively higher current costs
precluded their selection in the 2000
Integrated Resource Plan as a bulk power
system resource. If the cost of some of
these technologies can be reduced, it is
conceivable that such resources could have
applications in a distributed generation
strategy. Distributed generation (DG)
resources are small-scale generating units
and energy efficiency resources located
near customer loads. DG resources may
be economic alternatives to expansion of
the transmission and distribution system
and may improve system reliability.
further discussion of the role of distributed
generation within a resource strategy is
contained in Chapter 5.
A coal-fired generation strategy
was not selected for the final analysis
evaluation because of this technology
longer construction and pennitting lead
times, environmental issues, and becauseits operating characteristics do not
confonn to the desired peaking plant
characteristics.
Least-Cost Plan
Prior to 2004 the Company
expects to be able to satisfy its load
requirements with existing generation
resources and seasonal purchases from the
Pacific Northwest. Beginning in 2004
transmission restrictions will cap the
Company ability to satisfy monthly
capacity deficiencies with purchases from
the Northwest. Therefore, the acquisitionof generation resources either by
construction of a simple-cycle combustion
turbine by Idaho Power, or by means of a
power purchase contract that provides
Idaho Power with the same operational
flexibility Idaho Power would have with a
simple-cycle combustion turbine it owned
has been detennined to be Idaho Power
optimal strategy for satisfying load
requirements during the next ten years.
Near- Term Action Plan
During the next two years Idaho
Power will take the following steps to
address its resource needs.
Purchase seasonal energy and capacity
as needed to meet system load;
Initiate a request for proposals (RFP)to establish the cost of acquiring
dispatchable energy and capacity
beginning in 2004.
Chapter 7 describes these two actions
in more detail and describes other actions
Idaho Power will take in the near-term to
assure resource adequacy.
Chapter 2
Loads
Load Growth
The future demand for electricity
by customers in the Idaho Power Company
(Idaho Power or Company) service
territory is represented by three load
forecasts reflecting a range of load
uncertainty. Table I summarizes the three
forecasts of Idaho Power s annual total
load growth during the planning period.
The ten-year average annual growth rate
ranges from 1.21 percent in the low load
forecast to 2.32 percent in the high load
forecast, with an expected load forecast
growth rate of 1.76 percent.
The expected load forecast
represents the most probable projection of
service territory load growth during the
planning period. The forecast for total
load growth is detennined by summing the
load forecasts for individual classes of
service as more particularly described in
Appendix B, Sales and Load Forecast. For
example, the expected total load growth of
1.76 percent is comprised of residential
loads growing at 1.9 percent, commercial
loads growing at 3.3 percent, irrigation
loads growing at 0.1 percent, industrial
loads growing at 3.6 percent and
additional finn loads growing at 1.
percent. In addition FMC loads and
contract off-system loads are included in
the expected total load growth. Sections
within the Sales and Load Forecast detail
the load growth by customer class.
Economic growth assumptions
influence several of the individual class of
service growth rates. Economic growth
infonnation for Idaho and its counties can
be found in Appendix A , 2000 Economic
Forecast.
The number of households in the
state of Idaho is projected to grow
between 1.9 and 2.3 percent during the ten
year forecast period. Growth in the
number of households within individual
counties in Idaho Power s service area
differs from statewide household growth
patterns. Service area households are
derived from county specific household
forecasts. Growth in the number of
households within the Idaho Power service
territory combined with reduced
consumption per household results in the
previously mentioned 1.9 percent
residential load growth rate. Number of
households and employment projections
along with customer consumption patterns
are each used to fonn load projections.
statistical analysis of historic
load growth rates during the twenty-year
period from 1976 to 1998 was used
detennine the expected distribution of
annual growth rates about the expected
load forecast during the forecast period. A
high load forecast was then constructed to
have a growth rate that is exceeded by
only 10 percent of the historic growth rates
in the distribution, and a low load forecast
was constructed to have a growth rate
exceeded by 90 percent of the growth rates
in the distribution. Table I shows a
second set of probabilities to describe the
probability of occurrence of the low
expected and high load forecasts. This
probability indicates the likelihood that the
actual growth rate will be clCBer to the
TABLE 1
Idaho Power Company
Range of Load Growth Forecasts
Average Megawatts
Forecast Frob 2000 2002 2004 2006 2008 2010 Avg Annual
Growth Rate
High Load 26%845 950 009 114 211 319 32%
Expected Load 48%804 879 908 990 064 149 1.76%
Low Load 26%765 812 813 874 927 990 1.21%
growth rate specified in that scenario than
the growth rate specified in any other
scenario. For example, there is a 26
percent probability that the actual growth
rate will be closer to the high scenario
growth rate than to any of the other
forecast scenarios for the entire ten-year
planning horizon.
FMC Load
Included in each of the three load
forecast scenarios is the l20-megawatt
service load of FMC Corporation. With
the restructuring of the FMC contract, only
a first block load of 120 megawatts
required to be served by Idaho Power
system resources. Idaho Power s 2000
IRP does not include a term purchase or
construction of generating resources to
serve FMC's 130-megawatt second block
of load. FMC's second block load
supplied by Idaho Power purchasing
energy in the wholesale market for FMC'
account. The second block of 130
megawatts remains a transmission
obligation of the Company.
Customer Conservation Demand-
Side Management
In 1996, the Idaho Public Utilities
Commission conducted an investigation
into structural changes occUlTing in the
electric industry. In that proceeding, Idaho
Power Company was criticized by its
customers for conducting demand-side
management (DSM) programs that were
based upon the deferral of program
expenditures for later recovery in retailrates. In response to the customer
criticism in late 1996 Idaho Power
commenced a review of each of its system
DSM/customer conservation programs.
Following that review Idaho Power
determined that in light of long-term
structural changes being proposed for the
electric utility industry, DSM/conservation
programs premised on the deferral of
program expenditures and recovery of
those expenditures over an extended
period of time was no longer practical.
implement its decision, Idaho Power
initiated a standard process to seek
authority from both the IPUC and OPUCto discontinue certain DSM programs.
Since the DSM programs were operated
system-wide and the bulk of the cost of
those programs had been allocated to
Idaho Power s primary jurisdiction, the
State of Idaho, it was determined that
operating those programs as Oregon-only
programs was not economically feasible.
Accordingly, upon obtaining IPUC
approval for the discontinuance of a DSM
program, a tariff advice was filed with the
OPUC for discontinuance of the program
in Idaho Power s Oregon service territory.
Since 1996, Idaho Power has discontinued
the following system-wide DSM programs
in both its Oregon and Idaho service
territories:
Design Excellence Award Program
Partners In Industrial Efficiency
Program
Commercial Lighting Program
Agricultural Choices Program
On a system basis, Idaho Power
has shifted its efforts from Idaho Power
customer conservation/DSM programs to
regional conservation efforts conducted
through the Northwest Energy Efficiency
Alliance (NEEA).
Customer energy conservation
savings attributable to past participants in
Idaho Power s customer conservation /
DSM programs are reflected in , the
Company actual measured loads of
recent years and throughout the forecast of
projected loads for future years in the
planning period.
The Company most current
reports to the IPUC and the OPUC
regarding customer conservation / DSM
programs are attached as Appendix
2000 Conservation Plan.
B!HJional Conservation/DSM
Northwest Energy Efficiency
Alliance
NEEA's mission is to promote themarket transformation of energy
efficiencies in the region. Idaho Power
collects an assessment from its customers
to fund its participation in NEEA. Idaho
Power is one of seven entities that provide
NEEA's funding. In addition to Idaho
Power, the funders of NEEA include the
Bonneville Power Administration (BP A),
A vista Utilities Montana Power
Company, PacifiCorp, Portland General
Electric Company and Puget Sound
Energy. Idaho Power continuing
commitment to NEEA is dependent upon
regulatory approval of cost recovery.
NEEA conducts activities such as
market research, technology assessment
planning and brokering collaborations. In
addition, NEEA administers demonstration
programs, targeted market interventions
development of infrastructure to assist
market transformation and dissemination
of information. To ensure the effectivenessof its efforts, NEEA conducts a
comprehensive evaluation of each of the
projects.
The NEEA Board of Directors has
determined that NEEA is accomplishing
its purpose and has requested that Idaho
Power and the other funders renew their
commitment for the period 2000 through
2004. For that period Idaho Power
system-wide contribution is estimated to
be $1.3 million annually out of an annual
NEEA budget of $20 million. This
requested contribution is less than the $1.
million annually that Idaho Power was
previously contrib.1ting to NEEA.
Idaho Power supports and
complements NEEA activities in its retail
service territory in the states of Oregon
and Idaho. Due to the small size of the
Oregon retail service territory when
compared to the Idaho retail service
territory, most of the costs for participation
in NEEA have been allocated to the Idaho
retail service territory. For the same
reason the Idaho Public Utilities
Commission has been the primary agency
that the Company has looked to for
authorization to participate in the
Northwest Energy Efficiency Alliance.The Company has recently obtained
approval from the Idaho Public Utilities
Commission for continued participation in
NEEA through the year 2004. The OPUC
has consistently expressed its support of
the Company s participation in NEEA by
providing funding from Idaho Power
Oregon customers.
Public-Purposes Programs
Idaho Power participates in the
following conservation-related programs:
Low-Income Weatherization
Assistance
Low-Income Weatherization
Assistance (LIW A) is a public-purpose
program to make energy services more
affordable for lmv-income customers.
Payments are made to local non-profit
agencies participating in state-run
weatherization programs in Idaho and
Oregon to supplement federal funding of
weatherization projects. Idaho Power
typically pays 50 percent of the cost of
qualifying conservation measures plus a
$75 administration fee per dwelling. The
program also funds weatherization of
buildings occupied by tax-exempt
organizations.
Oregon Commercial Audit
Program
This Oregon statutory program
requires that all commercial building
customers be notified every year that
infonnation about energy saving
operations and maintenance measures is
available and that commercial energy audit
services can be providw, nonnally at no
charge. Customers using more than 4 000
kilowatt hours (kWh) per month may
receive a more detailed audit but may be
required to pay a portion of the cost.
Oregon Residential
Weatherization
This Oregon statutory program
requires the annual notification of all
residential customers to infonn them how
to obtain energy audits and financing for
energy conservation measures. To qualify
for an Idaho Power audit or financing,
customers must have electric space heat.
Energy Efficiency Promotion
Activities
Idaho Power continues to promote
the wise, efficient, and safe use of
electricity by providing infonnation and
education at workshops and conferences
and in the classroom. Idaho Power offers
infonnational material, consulting services
and energy audits as well as power quality
assistance, audits, and financing to help
customers avoid energy problems and
improve energy efficiency. These
activities are described in more detail in
Appendix 2000 Conservation Plan.
Term Off-System Sales
Idaho Power currently has six tenD
off-system sales contracts. Most of these
contracts were entered into in the late 1980s
or early 1990s when Idaho Power was
experiencing a resource surplus. The
contracts expiration dates, and average
sales amounts are shown in Table 2.
The tenD sales contract with the
City of Weiser is currently Idaho Power
only full-requirements contract. Under a
full-requirements contract Idaho Power is
TABLE 2
Idaho Power Company
Term Off-System Sales
Contract Expiration Sales
Sierra/Elko May, 2000 5aMW
Oregon Trail Electric Coop July, 2001 10 aMW
Washington City June, 2002 5aMW
City of Weiser December, 2002 10 aMW
Utah Associated Municipal Power Systems December, 2003 36 aMW
City of Colton September, 2009 3aMW
Silver State Energy Company (to be established)Undetermined 6aMW
Total Term Sales 75 aMW
responsible for supplying the entire load of
the City. The City of Weiser is located
entirely within Idaho Power s load control
area.
When approved by the Federal
Energy Regulatory Commission (FERC)
and the Public Utility Commission of
Nevada, a term sales contract with Silver
State Energy Company will also be
established as a full-requirements contract.
Silver State will be the electric distribution
utility serving Idaho Power former
customers in the state of Nevada. Silver
State is a wholly-owned subsidiary of
IdaCorp Inc.
As shown in Table 2, most of theterm off-system sales contracts are
scheduled to end before 2004. Idaho Power
will continue to evaluate the value cf term
off-system sales, but with the exception of
the City of Weiser and Silver State Energy
Company, Idaho Power has not included the
renewal of any term offsystem sales
contracts in its load projections.
Chapter 3
Existing Resources
!:!ydroe/ectric, Genera1i.!:m.
Resources
Description
Idaho Power operates
hydroelectric generating plants located onthe Snake River and its tributaries.
Together these hydroelectric facilities
provide a total nameplate capacity of
707 megawatts and median water annual
generation equal to approximately 1 071
average megawatts.
The backbone of the Company
hydroelectric system is the T.E. Roach
complex in the Hells Canyon reach of the
middle Snake River. The T.E. Roach
complex consists of the Browrlee, Oxbow
and Hells Canyon dams and associated
generating facilities. These three plants
provide approximately 70 percent of the
system s annual hydroelectric generation.
Water storage in the Brownlee reservoir
also enables the T.E. Roach complex to
provide the major portion of the power
supply system peaking and load
following capability.
Idaho Power hydroelectric
~acilities upstream from Hells Canyon
Include the American Falls, Milner, Twin
Falls Shoshone Falls Clear Lake
Thousand Springs, Upper and Lower
Malad, Upper and Lower Salmon, Bliss
l. Strike , Swan Falls and Cascade
generating plants. Water storage reservoirs
at Lower Salmon, Bliss and c.J. Strike
provide the potential for limited peaking
capabilities at these plants. All of the other
run -of-riverupstream plants utilize
streamflows for generation.
Federal Energy Regulatory
Commission Relicensing
Process
Idaho Power hydroelectric
facilities, with the exception of the Clear
Lake and Thousand Springs plants, operate
under federal licenses regulated by the
FERc. The process of relicensing Idaho
Power s hydroelectric projects at the end
of their initial fifty-year license periods
has begun. A license renewal was granted
by FERC in 1991 for the Twin Falls
project. Applications to reliceme the
Company three mid-Snake facilities
(Upper Salmon, Lower Salmon and Bliss)
were submitted to FERC in December
1995. The application to relicense the
Shoshone Falls project was filed in May,
1997. The application to relicense the C.
Strike project was filed in November
1998. Relicensing applications for theremaining hydroelectric facilities
including Swan Falls, the Upper and
Lower Malad plants and the T.E. Roach
complex, will be prepared and submitted
during the current ten -year planning
period. The relicensing schedule for
hydroelectric projects is shown in Table 3.
Failure to relicense the existing
hydropower projects at a reasonable cost
would create upward pressure on the
current low rates available to Idaho Power
customers. The relicensing process may
potentially decrease available capacity and
increase the cost of a project's generation
TABLE 3
Idaho Power Company
Hydropower Project Relicensing Schedule
FERC Nameplate Current File FERC
License Capacity License License
Project Number (MW)Expires Application
Bliss 1975 Dee 1997 Dee 1995
Lower Salmon 2061 Dee 1997 Dee 1995
Upper Salmon 2777 34.Dee 1997 Dee 1995
Shoshone Falls 2778 12.May 1999 May 1997
J. Strike 2055 82.Nov 2000 Nov 1998
Upper/Lower Malad 2726 21.8 July 2004 July 2002
E. Roaeh Complex 1971 1166.July 2005 July 2003
Swan Falls 503 June 2010 June 2008
through additional operating constraintsand requirements for environmental
protection, mitigation and enhancement
(PM&E) imposed as a condition for
relicensing. The Company goal in
relicensing is to maintain a low cost of
generation at its hydroelectric facilities
while implementing non-power measures
designed to protect and enhance the river
environment to which they belong. No
reduction to the available capacity of
plants to be relicensed was assumed in this
document.
Collaborative Process
Idaho Power is seeking to address
the risk of loss of its hydro generation by
pursuing collaborative approaches to
relicensing. Discussions with the State
Idaho and others have been initiated to
investigate ways that the low costs of
existing hydro generation can be retained
for the benefit of Idaho Power customers.
Idaho Power has established a
collaborative team consisting of federaland state resource agencies, tribes
regional and local governments, non-
governmental organizations, industrial and
commercial customers, regulatory bodies
and other interested entities to actively
participate with Idaho Power in
developing the components of new license
applications including Idaho Power
protection, mitigation and enhancement
proposals. The goals of the collaborative
team have been to:
involve resource agencies and the
public throughout the relicensingprocess for Idaho Power
hydroelectric projects
foster open exchange of views among
participants
facilitate well-defined and focused
study plans
encourage agreements among
participants on the content of
applications for relic ensing, on PM&E
plans and on conditions of new
licenses
ensure efficient use of resources and
avoid unnecessary study and process
costs
provide participants with more control
and certainty in the relicensing process
through better relationships with
affected entities and the public, and
reduce the likelihood and extent of
potential litigation.
FERC has expressed
encouragement for the collaborative
process and FERC representatives have
routinely attended collaborative team
meetings.
Environmental Analysis
The National Environmental
Policy Act requires that FERC perform an
environmental assessment (EA) of each
hydropower license application to
determine whether federal action will
significantly impact the quality of the
human environment. If so then an
environmental impact statement must be
prepared in connection with the renewal
application. As part of the EA for Idaho
Power s mid-Snake and Shoshone Falls
applications FERC visited Idaho during
!uly, 1997 to receive public and agency
mput through scoping meetings. FERC
issued additional information requests
(AIRs) in 1998 for the mid-Snake project.
FERC also visited Idaho to receive public
and agency input at a scoping meeting
held in September, 1999. FERC issued
AIRs for the c.J. Strike project in 1999.
FERC is currently developing an
approach to a cumulative environmental
analysis of the Snake River from Shoshone
Falls through the T.E. Roach complex.
Once the analysis is complete, FERC will
consider recommendations from affected
state and federal agencies and issue license
orders for the affected projects including
required PM&E measures. This process
may take from 2 to 5 years in the case of
the Shoshone Falls, Upper Salmon, Lower
Salmon and Bliss projects. Opportunity for
additional public comment will occur
before the license orders are issued. If a
project's current license expires before a
new license has been issued, annual
operating licenses are issued by FERC
pending completion of the licensing
process.
Salmon Recovery Program
Idaho Power system of
hydroelectric generating plants on the
Snake River and its tributaries generates
approximately 54 percent of the total
system energy output and is a primary
source of load following capability. In
recent years the movement of water
through the hydroelectric system to assist
spawning and migration of salmon has
substantially impacted the amount and
timing of hydroelectric generation. For
that reason the Company actively
monitors and participates in regional
efforts to develop a program of actions to
assist the recovery of endangered salmon
populations.
Hydroelectric Relicensing
Uncertainties
The Company is optimistic that it
will be able to relicense its hydroelectric
projects in a timely fashion. However
prior experience indicates that the
relicensing process will probably result in
an increase in the costs of generation from
the relicensed projects. These increased
costs are usually associated with new
PM&E requirements imposed on the
projects as a condition of relicensing.
Increased costs of generation are drivenby: (1) dollars expended to provide
additional PM&E; and (2) loss of energy-
generating capability due to changes in
operations associated with PM&E.
previously described in the discussion of
the ongoing FERC collaborative process
Idaho Power is currently discussing the
PM&E issues with the collabcrative team.
However, initial discussions with membersof the collaborative team concerning
proposed changes in project operations
that would impact the availability of
electric energy from the relicensed
projects have not commenced and are not
likely to commence for approximately
twelve months. Once those discussions
commence, Idaho Power will be better
able to estimate the potential impacts of
proposed PM&E requirements on energy-
generating capability. The FERC
relicensing process then provides Idaho
Power with time to assess proposed
PM&E requirements and to develop and
present responses to the proposals. As a
result, at this time Idaho Power cannot
reasonably estimate the impact (if any) of
the relicensing process on the generating
capability of the relicensed projects. At
the time of the 2002 IRP, Idaho Power
may have better infonnation on the
potential for loss of generation due to
PM&E measures.
Thermal Generating
Resou rces
Bridger
Idaho Power owns a one-third
share of the Jim Bridger (Bridger) coal-
fired plant located near Rock Springs
Wyoming. The plant consists of four
nearly identical generating units. Idaho
Power s one-third share of the generating
capacity of Bridger currently stands at 703
megawatts after the upgrade of the high
pressure/intennediate pressure (HP lIP)
turbines on three generating units. The
fourth unit HPIIP upgrade will be
completed in June of 2000. The upgrade
will add an additional 10 MW of capacity.
This will raise the Company s share of
Bridger generating capacity to 707megawatts. After adjustment for
scheduled maintenance periods and
estimated forced outages the annual
energy generating capability of Idaho
Power s share of the Bridger plant is
currently approximately 624 average
me~awatts increasing to 627 average
megawatts by the end of 2000.
Valmy
Idaho Power owns a 50 percent
share, or approximately 261 megawatts of
capacity from the 52l-megawatt Valmy
plant located east of Winnemucca
Nevada. The plant, which consists of one
254-megawatt unit and one 267-megawatt
unit, is owned jointly with Sierra Pacific
Power Company. Idaho Power s share of
the annual energy generating capability of
the Valmy plant is approximately 238
average megawatts.
Boardman
Idaho Power owns a 10 percent
ownership share of the 530-megawatt
coal-fired plant near Boardman, Oregon
operated by Portland General ElectricCompany. The plant contributes
approximately 45 average megawatts of
annual generating capability to the Idaho
Power system.
Salmon Diesel
In addition to the three coal-fired
steam generating plants, Idaho Power
owns and operates a 5.5-megawatt diesel
unit located at Salmon, Idaho. The
Salmon diesel is operated primarily during
emergency conditions.
Purchased Exchan~
Generating Resources
Public Utility Regulatory Policies
Act
Idaho Power purchases energyfrom independent power producers
operating as qualifying facilities (QFs)under the Public Utility Regulatory
Policies Act of 1978, at avoided cost rates
established by the public utility
commissions of the states in which the
Company provides service. A table on
page 62 of the Technical Appendix lists the
65 QF projects which, as of October, 1999
were delivering 110 average MW of power
to the Company.
Exchanges
In the past, seasonal load diversity
between Idaho Po\\er and the rest of the
region has enabled the Company to make
tenn power exchanges with other utilities
which maximize the utilization of the
Company existing power supply
resources. A current exchange agreement
with Montana Power Company provides
for the delivery to Montana of 108 000
megawatt-hours during the three-month
period from December through February.
For analysis purposes deliveries are
assumed to be constant at 50 average
megawatts. In return, Montana delivers to
Idaho 118 000 megawatt-hours during the
three-month June through August period.
For analysis purposes, power is assumed
to be received at 10 average megawatts in
June and 75 average megawatts in July
and August. Under a similar agreement
126 000 megawatt-hours are delivered to
Seattle City Light from November through
February and returned to Idaho Power
from July through September. For
analysis purposes deliveries to Seattle
City Light are assumed to be 25 average
megawatts in November and 50 average
megawatts in December, January and
February. Power receipts are assumed to
be 100 average megawatts in July, 54
average megawatts in August and
average megawatts in September. Both
agreements expire in 2003 and probably
will not be extended in their present fonn
due to the changes in load diversity in the
western region as well as restructuring of
the industry. Therefore, for analysis
purposes the power exchanges are
assumed to end in 2003.
