200401152nd Response of Idaho Power to ID Irrigation Pumpers.pdf

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BARTON L. KLINE ISB #1526
MONICA B. MOEN ISB #5734
Idaho Power Company
P. O. Box 70
Boise, Idaho 83707
Telephone: [phone]
FAX Telephone: [phone]
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Attorney for Idaho Power Company
Street Address for Express Mail
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS INTERIM)
AND BASE RATES AND CHARGES FORELECTRIC SERVICE.
CASE 1\10 IPC-03-
IDAHO POWER COMPANY'
RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'
SECOND DATA REQUEST
COMES NOW , Idaho Power Company ("Idaho Power" or "the Company
and in response to the Second Data Request of the Idaho Irrigation Pumpers Association
to Idaho Power Company dated December 15 , 2003, herewith submits the following
information:
REQUEST NO. 20: The expenses for FERC Account 557 seem to
fluctuate widely from year to year. Please provide an explanation of what occurred in
each year from 1992 to the present that caused such dramatic swings.
RESPONSE TO REQUEST NO. 20: FERC Account 557 fluctuates on an
actual basis because the Company s Power Cost Adjustment has been booked in that
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page
account since 1993. Also , the Oregon Excess Power Cost Adjustment was booked in
557 in 2001. The Idaho PCA and Oregon (EPC) costs are removed (normalized) for
ratemaking purposes. The remaining balance of the account is included for ratemaking
purposes. Please refer to Smith Exhibit 16, page 4 of 22 , line 9 that reflects Other
Power Supply expenses that have been included in that account per the Code of
Federal Regulations.
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 21: The expenses for FERC Account 502 seem to
fluctuate widely from year to year. Please provide an explanation of what occurred in
each year from 1992 to the present that caused such dramatic swings.
RESPONSE TO REQUEST NO. 21: FERC Account 502 contains the
costs of operating the boiler and associated equipment at each of Idaho Power s three
jointly-owned steam plants. The costs in this account are based on the amounts
reported to Idaho Power by the operating partner at each plant. The significant
components of the expenses booked in Account 502 are chemicals to maintain the
quality of the water used to produce steam and the labor costs to operate the boiler.
The chemical costs vary with changes in generation , while the labor costs remain fairly
constant. For accounting purposes , we estimate O&M expenditures for the month and
then adjust those estimates to the actual amounts in the following month when the
actual amounts are known. For simplicity, only a few accounts are used for estimating
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 2
purposes; Account 502 is one of those accounts. This estimating process can cause
year-to-year variations.
The attached table lists the changes by year by plant for Account 502 and
illustrates the changes based on generation. Three years -- 1995 , 2000 and 2002 --
show significant variations from the preceding year. The following discussion
addresses those years.
Note that during 1997 for the Boardman plant, PGE changed its
accounting philosophy regarding which accounts are used for operating expenses. The
amounts that previously had been charged to Account 502 are now being charged to
Account 500.
The decrease in expense in 1995 from 1994 of $840 596 is a result of
decreased generation at each of the plants primarily due to good hydro conditions
resulting in reduced chemical costs.
In 2000, Account 502 increased $1 284 718 over 1999. All of this
increase can be attributed to the Bridger Plant, which increased $1 302,415 over 1999.
The increase at Bridger is due to an increase in actual charges of $577 000, a reversal
of accruals of $214 000 made in 1999 that did not recur in 2000 , and an increase in the
estimate of expenses for December that was $506 000 greater than the corresponding
period in 1999.
In 2002 Account 502 decreased $1 751 360 -- Bridger decreased
150 000 and Val my decreased $602 000. Bridger s decrease is the result of a
decrease in actual charges of $436 000 and a decrease in the amount estimated for
December 2002 of $804 000 over December 2001. The decrease at Val my is due to
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 3
actual charges for 2002 being $508 000 less than 2001 charges, while the reversal of
the prior month's estimate in January of 2002 was $97 000 greater than the
corresponding period in 2001.
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 22: Since 1994 the expense associated with Account 500
(Supervision) have been generally decreasing.
What has caused this decreasing trend?
The actual expenses for the first six months of the test year are
three times what the projected expenses are for the remainder of the test year. For the
first six months of 2003 , please provide a detailed explanation as well as all supporting
documents regarding why these expenses increased so dramatically over this
timeframe.
RESPONSE TO REQUEST NO. 22: The decreasing trend is driven by
decreases in labor costs at the Bridger plant that are charged to Account 500. This
reduction is a combination of reductions to the labor force at Bridger and a change by
the operator PacifiCorp regarding the accounts to which supervisory labor is charged.
The decrease at Bridger is offset by increases at Boardman , where PGE has changed
its methodology to record most operational costs in Account 500. See the attached
table for a breakdown by plant of the expenses.
The actual charges for Account 500 through June 2003 include a large
entry in June for the Bridger Plant. This entry, for $1 134 000 , represents a temporary
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 4
accrual of annual overhaul costs. This accrual has been reversed in the following
months. Following this reversal , the annual charges to Account 500 for Bridger should
be similar to the levels experienced in 2001 and 2002.
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 23: Since 1994 the expense associated with Account 512
(Boiler Maintenance) have been generally steady. Please provide an explanation of
what changes occurred in the test year to have these expenses approximately 50%
greater than the long-term average.
RESPONSE TO REQUEST NO. 23: PacifiCorp and Sierra Pacific have
performed a significant amount of boiler work at the Bridger and Valmy plants in 2003
leading to increased labor and material costs.
Part of the increased costs at Bridger is explained by a change initiated by
PacifiCorp in how labor costs are charged. In 2002, almost 70% of the maintenance
labor dollars were charged to Account 514 with Account 512 receiving only 23% of the
maintenance labor dollars. In 2003 , the amounts by account equaled , to some degree
with Account 514 dropping to 40% of maintenance labor while Account 512 rose to
42%. In total, maintenance labor costs decreased 3% from 2002.
In response to various operating and maintenance requirements at the
plant, Valmy experienced material and outside contractor expense in 2003 that
exceeded prior years.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 5
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support, Idaho Power Company, in
consultation with Barton L. Kline , Senior Attorney, Idaho Power Company.
REQUEST NO. 24: Since 1997 the expense associated with Account 536
(Water for Power) have been generally decreasing. What has caused this decreasing
trend and please provide an explanation of what changes occurred in the test year to
have these expenses realize such a dramatic increase.
RESPONSE TO REQUEST NO. 24: The decreasing trend in Account
536 expenses since 1997 can be traced to three main factors: refinanced American
Falls debt obligation , conclusion of the amortization of FERC headwater benefits , and
reduced incentive royalty payments for Milner.
Idaho Power is realizing lower interest expenses related to the American
Falls debt obligation. This obligation was refinanced with a variable rate instrument in
2000 and interest rates have been very low recently.
An assessment for use of Federal water impoundments (headwater
benefits) was instituted in the late 1980's. Retroactive FERC headwater benefits
through 1988 were computed and paid in 1990. Based on IPUC Order 23224, this cost
was amortized over 120 months. In 2000 , the amortization period finished and expense
dropped accordingly.
Drought conditions throughout Idaho in recent years have affected
streamflows and generation at Milner. Since 2000, generation has fallen below the
threshold requiring payment of incentive royalties to Milner Dam Inc.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 6
Account 536 expenses in the test year are higher than the preceding two
years due to the cloud seeding program. The cloud seeding program was started in late
2002 , but the test year (2003) includes expenses for a full year of operation. Cloud
Seeding Program costs more than offset the expense reductions previously noted.
