20031212Supplemental 1st Response of Idaho Power to Staff.pdf

IDAHO POWER COMPANY
O. BOX 70
BOISE, IDAHO B3707
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BARTON L. KLINE
Senior Attorney
An IDACORP Company
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December 11 2003
Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise , Idaho 83720-0074
Re:Case No. IPC-03-
Idaho Power Company s Supplemental Response
to First Production Request of Commission Staff
(Production Request Nos. 1 , 4, and 20)
Dear Ms. Jewell:
In regard to the above-described response to the Commission Staff's
production request which Idaho Power filed on December 8, 2003 , I inadvertently
omitted the enclosed narratives. Enclosed with this letter are the narratives for the
Responses to Request Nos. 1 , 4 and 20.
Very truly yours
OJ a(
Barton L. Kline
BLK:jb
Enclosure
Donald L. Howell , II
Peter J. Richardson
Eric L. Olsen
Telephone [phone], Fax [phone] E-mail BKlinefiilidahopower.com
IDAHO POWER COMPANY
Case No. IPC-O3-
f~ECEIVED
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2003 DEC f I P11 4: 28
Supplemental
Response To First Production Request
of Commission Staff
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I L,unuTiES cm'H'1IsSION
REQUEST NO.1: Please provide a load-resource balance by month
reflecting as accurately as possible Idaho Power s load-resource conditions for each of
the next 10 years including consideration of the following:
abandonment of the Garnet contract;
addition of the PPL Montana contract;
addition of the Danskin plant;
changes in the load forecast considering economic factors; and
any other material change in generation or load since the October
2002 Garnet report.
Include load-resource balances for energy and peak hour, for median
70% and 90% water and load conditions as defined in the 2002 IRP.
SUPPLEMENTAL RESPONSE TO REQUEST NO.1: As noted in our
initial response to Request No 1 and Request No., the differences in peak-hour loads
between the current and the 2002 IRP load forecasts were under review - specifically
the increase in forecast June peak-hour loads. The outcome of the review was a
decrease in forecast June peak-hour loads. The revised June peak-hour load forecast
now more closely match historical data and the trend of June peak-hour load growth.
The June peak-hour load reduction in 70% load case ranges from 111 MW in 2004 to
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
FIRST PRODUCTION REQUEST OF COMMISSION STAFF Page 1
127 MW in 2013. Updated monthly peak-hour load resource balance data and charts
are attached.
The Response to this Request was prepared by Karl Bokenkamp. General
Manager Power Supply Planning, Idaho Power Company, in consultation with Barton L.
Kline and Monica B. Moen , attorneys for Idaho Power Company.
REQUEST NO.4: Please provide critical peak analysis data by month for
each of the years 2005-2015 for the following conditions all assuming loads at the
currently forecasted levels:
50% water, 50% load
70% water, 70% load
90% water, 70% load
SUPPLEMENTAL RESPONSE TO REQUEST NO.4: As noted in our
initial response to Request No 1 and Request No., the differences in peak-hour loads
between the current and the 2002 IRP load forecasts were under review - specifically
the increase in forecast June peak-hour loads. The outcome of the review was a
decrease in forecast June peak-hour loads. The revised June peak-hour load forecast
. now more closely match historical data and the trend of June peak-hour load growth.
The June peak-hour load reduction in 70% load case ranges from 111 MW in 2004 to
127 MW in 2013. Updated monthly peak-hour Northwest transmission deficit data
tables and charts are attached.
The Response to this Request was prepared by Karl Bokenkamp, General
Manager Power Supply Planning, Idaho Power Company, in consultation with Barton L.
Kline and Monica B. Moen , attorneys for Idaho Power Company.