Transmission Resources
Description
The Idaho Power transmission
system is a key element in the Company
ability to serve the needs of its retail
customers. The 230 kilovolt (kV) and
higher voltage main grid system essential for the delivery of bulk power
supply. Figure 1 shows the principal grid
elements of Idaho Power bulk
transmission system.
Capacity and Constraints
Idaho Power transmission
interconnections with neighboring utilities
provide the path over which offsystem
purchases and sales are made. The
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TABLE 4
Idaho Power Company
Power Transfer Capacity for Idaho Power Company Interconnections
Interconnection Line or Transformer Interties in TransmIssion Interconnection
Capacity
Transmission From Critical
Interconnections Idaho Idaho Line or Transformer Loading Connects Idaho Power To
Capacities
Northwest 200 MW 400 MW Oxbow - Lolo 230 kV 462 MW Washington Water Power
Midpoint - Summer Lake 500 kV 500 MW PacifiCorp (PPL Division)
Hells Canyon - Enterprise 230 kV 462 MW PacifiCorp (PPL Division)
Quartz Tap - LaGrande 230 kV 363 MW Bonneville Power Administration
Hines - Harney 138/115 kV 50MW Bonneville Power Administration
Sierra 262 MW 500 MW Midpoint - Humboldt 345 kV 360 MW *Sierra Pacific Power
Eastern Idaho Kinport - Goshen 345 kV 750 MW *PacifiCorp (UPL Division)
Bridger - Goshen 345 kY 750 MW *PacifiCorp (UPL Division)
Brady - Antelope 230 kV 462 MW *PacifiCorp (UPL Division)
Blackfoot- Goshen 161 kV 165 MW PacifiCorp (UPL Division)
Utah (Path C)L 785 to 830 MW Borah - Ben Lomond 345 kV 650 MW *PacifiCorp (UPL Division)
950 MW Brady - Treasureton 230 kV 230 MW *PacifiCorp (UPL Division)
American Falls - Malad 138 kV 129 MW *PacifiCorp (UPL Division)
Montana 79MW 79MW Antelope - Anaconda 230 kV 462 MW Montana Power Company
85MW 85MW Jefferson- Dillon 161 kV 165 MW Montana Power Company
Pacific 600 MW 600 MW Jim Bridger 345/230kV 600 MW PacifiCorp (Wyoming Division)
(Wvoming)
The Idaho Power - PacifiCorp interconnection total capacities in Eastern Idaho and Utah include Jim Bridger resource
integration.
2 The Path C transmission path also includes the internal PacifiCorp Goshen - Grace 161 kV line.
3 The direct Idaho Power- Montana Power schedule is through the Brady - Antelope 230kV line and through the Blackfoot-Goshen 161 kV line
that are listed as an interconnection with PacifiCorp. As a result, Idaho - Montana and Idaho - Utah capacities are not independent.
*Simultaneous rating with other lines.
transmission interconnections and their
power transfer capacities are identified in
Table 4. Table 4 shows that the capacity
of a transmission interconnection or path
may be comprised of multiple individual
circuits. The capacity of a transmission
path is generally less than the sum of the
individual circuit capacities. This is due to
a number of factors such as distribution of
loading, impact of outages and
surrounding system limitations.
addition to these restrictions on
interconnection capacities, there are other
internal transmission constraints that may
constrain Idaho Power s ability to access
specific energy markets. The internal
transmission paths needed to import
resources from other utilities and their
respective potential constraints were
shown on Figure 1 and are further
described below.
Brownlee East Path
The Brownlee East transmission
path is on the east side of the Northwest
Interconnection shown in Table 4. It is
comprised of the 230 kVand 138 kV lines
east of the Brownlee/Oxbow/Quartz area
and the Summer Lake-Midpoint 500 kV
line. The constraint on the Brownlee East
transmission path is within Idaho Power
main transmission grid in the area between
Brownlee and Boise on the west side of
the system.
The Brownlee East path is most
constrained during summer months
because of a combination of hydro
generation from the T.E. Roach Complex
concurrent with tenn transmission
wheeling obligations and purchases fromthe Pacific Northwest flowing into
Southern Idaho. Significant congestion
also occurs during the months of
November and December which can affect
purchases from the Pacific Northwest.
Idaho Power is currently
constructing a 50-mile Brownlee-Ontario
230 kV line in association with other
internal upgrades in order to enhance
service reliability for the Boise/Treasure
Valley area. This project is projected to be
complete in 2001.
Completion of the Brownlee-
Ontario upgrade project will reduce but
not eliminate congestion on the Brownlee
East constraint. The Brownlee East
constraint will still be the primary
restriction on imports of energy from the
Pacific Northwest. If new resources are
sited west of this constraint, additional
transmission capacity will be required to
transmit these new resources to the
Boise/Treasure Valley load a-ea.
Brownlee North Path
The Brownlee North path is a part
of the Northwest Interconnection and
consists of the Hells Canyon-Brownlee
and Oxbow-Brownlee 230 kV double
circuit line. This path is predominately
constrained during the summer months
when imports and hydro production levels
coincide. Congestion on this path also
occurs during the winter months of
November and December. A new 1 O-mile
230 kV line between Brownlee and
Oxbow is being evaluated to relieve
operating limitations at Oxbow and Hells
Canyon. This line may also increase
Brownlee East capacity and thus increase
the Company s ability to impact additional
resources from the Pacific Northwest for
native load use. The evaluation will assess
the ability of such a new line to relieve
limitations that would arise from an outage
of the existing double-circuit line. If new
resources are sited north or west of this
constraint additional transmission
capability will be needed to transmit these
new resources to the Boise/Treasure
Valley load.
Northwest Path
The Northwest path consists of the
500 kV Summer Lake-Midpoint line, the
three 230 kV lines between the Northwestand Brownlee and the 115 kV
interconnection at Harney. Deliveries of
purchased power from the Pacific
Northwest often flow over hese lines.
During low water conditions total
purchased power needs may exceed the
capability of the path. If new resources
are sited west of this constraint, additional
transmission capability will be needed
transmit these resources to the loads.
Borah West Path
The Borah West transmission pathis within Idaho Power main grid
transmission system located west of the
eastern Idaho , Utah Path C, Montana andPacific (Wyoming) Interconnections
shown in Table 4. The path consists of the
345 kV and 138 kV lines west of the
Borah/Brady/Kinport area. The Borah
West path will be of increasing concern
because the capacity of this path is fully
utilized by existing term obligations. If
new resources are constructed or acquired
from sites east of this constraint, additional
transmission will need to be constructed to
transmit these resources to the load areas.
Transmission Uncertainties
FERC Order 2000
On December 15 , 1999, the FERC
issued Order 2000 to encourage voluntary
membership in regional transmission
organizations (RTOs). The order requires
all public utilities that own, operate or
control interstate transmission to file
October 15, 2000 a proposal for an RTO.
Alternatively, utilities must describe their
efforts to participate in an RTO, the
reasons for not participating, any obstacles
to participation, and any plans for further
work toward participation. The RTOs are
to be operational by December 15 , 2001.
While these proposed restructuring
changes will not alter the capability of the
transmission system, it is uncertain how an
R TO structure will effect Idaho Power
use of its transmission system.
FERC Order 888
On May 10 , 1996 FERC issued
Order 888. The FERC intent of Order 888
was to promote the use of transmission
facilities for competiti\e markets at the
wholesale level. Because of the
geographic location of Idaho Power
transmission s facilities, Idaho Power can
anticipate that multiple entities will desire
to utilize transmission capacity in Idaho
Power bulk transmission system to
transport power from the Pacific
Northwest to the desert southwest. Under
the auspices of FERC Order 888, utilities
can be compelled to construct additional
transmission facilities to increase capacity
if the party seeking to use the increased
capacity pays the cost of adding the
capacity. In fact, use of Idaho Power
transmission facilities has already been the
subject of litigation before the FERC
brought by Arizona Public Service (APS)
against Idaho Power relating to APS' s
desire to use Idaho Power s tmnsmission
system for term transactions. In light of
FERC's continuing push for open access
to facilitate transactions at the wholesale
level, planning for future resources must
anticipate additional requirements being
placed on the transmission system as a
result of FERC Orders 888 and 2000.
Western Systems Coordinating
Council Operating Transfer
Capability Process
Since the transmission
disturbances of the summer of 1996
transmission system capabilities have
come under increasing scrutiny. A
transmission operator no longer has the
assurance that all of its capability will be
fully useable in the future. New
interactions with other existing
transmission paths previously
unidentified, can force reductions in
existing transmission capability. Future
resource planning must anticipate and
accommodate increasing regional scrutiny
of planning decisions.
Chapter 4
Future Adequacy of Existing Resources
Introduction
The reliability and quality of
service provided to the Company
customers is directly impacted by the
adequacy ofIdaho Power s electric supply.
Idaho Power utilizes a resource
adequacy criterion which requires that new
resources be acquired at the time that they
are needed to meet forecast energy growth
during the planning period, assuming a
median water condition for hydroelectric
generation. Idaho Power plans to meet
Western States Coordinating Council
(WSCC) criteria for reserves. This criteria
currently requires Idaho Power to maintain330 megawatts of internal/external
reserves above the peak load.
Monthly median water planning
differentiates Idaho Power from other
Northwest utilities, which typically plan
resources based upon having annual
generating capability sufficient to meet
forecast annual energy requirements under
streamflow conditions of historical
critical water period.
By eliminating energy deficits in
all months of each year during the
planning period the median water
planning criterion produces capacity and
energy surpluses whenever water is above
median levels. Of1:system sales of this
surplus energy and capacity provides
revenues which reduce the revenues
required from system customers. During
months when the Company is deficient
because of low streamflows or for any
other reasons, the Company plans to
purchase off-system resources from the
Pacific Northwest on a short-term basis to
meet load requirements.
Low water scenarios have been
evaluated and included in this report to
demonstrate the viability of the
Company s plan to serve peak and energy
loads under low water conditions. These
evaluations include consideration of the
Company transmission capability at
times of lower streamflows.
Impact of Salmon Recovery
Program on Resource Adequacy
Streamflow regulation at Idaho
Power hydroelectric gmerating plants
have been modified to assist salmon
recovery. These modifications are made
in accordance with the December, 1994
Amendments to the Northwest Power
Planning Council'fish and wildlife
program. The amended program calls for
427 000 acre-feet of water to be provided
by the federal government from reservoirson the Snake River upstream from
Brownlee reservoir to aid outmigration of
spring and summer Chinook juveniles
during May and June, outmigration of fall
Chinook salmon juveniles during July and
August, and inmigration of adult fall
Chinooks during late August and
September.
To accomplish this Federal
agencies have acquired water from various
sources in the Upper Snake River basin
and have entered into an agreement with
Idaho Power Company for release of water
from Brownlee Reservoir. The energy
produced by this water is modeled to be
delivered to BP A in July and August and
returned to Idaho Power Company during
the following September through April
time period when the water would
nonnally have been in the river. The
streamflow regulation modeling used in
preparation of the 2000 IRP reflects this
energy exchange and for analysis
purposes, assumes that a similar exchange
will continue throughout the planning
period.
Median Water. Expected
Load Growth (Energyl
Figure 2 shows the monthly energy
surpluses and deficiencies associated with
median water and the most probable future
load scenario. With expected loads and
median water the Company will
experience energy deficiencies in the
summer months of July and August in all
ten years of the forecast. Additionally, the
Company will experience winter energy
deficiencies in November and December.
Summer deficiencies are expected
increase from approximately 110
megawatts in 2000 to approximately 580
megawatts by 2009. Winter deficienciesare expected to increase from
approximately 50 megawatts in 2000 to
approximately 330 megawatts in 2009.
Median Water. Expected
Load Growth (Peak~
At the time of the monthly system
load peak, additional energy is required to
satisfy the peak demand. Figure 3 shows
that for median water scenarios
additional resources must be purchased
during the June through December period
beginning in 2000. Later in the planning
period, most months requires a peak hour
purchase to meet load requirements.
Low Water. Expected Load
Growth (EnerID!l
When low water conditions occur
a greater number of months have expected
deficiencies than in the median water
scenario. Figure 4 shows that summer
deficiencies begin earlier (typically in
May) with initial May through August
deficiencies of approximately 260
megawatts increasing to deficiencies of
approximately 640 megawatts by 2009.
Winter deficiencies in November and
December are expected to increase from
approximately 160 megawatts in 2000 to
approximately 450 megawatts in 2009.
Initially the January through April time
frame shows no deficiency, but by 2009
the deficiency for the January through
April time frame is approximately 120
megawatts. Initial September and OctobEr
surpluses are expected to become
deficiencies by 2009.
Low Water. Expected Load
Growth (Peak!
Figure 5 illustrates that, during
adverse water conditions almost all
months of the forecast period require peak
hour energy purchases.
Median Water. High Load
Growth (Energyl
Monthly loads in the high growth
scenario are typically 30 to 50 megawatts
higher than loads in the expected load
growth scenario. As a result, the pattern of
deficiencies for the median water, high
load growth scenario is similar to the
median water expected load growth
scenario discussed previously. July,
August, November, and December are still
the predominate months in which deficits
are expected to occur throughout the
forecast. May, June and September
become months for concern ate in the
forecast period. Monthly surpluses and
deficiencies for the median water, high
load growth scenario are shown in Figure
Low Water, Hiqh Load
Growth (Energyl
The pattern of deficiencies for the
low water, high load growth scenario is
similar to the pattern of deficiencies for
the low water, expected load growth
scenario. Deficiencies are typically 30 to
50 megawatts greater because of changesin loads. Monthly surpluses and
deficiencies for the low water, high load
growth scenario are shown in Figure 7.
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Planning Criteria for
Resource Adequac
Idaho Power Company s plan is to
acquire or construct resources that will
eliminate expected energy deficiencies in
every month of the forecast period
whenever median or better water
conditions exist. Idaho Power also intends
to serve customer loads whenever water
conditions drop below median. To assure
itself of its ability to accomplish both of
these goals, Idaho Power analyzed its
ability to serve customers ' peak and
energy needs under a low water condition.
Based on these analyses, the Company
believes it can reasonably expect to
acquire short-term resources from the
Pacific Northwest in amounts sufficient to
satisfy deficiencies during low water
conditions.
Idaho Power has included monthly
and hourly evaluations of surpluses and
deficiencies for a hypothetical low water
scenario with a 20 percent probability of
occurrence.
Idaho Power is able to reasonably
plan to use short-term power purchases to
meet temporary water-related generation
deficiencies on its own system because the
Company has summer peaking
requirements while the other utilities in the
Pacific Northwest region have winter
peaking requirements. As a result, the
Company s need for resources tends to
occur in months when the demands for
power is lower in other parts of the Pacific
Northwest. While Idaho Power has
transmission interconnections to the
Southwest, the Northwest market is a
much more reliable source of purchase
power for the Company. The Northwest
market is much larger, has many more
participants and is much more liquid. The
markets east of Idaho Power s system are
much smaller. It is anticipated that Idaho
Power s future ability to acquire short-
term resources from the Northwest Power
market during adverse water years will
remain reasonably constant as
consequence of continuing regional load
diversity. The addition of new generation
in the Northwest and continued growth of
the western power market should allow
Idaho Power to continue to rely on short-
term purchases in low water years. The
primary uncertainty associated with
planned short-term power purchases is the
availability of adequate Northwest to
Idaho transmission capacity to allow
imports at the times when they are needed.
Transmission Adequacy
Previous Integrated Resource
Plans have emphasized construction or
acquisition of generating resources to
satisfy load obligations. Transmission
limitations were not viewed as a major
impediment to Idaho Power s purchasing
power to meet its service oblgations. The
2000 IRP recognizes that transmission
constraints have begun to place limits on
purchased power supply strategies. To
better assess the adequacy of the power
supply and the transmission system, a
peak-hour transmission analysis has been
performed (See Figures 8 and 9).
The transmission adequacy
analysis reflects Idaho Power Company
contractual transmission obligations to
serve BP A loads in south Idaho and FMC
second block loads. These loads are
typically served from the Pacific
Northwest. Analyzing the transmission
limitations during the peak hour each
month helps the Company to assess the
adequacy of the transmission system to
serve Company, BPA, and FMC loads
with energy from the Pacific Northwest.
The results of these transmission
analyses indicate that for median water
conditions, Brownlee East is usually the
most constrained transmission path during
summer months. Figure 8 shows monthly
peak-hour transmission deficiencies during
median water conditions when the
Company s resource deficiencies are met
by purchases from the Pacific Northwest.The magnitude of the transmission
deficiencies is approximately 100 MW in
2002 (after completion of the Brownlee-
Ontario transmission project) and grows to
approximately 450 MW by 2009.
Transmission deficiencies during
low water conditions reach approximately
150 MW during 2002 and increase to
approximately 500 MW in 2009 (See
Figure 9).
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Chapter 5
Future Resource Options
Introduction
Idaho Power s primary resource
options for the planning period include
purchases of power from the wholesale
market, the construction of generating
resources from a variety of generating
technologies or the purchase of energy
from generating resources constructed by
others. The information about each
resource option required for resource
planning includes capacity and energycapability, seasonal availability,
dispatchability, investment and operating
costs, and fuel cost.
Identification of the resource
options themselves does not constitute a
resource plan, but the specification of
resource options is a first step in the
resource planning process.
Included in the first step is a cost
analysis of potential generating resources
sited at generic locations. This analysis
assists in the initial economic ranking of
all resources under consideration. After the
cost of each resource is determined for
generic locations, a more focused analysisof selected resources is performed
establish resource costs based specifically
on Idaho or Pacific Northwest regionaldata. Resource costs associated with
Northwest and Idaho sited technologies
are discussed in greater detail in Chapter 6.
Purchased and Exchanfl.!1Sl
Generation
Purchases from the Market
In the 1997 IRP, Idaho Power
chose supplemental seasonal energy and
capacity purchases as its near-term
strategy for meeting customer loads at
least cost. That strategy has been
successful. Idaho Power has been able to
take advantage of abundant supplies of
off-system surplus energy and available
transmission access to supplement the
Company own low-cost generation
resources.
Idaho Power plans to continue to
utilize seasonal energy and capacity
purchases to optimize the utilization of
Company-owned resources and to use the
expanding wholesale market to benefit the
company and its customers. Market-based
transactions that can carry out this strategy
include the purchase and sale of both
hourly and term energy.
Hourly Energy Purchases
Hourly energy is the output of the
marginal generation resources in the
interconnected region offered for sale
the short term at prices driven by the
market. Historically, the hourly market in
the WSCC has been very reliable and
robust allowing hourly spot purchases to
be a viable component of the Company
short term resource planning strategy.
Term Energy Purchases
Tenn energy purchases are for
specific quantities of energy during
specific periods of time which are
typically longer than time periods for
hourly energy purchases. Tenn energy
contracts may be entered into directly with
other utilities or may be established
through the New York Mercantile
Exchange (NYMEX).
The NYMEX currently offers
electricity futures contracts at two hub
locations in the WSCC region with a
possible future expansion to a third hub.
An exchange serves to guarantee contracts
by requiring collateral (margin) from
traders for each obligation they hold. The
exchange also sets standard tenns for
quantity (perhaps monthly blocks of tenn
power), quality, and location for delivery.
The mechanisms of the exchange and
futures contracts allow price discovery and
push prices to a market clearing price; that
, during a shortage prices rise until
demand meets supply. Standardized
futures contracts, together with options
based on futures, allow buyers ani sellers
to manage price risk as the only remaining
variable.
The current lack of liquidity in
NYMEX contracts limits their usefulness
in making tenn energy commitments. In
all likelihood bilateral contracts with
utilities will continue to be the principal
source of tenn energy transactions for the
foreseeable future.
Market Purchase Prices
For purposes of this 2000 IRP
estimates of future electric market prices
were based on the assumption that during
the planning period, energy purchased
from the Pacific Northwest market would
increasingly be generated from combined-
cycle combustion turbines (CCCTs). For
this reason Idaho Power estimated
market price for energy is equivalent to the
levelized cost of energy generated by a
250-MW CCCT with a 93% capacity
factor and thirty-year life. Transmission
costs must be added to this levelized
energy cost to represent the full cost of
market purchases. The market price
forecast for energy from the Northwest
used in this 2000 IRP is shown on page
in the Technical Appendix.
Gas Price Forecast
One of the primary variables
affecting the costs of energy from a CCCT
is the future price of natural gas. Variousgas price forecasts produced both
regionally and by national forecasting
organizations, have been examined as partof the process of detennining the
appropriate gas prices for use in estimating
market prices for electricity. The studies
which were examined are: (1) the 1999Wharton Econometrics Forecast
Associates (WEF A) Group long range
forecast of the price for natural gas
delivered to electric utilities in the
Mountain region (2) the 1999 PlRA
Energy Group forecast of prices at Rocky
Mountain and Sumas, (3) the forecast of
gas prices produced by the Northwest
Power Planning Council for the 1998 Draft
Fourth Northwest Conservation and
Electric Power Plan, and (4) the forecastused by the Bonneville Power
Administration in the 2002 power rate
case. The decision was to rely primarily
on the WEF long range forecast, with
two modifications. First, the nominal
delivered price for the year 2000 was
adjusted upward to $2.45 per mmbtu from
the WEF A forecasted price to reflect
actual 1999 market conditions. Secondly,
the escalation rate beyond 2010 was
reduced from the level indicated by WEF A
in its forecast. Based on the knowledge
and experience of its gas traders, Idaho
Power has assumed the annual escalation
rate beyond 2010 will be 2 percent.
The gas price forecast used to
develop the estimate of market prices
contained in this 2000 IRP is shown on
page 61 of the Technical Appendix. The
transportation piece of the gas price for the
year 2000 is approximately $0.261 while
the remainder of the gas price is comprised
of the commodity price.
Exchanges
Bilateral Utility Exchange
Idaho Power which is
predominantly summer-peaking utility, has
entered into long-term winter-for-summer
seasonal power exchange contracts with
two winter-peaking Northwest utilities to
reduce the need of each utility to add new
system resources. It is not clear whether
these agreements will be renewed during
the planning period due to changes
generating resource ownership, regional
load requirements and market conditions.
Idaho Power s own increasing winter
deficiencies impacts the suitability of
replacing these seasonal exchanges in the
future. Analyses in this 2000 IRP assume
that the Montana Power and Seattle City
Light contracts will not be extended
beyond their current expiration dates.
1 Escalation rates of transportation costs were not
provided in the WEFA study.