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support , Idaho Power Company, in
consultation with Barton L. Kline , Senior Attorney, Idaho Power Company.
REQUEST NO. 25: Why has Account 586 (Meters) increased so
dramatically in the last couple of years?
RESPONSE TO REQUEST NO. 25: Beginning in July 2001 , the
Company began using call center statistics (number of calls and duration of calls) to
allocate call center expenses to activities performed. At that time, the Company began
charging call center labor and expenses associated with customer requests for
connect/disconnects to account 586000. Previously these expenses were charged to
account 903000. In hindsight, this change in FERC account assignment was an error
and the amounts should have continued to be charged to account 903000. The dollar
amounts associated with this change are as follows:
Year Amount
2001
2002
2003
$ 708 002.
619 755.
$1,426,492.
The Company is planning on correcting the 2003 entries by decreasing
account 586000 and increasing account 903000 before the 2003 year-end accounting
books close.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 7
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 26: Why has Account 904 (Uncollectibles) increased so
dramatically in the last couple of years?
RESPONSE TO REQUEST NO. 26: The uncollectible account has
increased significantly since 2001 due to increased power rates, increases in Idaho
unemployment and adverse financial conditions in several sectors of the economy. For
example , Idaho Power has written off irrigation accounts of $426 138.85 in 2002 and
034 994.96 in 2003 , a category that previously had very few write-offs. See the
attached charges of uncollectible accounts by rate code , Idaho unemployment from the
S. Department of Labor.
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 27: What has caused the substantial increase in Account
924 (property insurance) during the test year?
RESPONSE TO REQUEST NO. 27: The following chart shows the
dramatic increase in property insurance premiums since 2000.
2000 2001 2002 2003
Idaho Power property program premiums 162 693 391 197 133 368 $2,497,479
Joint Venture property programs charges 560 388 887 322 989,483 $1,475,900
Total property insurance premiums 723,081 278 519 $3,122 851 973,379
Combined increase from previous year 32.24%37.06%27.24%
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 8
The increased costs for property insurance can generally be attributed to
the following items: A soft property insurance market from 1991 through 2000, i.e., few
losses, high investment returns held down property insurance premiums. That changed
in 2001. 2001 was a year of record losses and escalating reinsurance costs for
property insurers. Increased premiums also driven by reduced insurance capacity
during hardening market, which creates less competition and higher pricing. Terrorism
coverage immergence in 2002 increased property premiums an additional 12+%
annually. The utility industry, and subsequently the industry property insurers , have
experienced higher losses due to the aging of electrical equipment. Idaho Power
property loss history over the last seven years has been 96.6% -- 40% to 60% is
deemed expected. Along with substantial premium increases most utilities have seen
substantial increases in deductible levels. Joint venture insurance premiums have also
increased substantially as can be seen by the chart above. Most insurers now limit
payment to actual cash value rather than replacement cost for utility equipment twenty
years of age or older.
The following is a comparison of rate changes for the utility industry vs.
Idaho Power (as reported by FM Global).
FMG Industry
Renewal Ave. Rate Idaho Power
Year Change Rate Change
2000 15.00%10.00%
2001 35.00%19.85%
2002 45.00%33.50%
2003 00%27%
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 9
The response to this request was prepared by Randy P. Meyer
Property/Casualty Insurance Administrator, Idaho Power Company, in consultation with
Barton L. Kline , Senior Attorney, Idaho Power Company.
REQUEST NO. 28: What has caused the substantial increase in Account
926 (Employee Benefits) during the test year?
RESPONSE TO REQUEST NO. 28: The main driver for the increase in
Account 926 during the test year is Pension Expense. Based on actuarial calculations
in 2002 , FAS 87 pension expense was $(99 000), and in 2003 the same pension
expense was $7 018 000.
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support, Idaho Power Company, in
consultation with Barton L. Kline , Senior Attorney, Idaho Power Company.
REQUEST NO. 29: What has caused the substantial increase in Account
935 (Maintenance of General Plant) during the first six months of the test year?
RESPONSE TO REQUEST NO. 29: One of the main causes for the
increase in Account 935 during the test year is a change in the accounting for where
maintenance of communication equipment is expensed. Late in 2002 it was determined
within our Delivery Business Unit that this activity should be recorded in Account 935
instead of Account 562 (Trans Station Expense) where it had previously been
expensed. This increase in Account 935 represents a shift from another account and
not an increase in the overall level of expense.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 1 0
The response to this request was prepared by Darrell R. Tomlinson
Finance Team Leader, Financial Research/Support, Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 30: Please provide a copy of each Marginal Cost Study
that has been presented to the Commission or the Commission Staff for each year
since 1995.
RESPONSE TO REQUEST NO. 30: Idaho Power has not prepared nor
has it presented to the Commission or the Commission Staff any Marginal Cost Studies
since 1995. The Company did , however, perform an analysis of the generation and
transmission marginal costs during 2003 for use in the class cost-of-service study. A
copy of the Company s analysis is enclosed with this response.
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. 31: With respect to the marginal demand costs used in
Exhibit 40, what is the exact source of these numbers (historic/current contract values
projections, current values of indexed prices, etc.
RESPONSE TO REQUEST NO. 31: The marginal demand costs used in
Exhibit 40 are described on page 2 of the analysis provided in response to Request
No. 30.
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.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 11
REQUEST NO. 32: With respect to the marginal energy costs used in
Exhibit 40 , what is the exact source of these numbers (historic/current contract values
projections, current values of indexed prices , etc.)? Are these prices for firm energy?
RESPONSE TO REQUEST NO. 32: The marginal energy costs used in
Exhibit 40 are described on page 1 of the analysis provided in response to Request
No. 30.
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. 33: Please provide a copy of the Company s 2002
Integrated Resource Plan (IRP). Please identify specific areas in this Plan that identify
the months of capacity deficit.
RESPONSE TO REQUEST NO. 33: The requested information is
enclosed with this response. Section 4 of the plan entitled Adequacy of Existinq &
Planned Resources contains the requested capacity deficit information.
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. 34: With respect to the demand values listed on
Exhibit 40, what was the date and time that each peak occurred?
RESPONSE TO REQUEST NO. 34: The demand values listed on
Exhibit 40 are the 2002 demand values. The date and time that each peak occurred is
included with the response to Request No. 35.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 12
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. 35: For each of the last five years , what was the date and
time of the monthly system peak?
RESPONSE TO REQUEST NO. 35: The requested information is
enclosed with this response.
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. 36: During the hour of the monthly peak for each of the
last five years , please provide the following:
How many megawatts of generation were out of service for planned
maintenance?
How much electricity was generated from Company owned hydro?
How much electricity was purchased from Company owned thermal
power?
How much electricity was purchased from QF suppliers?
How much electricity was brought in through exchanges?
How much (non-QR) electricity was purchased and at what price?
Please list each transaction separately, stating name of seller, MWH purchased
purchase price , and type of purchase (LF, RQ, SF, OS, etc.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 13
How much electricity was sold off-system and at what price? Please
list each transaction separately, stating name of purchaser, MWH sold, sale price , and
type of sale (LF , RQ, SF, OS , etc.