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
FIRST PRODUCTION REQUEST OF COMMISSION STAFF Page 2
REQUEST NO. 20: Please perform the following computer simulation
runs for Idaho Power s system using the AURORA model. Before making any runs
however, review all assumptions for the transmission interconnections to Idaho Power
system, all assumptions for Idaho Power s existing generating plants, power purchase
and sales contracts, load shape and any other necessary input assumptions and make
any necessary adjustments so that the model corresponds as closely as possible to
actual conditions. Insure that the load and fuel price forecasts assumed in the modeling
runs are consistent with those of the 2002 )IRP. It may be desirable to use the AURORA
Portfolio" feature to model Idaho Power for purposes of the following analyses.
Perform an hourly simulation beginning June 1 , 2005 and extending
through December 2020 under an operating mode in which no new
capacity can be added within the Idaho Power system and supply
deficiencies are met through power imports from outside Idaho
Power s system. Based on the results of this run , identify the number
and timing of any hours in which transmission constraints limit the
amount of power that can be imported. In addition , identify those
transmission interconnections on which constraints occur. Identify the
timing and duration of any load curtailment predicted by the model.
Report the results in graphical format , including any narrative
necessary to interpret the results.
Perform a long-term optimization (capacity addition) study for the
period June 1 , 2005 through December 2020 (running five years
beyond the conclusion of the period of interest as recommended by
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
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EPIS). Use hourly dispatch to fully capture peak load hours. Confirm
that the new resource choices available match those identified in the
Company s 2002 IRP and that the Bennett Mountain project is also
available as a choice at the prices and terms assumed in the RFP
analysis for the months of June , July, August, November and
December. Assume also that market purchases are an available
option. Based on the results of this run, identify the type , timing and
location of new resources added along with the amount of capacity
and energy associated with each new resource. Confirm whether the
Bennett Mountain project is chosen as an alternative to meet load.
Summarize the months and the hours within each month when the
Bennett Mountain plant would be used to meet load. Identify any
other resources selected by the model.
Perform an hourly simulation beginning June 1 , 2005 and extending
through December 2020 assuming that capacity and energy is
available in accordance with the Bennett Mountain project but at zero
cost. Compare the net power supply cost over the duration of the
simulation to the net power supply cost for the model run conducted
in part "b" above. Compare the difference in net power supply cost to
the cost of the Bennett Mountain project.
Perform an hourly simulation beginning June 1 2005 and extending
through December 2020 assuming that capacity and energy is
available in accordance with the Bennett Mountain project and that
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
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additional capacity and energy beyond that sought in the 2003 RFP
can be purchased from the Bennett Mountain plant at predicted
market prices (i.e. Bennett Mountain s output in all months other than
June , July, August, November and December is modeled as a
contract option available at prevailing market prices in the Idaho
Power load-resource area). Report the amount, timing and cost of all
additional capacity and energy purchased from the Bennett Mountain
plant.
RESPONSE TO REQUEST NO. 20: The requested information is
attached. In responding to this request, Idaho Power has worked with EPIS
(Developers of the Aurora Electric Market Model) and an outside consultant to perform
the requested analyses. Comments are provided to assist in interpretation of the results
and also to point out several important factors not addressed in the Aurora analysis.
General Comments: Idaho Power does not believe that the Aurora model
adequately address the transmission issues encountered in actual day-to-day operation
of the Western grid. Several of our major concerns include; (1) Aurora does not model
Capacity Benefit Margin (CBM) or Transmission Reliability Margin (TRM), (2) Aurora
does not consider ownership of transmission rights , for example Aurora shows 337 MW
of transmission capacity from Montana to Idaho , however, Idaho Power does not have
contractual rights to use all of this import capacity yet the model uses it to serve the
loads in the Idaho-South area, (3) PacifiCorp s South Idaho loads are not included in
Aurora s Idaho-South area, and (4) we suspect that the Bridger plant is modeled as
being in the Wyoming area with no limitation on the amount of energy Bridger can
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
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supply to the Wyoming area - in reality there is a limit. These are serious concerns that
must be considered in a complete analysis of Idaho Power s need for additional
resources. Idaho Power estimates that the overall impact of not modeling CBM , TRM
and PacifiCorp s South Idaho load is on the order of 1000 MW during peak-load hours.