BPA Residential Exchange
Program
Under the residential exchange
program, established by the Northwest
Power Act regional investor-owned
utilities (IOUs) may offer to exchange
power with the BP A in an amount equal to
the utilities' residential and small farm
load. In the past, no actual power sales
have taken place and BP A provided
monetary benefits to the utilities based on
the difference between a utility s average
system cost and BPA'applicable
preference exchange rate multiplied by the
IOU's residential and small farm load.
As part of its power subscription
strategy for the post 200 1 period, BP A has
proposed a settlement of the residential
exchange program in which it will offer
for the residential and small farm loads of
the IOUs, 1 900 aMW of power and/or
financial benefits for the 2002-2006 period
and 2 200 aMW for the 2007-2011 period.
During the first five-year period, at least
000 aMW will be met with actual power
deliveries and during the second five-year
period, BP A's intention is for the entire
200 aMW to be met with actual physical
deliveries of power. The proposed IDwer
product is a block of energy with power
deliveries in equal hourly amounts over
the period, at a rate approximately equal to
BP A's PF Preference rate. The proposed
rate for a block purchase, as described, is
approximately 19.mills per kWh
excluding transmission, for the first five-
year period. The rate for the second five-
year period will not be established until
the next BP A power rate case.
BP A solicited the views of the four
regional state Commissions regarding the
allocation of the total settlement benefits
among the IOUs and joint
recommendation was submitted by the
Commissions. Idaho Power Company
allocated amount of the settlement for the
2002-2006 period is 120 aMW. For the
2007-2011 period the Company
allocation is 225 aMW. The allocation
can be taken as physical power (limited by
the Company s annual average resource
deficiency computed under critical
streamflow conditions), in financial
benefits, or as a combination. The laus
and BP A are currently negotiating the
settlement agreement contract and the
block sale contract.
The proposed settlement of the
residential exchange program represents a
potential source of energy at a price
approximately equal to 19.7 mills
excluding transmission, during the period
2002-2006; and a potential source of
additional energy at an unknown price
during the subsequent five-year period.
Transmission Resources
Upgrades
As noted previously, adequate
transmission capacity is critical to the
success of a strategy of utilizing purchases
from the wholesale market to supplement
and optimize the Company s owned andpurchased generation resources.
Transmission alternatives do not generate
additional energy or capacity; they merely
provide increased access to energy
markets. The cost of increasing the
transmission capabilities of the system is
expressed in a price adder to the capacity
and energy purchased.
Traditionally it has been a
generally accepted proposition among
electric utilities in the west that it is less
expensive and faster to construct new
transmission facilities than it is
construct new generation. In recent times
however, the environmental analyses and
other right-of-way requirements associated
with new transmission construction have
resulted in much longer lead times and
substantially higher costs for new
transmission when compared to prior time
periods. Typically, these permitting and
construction lead times are 5 to 8 years
depending on length and size of the
proposed project.
From time to time the costs and
impacts of conceptual transmission
upgrade alternatives are investigated. The
portion of the Company s transmission
path system that would provide the most
immediate benefit would be the upgrade ofthe transmission between the Pacific
Northwest region and the Boise area.
Transmission construction alternatives for
these paths would be of significant length
(between 170 and 400 miles). Analyses of
range of transmission alternatives
including substation additions show
construction costs of approximately
$400 000 to $700 000 per mile and
incremental transmission costs between
$45 and $90/kilowatt-year. These upgrade
costs are approximately 500 percent higherthan Idaho Power embedded
transmission costs. Assuming a 50 percent
annual load factor (typical for
interconnections) and further assuming
that all project capacity is subscribed
construction of new transmission results in
10 to 20 mill/kWh adder to Pacific
Northwest purchased energy prices. If
some of the transmission capacity is
unsubscribed, the estimated incremental
adders can increase substantially.
Transmission upgrades across the
Borah West path are estimated to cost
about $15/kilowatt-year. Upgrades to the
Borah West Path would be necessary for
network resource developments east of
Borah.
New Projects
Southwest Intertie Project (SWIP)
Idaho Power has obtained the
necessary right-of-way pennits
construct the Southwest Intertie Project, a
500-kV transmission line which would
interconnect the Company Midpoint
Substation with southwest transmission at
a location near Las Vegas, Nevada. Theuncertainties associated with
implementation of FERC Orders 888 and
2000 necessitate a temporary cessation of
further development of the SWIP Project.
Generating Resources
Background
The following discussion of tre
costs associated with various non-hydro
generating technologies is based on the
technology descriptions capital costs
operational and maintenance cost and heat
rate data derived from the Department of
Energy IEnergy Infonnation
Administration , (DOE/EIA's) 1999
Annual Energy Outlook (AEO) report.
Use of data taken from a common source
like the AEO report allows Idaho Power to
make a consistent first comparison of the
costs of the selected technologies at
generic locations. That initial cost
comparison is shown in Figure 10.
Idaho Power then applied
Company specific factors such as cost of
capital and tax rates to the generic
DOE/EIA data to further refine costs used
for comparisons. The fuel costs used are
derived ITom market forecasts prepared by
Wharton Econometrics Forecast
Associates. In making the above-
described cost comparisons Idaho Power
concluded that the AEO's generic data onthe capital costs of the compared
generating technologies appears to
consistently low. Assuming this
observation to be correct, the lowest cost
generation technologies selected (natural
gas-fired generation) were estimated again
using capital costs, operational costs and
capacity factors that were more consistent
with known and expected operational
assumptions for gas-fired generation sited
in the Pacific Northwest region.
!:Jydroelectric GeneratingResources
Efficiency Improvement
Projects
Any opportunity to improve
efficiency and increase the generating
capacity at Idaho Power existing
hydroelectric facilities will be considered
on a project-by-project basis. Proposed
capacity upgrades will be evaluated by
standards for cost effectiveness of longtenn resource investments including
uncertainty in environmental impact, as
utilized in the IRP least-cost methodology.
The most probable time for making such
evaluations is during the established FERC
relicensing process. No capacity
expansions are currently proposed by
Idaho Power in the pending relicensing
applications.
New Hydro Projects
The development of new
hydroelectric generating projects is limitedto sites that are geologically,
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environmentally and socially acceptable.
Resolution of fish and wildlife concernswater quality issues and other
environmental effects of hydroelectric
generation development are extremely
critical to the success of developing new
hydroelectric generating projects. Idaho
Power is unaware of any potential new
hydroelectric generating projects that
could meet the economic, environmental
and other public acceptance criteria
necessary for serious consideration.
Thermal GeneraUng
Resou rces
Efficiency Improvements
Boardman
The Boardman boiler modification
discussed in the 1997 IRP has been
completed. The low pressure turbine
project is scheduled to be completed in
July of 2000. The levelized cost of the
additional generation capacity gained from
the low pressure turbine project will be
approximately 10 mills per kilowatt-hour.
Valmy
project similar to the low
pressure turbine modification project at
Boardman could be implemented at the
Valmy Station. It is projected that the
modification could provide an increase in
total generation capacity of 14 megawatts
at a capital cost of about $700 per kilowatt
(a levelized cost of approximately 12 mills
per kilowatt-hour). Because of the
uncertainty suITounding future ownership
of SieITa Pacific Power Company s share
of the Valmy plant, no modifications have
been scheduled.
Bridger
The high pressure/intennediate
pressure turbine modification on Unit
will be completed in June of 2000. After a
testing period of several months it will be
fully operational in late 2000. The Unit 4
project will add approximately 10
megawatts of capacity (Idaho Power will
receive a 1/3 share of the 10 megawatt
increase) at levelized cost of
approximately 7 mills per kilowatt-hour.
New Thermal Projects
Coal-Fired Generation
Conventional Steam Turbine Plant
This technology is very well
known and utilizes a conventional steam
boiler to generate steam, that is then used
to drive a steam turbine. The emissions
from the combustion of coal are then
treated (scrubbed) to meet applicable clean
air standards.
For a 400-megawatt unit, the 1999
AEO assumes a capital cost of $1 093 per
kilowatt of plant capacity. Using an
percent capacity factor, a levelized cost of
approximately 40 mills per kilowatt-hour
at a generic location is projected (Figure
10).
Advanced Coal Technologies
The AEO uses the tenn "advanced
coal technologies" to address all of the
cleaner-burning coal technologies under
development including pressurized
fluidized bed combustion and integrated
gas combined-cycle (coal gasification).
The primary benefit of these types of
plants is the ability to achieve lower sulfur
dioxide and nitrous oxide emissions
without the need for add-on emISSIOn
control equipment.
Advanced coal technology plant
capital costs from the 1999 AEO were
606 per kilowatt for a 428-megawatt
plant. The derived levelized cost of
generation at generic location is
approximately 61 mills per kilowatt-hour
operating at an 80 percent capacity factor.
Gas-Fired Generation
Simple-Cycle Combustion Turbine
(SCCT)
A combustion turbine (CT), either
simple-cycle or combined-cycle bums
natural gas or fuel oil distillate creating a
hot exhaust gas, which is allowed to
expand through a turbine to turn an
electric power generator. Compared
coal-fired steam plants, CTs bum more
expensive fuel and typically have higher
heat rates. Compared to coal-fired
generation, the principal advantages of an
CT are lower capital costs per kilowatt of
generating capacity and shorter lead times
for siting and construction. The permitting
and construction time for a SCCT sited in
Idaho is estimated to be 34 months
whereas the time needed to site and
construct a coal-fired steam plant at a
generic location would likely exceed 60
months. SCCT's also have relatively
lower environmental impacts than do coal-
fired plants and possess the ability to more
rapidly adjust the level of generation over
the output range. Consequently, SCCTs
are often selected for peaking and other
low capacity factor requirements. After
installation, a SCCT may be converted to a
combined-cycle unit for more efficient
operation at higher capacity factors by
adding a heat recovery boiler and steam
turbine generator.
Combustion turbine operating
characteristics and cost data used in Idaho
Power current planning investigations
were taken from the 1999 ABO. The
estimated capital cost of a 160-megawatt
SCCT is $329 per kilowatt. Operating at
an 80 percent capacity factor, the levelized
cost of generation from a SCCT at a
generic location would be approximately
44 mills per kilowatt-hour (Figure 10).
As previously indicated, Idaho
Power has also estimated the cost of a
SCCT sited in Idaho. This second
estimate uses Pacific Northwest cost data
rather than more generic ABO data. The
estimated levelized cost of a SCCT sited at
an Idaho location operating at various
capacity factors, is discussed in Chapter 6.
Combined-cycle Combustion Turbine
(CCCT)
The CCCT adds a heat recovery
boiler and steam turbine generator to the
simple-cycle combustion turbine
decrease the effective heat rate and
increase overall generating efficiency.
The heat recovery system uses the residual
hot exhaust gas from the combustion
turbine to create steam, which is then usedto drive a secondary steam turbine
generator. The increased capital cost of
the CCCT coupled with increased fuel
efficiency tends to make the CCCT more
cost effective at higher capacity factors
than the SCCT.
Idaho Power estimates it would
take 42 months to obtain permits and
construct a CCCT in Idaho.
Construction costs and operating
characteristics for a new 250-megawatt
CCCT based on the 1999 AEO show an
estimated capital cost for the unit of $445
per kilowatt of capacity. Operating at an
80 percent capacity factor, the CCCT's
levelized cost of generation at a generic
location is approximately 36 mills per
kilowatt-hour (Figure 10).
As previously indicated Idaho
Power has also estimated the cost of a
CCCT sited in Idaho based on Pacific
Northwest costs rather than the more
generic AEO cost data. The estimated
levelized cost of a CCCT sited at an Idaho
location, operating at various capacity
factors, is discussed in Chapter 6.
Fuel Cells
Fuel cells are electrochemical
devices that convert the chemical energy
of a fuel, such as natural gas, into low
voltage electricity. In a typical fuel cell
hydrogen extracted from the fuel
oxidized at an anode using oxygen
supplied from the cathode. Ion flow
across the fuel cell is accompanied by flow
of electricity through the external circuit.
The by-products of this process are carbon
dioxide, water and heat.
An individual fuel cell has fairly
low output so they are usually stacked
together to in a "battery" configuration
forming "power modules.The power
modules are then combined to meet the
power application requirement. The
variable size of fuel cell power plants
makes them ideal for many distributed
resource applications. At this time
commercial fuel cell systems are just
becoming available and are limited in size
from a few watts to several kilowatts.
The fuel cell technology selected
in the 1999 AEO for cost projection
purposes was a 10-megawatt molten
carbonate system. A demonstration unit of
this type (2-megawatt capacity) was built
and operated in Santa Clara, California.
The unit was a limited success and
operated for several months on a restricted
basis during 1996. The AEO capital
assumption is $2 146 per kilowatt for the
unit (the demonstration project cost was
much higher than this). The resulting
levelized cost of generation at a generic
location is about 61 mills per kilowatt-
hour, operating at an 80 percent capacity
factor (Figure 10).
Renewables
The following renewable energy
technologies are included in recognition ofthe environmental and the resource
diversification benefit they can provide.
Renewable energy technologies are best
suited to distributed generation scenarios
where niche markets exist. Their
relatively high present-day costs preclude
their selection as least-cost bulk power
system resources during the term of this
resource plan.
Solar Photovoltaic
The building block of the solar
photovoltaic (PV) system is a solid state
solar cell which converts solar radiation
directly into electricity energy. In a
system , a number of solar cells are
interconnected to form a solar module. PV
systems can range in size from small
single module systems to large systems
with many hundreds of solar modules.
Small improvements continue tobe made to increase the electrical
efficiency and reduce the cost of
technology. PV generation costs have not
declined in any significant increment in
recent years. The 1999 AEO uses a capital
cost of $4 162 per kilowatt for a
megawatt station with a 28 percent
capacity factor. This yields a levelized
cost of about 147 mills per kilowatt-hour
for generation at a generic location (Figure
10).
Solar Thermal Generation
Solar thermal power plants convert
solar energy to electricity by concentrating
sunlight to produce heat and then
electricity. These systems are similar to
typical generating plants in that the heat is
converted into electricity via a turbine
generator using conventional steam cycle
technology.
Idaho Power participated in the
Solar Two demonstration project near
Barstow, California, along with several
other utilities and government agencies.The 10-megawatt Solar Two
demonstration project is now over.
The 1999 AEO uses a capital cost
of $2 904 per kilowatt for a 100-megawatt
station at a generic location yielding a
levelized cost of approximately 110 mills
per kilowatt-hour at a 42 percent capacity
factor (Figure 10).
Windpower
Wind turbine generation is
accomplished through the use of two or
three large blades, which catch the wind
and turn a generator shaft to produce
electricity. The turbines and attached
blades are mounted to the top of towersand usually resemble a traditional
windmill in appearance. Wind turbines
can be stand-alone systems but there are
operating advantages to siting wind
turbines in a large array to form a "wind
farm. "
Wind turbines currently being
deployed have improved aerodynamics
thereby creating wind plants that are less
costly and more reliable than earlier
versions. Using 1999 AEO capital costs of
109 per kilowatt the levelized cost at a
generic location would be approximately
64 mills per kilowatt-hour for a 50-
megawatt wind plant having a 30 percent
capacity factor (Figure 10).
Because wind intensity at a given
location will vary unpredictably, the
energy produced from wind turbines is less
useful than energy produced from
resources that can be dispatched to meet
system load requirements. Also, wind
farms require large amounts of land and
may alter the natural terrain on which they
are sited. Noise and avian mortality are
additional considerations which have not
been resolved to this point.
moderate potential for wind
energy development exists within the
Idaho Power service territory. However
in southern Idaho most of the wind sites
are on ridge tops where extreme cold can
affect turbine performance. Also, the
remote nature of the known wind sites in
Idaho may require large transmission
system expenditures in order to access the
energy.
Geothermal
This technology is of some interest
because there is a possibility that in the
future a suitable geothermal field may be
found within Idaho Power service
territory. However, because of their
remote locations and relatively low
temperature, the known geothermal areas
within our region have very limited
potential. Using 1999 AEO capital costs
of $1 831 per kilowatt, the levelized cost
would be approximately 44 mills per
kilowatt-hour for a 50 MW plant having
an 87 percent capacity factor and sited at a
generic location (Figure 10). It must be
noted that the AEO data does not assume
any cost for the use of geothermal fluid
nor does this cost estimate include any
transmission cost adders.
Because the AEO data do not
include the exploration and development
cost of the geothermal resource or the
costs of purchasing geothermal fluid from
the owner of the resource, geothermal
generation systems should not be assumedto be competitive. The AEO cost
information assumes that the geothermal
fluid resource exists and can be utilized at
zero cost. In reality, the cost of
geothermal fluid could be significant. It is
also critical to note that geothermal waterresources with adequate heat
characteristics are all located far from
Idaho Power s transmission system.
Energy Storage
This section is included because if
an effective energy storage system could
be developed it could enhance existing
generation and transmission resources. At
this time megawatt-sized energy storage is
limited to technologies like pumped
storage hydroelectric generation and
compressed air. These technologies are
very site specific. Consequently the
technologies are not applicable to most
energy storage needs. However, a
?romising technology, called Regenesys
IS now under development.
The Regenesys system has been
developed by National Power PLc. In
December of 1999 National Power
awarded a contract to construct the first
megawatt scale power grid connected unit
(I5-megawatt peak output with a storage
capacity of 120 megawatt-hours). The
facility will be built in England.
Operating like a very large
rechargeable battery, the Regenesys
System stores electricity when demand
and costs are low and releases the energy
when demand and prices are high
reducing the need to dispatch more
expensive generating resources.
Strategically placed energy storage
systems would lessen the impact
transmission constraints that exist at peak
loads or under adverse conditions. At its
heart is a fuel cell module. Two
electrolytes (salt solutions) flow through
the cell on either side of an ion exchange
membrane. By applying a voltage across
the electrolytes, the electolytes change
state and become charged. The charged
electrolytes are stored in tanks until
electricity is required. The process is then
reversed and the charged electrolytes flow
back into the fuel cell and electricity is
produced. The peaking capacity of the
system is limited by the surface area of the
fuel cell membrane and the power inverter.
The storage capacity of the system
limited by the volume of the electrolyte
storage implying that the units are scalable
and can be tailored to specific sites and
power needs.
At this time the actual costs of the
system are not established as the
technology is still in the demonstration
phase.
Distributed Generation
number of the generating
technologies previously described could
playa role in a planning strategy which
has come to be known in the electric utility
industry as distributed generation. A DG
strategy involves the placement of smaller
power generation units sited near
consumers and load centers to provide
benefits to individual customers and to
support the economic operation of the
existing power distribution grid. As the
electric industry has restructured in
selected areas of the United States, the
opportunities for customers
competitively select the optimum
combination of energy resources to meet
their needs has brought the DG strategy to
the forefront. Commercial technologies
such as reciprocating engines and small
combustion turbines are already being
used in a variety of applications from
emergency power to combined heat and
power applications. Emerging technology
such as fuel cells, micro turbines, and
photovoltaics, may, in the future, provide
additional options for distributed power
?eneration. Idaho Power already has
Interconnected with relatively large
number of distributed generation
applications. Examples include the small
reciprocating engines located at the
wastewater treatment plants in Boise and
Pocatello; the combined heat and power
operations located at the sugar processing
facilities of Amalgamated Sugar; the Boise
Cascade Emmett facility and at the Roland
Jones potato processing plants at Glenn
Ferry and Rupert; and numerous small
hydro facilities. With the exception of the
Amalgamated Sugar facilities Idaho
Power is currently purchasing all of the
energy generated by these facilities.
In those areas of the country with
higher costs for centrally-generated power
individual customer development o
distributed generating technologies may be
a successful strategy in holding down that
customers cost of power. Because of
Idaho Power s low electric service rates
~he .~plication of distributed generation by
IndIVIdual customers in order to reduce
their cost of energy is not likely to be an
attractive use of capital in the near term.
DG facilities can currently be attractive to
individual Idaho Power customers for
standby purposes and for remote
applications where the cost of bringing
central station power may be prohibitive.
Time of Use Applications
The costs of power vary hour by
hour depending on the demand and
availability of generating assets. Idaho
Power sees these variations, but its
customers typically do not. In some areas
of the country, larger customers pay time-
of-use rates that convert these hourly
variations into seasonal and daily
categories, such as on-peak, off-peak, or
shoulder rates. Time-of-use customers
could select distributed generation options
during high-cost peak periods to reduce
the customer s overall cost of power. In
turn, this customer capability could reduce
the need for the energy service provider to
generate or contract to receive and
distribute very high-cost power. Idaho
Power has studied the costs and benefits of
time-of-use rates in the past and these
studies are currently being reviewed.
Standby Power
Idaho Power system has
demonstrated itself to be extremelyreliable. Customers count
uninterrupted electric service 24 hours a
day, 7 days a week, week in and week out.
Outages do occur, of course, most of
which are the result of storm or accident
damage to overhead transmission and
distribution systems. With few
exceptions, such outages tend to be brief
and infrequent. Nevertheless, some
customers are so sensitive to outages that
they have standby generators on site to
supply power themselves until utility
service is restored. Some standby
generators are required by law to maintain
public health and safety, such as for
hospitals, elevators, and sewage pumpingstations. For other customers like
telecommunications and certain process
industries including the microchip
industry, the installation of standby
generators may be an economic choice
based on the cost of lost product due tooutages. As part of a distributed
generation strategy, Idaho Power is
exploring the feasibility of calling on this
pool of standby generation to provide
system support at times of critical need.
Grid Support
Even though Idaho Power s cost of
electric generation is very low, selected
use of DO could provide system benefits
by reducing the need for investment in
other parts of the system. Potential DO
benefits include:
Voltage and frequency support to
enhance reliability,
Avoidance or deferral of high cost
high lead-time, transmission and
distribution system upgrades
Reduction of line losses
Reactive power control
Fuel use reductions when solar
renewable, or high efficiency DO is
applied in place of central station
power, and emission reduction
from photovoltaics, fuel cells, and
wind generation.
The evaluation of these benefits
and the development of mechanisms
where DO can provide grid support are
very site specific.
Idaho Power will continue to
monitor the potential efficacy of
distributed generation strategy. Where
distributed generation technology could
provide the most cost-effective grid
support, Idaho Power will actively pursue
such opportunities. Idaho Power will also
work with its customers who are interestedin developing distributed generation
facilities to assist them in the planning
process and to ensure that the development
and installation of customer owned andoperated distributed generation
technologies are consistent with system
parameters and would not adversely affect
system reliability or service to other
customers.
SUmmary of Options
The costs for Idaho Power
generic generating resource options for the
2000 IRP are summarized in graphical
fonn on the chart shown in Figure 10. The
resources are listed in Figure 10 in order of
their energy supply costs based on each
resource s forecasted cost of energy output
at a generic site. For comparing resources
the energy cost of each resource is statedin levelized mills per kilowatt-hour
assuming a 2000 starting date.