RESPONSE TO REQUEST NO. 36: The requested material is included
with this response.
The response to this request was prepared by Sandy L. Ward , Contract
Administrator, Energy Transactions, Idaho Power Company, in consultation with Barton
L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO. 37: For each of the next three years , what are the dates
of scheduled maintenance, name of the units being maintained , and the megawatts
being taken out of service?
RESPONSE TO REQUEST NO. 37:
Power Production Maintenance Scheduling. Maintenance scheduling
for Idaho Power s generating units is a dynamic process. It is driven by factors that can
change from year to year, month to month , or even week to week.
Power Production s preliminary annual maintenance schedule for each up-
coming year is usually developed in October. The planned schedule is then revised in
the spring when snow pack conditions are known.
Elements that are considered when putting together an annual
maintenance schedule include: snow pack, stream flow and reservoir conditions
predicted system loads (peak periods and off peak periods), transmission constraints or
requirements, planned transmission and substation construction projects , available work
force , contractor requirements, failures or other problems associated with equipment
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 14
occasional non-routine maintenance to units and/or associated equipment, equipment
upgrade opportunities , and forward price indications.
Maintenance is always subject to cancellation or change due to real time
operational conditions.
Hydro Generation Unit Maintenance. The upper Snake Hydro plants
(American Falls through Swan Falls) usually have a one-week outage for general unit
maintenance inspections of each unit , each year. The lower Snake plants (Brownlee
Oxbow, Hells Canyon, and Cascade) have two-week outages for each unit, each year.
Thermal Generation Unit Maintenance. The maintenance outages of
our jointly owned coal-fired thermal facilities are coordinated with the operating partners.
Multi-year schedules are developed for these plants, with the first year fairly certain and
subsequent years considered preliminary.
Specific Dates. Idaho Power considers the specific dates for scheduled
outages for its generating units to be valuable competitive information. As a result , the
information on specific scheduled outages will only be supplied upon execution of a
confidentiality agreement.
The response to this request was prepared by Darwin D. Pugmire
Manager , Hydro Production , Idaho Power Company, in consultation with Barton L.
Kline , Senior Attorney, Idaho Power Company.
REQUEST NO. 38: Please provide copies of allIRP's filed by the
Company between 1995 and 2002.
RESPONSE TO REQUEST NO. 38: The requested information is
voluminous. As a result, it will be made available in the discovery room at Idaho Power.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 15
Any party desiring to review documents in the discovery room should call Myrna
Aasheim at 388-3558 to arrange a time for the room to be made available.
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. 39: With respect to the system , as well as class
demands and energies listed on Exhibit 40 , if the values listed are not actual (or directly
derived from load research data for that exact hour), please provide a description as
well as all data used to derive the values listed in Exhibit 40.
RESPONSE TO REQUEST NO. 39: The demand values listed on
Exhibit 40 are the coincident demands for 2002 with the following adjustments: 1) since
Astaris became a Schedule 19 customer in May, 2002, the coincident demands for
Schedule 19 for January through April 2002 were adjusted to reflect the inclusion of the
actual coincident demands for Astaris; and 2) to reflect the closing of Simplot'
ammonia processing plant in late August, 2002, the January through July 2002
coincident demands for Simplot were replaced with 2003 actual coincident demands
and the August 2002 coinctdent demand was adjusted.
The energy values listed on Exhibit 40 are normalized values at
generation level (i.e., adjusted for losses). A description of the process used to derive
the normalized values for 2003 can be found at pages 273-275 of the workpapers of
Company witness Obenchain.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 16
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. 40: On page 5 of the Brilz workpapers is a listing for a
Sailor Creek Substation as well as one for a Hidden Springs Substation. Please provide:
The hourly load data for each substation for 2002.
The approximate percentage of each substation (percent
customers , percent peak demand , and percent energy) used by various customer
classes.
RESPONSE TO REQUEST NO. 40:
The hourly load data for the Sailor Creek and Hidden Springs
substations is voluminous and as a result is included on the CD labeled "Irrigation
Pumpers Second Production Request" included with this response.
The Company does not have the requested information available
and is unable to produce the requested information without undertaking additional
systems development and interfaces. Such development would be unreasonably
burdensome.
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. 41: On page 12 of Brilz workpapers there are various
values listed under the column entitled "DA364". Please answer the following:
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 17
What is the source of the figure under Ration Computation for
Primary of 153 854,405?
Please describe the methodology of dividing Acct. 364 into its
primary component (153 854,405). Please give examples.
If a pole or tower carried both primary and secondary lines, what
portion of the pole would be assigned to the primary component (153 854,405)?
If a line transformer were on a pole or a tower such that the primary
line ends at this particular pole and the secondary line starts at this pole, what portion of
the pole would be assigned to the primary component (153 854 405)?
If a pole or tower were used as part of a Service Drop, would it be
assigned to Account 364 or Account 369?
Please provide a copy of the study that developed the System
Customer Component of 36.25% and the System Demand Component of 63.75%.
On page 12 of the workpapers , the total Secondary Direct
Assignment is listed as $12 208 967 while the figure on Exhibit 39 page 3 line 87 is
$13 360 114. Please reconcile these two figures.
RESPONSE TO REQUEST NO. 41:
The source of the figure $153 854,405 under Ratio Computation is
the Company s property accounting records as of December, 2002.
Poles , towers, and fixtures are identified as either primary or
secondary based on the purpose for which they are used. The identification occurs at
the time of installation and is tracked through the Company s work order process.
Poles , towers , and fixtures used to support the Company s primary lines are classified
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 18
as primary. Poles, towers, and fixtures used to support the Company s secondary lines
are classified as secondary.
If a pole or tower carried both primary and secondary lines, it would
be assigned to the primary component. In this situation , the pole or tower would need
to be constructed to the standards necessary to support primary lines. As such, it would
be classified as primary.
In the specific situation described , the pole or tower would be
assigned to the primary component since the pole would need to be constructed to the
standards necessary to support primary lines.
The investment in all poles and towers which support distribution
conductors and service wires, regardless of whether or not they are the last pole or
tower prior to the service drop, are booked to FERC Account 364.
The results from the analysis can be found on pages 10 and 11 of
the workpapers of Company witness Brilz. The hourly system load data for the years
2000 through 2002 used in the analysis are included on the CD labeled "Irrigation
Pumpers Second Production Request" included with this response.
The value of $12 208 967 is the sum of the actual investments as of
June 30 2003 for FERC Accounts 364 ($902 959), 365 ($940 606), 366 ($2 106 135),
and 367 ($8 259 267) which are directly assigned to customers and for which a monthly
facilities charge is paid. Each of these individual FERC Account values can be found on
Exhibit 37, page 7, lines 83 through 86 under column N , Secondary Lines - Direct.
Within the cost-of-service study, general plant is allocated to functional
categories based on the total Production, Transmission , and Distribution plant (PTD
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 19
allocator). The difference between the $12 208 967 value and the $13 360 114 value is
the amount of general plant investment functionalized into the Secondary Lines - Direct
category. Please refer to Exhibit 37 , page 12 under the column headed N for the detail
of the general plant functionalized to the Secondary Lines - Direct category.
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. 42: How many miles of primary and secondary conductor
are found in the Idaho Jurisdiction? Please describe how this figure is derived.