These three items can be thought of as a 1000 MW worth of additional load and
reductions in transmission capacity not currently considered in the Aurora analysis.
There may be ways to configure Aurora to address these issues. One possibility is to
increase the Idaho-South load forecast and to reduce the transmission capacity into
Idaho-South; however, Idaho Power does not believe these transmission issues are
adequately addressed in the attached results. Idaho Power will continue to work with
EPIS to investigate ways to address these transmission related issues in future Aurora
analyses.
Part A. The requested analysis was performed. An Aurora simulation
was performed for the Idaho Power Company (IPC) system modeling with no new
capacity being added and deficiencies met through power imports and DSM
curtailments if necessary. The simulation was performed for years 2005 through 2020
with 70 percentile water and 70 percentile loads, BPA transmission loads included and
the Bennett Mountain Plant removed from the simulation. Aurora calculated the
transmission path loadings for the following transmission interconnections:
. Oregon/Washington/ldaho-North to IPC
Montana to I
Wyoming to IPC
Utah to IPC
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
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. Nevada-North to I
Charts showing the transmission path loadings and the path limit are included for each
of the above transmission interconnections. Aurora will not violate the reserve margin
requirements within an area (Idaho-South for example), so , if the transmission
interconnections are full , Aurora will dispatch Demand Side Curtailment units to meet
load. This simulation produced Demand Side Curtailments beginning in 2010. This
information is included in chart form. A chart showing the Demand Side Curtailments in
the Nevada-North area is also included - both regions are experiencing curtailments at
the same time.
Another point of interest is the Nevada-North to IPC transmission path
loading. While the path has directional limits, the Aurora model's results are for the net
loading of the Nevada-North to IPC path. For example , if IPC is importing 200 MW
from Valmy to IPC and there is a simultaneous export of 150 MW from IPC to Nevada-
North , the net flow on the Nevada-North to IPC path would show as 50 MW. This
explains why the Nevada-North to IPC transmission path appears to be lightly loaded
during nearly all hours. The simultaneous curtailments in Nevada -North and IPC
explain why the I PC curtailments could not be served via imports from Nevada-North.
And finally, Idaho Power does not understand some of the transmission
flows predicted in this analysis - specifically the sustained flows on the Montana to IPC
interconnection. The results do not correspond to typical usage of this line.
Part B. The requested data is attached. The Bennett Mountain project
was selected as an alternative to meet load, however, the project was not selected until
2011. The first resource added to the area Idaho-South was added in 2011. A six
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
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page table of resources added in the WECC is included as well as a table and two
graphs summarizing the months and hours that the Bennett Mountain was dispatched.
As noted earlier, Idaho Power believes that if the transmission system were modeled
more accurately, a resource would have been required in the Idaho-South area prior to
2011. In fact, Idaho Power utilized its TRM and CBM during the summer of 2004, and
summer peak loads are expected to continue to grow.
Part C. The requested data is attached. As previously noted , the Bennett
Mountain project does not come on-line in this simulation until 2011. The differences in
net power supply costs are summarized in a table.
Part D. The requested data is attached. Bennett Mountain output in
MWh , average megawatts (aMW) and dispatch costs are tabulated for all months other
June , July, August, November and December. In this instance Bennett Mountain was
modeled as Resource Market Price contract. The cost of energy for the Resource
Market Price contract is calculated by multiplying the resource output times the market
price.
The Response to this Request was prepared by Karl Bokenkamp, General
Manager, Power Supply Planning, Idaho Power Company, in consultation with Barton L.
Kline and Monica B. Moen , attorneys for Idaho Power Company.
IDAHO POWER COMPANY'S SUPPLEMENTAL RESPONSE TO
FIRST PRODUCTION REQUEST OF COMMISSION STAFF Page 8