The production cost chart in Figure
10 is a useful tool for making preliminary
comparisons of the costs of generation
from individual generating technology
options and offers insight as to which
resources may be more economic for
serving base load requirements. Becausethe chart does not reflect resource
attributes such as dispatchability,
seasonality of generation, maintenance
requirements operating reliability,
environmental impacts and risk
characteristics, the supply chart cannot
show the order in which the various
resources should be included in the least
cost plan. Such resource attributes
TABLE 5
Idaho Power Company
Externality Cost Adder Ranges for Thermal Plant Emissions
Combinations of NOx , TSP and CO2 Adder levels
($/Ton)
Emmission level 1 level 2 level 3 level 4 level 5 level 6
NOx 640 640 640 600 600 $6,600
TSP 640 640 640 $5,280 $5,280 280
CO2 $13.$33.$52.$13.$33.$52.
strongly influence the value of resources
operating as part of the Idaho Power
supply system.
Societal Costs
All electric power resources have
costs, benefits and impacts beyond the
construction and operating costs which are
included in the price of electricity. The
non-internalized costs include the air
pollution and natural resource depletion
associated with thermal generation, the
effects on aquatic life and recreation
associated with hydroelectric dams, and
the aesthetic and bird mortality impact
associated with renewable wind power.
Order 93-695 , the Oregon Public Utility
Commission specified cost adders
associated with the level of sulfur dioxide
(SO2), carbon dioxide (CO2), nitrogenoxide (NOx), and total suspended
particulate (TSP) emissions from new
thermal generating plants. SO2 emission
costs are included in the calculation of
direct utility costs through modeling of the
emission allowance system established by
the Clean Air Act. The sensitivity of the
choice of least-cost adders for CO2, NOx
and TSP emissions has been investigated
for the six level-of-cost adders specified
by the OPUC in Order 93-695. The cost
comparison of resource strategies
including cost adders is found in Chapter
, Ten-Year Resource Plan, of this
document.
Table 5 shows the six specified
combinations of externality cost adders for
CO2, NOx and TSP emissions. Each
emission has been assigned a low and a
high level-of-cost adder, and the range of
total emission cost adders is represented
by the different possible combinations of
cost adders for the individual emissions.
The low end of the range is produced by
the low adder values for each emission
and the high end of the range by the high
adders for each emission.
Chapter 6
Ten-Year Resource Plan
Overview
Development of the ten-year
resource plan involves the selection of the
resources from Idaho Power new
resource options described in Chapter 5best suited to meet the forecast
deficiencies identified in Chapter 2.
this plan Idaho Power has selected three
strategies as the best candidates for final
selection as the Company s 2000 resourceplan. The three different resource
strategies are compared against each other
to determine the single strategy that is
most likely to meet expected loads at
lowest expected cost. The three strategies
are also analyzed in the context of their
relative sensitivity to various uncertainties.
Uncertainties include external cost adders
for emissions from thermal generation and
the discount rate used for levelizing future
resource plan costs. The sum of these
analytical comparisons lead to the
selection of Idaho Power s Ten-Year Least
Cost Resource Plan.
Resource Strate~
Three resource strategies have
been selected for evaluation for the 2000
Integrated Resource Plan. Each of the
three strategies selected assumes a
continuing level of seasonal market
purchases being made by Idaho Power
from the Pacific Northwest during the full
planning period. These planned purchases
consist of 250 average MWs of energy in
July and August and 200 average MW s of
energy in November and December.
The first resource strategy to be
considered is a market purchase strategy.
This market purchase strategy is a
continuation of the strategy selected by the
1997 IRP.
Having reviewed the cost of
electricity from the various generation
technologies from a relative levelized cost
ranking (Figure 10), the least-cost resource
technologies are scrubbed coal or gas-fired
combustion turbines. Due to increased
environmental acceptability, siting
flexibility, construction lead times, and
operating characteristics more closely
matched to resource needs gas- fired
combustion turbines are selected for
consideration as the second and third
resource strategies. It is important to note
that the second and third strategies could
be implemented either by the constructionby Idaho Power of gas-fired thermal
generating facilities or by Idaho Power
purchase of the dispatchable output of
generating facilities constructed by third
parties.
Market Purchase Strategy
The first strategy considered is
increased purchases of energy and
capacity from the Pacific Northwest
wholesale market. These increased market
purchases would be over and above the
planned 250 MW and 200 MW Northwest
market purchases discussed previously.
As shown in Figure 2 in Chapter 2
assuming expected loads and median
water, the Company forecasts deficits with
existing resources in 41 months of the 120
months throughout the entire planning
period. Fifteen of those monthly
deficiencies are eliminated by the
Company s continuing purchase from the
Northwest of 200 average megawatts
during the winter and 250 average
megawatts during the summer. Additional
purchases of capacity and energy could be
reasonable resource strategy for the
remainder of the planning period only if
(I) sufficient generating resources will be
available in the Pacific Northwest to
support a 250 MW purchase in addition to
the 200-250 MW winter-summer
purchases already included in the plan; (2)
sufficient transmission capacity
constructed or otherwise made available in
time to allow the Company to access
Northwest energy markets; and (3) the cost
of that additional transmission does not
cause the total cost of market purchases to
exceed the costs of the other alternative
strategies.
For comparing the three IRP
strategies, the market purchases strategy is
represented by planned additional
purchase of 250 MW of capacity and
energy from the Pacific Northwest in the
months of July, August November and
December beginning in 2004. Adoption of
the market purchase strategy would mean
that Idaho Power would be relying on
purchases from the Pacific Northwest
market in a total amount of 500
during July and August and 450 MW
during November and December from
2004 through 2009.
Combined-cycle Gas Fired
Generation Strategy
second possible strategy is the
construction or long-tenn purchase of the
output of a combined-cycle combustion
turbine for meeting service territory load
requirements beyond 2003. The energy
from a CCCT would be in the addition to
the planned 250 MW and 200 MW
Northwest market purchases discussed
previously. A combined-cycle combustion
turbine was selected because of its lower
cost and the ability of the resource to be
sited and constructed prior to 2004, the
time it is expected to be needed. A CCCT
has relatively low environmental impacts
and gas is still in abundant supply.
CCCT could be constructed and owned by
Idaho Power and included in Idaho
Power investment for revenue
requirement detenninations or
equivalent energy supply could be
acquired as the result of a competitive
bidding process.
For comparing the three selected
resource strategies, the CCCT strategy
assumes the planned addition of a 250
MW CCCT plant in 2004.
Simple-cycle Combustion
Turbine Strategy
The third selected strategy to be
considered is a 250 MW SCCT peaking
plant. The energy from a SCCT would be
in addition to the planned 250 MW and
200 MW Northwest market purchases
discussed previously. Like a CCCT, a
SCCT could be constructed and owned by
Idaho Power and included in Idaho
Power investment for revenue
requirement purposes or the energy could
be acquired from others based on a
competitive bidding process. The SCCT
would have the advantages of a lower
capital cost than a CCCT and reduced total
cost because of the SCCT's increased
ability to operate more efficiently to meet
peak loads (see Figure 13). The cost of
energy from a SCCT peaking plant located
TABLE 6
Cost Comparison of Resource Strategies
Over the Range of Emission Cost Adders
($000 000)
Emission Cost Adders
Resource Strategy Zero level 1 level 6
Market Purchase Strategy (93% Capacity Factor w/adder)1 ,443 004 281
Combined-cycle Gas-Fired Generation (30% Capacity Factor)243 804 081
Simple-cycle Combustion Turbine Strategy (30% Capacity Factor)111 035 138
within Idaho Power s system compares
favorably with the market price of on-peak
market energy plus transmission costs.
The SCCTs disadvantage, when compared
to a CCCT, is the higher operational cost.
For comparing the three resource
strategies, the SCCT strategy assumes the
addition of a 250 MW SCCT plant in
2004.
Figure 12 shows that even with the
addition of a new 250 MW resource in
2004, some smaller seasonal deficiencies
may occur in 2006 and beyond. Because
these deficiencies are relatively small andof short duration Idaho Power will
address the strategies to cover those short-
term deficiencies in the 2002 IRP.
Cost Comparison of Resource
Strategies Including Emission
Cost Adders
A cost analysis was performed for
each of the three resource strategies with
the emission adders identified in OPUC
Order 93-695. The results are summarized
above in Table 6. Cost estimates of the
SCCT and CCCT strategies have assumed
thirty-year operating lives. To correspond
to Idaho Power Company s deficiencies
operating capacities of 30 percent were
assumed for both the SCCT and CCCT
cases. The market purchase strategy was
quantified using a Northwest market price
forecast based on the levelized costs of a
250 MW CCCT operating at a 93 percent
capacity factor for a thirty-year term. A
cost adder of 15 mills/kWh was added to
the market price to address the costs of
construction of new transmission
associated with a long-term market
purchase strategy. The costs of the
resource plans for each acquisition
strategy are progressively increased by the
case of minimum adders. As shown in
Table 6, the SCCT strategy is the least cost
without emission cost adders, however, the
CCCT strategy is the least cost strategy for
both the lowest and the highest level of
emission cost adders and, by interpolation
for the other four adder levels as well.
Discount Rate
The discount rate used to include
future years' costs in the resource plan can
influence the choice of the plan. A high
discount rate , for example, tends to favor
resources having low initial investment
cost but high future operating costs, such
as gas-fired generation, over resources
with high investment costs but low
operating costs, such as hydroelectric
generation. Conversely, a low discount
rate tends to favor resources with a high
TABLE 7
Cost Comparison of Resource Strategies
Over the Range of Discount Rates
($000 000)
Discount Rate
Resource Strategy 5.4%10.
Market Purchase Strategy 396 1 ,443 502
Combined-cycle Gas Fired Generation 095 243 410
Simple-cycle Combustion Turbine Strategy 061 111 173
percentage of total costs occurring in the
early years of resource lifetime.
Idaho Power s after-tax weighted
average cost of new capital (W ACC) was
used as the discount rate for determining
resource plan costs in the 2000 IRP. The
current W ACC value is 7.percent.
Discount rates other than the W ACC are
sometimes proposed to reflect other costs
considered appropriate for resource
planning. For example, a low discount Tate
can be used as a "societal" discount rate to
emphasize the long-term costs to societyof nonrenewable energy resource
depletion. Conversely, a high discount rate
can be used to reflect the market price risk
inherent in making long-term resource
acquisition commitments.
Sensitivity of the choice of
resource strategy to different choices of
discount rate has been investigated over a
range of nominal discount rates from 5.4
percent to 10.percent. The resulting
range of resource plan costs for the three
strategies is shown in Table 7. The cost of
each discount rate choice is influenced not
only by varying discount rates but also
changes in the cost of capital. Financing
risks associated with different discount
rates cause the cost of capital to increase
as discount rates increase and, as a result
can offset the effects of changes in
discount rates. Even using the lowest
discount rate assumption, the resource plan
for the SCCT is the least-cost plan over the
range of discount rates evaluated.
Selection of Strategy
The market purchase strategy was
eliminated from further consideration
primarily because of transmission
capability concerns.
In all likelihood, obtaining permits
and rights-of-way to construct additional
transmission to remedy expected
constraints on the Brownlee East
Transmission Path would require
approximately 3 to 5 years. Actual
construction would require another 2 to 3
years. Therefore, the earliest additional
transmission capability could be available
would be 2005.
As noted in Chapter 5, the cost of
constructing additional transmission would
increase monthly market purchase costs by
10 to 20 mills per kWh assuming a 50
percent load factor.
In addition the uncertainties
associated with the impact of FERC
Orders 2000 and 888 make it more
difficult to assess the costs and benefits to
Idaho Power of relying on additional
transmission construction to address native
load requirements.
The choice between selection of
the CCCT strategy or the SCCT strategy
was driven by the levelized cost of the two
generating technologies.
Figure 11 shows levelized costs at
various capacity factors for a 250-
megawatt CCCT plant and a 250-
megawatt SCCT plant both sited in Idaho.
It is important to note that the Idaho sited
costs in Figure 11 differ from the generic
sited costs shown in Figure lOin Chapter
4. A comparison of the two gas-fired
resources in Figure 11 reveals that a SCCT
plant is more economical up to an
operating capacity factor of approximately
47 percent. Since the Company s deficits
occur in only four months out of each
year, a resource with an operating capacity
factor of approximately 30 percent is all
that is needed to meet nearly all of the
demand beyond 2003. For this reason
acquisition of resources either by
construction of a SCCT plant by Idaho
Power or a purchase of power having thesame operational flexibility and
dependability characteristics of a SCCT
plant owned by Idaho Power is the
economical choice to meet projected
seasonal deficits in 2004 through 2009.
Because the remaining deficiencies
beyond 2005 are small and for short
durations acquisition of resources
equivalent to an additional 250 MW SCCT
unit may not be wan-anted. This issue will
be visited again in the Company s 2002
IRP.
Least-cost Resource Plan
The Company s least-cost resource
plan consists of three elements. First, the
Company plans to continue to make
seasonal market purchases of 250 average
megawatts in the months of July and
August and 200 average megawatts in
November and December throughout the
ten-year planning horizon. This strategywill essentially eliminate energy
deficiencies through 2003. Second, the
Company plans to acquire the generation
output of a resource equivalent to a 250
MW SCCT during months of deficiency
beginning in 2004. This strategy will
essentially eliminate energy deficiencies
through 2005. Finally, the Company plans
to reassess the deficiencies that remain in
2006 though 2009 informally prior to 2002
and formally in its 2002 IRP.
Figures 12 and 13 show the
monthly energy surplus/deficiencies for
the ten-year planning period assuming
median and low water conditions. As
shown in Figure 12, with the addition of
seasonal purchases and output from a 250-
megawatt resource equivalent, deficiencies
under a median hydro condition are
essentially eliminated until the year 2006
when July deficiencies reappear.
Figure 13 shows monthly energy
surplus/deficiencies under a low water
condition. Under this condition, Idaho
Power plans to use additional market
purchases to satisfy deficiencies.
Figure 14 shows monthly peak
hour surpluses/deficiencies for expected
loads and median water conditions after
the addition of seasonal purchases and
250 MW generating unit. Figure 15 shows
similar monthly information for a low
water condition. Figures 16 and 17 show
the transmission deficiencies that exist for
the combined loads of Idaho Power
Company, BP A in south Idaho , and FMC
second block during median and low water
conditions after a 250 MW generating
resource has been added in 2004.
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Chapter 7
Near-Term Action Plan
The Integrated Resource Plan
serves three main purposes. First, the plan
identifies the timing and amount of new
resources which are expected to be needed
during the ten-year planning period. The
timing and amount of new resources
needed during the ten-year planning period
are shown in Figures 2 through 7. Second
the plan identifies the resources that can
meet those needs at least cost. The
resources that can meet future loads are
shown in ranked cost order in Figures 10
and 11. Third, the IRP describes specific
actions which need to be taken in the
future to implement the long-term plan.
Idaho Power plans to take the
following actions during the 2000 to 2002
period to implement the 2000 Integrated
Resource Plan.
Purchase Seasonal Energj!
and Capacity As Needed
Meet System Load
Purchasing energy and capacity
from the Northwest market will continue
to be the primary source of supply for
Idaho Power s incremental resource needs
during the 2000 to 2003 period. As can be
seen in Figure 2 and Figure 4 summer
energy deficiencies in 2003 grow to 250
MW under median water condition and
400 MW under a low water condition.
Winter deficiencies remain smaller than
summer deficiencies during this time
period. Idaho Power expects that, for at
least the next three years adequate
transmission capability will exist to allow
sufficient purchases to be delivered to
Idaho Power s system from the Pacific
Northwest.
Initiate Request For
f!!JyJosals To PurcfJase
Energy and Capacit
In recognition of the increasing
duration of seasonal energy deficit; shown
on Figures 2 and the seasonal peak
deficiencies shown on Figure 3 , and
recognizing the limitations of the
transmission system to permit these
deficits to be covered solely by oFlSystem
purchases, Idaho Power will need
acquire additional resources. The
Company intends to initiate a request for
proposals (RFP) to supply projected peak
and energy deficits during the planning
period. The results of the RFP would be
compared to the costs of Idaho Power
constructing new generation resources and
including the investment in the new
resource for revenue requirement
determination.
Idaho Power intends to structure
this RFP to encourage the most cost-
effective responses and to allow for an
expeditious review and selection of the
best resource. This structure will not
preclude innovative generation technology
proposals but it may make it more difficult
for smaller multiple site resources to be
selected. The results of this RFP will be
useful for establishing a benchmark
against which the cost of future distributed
generation and demand-side management
initiatives might be measured.
~ort the Idaho Power
tJydro Relicensing Process
An important aspect of the
relicensing process for Idaho Power
hydroelectric facilities is identifying the
present and future value of power
generation from the relicensed facility.
The IRP will provide a continuing basisand methodology to evaluate the
Company hydroelectric generating
facilities for relicensing consistent with
other resource options. Any proposed
modifications or expansions of generating
capacity at existing hydroelectric facilities
will be evaluated within the relicensing
process.
Participate in RTO
Discussions
Consistent with FERC Order 2000
Idaho Power will continue to participate in
discussions to ensure equitable access and
efficient operation of the regional power
grid. The costs and benefits of increased
openness in transmission access is of
critical importance to both Idaho Power
and its native load customers. Open
transmission access, accomplished in a
manner that recognizes the legitimate
interests of all parties, including native
load, has the potential to increase Idaho
Power s opportunities to participate in the
power market and acquire market-based
resources as part of a least-cost plan to
meet customer load growth.
Participate in Regional
Conservation and Public
f!m:pose Programs
The Company will continue to
participate in NEEA which emphasizes
regional market transfonnation efforts and
market-driven energy efficiencies. As
previously noted the IPUC has authorized
funding for the Company s NEEA
participation through 2004.
Idaho Power will also continue to
participate in the Low Income
Weatherization Assistance Program, the
Oregon Commercial Audit Program, the
Oregon Weatherization Program and
various energy efficiency promotion
programs.
Investigate Potential Cost-
Effective Distributed
Generation Resources
Technological advances suggest
that distributed generation resources may
become cost-effective considerations for
the future. Idaho Power will continue to
evaluate the benefits DO might provide to
Idaho Power system with particular
emphasis on how DO might provide
transmission/distribution support and
decrease transmission/distribution grid
costs.
Idaho Power Company
2002 Integrated Resource Plan
June 2002
Idaho Power Company
2002 Integrated Resource Plan
Table of Contents
1. Integrated Resource Plan Summary .......................................................................................... 1
Introduction ...............................................................................................................................................
Risk Management.....................................................................................................................................
Load Forecast............................................................................................................................................
Resource Adequacy ...................................................................................................................................
Future Resource Options...........................................................................................................................
Near- Tenn Action Plan... ............ ........... ............... ............... ....... .......... ...........
......................... ......... .......
2. Load Forecast............................................................................................................................
Load Growth .............................................................................................................................................
Tenn Off-System Sales ...........................................................................................................................
Energy Efficiency and Demand-Side Management ................................................................................
3. Existing and Planned Resources..............................................................................................
Hydroelectric Generating Resources.......... ............ ............... ......... ............ ...... ...... ........ .......... .......... ..... 15
Thennal Generating Resources ....
.............. ............ ......... ................. ..........
........................... ........... ....... 18
Purchased & Exchanged Generating Resources.. ............
...... ....... ............ ...................
........... ................. 18
Transmission Resources ................. ........
................ ......... ...... ......... ..,............
....................... .............. ..... 19
4. Adequacy of Existing and Planned Resources.........................................................................
Water Planning Criteria for Resource Adequacy .................................................................................... 26
Planning Scenarios.................................. ................................ .....
""""""'" ........ ........................... .........
5. Future Resource Options.
..................................... ............ ..................... ............ ................
...... 35
Purchased and Exchanged Generation .................................................................................................... 35
Generating Resources............................................."""""""""""""""""""""""""""...........................
Hydroelectric Generating Resources.... ..................
......... .......,... ............................................. ....... .........
Thennal Generating Resources..... .............
.......... ........................ ................ .................. ................. ........
Thennal Technologies.............................................................................................................................
Advanced Technologies ..........................................................................................................................
Demand-Side Measures and Pricing Options......... ......
............ ........ ............................. ..... ........... ..... .....
Societal Costs ..........................................................................................................................................
Ten- Year Resource Plan........
"""""""""""""""
.................................. ................. ................. 49
Overview """""'......................................,....."""""""""""""""""""""""""""....................................
Resource Strategies.................... ............. .............................................. ................. .........
................ ........
Strategy Selection....................................................................................................................................
Least-Cost Resource Plan........................................................................................................................
7. Near-Term Action Plan....
........... ........ ........ ...............
................. ................ ............ ....... .......... 61
Introduction .............................................................................................................................................
Near-Term Action Plan........................................................................................................................... 61
Market Purchases ....................................................................................................................................
Generation Resources.......................................,......................................................................................
Transmission Resources ..........................................................................................................................
Demand-Side Management, Energy Conservation, and Pricing Options ...............................................
Green Energy........................................................................
:..................................................................
Appendices:
Appendix A 2002 Economic Forecast
Appendix B 2002 Sales and Load Forecast
Appendix C 2002 Conservation Plan
Technical Appendix
Glossary of Acronyms
AEO - Annual Energy Outlook
AIR - Additional Information Requests
aMW - Average Megawatt
APS - Arizona Public Service
BP A - Bonneville Power Administration
CCCT - Combined-Cycle Combustion Turbine
CO2 - Carbon Dioxide
CT - Combustion Turbine
DOE - Department of Energy
DG - Distributed Generation
DSM - Demand-Side Management
EA - Environmental Assessment
EIA - Energy Information Administration
FERC - Federal Energy Regulatory Commission
HP /IP - High Pressure/Intermediate Pressure
IOU - Investor-Owned Utility
IPC - Idaho Power Company
IPUC - Idaho Public Utilities Commission
IRP - Integrated Resource Plan
kV - Kilovolt
kWh - Kilowatt hour
LIW A - Low-Income Weatherization Assistance
MMBTU - Million British Thermal Units
MW - Megawatt
MWh - Megawatt hour
NEEA - Northwest Energy Efficiency Alliance
NWPPC - Northwest Power Planning Council
NOx - Nitrogen Oxides
NYMEX - New Yark Mercantile Exchange
OPUC - Oregon Public Utility Commission
PM&E - Protection, Mitigation and Enhancement
PV - Photovoltaic
QF - Qualifying Facility
RFP - Request for Proposal
R TO - Regional Transmission Organization
SCCT - Simple-Cycle Combustion Turbine
S02 - Sulfur Dioxide
SWIP - Southwest Intertie Project
TSP - Total Suspended Particulates
W ACC - Weighted Average Cost of Capital
WEFA - Wharton Econometrics Forecast Associates
WECC - Western Electricity Coordinating Council
1. Integrated Resource Plan Summary
Introduction
The 2002 Integrated Resource Plan
(IRP) is Idaho Power Company s (IPC or
the Company) sixth resource plan prepared
to fulfill the regulatory requirements and
guidelines established by the Idaho Public
Utilities Commission (IPUC) and the
Oregon Public Utility Commission (OPUC).