RESPONSE TO REQUEST NO. 42: Idaho Power tracks the number of
miles of conductor by both pole miles and wire miles. The pole miles refer to the
distances between poles. The wire miles refer to the distances between poles times
the number of wire phases. For example, a 100 foot span of three-phase conductor
would equal 1 00 feet of pole miles and 400 feet of wire miles (Le., three wires plus the
neutral or four times the pole distance). Conductor miles are derived from the work
orders prepared as part of the Company s facilities installation process.
The following are the lines miles within the Idaho jurisdiction as of
December, 2002:
Secondary Primary
Pole Miles
Wire Miles
359
656
075
596
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.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 20
REQUEST NO. 43: On page 13 of Brilz workpapers there are various
values listed for Account 368. Please answer the following:
What is the source of the figures 51 716 055 and 204 373 052?
Please describe the methodology of dividing Acct. 368 into its
primary component (47 529 633). Please give examples.
Please provide a general explanation regarding what is meant by
the primary component versus the secondary component when it comes to line
transformers.
How do the values on this page of $11 473 741 for Direct
Assignment relate to figure on Exhibit 39 page 3 line 90 of $12 555 559 for direct
assignment of line transformers?
How do the values on this page of $176 355 283 for Other
Secondary relate to figures on Exhibit 39 pager 3 lines 91 plus 92 of $123 026 789 and
$69 956,409 respectively (totaling $192 983 198) for Other Secondary for line
transformers?
RESPONSE TO REQUEST NO. 43:
The source of the figures $51 716 055 and $204 373 052 is the
Company s property accounting records as of December, 2002.
Facilities booked to FERC Account 368 are classified as either
primary or secondary based on the purpose for which they are used. The identification
occurs at the time of installation and is based on the information included on the actual
work orders prepared as part of the Company s facilities installation process.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 21
Transformers are classified as either primary or secondary based
on their usage. Transformers located between substations and the transformers that
ultimately serve customers are considered primary. Transformers used to directly
provide service to customers are considered secondary.
The value of $11,473 741 is the actual investment as of June, 2003
in transformers which are directly assigned to customers and for which a monthly
facilities charge is paid. This value can be found on Exhibit 37, page 7 under the
column headed Q. It is the plant investment assigned to the Line Transformer - Direct
functional category.
Within the cost-of-service study, general plant is allocated to functional
categories based on the total Production , Transmission, and Distribution plant (PTD
allocator). The difference between the $11,473 741 value and the $12 555, 559 value is
the amount of general plant investment functionalized into the Line Transformer - Direct
category. Please refer to Exhibit 37, page 12 under the column headed Q for the detail
of the general plant functionalized to the Line Transformer - Direct category.
The value of $176 355 283 for Other Secondary line transformer
investment is classified between demand-related ($112,426 493) and customer-related
($63 928 790) on page 13 of the workpapers of Company witness Brilz. These values
can be found on Exhibit 37, page 7 under the column headed R and on Exhibit 37
page 8 under the column headed S , respectively.
Within the cost-of-service study, general plant is allocated to functional
categories based on the total Production , Transmission , and Distribution plant (PTD
allocator). The difference between the $176 355 283 value and the $192 983,198 value
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 22
is the amount of general plant investment functionalized into the Line Transformer-
Secondary categories. Please refer to Exhibit 37, page 12 under the column headed R
and Exhibit 37, page 13 under the column headed S for the detail of the general plant
functionalized to the Line Transformer - Secondary categories.
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. 44: On page 14 of Brilz workpapers there are various
values listed for Account 369. Please answer the following:
How were the figures of $203.87 and $287.83 for the average cost
of single-phase and three-phase customers derived? Please supply supporting study.
What do the figures of $203.87 and $287.83 for the average cost of
single-phase and three-phase customers represent as far as the average length of a
Service?
What is the average length of a Service for an Irrigation customer?
RESPONSE TO REQUEST NO. 44:
The Company s PassPort work management system , which is used
to provide work order estimates for new line construction , was used to derive the
average cost of a single-phase and a three-phase service drop. The single-phase
average cost of $203.87 was derived by utilizing PassPort to compute the cost of a 70-
foot service drop using #2 conductor and the necessary conductor hardware, requiring
one hour of lineman labor, and requiring one hour s usage of a linebed or bucket truck.
The three-phase average cost of $287.83 was derived utilizing PassPort to compute the
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 23
cost of a 70-foot service drop using #2 conductor with one extra strand of conductor and
the necessary conductor hardware , requiring one hour of lineman labor, and requiring
one hour s usage of a linebed or bucket truck.
The average length of the service drop used to derive the average
cost of single-phase and three-phase service drops was 70 feet.
The Company does not maintain the detailed data on the length of
the service drop for each customer and therefore cannot calculate the actual average
service drop length by customer class. However, based on the expertise of the
Company s agricultural representatives and their knowledge of the Company
customers , it is believed that no service drop for irrigation customers exceeds 120 feet
or would be less than 10 feet and on average would be approximately 60 feet in length.
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. 45: Please provide a copy of any cost-of-service studies
the Company may have supplied to the Commission or Commission Staff since the last
rate case.
RESPONSE TO REQUEST NO. 45: The Company has provided only
one class cost-of-service study to the Commission or Commission Staff since the last
general rate case. A copy of that study is included with this response.
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.
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 24
DATED at Boise , Idaho, this 13th day of January, 2004.
BARTQ!ftL-
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO IDAHO IRRIGATION
PUMPERS ASSOCIATION'S SECOND DATA REQUEST Page 25
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 13th day of January, 2004, I served a
true and correct copy of the within and foregoing IDAHO POWER COMPANY'
RESPONSE TO SECOND PRODUCTION REQUEST OF IDAHO IRRIGATION
PUMPERS ASSOCIATION upon the following named parties by the method indicated
below, and addressed to the following:
Lisa D. Nordstrom
Weldon B. Stutzman
Deputy Attorneys General
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise, Idaho 83720-0074
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
Randall C. Budge
Eric L. Olsen
Racine, Olson , Nye , Budge & Bailey
O. Box 1391; 201 E. Center
Pocatello, I D 83204-1391
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
Anthony Yankel
29814 Lake Road
Bay Village , OH 44140
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
Peter J. Richardson
Richardson & O'Leary
99 East State Street, Suite 200
O. Box 1849
Eagle , ID 83616
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
Don Reading
Ben Johnson Associates
6070 Hill Road
Boise, ID 83703
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
Lawrence A. Gollomp
Assistant General Counsel
U. S. Department of Energy
1000 Independence Avenue , SW
Washington , D.C. 20585
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
Dennis Goins
Potomac Management Group
5801 Westchester Street
Alexandria, VA 22310-1149
CERTIFICATE OF SERVICE, Page
Hand Delivered
S. Mail
Overnight Mail
FAX
Conley E. Ward
Givens , Pursley LLP
601 W. Bannock Street
O. Box 2720
Boise , ID 83701-2720
Dennis E. Peseau , Ph.D.
Utility Resources , Inc.
1500 Liberty Street S., Suite 250
Salem , OR 97302
Dean J. Miller
McDevitt & Miller LLP
O. Box 2564
Boise , ID 83701
Jeremiah Healy
United Water Idaho, Inc.
O. Box 190420
Boise , 10 83719-0420
William M. Eddie
Advocates for the West
O. Box 1 612
Boise , ID 83701
Nancy Hirsh
NW Energy Coalition
219 First Ave. South , Suite 100
Seattle, W A 98104
Brad M. Purdy
Attorney at Law
2019 N. 17th Street
Boise, ID 83702
Michael Karp
147 Appaloosa Lane
Bellingham , W A 98229
Michael L. Kurtz, Esq.
Kurt J. Boehm, Esq.
Boehm, Kurtz & Lowry
36 East Seventh Street, Suite 2110
Cincinnati, OH 45202
CERTIFICATE OF SERVICE, Page 2
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
Hand Delivered
- U.S. Mail
Overnight Mail
FAX [phone]
Kevin Higgins
39 Market Street, Suite 200
Salt Lake City, UT 84101
Hand Delivered
S. Mail
Overnight Mail
FAX
Thomas M. Power
Economics Department, LA 407
University of Montana
32 Campus Drive
Missoula, MT 59812
Hand Delivered
S. Mail
Overnight Mail
FAX
0J1u
BARTON L. KLINE
CERTIFICATE OF SERVICE , Page 3
IDAHO POWER COMPANY
CASE NO. IPC-O3-
SECOND PRODUCTION REQUEST
IDAHO IRRIGATION PUMPERS ASSN.
TT A CHMENT TO
RESPONSE TO
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7
IDAHO POWER COMPANY
CASE NO. IPC-O3-
SECOND PRODUCTION REQUEST
IDAHO IRRIGATION PUMPERS ASSN.
TT A CHMENT TO
RESPO NSE TO
REQUEST NO.
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IDAHO POWER COMPANY
CASE NO. IPC- E-O3-
SECOND PRODUCTION REQUEST
IDAHO IRRIGATION PUMPERS ASSN.
TT A CHMENT TO
RESPONSE TO
REQ UEST NO. 26
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2002 2003*
* January 1 , 2003 thru November 30 , 2003
0 Other
. Miscellaneous 66
m Unmetered General 40
. Irrigation 24
0 Streetlighting 15
0 Commericial 09
. Small Commercial 07
. Residential 01
, .
Page 1 of
unemployment rate
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Page 1 of
unemployment
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Month
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:______,--' ____\.._
AC'C"T"1L:(\(\(\(\/V') 1CC(\1 1'1 no 1'11V\'2
IDAHO POWER COMPANY
CASE NO. IPC-03-
SECOND PRODUCTION REQUEST
IDAHO IRRIGATION PUMPERS ASSN.
TT A CHMENT TO
RESPONSE TO
REQUEST NO. 30
IDAHO
POWER
IDAHO POWER COMPANY
O, BOX 70
BOISE, IDAHO 83707
An IDACORP Company
-...----,------..--.--.---.-----.-- - -------..' ..---.. -, - - .---.----. --.- .....------- ..-.- - -- -..--
Pete Pengilly
Senior Analyst
Pricing Regulatory Services
Chq-
rr 2281
Date: August 19, 2003
Re:Marginal Cost Analysis 2003
To:Maggie Brilz
Attached are the results of the 2003 Marginal Cost Analysis. This is an update of the 1993
Marginal Cost Study completed by Patty Nichols. The 1993 study followed the model used for
previous years studies. The concept and design of these studies is from the National Economic
Research Associates Inc. (NERA) marginal cost model. The NERA model is constantly being
refined but the basic concepts and methods have remained the same since Idaho Power began
using this method. In this analysis , only the Generation Capacity, Transmission Capacity, and
the Generation Energy marginal costs have been updated for use in the Company s class cost
of service model. A five-year historic period and a five year forecast period were selected for
this update. The historic data used for this analysis is from the years 1998 to 2002. The
projected data used is from 2003 to 2007.
Attachments Worksheets:
Marginal Cost of Energy
Annual Generation Capacity Marginal Costs
Seasonalization of Generation Capacity Marginal Costs
Annual Transmission Marginal Costs
Seasonalization of Transmission Marginal Costs
Marginal Cost of Energy
The marginal cost of energy was derived from output of the Company s power supply model
AURORA, The model was run under median water conditions. The inputs were consistent with
the inputs used for the normalized net power supply cost runs used for the 2003 rate case.
However, since the marginal cost runs were done for a five year projected period, rather than a
single test year, the existing power supply contracts were left in place for 2003 and then allowed
to expire as contracted, the PPL and Tiber (CSPP) contracts were allowed to begin as contracted
coal prices reflected the contracts in place, average gas prices were used, and additional
resources were added as specified in the Company s 2002 Integrated Resource Plan (IRP), The
model was first run for the five projected load years beginning with 2003. The model was then run
a second time with the same inputs except the loads were increased by ten average megawatts
shaped across all hours, The difference in power supply costs and the difference in megawatt
hours were then used to calculate an average monthly marginal cost per megawatt hour. Added
to this cost were the marginal fuel inventory, grossed up for cost of capital and taxes, and the
marginal variable operation and maintenance costs. This loaded energy cost was then increased
for losses at the transmission and distribution levels of service.
Generation C8pacity Marginal Costs
The annual generation capacity marginal costs were derived from data contained in Idaho
Power s 2002 IRP, Because of transmission constraints to the west of the Treasure Valley which
limits market imports, a simple cycle combustion turbine located east of Brownlee, is the most
likely marginal peaking resource needed on the system. A 61.2 MW simple cycle combustion
turbine was chosen as the next marginal peaking resource in the 2002 IRP. The investment in
dollars per kw, the fixed operating and maintenance costs, weighted cost of capital, composite tax
rate, escalation rate, and the after tax discount rate used in this analysis were all obtained from
the 2002 IRP Technical Appendix. The life of the resource (35 years) used in calculating the
carrying charge was obtained from Idaho Power s 2003 depreciation study. The materials and
supplies costs loading factors are derived from an average of five historic years data, from the
years 1998 through 2002. The revenue requirement, taxes, and the reserve margin calculations
are based on year-end 2002 information.
Seasonalization of Generation Capacity Marginal Costs
The seasonalization of the generation capacity marginal costs is based on information from the
2002 IRP and five-year historic coincidence peak (CP) data from the FERC Form 1, Using the
th percentile water and the 70th percentile load forecast information for the years 2003 to 2007
the 2002 IRP identifies June, July, August, November, and December as the months with
generation deficiencies. The monthly CP information was used to identify what portion of the
annual generation capacity marginal costs should be assigned to these months. For each month
the percentage of that monthly CP to the annual CP was calculated. These percentages were
averaged for each month for 1998 to 2002, These numbers were summed for the relevant
months and the percent for each month of the total was calculated. This method assigned a
portion of the annual generation capacity marginal costs to the months of June, July, August
November, and December.
Transmission Marginal Costs
The method of calculating the transmission marginal cost is similar to the method for calculating
the generation capacity marginal cost. The cost of integrating a new network resource to meet
native load service requirements was used. This is the cost of integrating a new gas fired
generator located within 30 miles of Boise. This cost would be approximately $92 per kw for a
230 kv line and a small amount of 138 kv line to connect to distribution voltage. These costs were
obtained from the Company s Grid Operations and Planning Department. This cost was then
treated similarly to the generation capacity marginal costs. The cost was loaded with General
Plant loadings. The economic carrying charge rate was calculated using the same inputs as the
generation capacity costs except a different asset life (50 years) was used~ The asset life was
obtained from Idaho Power s 2003 depreciation study. Operation & Maintenance and
Administrative & General loadings were added to this cost. Materials & Supplies loadings that
were derived from historic five-year averages and grossed up for revenue requirement and taxes
were then added to complete the transmission marginal cost.