Prior to submission of the 2002
Integrated Resource Plan, two sets of public
meetings were held. The first set of
meetings solicited comments regarding
water-planning criterion. Previous IRPs
used median, or normal, stream flows for
resource planning. The second set of public
meetings followed the release of the draft
version of the plan. In addition, written
comments were solicited from the public at
both stages.
Based on legislative actions in
Oregon and Idaho, the 2002 Integrated
Resource Plan assumes that during the
planning period, from 2002 through 2011
Idaho Power will continue to be responsible
for acquiring sufficient resources to serve all
of its customers in its Idaho and Oregon
certificated service areas and will continue
to operate as a vertically-integrated electric
utility. It is the intent that neither the
Company nor its customers will be
disadvantaged by decisions made in
accordance with the 2002 Integrated
Resource Plan.
The two primary goals of the 2002
Integrated Resource Plan are to:
1. Maintain Idaho Power s ability to
reliably serve the growing demand
for electricity within the service
territory throughout the 10-year
planning period.
2. Ensure that resources selected are
cost-effective, low risk, and meet the
increasing electrical energy demands
of our customers.
The number of households in the
Idaho Power Company service territory is
expected to increase from around 310 000
today to nearly 380 000 by the end of the
planning period in 2011. Population growth
in Southern Idaho is an inescapable fact, and
IPC will need physical resources to meet the
electrical energy demands of the additional
customers.
Idaho Power Company has an
obligation to serve customer loads
regardless of the water conditions that may
occur. In light of public input to the
planning process, IPC will emphasize a
resource plan based upon a worse-than-
median level of water. In the 2002 resource
plan, IPC is emphasizing the 70th percentile
water conditions and 70th percentile load
conditions for resource planning. The
water-planning criteria are discussed further
in Chapter 4.
Risk Management
Idaho Power, in conjunction with
the IPUC staff and interested customer
groups, developed a risk management policy
during 2001 to protect against severe
movements in the Company s Power Cost
Adjustment (PCA) balance. The risk
management policy is primarily aimed at
managing short-term market purchases and
hedging strategies. The policy is intended to
supplement the existing IRP process. In
summary, the IRP will be the forum for
making long-term resource decisions while
the risk management policy will address the
Chapter Plan Summary
short-tenD resource decisions that arise as
resources, loads, costs of service, market
conditions, and weather vary.
Load Forecast
The 2002 Sales and Load Forecast
includes three forecasts defining possible
load conditions in the Idaho Power service
territory during the 2002 through 2011
planning period.
The expected load forecast assumes
median temperatures and median
precipitation. Since actual loads can vary
significantly dependent upon weather
conditions , two alternative scenarios are also
considered.
70th percentile load forecast and
90th percentile load forecast were prepared
to address the weather risk and uncertainty
inherent in forecasting loads. The 70th
percentile load assumes a level of monthly
loads that are not likely to be exceeded 70
percent of the time. However, the 70th
percentile load forecast is expected to be
exceeded 3 out of 10 years, or 30 percent of
the time.
The 90th percentile load forecast
assumes monthly loads that are not likely tobe exceeded 90 percent of the time.
However, the 90th percentile load forecast is
expected to be exceeded in lout of 10 years
or 10 percent of the time.
The three forecasts are discussed
further in Chapter 2 and in Appendix B
2002 Sales and Load Forecast.
Resource Adequacy
In the Integrated Resource Plan
modeling process, monthly demand and
energy requirements from the 2002 Sales
and Load Forecast are compared throughout
the planning period against the generating
capability of Idaho Power s power supply
system. The comparison reveals Idaho
Power s future need for additional capacity
and energy resources.
Idaho Power has detennined that
existing resources, as described in Chapter
, are likely to be insufficient to meet
expected peak energy requirements under
the 70th percentile load and water conditions
as early as 2003. Under the 70th percentile
water and load conditions, projected peak-hour loads may cause peak-hour
transmission overloads from the Pacific
Northwest presenting significant difficulties
during the summers of 2003 and 2004. A
combination of purchases from the east side
demand reduction programs, and temporary
generation resources may be required to
meet the projected summer peak-hour loads
in 2003 and 2004.
Idaho Power Company recognizesthat capacity constraints may present
significant difficulties during the summer
peak-hour conditions. IPC is addressing thepotential difficulties (transmission
overloads) projected for the summers of
2003 and beyond by pursuing several
strategies that will enhance IPC's ability to
serve projected loads without encountering
transmission overloads from the Pacific
Northwest. The strategies include:
1. Making finD purchases for the
system (possibly sourced from areas
other than the Pacific Northwest)
while simultaneously making a non-
finD off-system sale. This provides
Idaho Power with the ability to
interrupt the non- finD sale during
critical peak-hour conditions.
2. Accelerating construction of the
Brownlee to Oxbow Number 2
transmission line. The transmission
deficiencies illustrated in Figure
Chapter Plan Summary
assume the line is available summerof 2005. IPC is considering
accelerating construction of the
project to have the transmission
available summer of 2004.
3. Idaho Power plans to continue
investigating opportunities for cost-
effective power exchanges as a
method to manage projected
surpluses and deficiencies. For
example the existing Montana
exchange ends in December of 2003- if an agreement similar to the
current agreement was in place for
summer 2004 the projected
transmission overload from the
Pacific Northwest projected for July
would be reduced by 75 MW. Idaho
Power has already contacted
Northwestern Energy to discuss this
opportunity .
In addition to the above strategies
Idaho Power has some short-tenn peaking
capability at C.J. Strike, Bliss and Lower
Salmon hydro plants that was not modeledin the monthly peak-hour surplus and
deficiency, or the monthly peak-hour NW
transmission deficit analyses. For these
analyses, the three hydro plants were
assumed to operate at the monthly average
generation values. While the assumption
simplifies the analysis, it also understates
the important peaking capability of the
projects.
The combined peaking capacity of
these projects that is not accounted for in the
above-mentioned analyses is approximately
100 MW for a I-hour period. The dispatch
of the plant capacity presents a complex
modeling problem. Because of the
complexity, the peaking capacity of the
plants was not included in the resource
model. However, Idaho Power Company
intends to continue to use the peaking
capacity of these plants in actual operations.
An additional 100 MW of tenn
market purchases in June, July, November
and December to supplement the existing
IPC resources are planned to meet the
monthly average energy requirements
through the summer of 2011.
Contingency Plans
The energy crisis of 2001 was a
learning experience for Idaho Power.
Several of the demand reduction programs
developed during the energy crisis are
considered to be active contingency plans
capable of being utilized again. One
example is the Energy Exchange Program.
The Energy Exchange Program enabled
industrial customers to reduce load during
certain hours in exchange for a payment
from Idaho Power. While the program is
currently inactive, the Energy Exchange
Program could be reactivated on short
notice, if necessary to respond to extreme
conditions. Other demand reduction
programs, such as the Irrigation VoluntaryLoad Reduction Program can
implemented on short notice if deemed
necessary .
Garnet Delayed
In the 2000 Integrated Resource
Plan, Idaho Power identified a need for
additional generating resources located close
to the Treasure Valley load center beginning
in June of2004. The identified need was the
basis upon which Idaho Power issued the
request for proposals (RFP), specifying an
on-line date of June 1 , 2004. The Gamet
Energy LLC proposal was selected. A
Power Purchase Agreement (PP A) between
Idaho Power Company and Gamet Energy
Chapter Plan Summary
LLC was negotiated and filed with the IPUC
in December 2001. Section 4.4 of the PPA
provides Idaho Power with an option to
delay the guaranteed commercial operation
date of the Gamet facility from the currently
scheduled date of June 1 , 2004 until June 1
2005. The option exercise date was April
2002.
To assess the cost, benefits and
prudence of the PP A for Idaho Power rate-
making purposes, the IPUC has scheduled
technical hearings in Case No. IPC-01-
for late July 2002. Considering the nature of
Idaho Power s projected deficiencies for
2004, and the hearing schedule that
commences after the Gamet delay option
expires, Idaho Power has detennined that itis prudent to delay the guaranteed
commercial operation date of the Gamet
facility until June 1 2005.
Idaho Power s decision to delay the
commercial operation date of the Gamet
facility until June 1 , 2005, will present
several near-tenn challenges that will need
to be addressed if a low-water and high-load
condition occurs in 2004.
Future Resource Options
Beginning in June 2005, additional
pennanent resources will be required to
meet Idaho Power Company service
territory load requirements. Idaho Power
Company has three options available to meet
the projected resource requirements:
1. Market purchases.
2. Generation and transmission
resources.
3. Targeted demand-side management
targeted conservation measures, and
pricing options.
Market Purchases
In the 2002 IRP, Idaho Power
Company plans to use tenn market
purchases from the Pacific Northwest
throughout the planning period
supplement company resources in June
July, November, and December. The
market purchases are placed in the resource
plan in 100 MW increments. A tenn market
purchase implies the purchase of a specific
quantity of energy and capacity during a
specific time period. Tenn market
purchases are usually made prior to actual
need and not during real-time system
operation. Additionally, tenn market
purchases are usually for longer time periods
than are the hourly market purchases made
during real-time system operations.
To not rely solely on long-tenn
market purchases beyond 2004 was
detennined to be the optimum strategy
because the delivery of increased market
purchases from the Pacific Northwest would
require substantial investments in additional
transmission facilities to relieve constraints
on Idaho Power transmission system.
However, tenn market purchases remain an
important aspect of resource planning,
allowing efficient timing of new resources
as well as efficient use of existing resources.
Transmission constraints are discussed more
thoroughly in Chapter 3.
Generation and Transmission
Resources
Generic generating resources using
currently available technologies, including
gas-fired and coal-fired thennal generation
renewable resource technologies such as
hydropower, solar, geothennal, wind power
and generation from fuel cells, were
considered as potential resources for
inclusion in the 2002 Integrated Resource
Plan. One of the technologies, a 100 or 200
MW simple-cycle gas-fired combustion
Chapter Plan Summary
turbine, was selected as the core supply-side
resource for the third and fourth resource
strategies in the final evaluation. A 64 MW
upgrade to the Shoshone Falls plant is part
of each resource strategy.
The 2002 Integrated Resource Plan
incorporates the planned addition of a new
lO-mile 230 kV transmission line between
Brownlee and Oxbow. The Brownlee-
Oxbow upgrade is expected to add 100 MW
of transmission capacity. The transmission
upgrade is planned to be in service by the
fall of 2004.
Demand-Side Management and
Targeted Conservation Measures
Due to the nature and timing of
projected energy deficits and transmission
overloads, conservation and demand-side
measures must be carefully targeted to cost-
effectively address the projected deficits. If
the Idaho PUC approves the Company
proposed conservation rider, Idaho Power
Company anticipates the addition of targeted
demand-side management and targeted
energy conservation programs.
Idaho Power Company plans to
continue supporting regional and local
conservation efforts including NEEA.
Participation in regional and local
conservation efforts is contingent upon
committed funding. Idaho Power Company
will also proceed with plans to improve
energy efficiency at other company
facilities. Although not specifically
identified in the Resource Strategies or the
Near- Term Action Plan, Idaho Power willcontinue cost-effective incremental
efficiency upgrades to existing generation
facilities.
Four Resource Strategies Analyzed
Idaho Power s resource options for
the planning period are described in Chapter
5. To meet the forecast loads in a cost-
efficient manner throughout the 10-year
planning period, IPC considered multiple
resource acquisition strategies. The
strategies included increased monthly
energy and capacity purchases from the
Pacific Northwest power market to meet
seasonal deficiencies and the acquisition of
additional generating capability from a
portfolio of various generation technologies.
Each resource strategy includes upgrading
the Oxbow to Brownlee transmission path
adding 100 MW of import capacity from the
Pacific Northwest. Four strategies are being
considered for final analysis and review:
1. The first resource strategy is a long-
term limited-quantity market
purchase strategy.
2. The second resource strategy is a
combination of long-term market
purchases of varying quantities and a
64 MW facility upgrade to the
existing Shoshone Falls hydro plant.
3. The third resource strategy is a
combination of short-term limited-
quantity market purchases the
acquisition of 200 MW of peaking
resources and a 64 MW facility
upgrade at Shoshone Falls.
4. The fourth resource strategy is a
combination of long-term limited-
quantity market purchases the
acquisition of 100 MW of peaking
resources and a 64 MW facility
upgrade at Shoshone Falls.
The portfolio of resources is fully described
in the Near-Term Action Plan (Chapter 7).
Near-Term Action Plan
Customer growth is the primary
driving force behind Idaho Power
Company s need for additional resources.
Population growth throughout Southern
Chapter Plan Summary
Idaho and specifically, in the Treasure
Valley requires additional measures to meet
both peak and electrical energy needs.
Over the past 85 years, Idaho Power
Company has developed a portfolio
generation resources. The Company
believes that a blended approach based on a
portfolio of options is the most cost-
effective and least-risk method of addressing
increasing energy demands of Idaho Power
customers.
Because of the short duration of the
forecast peak load conditions, Idaho Power
has identified a resource strategy using both
supply-side and demand-side measures.
Idaho Power believes that the following
plan, which outlines a balanced approach
has a high probability of being the least
expensive for Idaho Power s customers.
The plan is based on Strategy 4, a
combination of limited long-term market
purchases and generation additions. The
plan also calls for a transmission upgrade
along with an investigation into demand
reduction measures suitable to address the
short duration of projected peak-hour
transmission overloads.
In summary, Idaho Power has
identified six items to address the resource
needs in the Near- Tenn Action Plan:
First, Idaho Power Company plans to
continue to make seasonal market purchases
of 100 aMW in the months of June, July,
November and December throughout the
planning period.
Second Idaho Power Company
plans to integrate demand-side measures
where economical, to address the short
duration peaks of the system load.
Third, Idaho Power Company plans
to solicit proposals and initiate the siting and
pennitting for approximately 100 MW of a
utility-owned and operated peaking resource
to be available beginning in 2005.
Fourth, assuming the Idaho PUC
approves the Gamet Power Purchase
Agreement, Idaho Power will purchase up to
250 MW of capacity and associated energy
during periods of peak need beginning June
2005.
Fifth, Idaho Power Company plans
to proceed with the Brownlee to Oxbow
transmission line, expecting the project to be
in-service in 2005 and increasing the import
capabilities from the Pacific Northwest.
Sixth, Idaho Power Company plans
to proceed with the Shoshone Falls upgrade
project, expecting the upgrade to be in-
service in 2007.
Finally, Idaho Power Company plans
to infonnally reassess the deficiencies that
remain in 2008 though 2011 prior to 2004.
The deficiencies will be fonnally assessed in
the 2004 IRP.
Additional Steps
Idaho Power Company supports the
Green Power Program. In order to meet the
needs of customers desiring Green Energy,
IPC has identified two specific near-tenn
actions to be initiated during the next two
years:
1. Idaho Power anticipates participatingin several educational and
demonstrational energy projects with
a focus on green resources.
2. Idaho Power intends to dedicate up to
$50 000 to explore the feasibility of
constructing a pilot anaerobic
digester project within the IPC
service territory.
Idaho Power Company and the
Commissions must agree on mechanisms
that insure prompt recovery of prudent costs
Chapter Plan Summary
incurred for the pilot and demonstration
projects.
Although not specifically identified
in the Four Resource Strategies or in the
Near- Term Action Plan, Idaho Power willcontinue to pursue cost-effective
incremental upgrades at existing generation
facilities.
Consistent with the final Risk
Management Policy under review in Case
No. IPC-OI-, Idaho Power Company
will continue to use the short-term regional
market to balance system load and
generation, as well as take advantage of the
long-term energy market to secure energy at
reasonable prices.
Idaho Power Company continually
works to improve the resource planning
process. Idaho Power has recently made
organizational changes to further improve
integrated resource planning. The Company
agrees with the IPUC that integrated
resource planning will continue to be
important and ongoing activity at Idaho
Power Company.
Chapter Plan Summary
Chapter Plan Summary
2. Load Forecast
Load Growth
Future demand for electricity by
customers in Idaho Power Company
service territory is represented by three load
forecasts, which reflect a range of load
uncertainty. Table 1 summarizes the three
forecasts of Idaho Power s annual total load
growth during the planning period. The
forecast 10-year average annual growth rate
in the expected load forecast is 2.3 percent.
The expected load forecast
represents the most probable projection of
service territory load growth during the
planning period. The forecast for total load
growth is determined by summing the load
forecasts for individual classes of service, as
more particularly described in Appendix B
2002 Sales and Load Forecast. For
example, the expected total load growth of
3 percent is comprised of residential loads
growth of 2.4 percent, commercial loads
growth of 4.1 percent irrigation loads
growth of 0.4 percent industrial loads
growth of 2.4 percent, and additional firm
loads growth of 2.2 percent.
Economic growth assumptions
influence the individual customer-class
forecasts. The number of households and
employment projections along with
customer consumption patterns, are used to
form load projections. Economic growth
information for Idaho and its counties can be
found in Appendix A , 2002 Economic
Forecast.
The number of households in the
State of Idaho is projected to grow at an
annual average rate of 2.1 percent during the
10-year forecast period. Growth in the
number of households within individual
counties in Idaho Power service area
differs from statewide household growth
patterns. Service area household projectionsare derived from individual county
household forecasts. Growth in the number
of households within the Idaho Power
service territory, combined with reduced
consumption per household, results in the
previously mentioned 2.4 percent residential
load growth rate.
The expected case load forecast
assumes median temperatures and median
precipitation; i., there is a 50 percent
chance that loads will be higher or lower
than the expected forecast loads due to
colder-than-median' or hotter-than-median
temperatures or wetter-than-median or drier-
than-median precipitation.
Since actual customer loads can
vary significantly dependent upon weather
conditions, two alternative scenarios were
considered that address load variability due
to weather. IPC has generated load forecastsfor 70th percentile weather and 90th
percentile weather. 70th percentile weather
means that in seven out of 10 years, the load
is expected to be less than the forecast and
in three out of 10 years, the load is expected
to exceed the forecast. 90th percentile load
has a similar definition.
Cold winter days create high heating
load. Hot, dry summers create both high-
cooling and high-irrigation loads. In the
winter, maximum load occurs with the
highest recorded levels of heating degree
days (HDD). In the summer, maximum load
occurs with highest recorded levels of
cooling and growing degree days (CDD and
GDD). Heating degree days, cooling degree
days, and growing degree days are used by
IPC to quantify the weather and estimate a
load forecast.
Chapter Load Forecast
Table 1 Idaho Power Company
Range of Load Growth Forecasts
Average Megawatts
Forecast 2002 2004 2006 2008 2010 2012 Avg Annual
Growth Rate
889 003 091 174 261
821 933 018 099 183
781 892 976 056 139
th Percentile Load
th Percentile Load
th Percentile Load
(Expected or Median)
818
753
714
For example, at the Boise Weather
Service Office, the median number of HDD
in December over the 1964-2000 time
period is 1 039 HDD. The coldest
December over the same time period was
December 1995 when there were 1 619
HDD recorded at Boise.
For December, the 70th percentile
HDD is 1 079 HDD. The 70th percentile
value is likely to be exceeded in three out of
10 years on average. The 90th percentile
HDD is 1 278 HDD and is likely to
exceeded in one out of 10 years on average.
Percentile estimation was used in each
month throughout the year for the weather-
sensitive customer classes - residential
commercial, and irrigation - to forecast load.
In the 70th percentile residential and
commercial load forecasts, temperatures in
each month were assumed to be at the 70th
percentile of HDD in winter and at the 70th
percentile of CDD in the summer. In the
70th percentile irrigation load forecast, GDD
were assumed at the 70th percentile and
precipitation was assumed to be at the 70th
percentile, reflecting weather that is both
hotter and drier than median weather. The
90th percentile irrigation load forecast was
similarly constructed using weather values
measured at the 90th percentile.
Idaho Power loads are highly
dependent upon weather. The three
scenarios allow careful examination of load
variability and how the load variability may
impact resource requirements. It
important to understand that the
probabilities associated with the load
forecasts apply to any given month and that
an extreme month may not necessarily be
followed by another extreme month. In fact
normal year likely contains extreme
months as well as mild months.
Astaris Load
The Astaris elemental phosphorous
plant temporarily ceased production at the
end of 2001. Because of the change in its
business situation, Astaris is expected to
only require 10 MW per month for on-going
maintenance. The 10 MW is included as a
firm load requirement of Idaho Power. The
Astaris special contract with Idaho Power
will expire in March 2003, at which time
Astaris is expected to become a Schedule 19
industrial customer. The Astaris contract
allows for up to 240 MW of load and, until
Astaris notifies Idaho Power of changes to
the contract, IPC must consider the
possibility of up to 240 MW of Astaris load.
Until recently, Astaris had been IPC'
largest individual customer.
Chapter Load Forecast
Table 2 Idaho Power Company
Term Off-System Sales
Contract 2002 Average LoadExpiration
Washington City
City of Weiser
Utah Associated Municipal Power Systems
City of Colton
Raft River Rural Electric Cooperative
Total Term Sales
June 2002
December 2002
December 2003
May 2005
September 2006
2aMW
6aMW
40 aMW
3aMW
6aMW
57 aMW
Term Off-System Sales
Idaho Power cuITently has five term
off-system sales contracts. Most of the five
contracts were entered into in the late 1980s
or early 1990s when Idaho Power had an
energy and capacity surplus. The contracts
expiration dates, and average sales amounts
are shown in Table 2.
The term sales contract with the
City of Weiser is a full-requirements
contract with Idaho Power. Under a full-
requirements contract, Idaho Power
responsible for supplying the entire load of
the City. The City of Weiser is located
entirely within Idaho Power s load-control
area.
term sales contract with Raft
River Rural Electric Cooperative Inc. was
established as a full-requirements contract
after being approved by the Federal Energy
Regulatory Commission (FERC) and the
Public Utilities Commission of Nevada.
Raft River Rural Electric Cooperative Inc. is
the electric distribution utility serving Idaho
Power s former customers in the State of
Nevada. Idaho Power sold the transmission
and distribution facilities, along with the
rights-of-way that serve about 1 250
customers in Northern Nevada and 90
customers in Southern Owyhee County, to
Raft River Rural Electric Cooperative Inc.
The closing date of the transaction was April
, 2001. The area sold to Raft River Rural
Electric Cooperative Inc. is located entirely
within Idaho Power s load-control area.
Idaho Power Company recently
notified the City of Colton that IPC intends
to terminate the contract at the end of Mayin 2005. Contract termination requires
three-year advance notification and can be
initiated by either party. Peak and energy
forecasts used in the IRP assumed
termination of the Colton contract at the end
of June 2004.
As shown in Table 2, most of the
term off-system sales contracts are
scheduled to end by the end of 2003. Idaho
Power will continue to evaluate the value of
term off-system sales but with the
exceptions of the City of Weiser and Raft
River Rural Electric Cooperative Inc., Idaho
Power has not included the renewal of any
term off-system sales contracts in its load
projections.