Sp.asonali7ation of Transmission Marginal Costs
The 2002 lAP identifies June, July, and August as the months that transmission constraints can
be expected in future years. Since the lAP identifies these months as the ones with transmission
constraints, the marginal cost of transmission capacity was allocated to these months based on
average monthly CP as compared to the annual CP for the years 1998 to 2002 using the same
method as was used for the generation capacity marginal costs,
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IDAHO POWER COMPANY
MARGINAL COST Analysis 2003
ANNUAL GENERATION CAPACITY COST: DOLLARS PER KW
(1) Investment ($/kw)'A)
(2) General Plant Loading (1) x 1.07 (B)
(3) Economic Carrying Charge Rate (C) %
(4) A&G Loading (D) .42%
(5) Total Carrying Charge
(6) Annual Cost ($/kw) (2) x (5)
(7) Demand related fixed O&M (E)
(8) A&G loading (7) x 1.35 (F)
(9) Marginal Demand Related Costs (6) + (8)
Working Capital
(10) Materials & Supplies (2) x ,88%
(11) Revenue Requirement and Taxes for Materials & Supplies (10) x 11,91%
(12) Total Marginal Demand Related Costs (9) + (10) + (11) rounded
(13) Adjusted for reserve margin (12%)
(A) Estimated cost of a simple cycle combustion turbine, IPCo IRP Technical Appendix p. 46
(B) Average general plant loading 1998 - 2002
(C) Financial assumptions from the IPCo IRP Technical Appendix p. 46
(0) Average A & G expenses 1998 - 2002 applicable to plant related expenses
(E) Estimated cost of a simple cycle combustion turbine, IPCo IRP Technical Appendix p. 46
(F) Average A & G expenses 1998 - 2002 applicable to non-plant related expenses
$653,
$698,
92%
0.42%
34%
$58,
$6.
$9,
$73.
$6,
$0,
$81.00
$90.
IDAHO POWER COMPANY
Marginal Cost Analysis 2003
Seasonalized Generation Capacity Marginal Costs(1) (2) (3)
Monthly
% Share $$/kwlvear MarQinal
of Total* $90.72 Cost
(1) x (2 A)
19.
20,
19.
15.
15.
90,
(A)
(6)
(C)
(D)
(E)
(F)
(G)
(H)
(I)
(J)
(K)
(L)
(M)
(N)
Month
Jan
Dee
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Noy
Dee
Sum
00%
00%
00%
00%
00%
21.74%
22.82%
21.14%
00%
00%
16,78%
17.53%
100.00%
*Seasonalized based on monthly CP 1998-2002
and 2002 IRP deficit months
IDAHO POWER COMPANY
Marginal Cost Analysis 2003
Annual Transmission Marginal Costs
Dollars/kw
(1) Investment ($/kwiA)
(2) With General Plant Loading (1) x 1.07 (8)
(3) Economic Carrying Charge Rate (C) 7.10 %
(4) A&G Loading (D) .42%
(5) Total Carrying Charge
(6) Annual Cost ($/kw) (2) x (5)
(7) Demand related O&M (E)
(8) With A&G loading (7) x 1.35 (F)
(9) Marginal Demand Related Costs (6) + (8)
Working Capital
(10) Materials & Supplies (2) x ,88%
(11) Revenue Requirement and Taxes for Materials & Supplies (10) x 11.91 %(G)
(12) Total Marginal Demand Related Costs (9) + (10) + (11) Rounded
(13) Total Annual transmission marginal Costs (rounded)
(A) Estimated cost to integrate approximately 170 MW generation.
(B) Average general plant loading 1998 - 2002
(C) Financial assumptions from the IPCo lAP Technical Appendix p. 46 and the 2003 depreciation study.
(D) Average A & G expenses 1998 - 2002 applicable to plant related expenses
(E) Average 0& M loading 1998 - 2002 w/o accts. 565 & 567
(F) Average A & G expenses 1998 - 2002 applicable to non-plant related expenses
(G) December31,2002
$92.
$98.44
0.42
$7.40
$4.
$6.42
$13.
$0.
$0.
$14.
$14.
IDAHO POWER COMPANY
Marginal Cost Analysis 2003
Seasonalized Transmission Marginal Costs(1) (2) (3)
Monthl
% Share
$$/
kw ear Mar inal
of Total* 14.00 Cost
(1) x (2 A)
$0,
$0,
$0,
$0.
$0.
$4.
$4,
$4.50
$0,
$0.
$0,
$0,
$14,
(A)
(6)
(C)
(D)
(E)
(F)
(G)
(H)
(1)
(J)
(K)
(L)
(M)
(N)
Month
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dee
Sum
00%
00%
00%
00%
00%
33,09%
34,73%
32,18%
00%
00%
00%
00%
100.00%
*Seasonalized based on monthly CP 1998-2002
and 2002 lRP months with transmission constraints
IDAIIO POWER COMPANY
CASE NO. IPC-O3-
S)~CON)) PJ~ODUC1')ON REQU)~ST
)))AI-IO IR)~lGA TION PUMPEI~S ASSN.
A 1'CHMENT TO
)lESPONS)~ TO
)l)~QUES1' NO. 33
2002
INTEGRATED
,- -, -, -", -, - - -" -, - - - - - - - - - - - --- - -" - -, - - - -" -".., - - - - - - - - -, ------------------,- -".., - - -, - -. -, - -, - - - - - - - - - - --:::;j!;:::::::::::::
SEE CASE FILE FOR THIS
REPORT
'~
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Name of Respondent
Idaho Power Company
ThiS R.$I?ort I~: Date of Report(1) l25J An Original (Mo, Da, Yr)
(2) DA Resubmission 04/30/1999
MONTHLY PEAKS AND OUTPUT
1. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
2. Report in column (b) the system s energy output for each month such that the total on line 41 matches the total on line 20.
3. Report in column (c) a monthly breakdown of the Non-Requirements Sales For Resale reported on line 24. include in the monthly amounts any
energy losses associated with the sales so that the total on line 41 exceeds the amount on line 24 by the amount of losses incurred (or estimated) in
making the Non-Requirements Sales for Resale.
4. Report in column (d) the system s monthly maximum megawatt Load (60-minute integration) associated with the net energy for the system defined asthe difference between columns (b) and (c)
5, Report in columns (e) and (f) the specified information for each monthly peak load reported in column (d).
Year of Report
Dec. 31 1998
NAME OF SYSTEM:
line I Monthly Non-Requirments MONTHLY PEAKSales for Resale &
No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(e)(d)(e)
January 150 981 894 117 199 8am
February 063 378 018 389 072 8am
March 380 342 188 221 081 8am
April 088,840 091 980 967 6pm
May 617 402 484 231 981 4pm
June 714 643 563,696 553 5pm
July 109 511 400 198 747 6pm
August 695 477 223,112 593 4pm
September 955 191 821 053 458 7pm
October 945 520 861 639 918 8am
November 828 187 599 014 015 8am
December 965 312 712 618 459 8am
TOT AL 514 784 858,268
FERC FORM NO.1 (ED. 12-90)Page 401 b
This ~on Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/28/2000
MONTHLY PEAKS AND OUTPUT
1. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
2, Report in column (b) the system s energy output for each month such that the total on line 41 matches the total on line 20.