Energy Efficiency and Demand-
Side Management
In response to IPUC Order No.
28722, Idaho Power filed a comprehensive
Demand-Side Management (DSM) program
on July 31 , 2001. The filing proposed a
Chapter Load Forecast
percent charge applied to all customer
classes to fund new DSM programs. The
proposed charge was to be included as a
rider on customer bills. A list of program
options that could be implemented with
DSM funding was included as part of the
filing. Idaho Power Company also proposed
developing an Energy Efficiency Advisory
Group to assist with selecting and evaluating
DSM programs if the rider charge for
conservation funding is approved. On
November 21 , 2001 , in Order No. 28894the Idaho Commission postponed
consideration of DSM funding until the
2002 PCA filing in April 2002.The energy conservation
improvements attributable to past
participation in Idaho Power s DSM
programs are reflected in the actual
measured loads of recent years and
throughout the forecast of projected loads
for future years in the planning period.
Idaho Power Company most
current reports to the IPUC and the OPUC
regarding DSM programs are attached
hereto as Appendix 2002 Conservation
Plan.
Northwest Energy Efficiency Alliance
The Northwest Energy Efficiency
Alliance mission is to promote market
transfonnation to energy efficient products
and services in the Pacific Northwest. Idaho
Power is one of six investor-owned utilities
and eight public utilities that provide
funding in the region. Idaho Power
continuing commitment to the Alliance
dependent upon regulatory approval of cost
recovery .
The Northwest Energy Efficiency
Alliance conducts activities such as market
research, technology assessment, planning,
and brokering collaborations. In additionthe Alliance administers demonstration
programs targets market interventions
develops infrastructures to assist market
transfonnations and disseminates
infonnation. To ensure the effectiveness of
its efforts the Alliance conducts a
comprehensive evaluation of each of the
projects.
Idaho Power has entered into a
Memorandum of Agreement to fund the
Northwest Energy Efficiency Alliance
through 2004. For that period, Idaho
Power system-wide contribution is
estimated to be $1.3 million annually out of
an annual Alliance budget of $20 million.
The $1.3 million requested contribution is
less than the $1.million annually that
Idaho Power was previously contributing to
the Alliance. Idaho Power Company is
hopeful that the public utility commissions
of Idaho and Oregon will support the
funding request.
Idaho Power supports and
complements the Alliance activities in its
retail service territory in the states of Oregon
and Idaho. Due to the small size of the
Oregon retail service territory compared to
the Idaho retail service territory, most of the
costs for participation in the Alliance have
been allocated to the Idaho retail service
territory. For the same reason, the Idaho
Public Utilities Commission has been the
primary agency that the Company has
looked to for authorization to participate in
the Northwest Energy Efficiency Alliance.
Idaho Power Company has recently obtained
approval from the IPUC for continued
participation in the Alliance through the year2004. The OPUC has consistently
expressed its support of the Company
participation in the Alliance by providing
funding from Idaho Power Oregon
customers.
Chapter Load Forecast
Northwest Power Planning Council
Regional Efficiency
The Northwest Power Planning
Council (NWPPC) has a conservation goal
of 300 aMW within three years. The
NWPPC suggests that IPC can contribute
160 MWh, or just over 9 aMW, to the
effort. Idaho Power Company intends tomeet the NWPPC goal through a
combination of customer and company
conservation. Idaho Power Company has a
variety of large facilities, including offices
maintenance shops, generation facilities, and
distribution and transmission facilities.
Conservation at the various IPC facilities is
expected to make a significant contribution
to the Northwest Power Planning Council
conservation goal.
BPA Conservation and Renewable
Discount Program
Under the Bonneville Power
Administration (BP A) residential exchange
program Idaho Power is eligible to
participate in the Conservation and
Renewable Discount Program (C&RD).
The C&RD is a credit that is made availableto Idaho Power in order to further
conservation and renewable development in
the region. Idaho Power can spend up to
$525 000 per year on qualified expenditures
through 2004. Qualified expenditures are
specified by BP A.
Idaho Power allocates the C&RD
credit to residential conservation programs.
During the winter of 2001-2002, 14 000
energy efficiency packets were distributed to
lower income or high electrical usage
customers. Each packet included energy
efficiency information and an Energy Star
compact fluorescent bulb as an example of
energy conservation. Future programs using
C&RD funding are in planning stages.
Public-Purpose Programs
Low-Income Weatherization Assistance
Low-Income Weatherization
Assistance (LIW A) is a public-purpose
program to make weatherization services
more affordable for low-income customers.
Payments are made to local non-profit
agencies participating in state-run
weatherization programs in Idaho and
Oregon to supplement federal funding. In
Idaho, the program is fuel-blind and allows
payments for some health and safety
measures, as well as weatherization. In
Oregon, all dwellings must be electrically
heat~d and all measures must provide cost-
effective electricity savings to be eligible for
funding. Idaho Power typically contributes
50 percent of the cost for qualifying
measures, plus a $75 administration fee, perdwelling. The program also funds
weatherization of buildings occupied by tax-
exempt organizations.
Oregon Commercial Audit Program
The Oregon Commercial Audit
Program is a statutory program specifying
that all commercial building customers be
notified every year that information
regarding energy-saving operations and
maintenance measures is available and that
commercial energy-audit services can be
provided. The audit services are nonnally
provided at no charge to the customer.
Customers using more than 4 000 kWh per
month may receive a more detailed audit but
may be required to pay a portion of the cost.
Oregon Residential Weatherization
The Oregon Residential
Weatherization Program is statutory
requirement program specifying annual
notification to all residential customers
informing them how to obtain energy audits
and financing for energy conservation
Chapter Load Forecast
measures. To qualify for an Idaho Power
audit or financing, customers must have
electric space heat.
Energy Efficiency Promotion
Activities
Idaho Power continues to promote
the wise, efficient, and safe use of electricity
by providing infonnation and education at
workshops and conferences. Idaho Power
offers infonnational material, consulting
services energy audits, power quality
assistance, audits, and financing to help
customers avoid energy problems.
Chapter Load Forecast
3. Existing and Planned Resources
Hydroelectric Generating
Resources
Idaho Power operates
hydroelectric generating plants located onthe Snake River and its tributaries.
Together these hydroelectric facilities
provide a total nameplate capacity of 1 707
MW and median water annual generation
equal to approximately 1 071 aMW.
The backbone of the Company
hydroelectric system is the Hells Canyon
Complex in the Hells Canyon reach of the
middle Snake River. The Hells Canyon
Complex consists of the Brownlee, Oxbow
and Hells Canyon dams and associated
generating facilities. The three plants
provide approximately 70 percent of IPC'
annual hydroelectric generation and nearly
40 percent of the total energy generation.
Water storage in the Brownlee reservoir also
enables the Hells Canyon Complex
provide the major portion of IPC's peaking
and load-following capability.
Idaho Power hydroelectric
facilities upstream from Hells Canyon
include the American Falls, Milner, Twin
Falls, Shoshone Falls, Clear Lake, Thousand
Springs, Upper and Lower Malad, Upper
and Lower Salmon, Bliss, C.l. Strike, Swan
Falls and Cascade generating plants. Water
storage reservoirs at Lower Salmon, Bliss
and C.l. Strike provide for peaking
capabilities at these plants. All of the other
upstream plants utilize run-of-river stream
flow for generation.
Federal Energy Regulatory
Commission Relicensing Process
Idaho Power Company
hydroelectric facilities , with the exception of
the Clear Lake and Thousand Springs plants
operate under federal licenses regulated by
the FERC. The process of relicensing Idaho
Power s hydroelectric projects at the end of
their initial 50-year license periods is well
under way. A license renewal was granted
by FERC in 1991 for the Twin Falls project.
Applications to relicense the Company
three mid-Snake facilities (Upper Salmon
Lower Salmon and Bliss) were submitted to
FERC in December 1995. The application to
relicense the Shoshone Falls project was
filed in May 1997. The application to
relicense the C.l. Strike project was filed in
November 1998. Relicensing applications
for the remaining hydroelectric facilities
including Swan Falls, the Upper and Lower
Malad plants, and the Hells Canyon
Complex, will be prepared and submitted
during the current ten-year planning period.
The relicensing schedule for hydroelectric
projects is shown in Table 3.
Failure to relicense existing
hydropower projects at a reasonable cost
would create upward pressure on the current
low rates available to Idaho Power
customers. The relicensing process may
potentially decrease available capacity and
increase the cost of a project's generation
through additional operating constraints and
requirements for environmental protection
mitigation and enhancement (PM&E)
imposed as a condition for relicensing.
Idaho Power Company s goal in relicensing
is to maintain the low cost of generation atthe hydroelectric facilities while
implementing non-power measures designedto protect and enhance the river
environment. No reduction of the available
capacity of hydroelectric plants to be
relicensed was assumed as part of the 2002
Integrated Resource Plan. If capacity
reductions occur as a result of the process
Chapter Existing and Planned Resources
Table 3 Idaho Power Company
Hydropower Project Relicensing Schedule
FERC Nameplate Current File FERC
Project License Capacity License License
Number (MW)Expires Application
Bliss 1975 Dec 1997 Dec 1995
Lower Salmon 2061 Dec 1997 Dec 1995
Upper Salmon 2777 34.Dec 1997 Dec 1995
Shoshone Falls 2778 12.May 1999 May 1997
J. Strike 2055 82.Nov 2000 Nov 1998
Upper/Lower Malad 2726 21.July 2004 July 2002
Hells Canyon Complex 1971 1166.July 2005 July 2003
Swan Falls 503 June 2010 June 2008
then Idaho Power Company would be forced
to add other capacity resources in order to
maintain reliability.
Collaborative Process
Idaho Power is seeking to address
concerns regarding hydro generation by
working with various public and private
agencies and organizations and pursuing a
collaborative approach to the relicensing of
the hydro generation facilities. Discussions
with state and federal agencies have been
initiated to investigate ways in which the
low costs and flexibility of existing hydro
generation can be retained for the benefit of
Idaho Power customers.
Idaho Power has established a
collaborative team consisting of federal and
state resource agencies, tribes, regional and
local governments, non-governmental
organizations industrial and commercial
customers regulatory bodies and other
interested entities to actively participate with
Idaho Power by exchanging infonnation and
providing input on components of new
license applications including Idaho
Power s PM&E proposals. The goals of the
collaborative process are to:
Involve resource agencies and the public
throughout the relicensing process for
Idaho Power s hydroelectric projects.
- F oster open exchange of views among
participants.
Facilitate well-defined and focused study
plans.
Encourage agreements among
participants on the content of
applications for relicensing, on PM&E
plans and on conditions of new licenses.
Ensure efficient use of resources and
avoid unnecessary study and process
costs.
Provide participants with more control
and certainty in the relicensing process
through better relationships with affected
entities and the public.
Reduce the likelihood and extent of
potential litigation.
The FERC has expressed
encouragement for the collaborative process
and FERC representatives routinely attend
the collaborative team meetings.
Chapter Existing and Planned Resources
Environmental Analysis
The National Environmental Policy
Act requires that FERC perform an
environmental assessment (EA) of each
hydropower license application to determine
whether federal action will significantly
impact the quality of the natural
environment. If so, then an environmental
impact statement (ElS) must be prepared
prior to granting a new license. As part of
the EA for Idaho Power s mid-Snake and
Shoshone Falls applications, FERC visited
Idaho during July 1997 to receive public and
agency input through scoping meetings.
FERC issued additional information requests
(AIRs) in 1998 for the mid-Snake project.
FERC also visited Idaho to receive public
and agency input at a scoping meeting held
in September 1999. FERC issued AIRs for
the C.J. Strike project in 1999. A draft EIS
was issued on the mid-Snake projects in
January 2002, and the FERC was in Idaho in
February 2002 to receive public and agency
comment. Completion of the final EIS
regarding the mid-Snake projects is
expected later in 2002.
FERC is currently developing an
approach to a cumulative environmental
analysis of the Snake River from Shoshone
Falls through the Hells Canyon Complex.
Once the analysis is complete, FERC will
consider recommendations from affected
state and federal agencies and issue license
orders for the affected projects, including
required PM&E measures. The process may
take from two to five years in the case of the
Shoshone Falls, Upper Salmon, Lower
Salmon and Bliss projects. Opportunity for
additional public comment will occur before
the license orders are issued. If a project's
current license expires before a new license
has been issued, annual operating licenses
are issued by FERC pending completion of
the licensing process.
Salmon Recovery Program
In recent years , the movement of
water through the hydroelectric system to
assist spawning and migration of salmon has
substantially impacted the amount and
timing of hydroelectric generation. For that
reason IPC actively monitors and
participates in regional efforts to develop a
program of actions to assist the recovery of
the endangered salmon populations.
Hydroelectric Relicensing
Uncertainties
Idaho Power Company is optimistic
that the hydro project relicensing will be
completed in a timely fashion. Howeverprior experience indicates that the
relicensing process will probably result in an
increase in the costs of generation from the
relicensed projects. The increased costs are
usually associated with the requirements
imposed on the projects as a condition of
relicensing. As previously described in the
discussion of the ongoing FERC
collaborative process Idaho Power
currently discussing relicensing issues with
the collaborative team. Initial discussions
with members of the collaborative team
have begun concerning proposed changes in
project operations that would impact the
availability of electric energy from the
relicensed projects. Once complete, Idaho
Power will be able to better estimate the
potential impacts of the proposed
requirements on energy-generating
capability. The FERC relicensing process
then provides IPC with time to assess
proposed requirements and to develop and
present responses to the proposals. As a
result, Idaho Power cannot reasonably
estimate at this time the impact of the
relicensing process on the generating
capability of the relicensed projects. At the
time of the 2004 IRP, Idaho Power will have
Chapter Existing and Planned Resources
better infonnation regarding the power
generation impacts of relicensing.
Thermal Generating Resources
Bridger
Idaho Power Company owns a one-
third share of the Jim Bridger (Bridger)
coal-fired plant located near Rock Springs
Wyoming. The plant consists of four nearly
identical generating units. Idaho Power
one-third share of the generating capacity of
Bridger culTently stands at 707 MW afterthe upgrade of the high-
pressure/intennediate-pressure (HP lIP)
turbines on all four generating units. The
fourth unit HPIIP upgrade was completed in
June of 2000. After adjustment for
scheduled maintenance periods and
estimated forced outages and de-ratings, the
annual energy-generating capability of Idaho
Power share of the Bridger plant is
approximately 627 aMW.
Valmy
Idaho Power Company owns a 50
percent share, or approximately 261 MW of
capacity of the 521 MW Valmy plant
located east of Winnemucca, Nevada. The
plant, which consists of one 254 MW unit
and one 267 MW unit, is owned jointly with
SielTa Pacific Power Company. After
adjustment for scheduled maintenance
periods and estimated forced outages and
de-ratings, the annual energy-generating
capability of Idaho Power s share of the
Valmy plant is approximately 231 aMW.
Boardman
Idaho Power owns a 10 percent
share of the 552 MW coal-fired plant near
Boardman, Oregon, operated by Portland
General Electric Company. After
adjustment for scheduled maintenance
periods and estimated forced outages and
de-ratings, the annual energy-generating
capability of Idaho Power s share of the
Boardman plant is approximately 47 aMW.
Evander Andrews Power Complex
In addition to the three coal-fired
steam-generating plants, Idaho Power owns
and operates the Evander Andrews Power
Complex, a 90 MW natural gas-fired
combustion turbine plant and the associatedswitchyard. The 12-acre complex
constructed during the summer of 2001 , is
located northwest of Mountain Home
Idaho. The complex was named in honor ofAir Force Master Sergeant Evander
Andrews, a member of a civil engineering
squadron from Mountain Home Air Force
Base. Master Sergeant Andrews was the firstu.S. casualty of Operation Enduring
Freedom.
The Andrews Complex will operate
as needed to support system load or in
response to favorable market conditions.
Salmon Diesel
Idaho Power owns and operates two
diesel generation units located at Salmon
Idaho. The Salmon diesels produce 5.5 MWand are primarily operated during
emergency conditions.
Purchased & Exchanged
Generating Resources
Garnet Purchased-Power Contract
Idaho Power Company has entered
into an agreement to purchase up to 250
MW of capacity and associated energy
during periods of peak need from the Gamet
Energy LLC facility. As proposed, the
Chapter Existing and Planned Resources
facility would be a nominal 250 MW natural
gas-fired combined-cycle combustion
turbine electrical generation facility capable
of expansion to a nominal 500 MW project.
The planned site for the Garnet
facility is be located in Canyon County
about 1 mile south of Middleton, Idaho, on
30 acres east of Middleton Road, south of
the south channel of the Boise River. The
location is approximately 1.25 miles northof the future Locust Grove-Caldwell
transmission line and about 3 miles west of
the Williams Northwest natural gas pipeline.
Public Utility Regulatory Policies Act
Idaho Power purchases energy from
Independent power producers operating as
qualifying facilities (QF) under the Public
Utility Regulatory Policies Act of 1978 at
avoided cost rates established by the public
utility commissions of Idaho and Oregon.
Technical Appendix lists the various QF
projects. As of December 2001, the various
QF projects were delivering 93 aMW of
power to IPC and its customers.
Exchanges
In the past, seasonal load diversity
between Idaho Power and the rest of the
region has enabled IPC to make term power
exc~an~~s with other regional utilities
maxlml~mg the utilization of IPC's existing
generatIOn and transmission resources.
An exchange agreement with
Montana Power Company (NorthwesternEnergy) provides for the delivery to
Montana of 108 000 MWh during the three-
month period from December through
February. Deliveries are assumed to be
constant at 50 aMW. In return, Montana
Power Company delivers to Idaho 118 000
MWh during the three-month June through
August period. Power receipts are assumed
to be 10 aMW in June and 75 aMW in July
and August.
Under a similar agreement, 126 000
MWh are delivered to Seattle City Light
from November through February and
returned to Idaho Power from July through
September. Deliveries to Seattle City Light
are assumed to be 25 aMW in November
and 50 aMW in December, January and
February. Power receipts are assumed to be
100 aMW in July, 54 aMW in August and
16 aMW in September. The last transfer of
energy in the Seattle agreement occurs in
September 2002 and the last transfer of
energy in the Montana agreement occurs in
December 2003.
Idaho Power plans to continue
investigating opportunities for cost-effective
power exchanges as a method to manage
projected surpluses and deficiencies -
especially with the Montana Exchange
ending in December 2003. Idaho Power has
contacted Northwestern Energy to discuss
continui~g an energy exchange between the
companIes.
Additionally, properly timed
seasonal exchanges or wholesale purchases
delivered to the east side of the IPC system
will result in a direct reduction in the
number of hours of transmission deficit from
the Pacific Northwest. East side deliveries
can directly reduce the load and congestion
on the Brownlee East transmission path. For
these reasons, IPC continues to pursue cost
effective exchanges delivered to the east
side of the Idaho Power system.
Transmission Resources
Description
The Idaho Power transmission
system is a key element serving the needs of
its retail customers. The 230 kilovolt (kV)
and higher voltage main grid system
essential for the delivery of bulk power
supply. Figure 1 shows the principal grid
Chapter Existing and Planned Resources
elements of Idaho Power high-voltage
transmission system.
Capacity and Constraints
Idaho Power Company
transmission connections with regional
utilities provide paths over which off-system
purchases and sales are made. The
transmission interconnections and the
associated power transfer capacities are
identified in Table 4. The capacity of a
transmission path may be less than the sum
of the individual circuit capacities. The
difference is due to a number of factors
including load distribution, potential outage
impacts, and surrounding system limitations.In addition to the restrictions on
interconnection capacities, there are other
internal transmission constraints that may
limit IPC' s ability to access specific energy
markets. The internal transmission paths
needed to import resources from other
utilities and their respective potential
constraints are shown in Figure 1 and Table
Brownlee East Path
The Brownlee East transmission
path is on the east side of the Northwest
Interconnection shown in Table
Brownlee East is comprised of the 230 kVand 138 kV lines east of the
Brownlee/Oxbow/Quartz area and the
Summer Lake-Midpoint 500 kV line. The
constraint on the Brownlee East
transmission path is within Idaho Power
main transmission grid and located in the
area between Brownlee and Boise on the
west side of the system.
The Brownlee East path is most
likely to face summer constraints. The
summer constraints result from
combination of Hells Canyon Complex
hydro generation flowing east into the
Treasure Valley, concurrent with tenn
transmission wheeling obligations and
purchases from the Pacific Northwest. The
tenn transmission also flows southeast into
and through Southern Idaho. Significant
congestion affecting southeast energy
transmission flow from the Pacific
Northwest also occurs during the months of
November and December.
The Brownlee East constraint is the
primary restriction on imports of energy
from the Pacific Northwest. If new
resources are sited west of this constraint
additional transmission capacity will be
required to remove the existing Brownlee
East transmission constraint and deliver the
energy from the additional resources to the
Boise/Treasure Valley load area.
new 10-mile, 230 kV line
between Brownlee and Oxbow is planned to
relieve the operating limitations at Oxbow
and Hells Canyon. The transmission
upgrade will increase the Brownlee East
capacity by approximately 100 MW, thereby
increasing IPC' s ability to import additional
energy from the Pacific Northwest for native
load use. The transmission upgrade is
expected to be completed and in service by
the fall of 2004.
Brownlee North Path
The Brownlee North path is a part of
the Northwest Interconnection and consists
of the Hells Canyon-Brownlee and Oxbow-
Brownlee 230 kV double circuit line. The
Brownlee North path is most likely to face
constraints during the summer months when
high southeast energy flows and high hydro
production levels coincide. Congestion on
the Brownlee North path also occurs during
the winter months of November and
December due to large southeast energy
transfers.
Chapter Existing and Planned Resources
Northwest Path
The Northwest path consists of the
500 kV Summer Lake-Midpoint line, the
three 230 kV lines between the Northwest
and Brownlee and the 115 kV
interconnection at Harney. Deliveries of
purchased power from the Pacific Northwest
often flow over these lines. During low
water conditions, total purchased power
needs may exceed the capability of the path.
If new resources are sited west of this
constraint, additional transmission capability
will be needed to transmit the energy into
the IPC control area.
Borah West Path
The Borah West transmission path iswithin Idaho Power main grid
transmission system located west of the
Eastern Idaho, Utah Path C, Montana and
Pacific (Wyoming) interconnections shown
in Table 4. The Borah West path consists of
the 345 kV and 138 kV lines west of the
BorahiBrady/Kinport area. The Borah West
path will be of increasing concern because
the capacity of this path is fully utilized by
existing term obligations. If new resources
are constructed or acquired from sites east of
the Borah West constraint additional
transmission facilities will need to be
constructed to transmit the energy to
customers in the Treasure Valley and Magic
Valley.