3. Report in column (c) a monthly breakdown of the Non-Requirements Sales For Resale reponed on line 24. include in the monthly amounts any
energy losses associated with the sales so that the total on line 41 exceeds the amount on line 24 by the amount of losses incurred (or estimated) in
making the Non-Requirements Sales for Resale.
4. Report in column (d) the system s monthly maximum megawatt Load (60-minute integration) associated with the net energy for the system defined as
the difference between columns (b) and (c)
5. Report in columns (e) and (f) the specified information for each monthly peak load reponed in column (d).
Year of Report
Dec. 31, 1999
Name of Respondent
Idaho Power Company
NAME OF SYSTEM:IDAHO POWER COMPANY - SYSTEM LOAD
line Monthly Non-Requirments MONTHL Y PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr.Day of Month Hour
(a)(b)(c)(d)(e)(f)
January 485,798 419 098 227 8AM
February 280 967 952 535 235 8AM
March 088,367 694 281 128 8AM
April 521 649 765,146 954 8AM
May 521 656 450 611 237 5PM
June 492 801 603,363 702 4PM
July 291,501 230,756 839 8PM
August 990,853 255 883 567 5PM
September 971,159 454 881 051 6PM
October 349 896 583,935 151 8AM
November 155 836 323,672 132 8AM
December 893 695 139,416 228 7PM
TOTAL 044 178 873,577 ~1Af\L)H~1G;)Jt~1~(:i'.;-f\Qj~;'RA;Aj;d;!~7j~~1:f:
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IOllhO Power Company
Date of Report
(Mo, Da, Yr)
04/30/2001
Year of Report
Dec. 31 2000
..-..- w' ",vo"..."u",'"
1. II the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.~, Report In column (b) the system s energy output for each month such that the total on Line 41 matches the total on Line 20.
3. Report In column (c) a monthly breakdown of the Non-Requirements Sales For Resale reported on Line 24. include in the monthly amounts any
tmorgy losses associated with the sales so that the total on Line 41 exceeds the amount on Line 24 by the amount of losses incurred (or estimated) in
milking the Non-Requirements Sales for Resale.
, Report in column (d) the system s monthly maximum megawatt Load (60-minute integration) associated with the net energy for the system defined as
the dlHerence between columns (b) and (c)
!I. Report in columns (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(I)
29 January 800 500 460 817 266 9AM
30 February 577 869 428 490 132 8AM
31 March 822 332 643,365 978 8AM
32 April 919,411 791 457 000 4PM
33 May 686 089 338 590 253 10PM
34 June 818 574 220 719 799 8PM
35 July 970,723 259 142 919 5PM
36 August 849 104 284 ,891 746 5PM
37 September 687 441 472 823 418 7PM
38 October 361 903 287 617 898 8AM
39 November 394 033 131 368 179 8AM
40 December 500,753 158,150 091 8PM
TOTAL 20,388,732 477,429
FERC FORM NO.1 (ED. 12-90)Page 401b
This ~ort Is: Date 01 Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/30/2002
MONTHLY PEAKS AND OUTPUT
1. II the respondent has two or more power systems which are not physically integrated, lurnish the required inlormation lor each non-integrated system.
2. Report in column (b) the system s energy output lor each month such that the total on Line 41 matches the total on Line 20.
3. Report in column (c) a monthly breakdown 01 the Non-Requirements Sales For Resale reported on Line 24. include in the monthly amounts any
energy losses associated with the sales so that the total on Line 41 exceeds the amount on Line 24 by the amount 01 losses incurred (or estimated) in
making the Non-Requirements Sales lor Resale.
4. Report in column (d) the system s monthly maximum megawatt Load (60-minute integration) associated with the net energy lor the system delined as
the difference between columns (b) and (c)
5. Report in columns (e) and (I) the specilied inlormation lor each monthly peak load reported in column (d).
Name 01 Respondent
Idaho Power Company
Year 01 Report
Dec. 31 2001
NAME OF SYSTEM:Idaho Power System Load
Line
Monthly Non-Requirments MONTHLY PEAK
Sales lor Resale &
No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day 01 Month Hour
(a)(b)(c)(d)(e)(f)
January 601,850 245,496 299 8AM
February 180,648 730 345 8AM
March 340,827 229,445 084 8AM
April 191,295 174 545 868 8AM
May 395,732 170,135 305 7 PM
June 477,599 167,014 496 6PM
July 661 114 260.976 570 7 PM
August 648,932 224 177 543 7 PM
September 341,171 233.758 102 5 PM
October 208,896 165.430 774 8AM
November 282,616 225.981 059 7 PM
December 431 282 194 278 030 8AM
TOTAL 16,761 962 296.965 \. t;~;i:';i::.').:;i~i;,
:;:
j'.:rl:":;;;i,:;:i.
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FERC FORM NO.1 (ED. 12-90)Page 401 b
Name of Respondent
Idaho Power Company
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/30/2003
MONTHLY PEAKS AND OUTPUT
1: II the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
2. Report in column (b) the system s energy output for each month such that the total on Line 41 matches the total on Line 20.
3. Report in column (c) a monthly breakdown of the Non-Requirements Sales For Resale reported on Line 24. include in the monthly amounts any
energy losses associated with the sales so that the total on Line 41 exceeds the amount on Line 24 by the amount of losses incurred (or estimated) in
making the Non-Requirements Sales for Resale.
4. Report in column (d) the system s monthly maximum megawatt Load (60-minute integration) associated with the net energy for the system defined as
the difference between columns (b) and (c)
5. Report in columns (e) and (f) the specified information for each monthly peak load reported in column (d).
Year of Report
Dec. 31 2002
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &
No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(1)
January 614 296 418,746 131 8AM
February 165 978 112 210 074 8AM
March 310,521 260 652 917 8AM
April 161 689 207 684 1.719 8AM
May 314 295 136 529 365 5 PM .
June 454 941 697 822 4 PM
July 687 221 813 963 4 PM
August 504 329 110,695 529 6PM
September 291 805 165 481 310 6PM
October 218,042 164 615 934 8AM
November 125,493 62,902 912 8AM
December 343,781 172 198 942 7 PM
TOTAL 16,192 391 962 222 ~l\liM~!:ITIT~i~f\~.
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IDAHO POWER COMPANY
CASE NO. IPC-O3-
SECOND PRODUCTION REQUEST
IDAHO IRRIGATION PUMPERS ASSN.