Chapter Existing and Planned Resources
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Table Idaho Power Company Transmission Interconnections
Transmission From Line or Transformer Connects Idaho Power To
Interconnections Idaho Idaho
Northwest 100 to 2,400 MW Oxbow - Lolo 230 kV Washington Water Power
200 MW Midpoint - Summer PacifiCorp (PPL Division)
Lake 500 kV
Hells Canyon -PacifiCorp (PPL Division)
Enterprise 230 kV
Quartz Tap -Bonneville Power
LaGrande 230 kV Administration
Hines - Harney Bonneville Power
138/115 kV Administration
Sierra 262 MW 500 MW Midpoint - Humboldt Sierra Pacific Power
345 kV
Eastern Idaho Kinport - Goshen 345 PacifiCorp (UPL Division)
Bridger - Goshen 345 PacifiCorp (UPL Division)
Brady - Antelope 230 PacifiCorp (UPL Division)
Blackfoot - Goshen PacifiCorp (UPL Division)
161 kV
Utah (Path C)775 to 830 to Borah - Ben Lomond PacifiCorp (UPL Division)
345 kV
950 MW 870 MW Brady - Treasureton PacifiCorp (UPL Division)
230 kV
American Falls -PacifiCorp (UPL Division)
Malad 138 kV
Montana 79MW 79MW Antelope - Anaconda Montana Power Company
230 kV
87MW 87MW Jefferson - Dillon 161 Montana Power Company
Pacific (Wyoming)600 MW 600 MW Jim Bridger 345/230kV PacifiCorp (Wyoming
Division)
Power Transfer Capacity for Idaho Power Company Interconnections
I The Idaho Power-PacifiCorp interconnection total capacities in Eastern Idaho and Utah include Jim Bridger resource
integration.
2 The Path C transmission path also includes the internal PacifiCorp Goshen-Grace 161 k V line.3 The direct Idaho Power-Montana Power schedule is through the Brady-Antelope 230kV line and through the Blackfoot-Goshen 161 kV line
that are listed as an interconnection with PacifiCorp. As a result, Idaho-Montana and Idaho-Utah capacities are not independent.
Chapter Existing and Planned Resources
Transmission Uncertainties
FERC Order 2000
On December 15, 1999, the FERC
issued Order 2000 to encourage voluntary
membership in regional transmission
organizations (RTO). The order required all
public utilities that own, operate or control
interstate transmission facilities to file
October 15, 2000 a proposal for an RTO.
Idaho Power Company has been an active
participant in efforts to determine
appropriate structure for R TO West, a R TOfor the Pacific Northwest. While the
proposed restructuring changes will not alter
the physical capability of the transmission
system, it is uncertain how an R TO structure
will affect Idaho Power use of its
transmission system.
FERC Order 888
On May 10, 1996 FERC issued
Order 888. The FERC intent of Order 888
was to promote the use of transmission
facilities for competitive markets at the
wholesale level. Because of the geographic
location of Idaho Power transmission
facilities, Idaho Power anticipates that
multiple entities may request transmission
capacity in Idaho Power main grid
transmission system to transport power fromthe Pacific Northwest to the Desert
Southwest. Under the auspices of FERC
Order 888, utilities can be compelled
construct additional transmission facilities to
increase capacity if the party seeking to use
the increased capacity pays the cost of
adding the capacity. In fact, use of Idaho
Power s transmission facilities has already
been the subject of litigation before the
FERC brought by Arizona Public Service
(APS) against Idaho Power relating to
APS'desire to use Idaho Power
transmission system for term transactions.
In light of the FERC support for open access
facilitating transactions at the wholesale
level, planning for future transmission
resources must anticipate additional
regulatory requirements being placed on the
transmission system as a result of FERC
Orders 888 and 2000.
FERC Docket No. RMO1-12-000
On April 10, 2002, in Docket No.
RMO 1-12-000, entitled Electricity Market
Design and Structure, the FERC issued a
Notice of Options paper to initiate
discussions on proposed rule making to
address standardized transmission service
and wholesale market design. While the
rule making is in the very early stages, an
initial review indicates that it could have
considerable impact on Idaho Power
transmission operations and recovery of
costs for transmission service. Idaho Power
Company is working with the other R
West participants to respond to the rule
making.
Western Electricity Coordinating Council
Operating Transfer Capability Process
Since the transmission disturbances
of the summer of 1996, transmission system
capabilities have come under increasingscrutiny. The Western Electricity
Coordinating Council (WECC) has adjusted
the transfer capability on many transmission
lines. A transmission operator no longer has
the assurance that all of the line capability
will be fully usable in the future. New
interactions with other existing transmission
paths, previously unidentified, can force
reductions in existing transmission
capability.
Chapter Existing and Planned Resources
4. Adequacy of Existing and Planned Resources
Idaho Power Company is committed
to generate and deliver reliable, low-cost
power for its customers. Reliability and
quality of service are directly impacted by
the adequacy ofIPC's electric supply.
Idaho Power has specified a
resource adequacy criterion requiring new
resources be acquired at the time that the
resources are needed to meet forecast energy
growth, assuming a water condition at the
70th percentile for hydroelectric generation.
Idaho Power is proposing to change fromthe previous median water-planning
criterion. The change is discussed in greater
detail later in this chapter.
The 70th percentile means that Idaho
Power plans generation based on stream
flows that occur in seven out of 10 years on
average. Stream-flow conditions are
expected to be worse than the planning
criteria 30 percent of the time. Idaho Power
plans to meet WECC criteria for reserves.
The WECC criteria currently requires Idaho
Power to maintain 330 MW of reserves
above the forecast peak load to cover an
unexpected loss equal to Idaho Power
share of two Bridger generation units.
70th percentile monthly water
planning differentiates Idaho Power from
other Northwest utilities, which typicallyplan resources based upon having annual
generating capability sufficient to meet
forecast annual energy requirements under
critical water conditions. Critical water
conditions are generally defined to be the
worst or nearly worst annual water
conditions based on historical stream flow
records.
Using the 70th percentile water-
planning criterion produces capacity and
energy surpluses whenever stream flows are
greater than the 70th percentile. Temporary
off-system sales of surplus energy and
capacity provide additional revenue and
reduce the costs to IPC customers. During
months when Idaho Power faces an energy
or capacity deficit because of low stream
flow, excessive demand, or for any other
reason, Idaho Power plans to purchase off-
system energy and capacity on a short-term
basis to meet system requirements.
Low-water (90th percentile)
scenarios have been evaluated and included
in the 2002 Integrated Resource Plan to
demonstrate the viability of IPC's plan to
serve peak and energy loads under low-
water conditions. The evaluations include
consideration of IPC'transmission
capability at times of lower stream flows.
Impact of Salmon Recovery Program
on Resource Adequacy
The December 1994 Amendments
to the Northwest Power Planning Council's
fish and wildlife program and the biological
opinions issued under the Endangered
Species Act (ESA) for the four lower Snake
River federal hydroelectric projects call for
427 000 acre-feet of water to be acquired by
the federal government from willing lessors
upstream of Brownlee Reservoir. The
acquired water is then to be released during
the spring and summer months to assist
ESA-listed juvenile salmonids (spring,
summer fall Chinook and steelhead)
migrating past the four federal hydroelectric
projects on the lower Snake River. In the
past, water releases from Idaho Power
hydroelectric generating plants have been
modified to cooperate with the federal
efforts. Idaho Power also adjusts flows in
the late fall of each year to assist with the
spawning of fall Chinook below the Hells
Canyon Complex.
Chapter Resource Adequacy
Because of the practical, physical
and legal constraints that federal interests
must deal with in moving 427 000 acre-feet
of water out of Idaho, Idaho Power has pre-
released, or shaped, a portion of the acquired
water with water from Brownlee Reservoir
and later refilled the reservoir with water
leased under the federal program. At times
Idaho Power has also contributed water from
Brownlee to assist with the federal efforts to
improve salmonid migration past the lower
Snake federal projects.
Idaho Power s cooperation with the
federal programs has been pursuant to an
agreement with the BP A that provided for
an energy exchange which reimbursed Idaho
Power for any energy or generating capacity
lost by the shaping or modification of flows.
The BP A agreement insured that Idaho
Power customers were not adversely
affected by Idaho Power s cooperation with
federal efforts.
The agreement with the BP A
expired on April 15 , 2001 , and has not been
renewed. As such, the energy exchange
with the BP A that was modeled in the 2000
IRP is not included in the 2002 IRP. Idaho
Power does not intend to modify
otherwise shape flows from its hydroelectric
projects to address federal responsibilities in
the lower Snake River in the absence of an
appropriate agreement with the BP A
other federal interests. While such
agreement may be negotiated in the future
Idaho Power Company does not intend to
enter into any such agreement that would
adversely affect Idaho Power customers or
require the construction of additional
resources.
Water Planning Criteria for
Resource Adequacy
Idaho Power Company has an
obligation to serve customer loads
regardless of the water conditions that may
occur. In the past, when water conditions
were at low stream-flow levels, IPC relied
on market purchases to serve customer
loads. Historically, IPC's plan has been to
acquire or construct resources that will
eliminate expected energy deficiencies in
every month of the forecast period whenever
median or better water conditions exist
recognizing that when water levels are
below median, IPC historically relied on
market purchases to meet any deficits.
In connection with the recent market
price movements to historical highs during
the summer of 200 1, IPC has reevaluated the
planning criteria. The public, the Idaho
Public Utilities Commission, and the Idaho
legislature all have suggested that Idaho
Power may place too great a reliance on
market purchases based upon the IRP
planning criteria. Greater planning reserve
margins or the use of more conservative
water planning criteria have been suggested
as methods requiring IPC to acquire more
finn resources and reduce the likelihood of
market purchases.
Due to the public input to the
planning process, IPC is proposing a
resource plan based upon a lower-than-
median level of water. In the current
resource plan, IPC is using the 70th
percentile water conditions and load
conditions for resource planning. However
IPC will continue to evaluate resource
adequacy under a median water condition
and include that evaluation as part of the
Integrated Resource Plan.
Idaho Power will continue to
analyze its ability to serve customers' peak
and energy needs under a low-water
condition (90th percentile) as well. Based on
the low-water analyses, IPC believes that it
will be difficult to acquire and deliver short-
tenn resources from the Pacific Northwest in
Chapter Resource Adequacy
amounts sufficient to satisfy peak-hour
deficiencies during low-water conditions.
Historically, Idaho Power has been
able to reasonably plan for the use of short-
term power purchases to meet temporary
water-related generation deficiencies on its
own system. Short-term power purchases
have been successful because Idaho Power
customers typically have summer peaking
requirements while the other utilities in the
Pacific Northwest region have winter
peaking requirements.
Although Idaho Power has
transmission interconnections to the
Southwest, the Northwest market is the
preferred source of purchased power. The
Northwest market has a large number of
participants, high transaction volume, and is
very liquid. The accessible power markets
south and east of Idaho Power s system tend
to be smaller, less liquid, and have greater
transmission distances.
Under the low water and high-load
conditions, projected peak-hour loads are
likely to cause peak-hour transmission
overloads from the Pacific Northwest. The
transmission overloads may present
significant difficulties as early as the
summers of 2003 and 2004 (transmission
adequacy is discussed later in this chapter).
Recent experiences indicate that, even when
Northwest power is available, the short-term
prices can be quite high and volatile.
Recent market price events
demonstrate that while IPC has been able to
rely on market purchases, the price can behigh. The price risk has led to the
development of the Risk Management
Policy discussed in the Introduction. TheRisk Management Policy represents
collaboration of Idaho Power, the IPUC
staff and interested customers in
Commission Case IPC-01-16.
The primary uncertainties associated
with planned short-term power purchases
are the availability of adequate Northwest to
Idaho transmission capacity to allow imports
at the times when needed, and uncertainty
concerning the market prices of the
purchases.
Planning Scenarios
Median Water, Median Load (Energy)
Figure 2 shows the monthly energy
surpluses and deficiencies associated with
median water and the most probable or
expected future load scenario. With median
water, median loads, and the additional
generation from both the Evander Andrews
Power Complex near Mountain Home and
Gamet in 2005, IPC will experience energy
deficiencies in the winter months starting in
December 2006. Winter deficiencies are
expected to increase from approximately 38
aMW in 2006 to approximately 190 aMW in
2011. Additionally, IPC will experience
summer energy deficiencies starting in July
2008. Summer deficiencies are expected to
increase from approximately 28 aMW in
2008 to approximately 178 aMW by 2011.
Median Water, Median Load (Peak)
At the time of the peak monthly
system load, additional energy is required to
satisfy the peak demand. Figure 3 shows
that, for the median water and median load
scenario additional resources must be
purchased in the summer beginning in June
2002 and in the winter starting in December
2004. Under the median water and median
load scenario, deficiencies are generally
limited to June July, November, and
December; however, peak-hour energy
deficiencies do begin to occur in other
months starting in 2010.
Chapter Resource Adequacy
70th Percentile Water, 70th Percentile
Load (Energy)
When below-normal water and
higher-than-expected load conditions occur
a greater number of months are expected to
have deficiencies than in the median water
and median load scenario. Figure 4 shows
that winter deficiencies begin in December2002 with initial deficiencies of
approximately 10 aMW increasing to
approximately 277 aMW by November
2011. Summer deficiencies in June and July
are expected to increase from approximately
45 aMW in 2004 to approximately 293
aMW in 2011. Initial surpluses in August
September and October are expected to
become deficiencies starting in August
2006, at 5 aMW and increasing to 200 aMW
by September 2011.
70th Percentile Water, 70th Percentile
Load (Peak)
Figure 5 illustrates that with 70
percentile water and 70th percentile load
conditions summer peak-hour energy
deficiencies occur starting in June 2002 at
161 MW and increase to 610 MW in July
2011. Winter peak-hour deficiencies occur
beginning in December 2002 at 107 MW
and increase to 314 MW in November 2011.
Peak-hour energy deficiencies are limited to
June, July, November and December until
2006, when deficiencies begin to occur in
other months. By 2011 , deficiencies occur
in 11 of 12 months.
90th Percentile Water, 70th Percentile
Load (Energy)
Figure 6 illustrates that under the
90th percentile water, 70th percentile load
scenario, summer deficiencies occur in all
years starting in June 2002, with 164 aMW
and increasing to 429 aMW in July 2011.
Winter deficiencies also occur in all years
starting in December 2002 at 101 aMW and
increasing to 316 aMW by December 2011.
By 2005 , deficiencies occur in 9 of 12
months; by 2010, all months are deficit.
90th Percentile Water, 70th Percentile
Load (Peak)
The pattern of deficiencies for the
90th percentile water, 70th percentile load
scenario is similar to the pattern of
deficiencies for the 70th percentile water
70th percentile load scenario. Deficiencies
in the peak months are typically 40 to 60
MW greater because of changes in waterconditions. Monthly surpluses and
deficiencies for the 90th percentile water
70th percentile load growth are shown in
Figure 7.
Chapter Resource Adequacy
Figure 2 Monthly Energy Surplus / Deficiency
Median Water, Median Load , Existing Resources with Garnet
1000
800
600
_______
400
---
200
200
-400
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Figure 3 Monthly Peak-hour Surplus / Deficiency
Median Water, Median Load, Existing Resources with Garnet
1000
800
600
400
200
- - - - - -
, - - - - - - T - - - - - -
,- - - - - - -, - - - - - - -, - - - - - - -- - - - - - -- - - - - - -- - - - - - -, - - - - ------ ----,- ---- -,- --------------------------
-400
200
600
-BOO
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Chapter Resource Adequacy
Figure 4 Monthly Energy Surplus / Deficiency
70th Percentile Water and Load , Existing Resources with Garnet
600
500
____
- - - - 1.
400
--------
300
- '-____
200
100
100
- - - - 1.
- - - - - - ~ - - - - - - ~ - - - - - - ~ - - - - - - ~- - - - - - ~- - - - - - _
L - - - - --
- - - - T - - - - -
, - - - - - -, - - - - - -, - - - - - -,- - - - - -,- - - - - - -
r - - - - --
___
l ____1 ---J ----_J ______
__________________----+ --~ ----~ ----~ ----~ ----~-------~------
1 --J -
. ---~ ----~ _____
300
400
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Figure 5 Monthly Peak-hour Surplus / Deficiency
70th Percentile Water and Load , Existing Resources with Garnet
600
200
- - - -. - - - - - - ~ - - - - - -
1- ---_J- ----
-------- --+-- --
--~--- -- 1-
- -~--- ~--- ~-----___
L____
____
1______
~---------~--- -- _
L_- ___
- - - - - - ,. - - - - - - T - - - - - -
., - - - - - - -, - - - - - - -, - - - - - - -, - - - - - - -- - - - - - -- - - - - - - ,- - ---------____- - - - -
1- - - - - - -1- - - - - - -1- - - -
- --___- __________________-
400
200
-400
600
~oo
2002 2003 2004 2005 2006 2007 2006 2009 2010 2011
Chapter Resource Adequacy
Figure 6 Monthly Energy Surplus / Deficiency
90th Percentile Water, 70th Percentile Load , Existing Resources with Garnet
300
200
----,..
- f-
-----,..----+
- - - - - T - - - - - - , - - - - - -
.., - - - - - - -,- - - - - - -,- - - - - - -,- - - - - - -,- - - - - -- - - - + - - - - - -., - - - - - - --j - -
- - - - -1- - - - - - -1- - - - - - -1- - - - - - -1- - - - - -100,-
100
200
____
L_- ---1_- 1
- ,
300
-----~-----
T--
---+------~-- ---:--- --:--- --:--- -:---
-400 - - - - - - ~ - - - - - - ~ - - - - - -
+ - - - - - - ~ - - - - - - ~ - - - - - --:- - - - -- -:- - - - - - -:- - -- - - -:- --
500 - - - - - - r - - - - - - T - - - - - - T - - - - - - ,
- - - - - - -, - - - - - - -, - - - - - - -,- - - - - - -- - - - - - - ,- - - - - - -
600
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Figure 7 Monthly Peak-hour Surplus / Deficiency
90th Percentile Water, 70th Percentile Load , Existing Resources with Garnet
600
200
---f---- ---- 1--- -- 1-- 1-- 1-
- - - - - - L - - - - - -
- - - - - - ~ - - - - - - ~ - - - - - - _- - - - - - _- - - - - _- - - - - _- -- - - - - - ,- - - - - - - ,- - - - - - -
T - - - - - - I - - - - - - -
, - - - - - - -, - - - - - - -- - - - - - -- - -
400
200
-400
-600
-BOO
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Chapter Resource Adequacy
Transmission Adequacy
Prior to 2000, Integrated Resource
Plans have emphasized construction or
acquisition of generating resources to satisfy
load obligations. Transmission limitations
were not viewed as a major impediment to
Idaho Power s purchasing power to meet its
service obligations. The 2002 edition of the
IRP, as well as the 2000 IRP, recognizes that
t:a~smission constraints have begun to place
lImIts on purchased power supply strategies.
To better assess the adequacy of the power
supply and the transmission system, IPC
analyzed peak-hour transmission conditions.
The transmission adequacy analysis
reflects IPC' contractual transmission
obligations to serve BP A loads in Southern
~ho. The BP A loads are typically served
wIth energy and capacity from the Pacific
Northwest. Analyzing the transmission
limitations during the peak hour of each
month allows IPC to assess the adequacy of
the transmission system to serve IPC
customers and BP A customers with energy
from the Pacific Northwest.
The results of the transmission
analyses indicate that the Brownlee East
path is most likely to face transmission
constraints. The transmission analysis
shows monthly peak-hour transmission
deficiencies when the IPC resource
deficiencies are met by energy purchases
from the Pacific Northwest at the same time
the transmission system is delivering energy
to BP A customers in Southern Idaho.
Figure 8 represents the monthly
peak-hour transmission deficiencies for a
median water and median load condition.The magnitude of the transmission
deficiency is 21 MW in July 2003 and 84
MW in July 2004. Assuming that Gamet is
available in June 2005 , the next transmission
deficiency occurs in July of 2006 and has a
magnitude of approximately 45 MW. Julypeak transmission deficiencies for
subsequent years increase by approximately
70-80 MW per year.
Figure 9 represents the monthly
peak-hour transmission deficiencies for ath percent! e water and 70 percentile loadcondition. The magnitude of the
transmission deficiency is 86 MW in July
2003 and 180 MW in July 2004. Assuming
that Gamet is available in June 2005 , then
the July 2005 transmission deficiency is
reduced to 25 MW. Transmission
~eficiencies for subsequent July peaks
Increase by approximately 75-90 MW per
year. By 2010, transmission deficiencies
begin to appear in December.
Figure 10 represents the monthly
peak-hour transmission deficiencies for ath percent! e water and 70 percentile loadcondition. The magnitude of the
transmission deficiencies is 141 MW in July
2003 and 225 MW in July 2004. Assuming
that Gamet is available in June 2005, theJuly 2005 deficiency is 92 MW.
Transmission deficiencies for subsequentJuly peak conditions increase by
approximately 75-90 MW per year. By the
winter season of 2010-2011 , transmission
deficiencies begin to appear in December
and January.
Chapter Resource Adequacy
600
400
200
:s:
:a:
200
-400
600
Figure 8 Monthly Peak-hour NW Transmission Deficit
Median Water Median Load
- - - - - - L - - - - - - L - - - - - - 1 - - - - - - ~ - - - - - - .J - - - - - - _
, - - - - - - _- - - - - - _- - - - - - _- - - - - - -- - - - - -
" - - - - - - t' - - - - - - l' - - - - - - ~ - - - - - - ~ - - - - -
- -j - - - - - - -
1- - - - - - -1- - - - - - -1- - - -
- -
800
-----~------'-------'----,---
4-------I----1-
- --- -- ---
1---
- - - - - - , - - - - - -
- - - - - - T - - - - - - , - - - - - - l - - - - - - -
, - - - - - - -, - - - - - - -- - - - - - -- - -
- - - - - - L - - - - - - L - - - - - - 1 - - - - - - ~ - - - - - - .J - - - - - - .J - - - - - - _
- - - - - - _- - - - - - _- - - - - - -
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
600
400
200
200
-400
600
800
Figure 9 Monthly Peak-hour NW Transmission Deficit
70th Percentile Water, 70th Percentile Load , Existing Resources with Garnet
- - - - - - ~ - - - - - - ~- - - - - - - L - - - - - - ~ - - - - - - ~- - - - - - - L - - - - - - ~ - - - - - - ~- - - - - - - L - - - - - -.
- - - - - - ~ - - - - - - ~ - - - - - - - ~ - - - - - - ~ - - - - - - ~ - - - - - - - ~ - - - - - - ~ - - - - - - ~ - - - - - - - ~ - - - - - - -----
4------
~-----~---.------~--- ---~--- --
4--- -
~--- ---~---
- - - - - - , - - - - - - ~- - - - - - - r - - - - - - , - - - - - - ~- - - - - - - r - - - - - - , - - - - - - ~- - - - - - r - --
- - - - - - ~ - - - - - - ~- - - - - - - L - - - - - - ~ - - - - - - ~- - - - - - - L - - - - - - ~ - - - - - - ~- - - - - - - L - - - -
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
Chapter Resource Adequacy
600
400
200
:2;
200
-400
-600
Figure 10 Monthly Peak-hour NW Transmission Deficit
90th Percentile Water, 70th Percentile Load , Existing Resources with Garnet
......
.. L.. n - - - - L - - - - - - 1 - - - - - - ~ - - - - - - ~ - - - - - - _
- - - - - - _- - - - - - -- - - - - - -- - - - - --
.. - - - - - r - - - - - - t- -.. - - - - T - - - - - - ~ - - - - - - ~ - - - - - -
.., - - - - - - -
1- - - - - - -
,- - - - - - -,- - - - - --
-800
------~---- --~-_.._~---~--- ---'--- ---
1--- ---
,--- ---,---
- - - - - - r" - -.. - - T - - -.. - - T -.. - - - -.,.... - - - - 'l - -.. - - - -
, - - - - - - -- - - - - -- - - - - -- --
- - - - - - L - - -
.. - - - - - - - - "- - -.. - -
.1 - -
- - - - ~ - - - - - _
.J - - - - - - -
- - - - - - -- - - - - - -- - - - - -
2002 2003 2004 2005 2006 2007 2008 2010 20112009
Chapter Resource Adequacy
5. Future Resource Options
Idaho Power primary resource
options for the planning period include
purchases of power from the wholesale
market the acquisition of additional
generating resources and, to a lesser extentpricing options and demand-side
management programs. The information
about each resource option required for
resource planning includes capacity and
energy capability, expected resource life
~easonal availability, dispatchability,
Investment and operating costs, and fuel
cost.
Identification of the resource
options themselves does not constitute a
resource plan, but the specification of
resource options is a first step in the
resource planning process. Included in the
first step is a cost analysis of potential
generating resources sited at generic
locations. The cost analysis assists in ' the
initial economic ranking of all resources
under consideration.
After the cost of each resource
determined for generic locations, a more
focused analysis of selected resources
performed to establish resource costs based
specifically on Idaho or Pacific Northwest
regional data. Resource costs associatedwith Northwest- and Idaho-sited
technologies are discussed in greater detail
later in this chapter, as well as in Chapter 6.
Purchased and Exchanged
Generation
Market Purchases
In the 1997 IRP, Idaho Power chose
supplemental seasonal energy and capacity
purchases as the near-term strategy to
optimize the use of company-owned
resources and meet customer loads at the
least cost. That strategy had been successful
and was continued in the 2000 IRP. Idaho
Power had been able to take advantage of
abundant supplies of off-system surplus
energy and available transmission access to
supplement the Company s own low-cost
generation resources. In 2001 , IPC and
many other Northwest utilities experienced
low-water conditions and once again relied
on the market place to satisfy deficiencies.
During that spring and summer, market
prices moved to unprecedented levels, often
in the hundreds of dollars per MWh. While
power was available for purchase, the cost to
IPC and its customers was extremely high.
Idaho Power plans to continue
using, but much less frequently, seasonal
energy and capacity purchases to optimize
utilization of Company-owned resources.
. .
Y emp aSIZIng a 70 percentile water
planning criteria, the Company plans to have
adequate resources available to satisfy all of
Its customers monthly energy needs in 7 out
of 10 years. In only 3 years out of 10 would
IPC expect monthly energy deficiencies to
occur based upon low-water conditions.
Market-based transactions of both hourly
and term energy will continue to be used
under deficit conditions.
Hourly Energy Purchases
The market price of hourly energy is
based on the output of the marginal
generation resources in the interconnected
region offered for sale in the short-term.
Historically, the hourly market in the WECC
has been very reliable and robust, allowing
hourly spot-purchases to be viable
component of the Company s short-term
resource planning strategy.
Chapter Future Resource Options
Term Energy Purchases
Term energy purchases are for
specific quantities of energy during specific
periods of time that are typically longer than
time periods for hourly energy purchases.
Term energy contracts may be entered into
directly with other utilities or may be
established through local markets.
The New York Mercantile
Exchange (NYMEX) is currently in the
process of reconfiguring its electricity
strategy to incorporate both futures and
over-the-counter (OTC) instruments that are
more flexible and address changes in the
way the electricity industry does business
today. The previous futures contracts traded
at Palo Verde and the California-Oregon
Border (COB) were recently delisted in
anticipation of the new products that
NYMEX plans to introduce.
An exchange serves to guarantee
contracts by requiring collateral (margin)
from traders for each obligation they hold.
The exchange also sets standard terms for
quantity, quality, and location for delivery.
The mechanisms of the exchange and the
futures contracts allow price discovery and
push prices to a market-clearing price.
Standardized futures contracts, together with
options based on futures, allow buyers and
sellers to manage price risk.
The current lack of NYMEX
contracts limits the regional electricity
market. In all likelihood, individual bilateral
contracts with utilities and other generation
owners will continue to be the principal
source of term energy transactions for the
foreseeable future.
Market Purchase Prices
Idaho Power estimated market
price during the planning period is best
represented by a combination of the forward
price curve and a price forecast. The
forward price curve was used for the first
five years of the planning period, and a price
forecast was used for the remaining five
years to represent the full cost of ma~ket
purchases. The estimated market pnces
used in the IRP are shown in the Technical
Appendix.
Gas Price Forecast
One of the primary variables
affecting the costs of energy from either a
simple-cycle or combined-cycle combustion
turbine is the price of natural gas. Forward
market prices and gas price forecasts
produced by national forecasting
organizations have been examined as part of
the process to determine the appropriate gas
prices used to estimate market prices for
electricity.
IPC relies on a combination of
forward market prices and the WEF A long-
range forecast to estimate future gas prices
for the IRP. The price forecasts which were
examined are: (1) the November-adjusted
2001 WEF A Group long-range forecast of
the price for natural gas delivered to electric
utilities in the Mountain region, and (2) the
November 2001 PlRA Energy Group
forecast of prices at Sumas (a major gas
trading hub serving the Western United
States). The long-term gas market in the
Northwest is typically thinly traded, causing
forward pricing data to be less reliable.
For the year 2002, a nominal
delivered price of $2.69 per MMBTU, based
on forward market prices, was used in the
IRP. For subsequent years, the WEFA
forecast was used for the IRP.
The gas price forecast used to
develop the estimate of market prices
contained in this 2002 IRP is shown in the
Technical Appendix.
Chapter Future Resource Options
Coal Price Forecast
The IRP coal price forecast is a
composite of Idaho Power spot coal
forecasts for its three existing thermal
plants. The plant forecasts are created using
current coal and rail transportation market
information and then escalated based on the
2001 WEF A long-range forecasts. The
resulting $/MMBTU cost estimate
represents the delivered cost of coal
including rail cost, coal cost, and use taxes.
Transmission Resources
Upgrades
Adequate transmission capacity is
critical to the success of a strategy that
utilizes purchases from the wholesale
market to supplement and optimize the IPC-
owned and purchased generation resources.
Transmission alternatives do not generate
additional energy or capacity, but the
transmission system does provide access to
energy markets.
Traditionally, it has been a generally
accepted proposition among electric utilities
in the West that it is less expensive and
faster to construct new transmission
facilities than to construct new generation.
However, in recent times, the regulatoryanalyses and other right-of-way
requirements associated with new
transmission facilities construction have
resulted in much longer lead times and
substantially higher costs for new
transmission facilities when compared to
prior time periods. Typically, the permitting
and construction lead times are five to eight
years, depending on transmission distance
and the voltage level.
The costs and impacts of potential
transmission upgrade alternatives are
investigated as part of the IRP. The portion
of the Company s transmission system that
would provide the most immediate benefit
would be the upgrade of the transmission
lines between the Pacific Northwest region
and the Boise area. Transmission
construction alternatives for the Pacific
Northwest lines would be significantly long
(between 170 and 400 miles). Analyses of a
range of transmission alternatives, including
substation additions, show construction
costs of approximately $400 000
$700 000 per mile and incremental
transmission costs between $45 and $90/kW
per year for additional Pacific Northwest
transmission connections.
The projected Pacific
transmission upgrade costs are
approximately 500 percent higher than
Idaho Power s embedded transmission costs.
Assuming a 50 percent annual load factor
(typical for interconnections) and further
assuming that all project capacity is
subscribed construction of new
transmission lines results in 10 to 20
mills/kWh added to Pacific Northwest
purchased energy prices. If some of the
transmission capacity is unsubscribed, thenthe estimated transmission upgrade
estimates are further increased.
Transmission upgrades across the
Borah West path located west of American
Falls, Idaho, are estimated to cost about
$15/kW per year. Upgrades to the Borah
West Path would be necessary for network
resource developments east of Borah.
New Transmission Projects
Southwest Intertie Project (SWIP)
Idaho Power has obtained the
necessary right-of-way permits to construct
the Southwest Intertie Project, a 500-
transmission line to connect the Company
Midpoint Substation with Southwest
transmission lines at a location near Las
Vegas, Nevada. Uncertainties associated
Chapter Future Resource Options
with implementation of FERC Orders 888
and 2000 have halted development of the
SWIP Project.
Brownlee to Oxbow 230 kV
Transmission Line Number 2
To improve reliability of the
Brownlee to Oxbow transmission line and
increase the transfer capacity, IPC plans to
build a new lO-mile, 230 kV transmission
line between Brownlee and Oxbow. The
project would increase Brownlee East
capacity by approximately 100 MW. Idaho
Power Company is presently siting the
transmission facilities. The transmission
upgrade is expected to cost $18 million and
to be completed and in service by the fall of
2004.
Borah West Transmission Upgrade
The Borah West path is a fully-
subscribed transmission path and is a known
constraint within the IPC main grid
transmission system. Idaho Power Supply
has submitted a study request to the Idaho
Power Transmission Group to determine the
feasibility and cost of upgrading the Borah
West transmission line and increasing the
transmission capacity by 150 MW.
LaGrande Upgrade
Idaho Power Company has submitted
a study request to determine the feasibility
and cost of upgrading the transmission line
from Brownlee to LaGrande, increasing the
transmission capacity by 154 MW.
Generating Resources
Background
The following discussion of the
costs associated with various non-hydro
generating technologies is based on the
technology descriptions capital costs
operational and maintenance cost and heat-
rate data derived from the Department of
Energy/Energy Information Administration
(DOE/EIA) 2002 Annual Energy Outlook
(AEO) report. The government data were
combined with specific IPC financial
factors, such as cost of capital, interest on
funds used during construction, and tax
rates, to further refine costs used for
comparisons. Use of data taken from a
common source like the AEO report allows
Idaho Power to make a consistent first
comparison of the costs of the selected
technologies at generic locations. The initial
cost comparison is shown in Figure 11. The
fuel cost estimates are described earlier in
this chapter.
Idaho Power selected several
generation technologies for investigation at
specific Idaho locations. The selected
generation technologies were estimated
using plant-sizing, capital costs, operational
costs, and capacity factors that were more
consistent with known and expected
operational assumptions for generation
within the Idaho Power service territory.
While the average load continues to
increase in the Idaho Power service territory,
the near-term problem is serving the peak
load. Figure 4 shows that under the 70th
percentile water and 70th percentile load
planning scenario, the monthly energy
deficiencies are expected to be less than 100
MW until December 2005. However, under
the same planning scenario, peak-hour
deficits exceed 200 MW in 2003, 2004 and
again in 2006. The peak-hour deficienc~
drops below 200 MW in 2005 when Gamet
comes on-line, but deficiencies exceed 200
MW in 2006 and increase to over 600 MW
by 2011. The near-term requirements
indicate the need for a peak-hour resource.
The generation resources are ranked in
Figure 11 through Figure 14.
Chapter Future Resource Options
Hydroelectric Generating
Resources
Efficiency Improvement Projects
Idaho Power continually
investigates and evaluates opportunities to
economically improve efficiency and
generating capacity at existing hydroelectric
facilities. Each improvement opportunity is
technically and economically considered on
an individual project basis. Proposed
capacity upgrades are evaluated by
standards for cost effectiveness of long-tenn
resource investments , including uncertainty
in environmental impact.
New Hydro Projects
Idaho Power is proposing a
significant hydro capacity upgrade at the
Shoshone Falls facility. The existing
Shoshone Falls Hydroelectric facility was
completed in 1921 and has a generating
capacity of 12.5 MW. Idaho Power is
proposing a 64 MW expansion at the
Shoshone Falls facility.
With the expiration of Shoshone
Falls FERC License No. 2778 , Idaho Power
filed an application to relicense the facility
in 1997. As part of the license preparation
facility expansion was identified and
investigated. At the time of license
submittal, Idaho Power determined it was
not economical to expand the facility. Re-
examination of the facility expansion
investigation following the recent energy
crisis has led IPC to propose the Shoshone
Falls upgrade. The Shoshone Falls upgrade
must be considered within the Shoshone
Falls relicensing process. If Idaho Power
Company receives positive feedback
concerning the proposal then IPC will begin
the environmental and regulatory process
involved in licensing and permitting the
Shoshone Falls upgrade.
If Idaho Power does not proceed
with the Shoshone Falls upgrade, there is no
guarantee that the upgrade will be available
for IPC customers in the future. Therefore
the project has been designated as non-
deferrable.
Thermal Generating Resources
Efficiency Improvement Projects
Idaho Power Company, in
conjunction with its operating partners, is
continually looking for economic efficiency
and capacity improvements at the thermal
generation facilities. The Company is
presently considering efficiency upgrades at
both the Boardman and Valmy generation
facilities.
Boardman
high pressurelintermediate
pressure turbine modification is being
evaluated. The modification would add
approximately 2.5 MW of capacity (Idaho
Power would receive 10 percent of the 25
MW increase) at a levelized cost of
approximately 8 mills per kWh.
Valmy
A low-pressure turbine modification
is being evaluated for both Units 1 and 2.
The modifications are projected to add
approximately 7 MW of capacity (Idaho
Power would receive 50 percent of the
MW increase) at a levelized cost of
approximately 11 mills per kWh.
Chapter Future Resource Options
",....-,..-....--",..,......-.......,........-...., ,..,....-.....-....,.....,............,.."'.........."'.......,..,.....,-..,.............."".-....-,..-.......... ""........,.."......._".............',-",....,...""_....,........,,-_..,....._",,,
Figure 11 30-Year Nominally Levelized Cost of Production
For Economic Ranking at a Generic Location (excluding transmission costs)
Scrubbed Coa! (400 MW)80% Capacily Factor
i Integraled Coal Gasification
I Combined Cycie
(428 MW)80%'Capacity Faclor
Geothermal (50 MW)87% Capacity Factor
r:J Capacity
Iii! Non Fuel O&M
Conventional Gas/Oil
I Combined Cycle (250 MW)
Advanced Combustion
Turbine (120 MW)
Conventional Combustion
Turbine (160 MW)
Wind (50 MW)
80% Capacity Factor r:J Fuel
80% Capacity Factor
80% Capacity Factor
32% Capacity Factor
Fuel Cells (10MW)80% Capacity Factor
Photovoltaic (5 MW)
42% Capacity FactorSoiarThermal (100 MW)
28% Capacity Factor
100 120 140 160 180 200 220 i
$/MWh
Figure 12 30-Year Nominally Levelized Cost of Production
For Economic Ranking at an Idaho Location (excluding transmission costs)
Shoshone FalisUpgrade(64 MW)47% Capacity Factor
ValmyUnit 3(130MW)88.4% Capacity Factor
DanskinCCExpansion
Incremenlal (38,96 MW)91% Capacity Factor
III Capacity
lEI Non Fuel O&M
0 Fuel
Boardman Unit 2(56MW)84.1% Capacity Factor
Idaho- Conventiona!V64,
Combined Cycle (88,6 MW)91% Capacity Factor
Idaho- Advanced Combust ion
Turbine LM 6000 (2ea) (78,52MW)59% Capacity Factor
Idaho- Conventional Combustion
TurbineV64,3(61.2MW)59% Capacity Factor
Idaho Wind (10 MW)23% Capacity Factor
100 120 140 160 180 200 220
$/MWh
Chapter Future Resource Options
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Figure 13 30-Year Nominally Levelized Fixed Costs of Operation
For Economic Ranking at a Generic Location (excluding transmission costs)
I c=:~~::~2~~O
Scrubbed C"" (400 MW)
l'O"""""CooIG,,;ooaIiOOi Combio'" CY"'(428 MW)
W'od (50 MW)
0 Capacity
Ii Non Fuel O&M
Coo"olioo~ Comb,,'100
T"""" (160 MW)
Adv~"" Comb"'100
T"""", (120 MW)
F"o Co" (10 MW)
G"'h,,",~ (SO MW)
SoIMTh,,",~(100MW)
Phot""."" (5 MW)
$/kW Month
Figure 14 30-Year Nominally Levelized Fixed Costs of Operation
For Economic Ranking at an Idaho Location (excluding transmission costs)
Idaho .. Conventional Combustion
Turbine.. V64.3 (61.2 MW)
0 Capacity
II Non Fuel O&Mi Idaho - Advanced Combustion Turbine
LM 6000 (2ea) (78.52 MW)
Idaho .. Conventiona! V64.
Combined Cycle (88.6 MW)
Shoshone Falls Upgrade (64 MW)
IdahoWind(10MW)- i
Valmy Unit 3 (130 MW)
Boardman Unit 2 (56 MW)
Danskin CC Expansion
Incremental (38.96 MW)
$/kW Month
Chapter Future Resource Options
Thermal Technologies
Conventional Steam Turbine Plant
Conventional coal-fired steam
turbine technology is well developed. The
standard configuration has a conventional
steam boiler generating steam, which is then
used to drive a turbine to generate
electricity. The emissions from the
combustion of coal are treated (scrubbed) to
meet applicable clean-air standards.
For a 400 MW unit, the 2002 AEO
assumes a capital cost of $1 148 per kW of
plant capacity. Using an 80 percent capacity
factor, a levelized cost of approximately
43.6 mills per kWh at a generic location is
projected (Figure 11).
Advanced Coal Technologies
The AEO uses integrated coal
gasification combined-cycle technology toaddress the cleaner-burning coal
technologies under development. The
primary benefit of advanced coal technology
plants is the ability to achieve lower
emissions of sulfur dioxide and nitrogen
oxides without the need for add-on emission
control equipment.
Integrated coal gasification
combined-cycle plant capital costs from the
2002 AEO were $1 373 per kW for a 428
MW plant. The derived levelized cost of
generation at generic location
approximately 44.4 mills per kWh
operating at an 80 percent capacity factor.
Simple-Cycle Combustion Turbine
(SCCT)
Combustion turbines (CT), either
simple-cycle or combined-cycle, bum
natural gas or fuel oil distillate to create hot
exhaust gas, which is allowed to expand
through a turbine to turn an electric power
generator. Compared to coal-fired steam
plants, CTs bum more expensive fuel and
typically have higher heat rates. Comparedto coal- fired generation the principal
advantages of a CT are lower capital costs
per kW of generating capacity and shorter
lead times for siting and construction.
SCCTs also have relatively lower
environmental impacts than do coal-fired
plants and possess the ability to more
rapidly adjust the level of generation over
the output range. Consequently, SCCTs are
often selected for peaking and other low-
capacity factor requirements. After
installation, a SCCT may be converted to a
combined-cycle unit for more efficient
operation at higher capacity factors by
adding a heat recovery boiler and steam
turbine generator.
The 2002 AEO report estimates that
capital costs of a 160 MW simple-cycle
combustion turbine plant are $348 per MW.
The levelized cost of generation at a generic
location is approximately 55.mills per
kWh, operating at an 80 percent capacity
factor (Figure 11).
Idaho Power has estimated the cost
of simple-cycle technology sited in Idaho.
Both a conventional combustion turbine and
an advanced aero-derivative combustion
turbine were estimated. Both of these
turbines are smaller in capacity than the 160
MW SCCT used in the AEO report. The
smaller sized SCCTs were chosen because
of the operating hour limitations a 160 MW
plant would have under state emission
regulations unless the unit was equipped
with selective catalytic reduction emissions
controls. Although the smaller capacity
SCCTs have a higher capital cost per kW
installed, the smaller size allows greater
Chapter Future Resource Options
operating flexibility and a higher capacity
factor.
Combined-cycle Combustion Turbine
(CCCT)
The CCCT adds a heat recovery
boiler and steam turbine generator to the
simple-cycle combustion turbine to decrease
the effective heat rate and increase overall
generating efficiency. The heat recovery
system uses the residual hot exhaust gas
from the combustion turbine to create steam
which is then used to drive a secondary
turbine to generate electricity. The
increased capital cost of the CCCT, coupled
with increased fuel efficiency, tends to make
the CCCT more cost-effective at higher
capacity factors than the SCCT.
Construction costs and operating
characteristics for a new 250 MW CCCT
based on the 2002 AEO show an estimated
capital cost for the unit of $468 per kW of
capacity. Operating at an 80 percent
capacity factor, the CCCT has a levelized
cost of generation at a generic location of
approximately 44.8 mills per kWh (Figure
11 ).
Idaho Power has estimated the cost
of a specific CCCT sited in Idaho in contrast
to the more generic AEO cost data. The
simple-cycle combustion turbine estimated
in the previous section was expanded to a
CCCT plant sited in Idaho.
Micro-Turbines
Micro-turbines are scaled-down
versions of the larger combustion turbine
generators. Micro-turbines range in size
from 25 to 100 kW and are applicable to
small commercial facilities, acting as either
backup power sources or as generators that
run in parallel with the utility system.
Banks of the machines have been set up to
provide power to larger commercial
facilities and some industrial facilities.
Micro-turbine commercialization is limited
with only a few manufacturers offering the
products. At this time, there are no micro-
turbine generators operating on the Idaho
Power system.
Diesel and Natural Gas Internal
Combustion Generators
Diesel- and gas-fueled generators
are one of the most common forms of
distributed electric generation. Based on the
internal combustion engine, the generators
provide reliable electrical service in many
diverse locations. Diesel generator
capacities range from a few kW to beyond
10 MW. Idaho Power owns two 2.5 MW
diesel engine-generators in Salmon, Idaho
that are primarily used for backup power.
Many industrial and large commercial
facilities have internal combustion engine
generators used for backup power. Nearly
every hospital in Idaho has an emergency
internal combustion engine generator.
Many diesel generators were
deployed throughout the Northwest last
summer when the market price of electricity
made distributed diesel generation profitable
to operate. When market prices returned to
historical norms, use of the diesel generators
declined significantly. Idaho Power s own
trial with diesel generators in the Treasure
Valley in the summer of 2001 was, at best
problematic.
Advanced Technologies
Fuel Cells
Fuel cells are electrochemical
devices that convert the chemical energy of
a fuel, such as natural gas, into low-voltage
electricity. In a typical fuel cell, hydrogen
extracted from the fuel is oxidized at an
anode using oxygen supplied from the
Chapter Future Resource Options