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IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPAN'
QUESTION 36
B THROUGH D YEARS 1999 THROUGH 2003
E YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Hydro Thermal Exchange
Month Day Year Time Generation Generation Suppliers In
MWH MWH MWH MWH
Jan 1999 0800 1680 709
Feb 1999 0800 1660 868
Mar 1999 0800 1695 747
Apr 1999 0800 1502 559 133
May 1999 1700 1683 765 140
Jun 1999 1600 1598 762 161
Jul 1999 2000 1436 804 157
Aug 1999 1700 1296 732 154
Sep 1999 1800 1016 827 123
Oct 1999 0800 1164 811 118
Nov 1999 0800 852 784
Dee 1999 1900 1239 871
Jan 2000 0900 1547 651
Feb 2000 0800 1544 616
Mar 2000 0800 1261 759
Apr 2000 1600 1717 436
May 2000 2200 707 533 133
Jun 2000 2000 1182 723 116
Jul 2000 1700 1454 786 119
Aug 2000 1700 886 707 127
Sep 2000 1900 1312 721 100
Oct 2000 0800 1222 844 100
Nov 2000 0800 807 955
Dee 2000 2000 552 894
Jan 2001 0800 1007 993
Feb 2001 0800 1306 980
Mar 2001 0800 902 882
Apr 2001 0800 889 694
May 2001 1900 999 782 118
Jun 2001 1800 776 980 109
Jul 2001 1900 907 996 112 100
Aug 2001 1900 1039 991 114
Sep 2001 1700 1045 972
Oct 2001 0800 689 722
Nov 2001 1900 885 1000
Dee 2001 0800 940 972
Jan 2002 0800 1262 933
Page 1 of 2
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPAN'
QUESTION 36
B THROUGH D YEARS 1999 THROUGH 2003
E YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Hydro Thermal Exchange
Month Day Year Time Generation Generation Suppliers
MWH MWH MWH MWH
Feb 2002 0800 1283 576
Mar 2002 0800 1273 889
Apr 2002 0800 1380 535
May 2002 1700 1085 698 110
Jun 2002 1600 995 751 113
Jul 2002 1600 1104 939 118 175
Aug 2002 1800 1171 901 116 129
Sep 2002 1800 1145 960 104 107
Oet 2002 0800 834 962
Nov 2002 0800 954 810
Dee 2002 1900 816 968
Jan 2003 0800 821 853
Feb 2003 0800 1345 727
Mar 2003 0800 1114 826
Apr 2003 0800 1010 661
May 2003 1700 1310 812
. Jun 2003 1800 1301 569 111
Jul 2003 1700 1217 824 119
Aug 2003 1700 1108 686 117
Sep 2003 1900 1195 728
Oet 2003 1800 794 938
Nov 2003 0900 742 1000
Dee 2003 0800 768 809
Page 2 of 2
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Dav Year Time Purchases
Seller MWH Price
Jan 2001 0800 Avista Energy, Inc.16.200
Enron Power Marketing 180.000
IPCo Non-System 114.770
IPCo Non-System 500,000
IPCo Non-System 222 185.050
IPCo Non-System 136 207.280
Feb 2001 0800 Avista Energy, Inc.16,200
IPCo Non-System 250.000
IPCo Non-System 83,860
IPCo Non-System 121 390,480
Avista Energy, Inc.16.200
Mar 2001 0800 IPCo Non-System 385 306.610
Apr 2001 0800 AEP Service Corp.230,000
Avista Energy, Inc.16.200
Enron Power Marketing 240.000
IDACORP Energy LP.145 467,370
Portland General Electric Company 230.000
May 2001 1900 AEP Service Corp.230.000
Avista Energy, Inc.16.200
Enron Power Marketing 240.000
IDACORP Energy LP.123 281.980
IDACORP Energy LP.242 426,340
Portland General Electric Company 230.000
Jun 2001 1800 AEP Service Corp.230,000
Avista Energy, Inc.16.200
Bonneville Power Administration 300.000
EI Paso Merchant Energy, LP.345,000
EI Paso Merchant Energy, LP.345.000
Enron Power Marketing 240.000
Enron Power Marketing 347,000
Enron Power Marketing 345.000
Enron Power Marketing 345.000
Enron Power Marketing 345.000
IDACORP Energy- Internal 314 77,500
IDACORP Energy LP.148 92.500
Portland General Electric Company 305,000
Portland General Electric Company 230.000
Jul 2001 1900 AEP Service Corp.142.000
AEP Service Corp.193.500
AEP Service Corp.440.000
Aquila Energy Marketing Corporation 155.000
Avista Energy, Inc.16.200
Bonneville Power Administration 300.000
EI Paso Merchant Energy, LP.195.000
Enron Power Marketing 159.000
Enron Power Marketing 155.500
Enron Power Marketing 450.000
Enron Power Marketing 450,000
IDACORP Energy- Internal 384 88,400
IDACORP Energy LP.73.570
Page 1 of 8
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Purchases
Seller MWH Price
Morgan Stanley Capital Group Inc.205.000
Portland General Electric Company 305.000
Powerex Corp.200.000
Aug 2001 1900 AEP Service Corp.142.000
AEP Service Corp.193.500
AEP Service Corp.440.000
Aquila Energy Marketing Corporation 155.000
Avista Energy, Inc.16.200
EI Paso Merchant Energy, loP.195.000
Enron Power Marketing 159.000
Enron Power Marketing 155.500
Enron Power Marketing 450.000
IDACORP Energy loP.515 58.390
Morgan Stanley Capital Group Inc.205.000
Powerex Corp.200.000
Sep 2001 1700 AEP Service Corp.440.000
AEP Service Corp.193.500
AEP Service Corp.142.000
Aquila Energy Marketing Corporation 155.000
Avista Energy, Inc.16.200
EI Paso Merchant Energy, loP.195.000
Enron Power Marketing 159.000
Enron Power Marketing 155.500
Enron Power Marketing 450.000
Enron Power Marketing 450.000
IDACORP Energy loP.29.200
Morgan Stanley Capital Group Inc.205.000
Powerex Corp.200.000
Oct 2001 0800 Bonneville Power Administration 23.790
Bonneville Power Administration 23.790
IDACORP Energy loP.424 30.580
Nov 2001 1900 Chelan Co PUD 150 29.600
IDACORP Energy loP.34.402
PG&E Energy Trading - Power LP 36.500
PG&E Energy Trading - Power LP 36.500
PG&E Energy Trading - Power LP 36.500
Reliant Energy Services, Inc,36.000
Reliant Energy Services, Inc.36.000
Reliant Energy Services, Inc.36.000
Dec 2001 0800 AEP Service Corp.49.500
AEP Service Corp.30.100
Enron Power Marketing 81.000
Enron Power Marketing 100 30.250
IDACORP Energy loP.26.556
Morgan Stanley Capital Group Inc.45.000
Public Service Co. of Colorado 45.000
Sierra Pacific Power Company 100 32.250
Jan 2002 0800 AEP Service Corp.28.750
AEP Service Corp.28.750
AEP Service Corp.28.750
Page 2 of 8
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Purchases
Seller MWH Price
AEP Service Corp.28.750
AEP Service Corp.28.750
AEP Service Corp.28.750
AEP Service Corp.28.750
AEP Service Corp.28,750
Enron Power Marketing 100 31.750
IDACORP Energy LP.374 22.170
Feb 2002 0800 IDACORP Energy LP.474 20,000
Mar 2002 0800 IDACORP Energy LP.30,290
Apr 2002 0800 IDACORP Energy LP.190 11.000
May 2002 1700 Bonneville Power Administration 22.250
Bonneville Power Administration 22,250
Bonneville Power Administration 22,250
Bonneville Power Administration 22,250
Dynegy Power Marketing, Inc.22.250
Dynegy Power Marketing, Inc.22,250
Dynegy Power Marketing, Inc.22.250
EI Paso Merchant Energy, LP.22,250
IDACORP Energy LP.167 22.300
Morgan Stanley Capital Group Inc.25.250
Morgan Stanley Capital Group Inc.22.250
Morgan Stanley Capital Group Inc.22,250
PPL Montana, LLC 25,750
Jun 2002 1600 Bonneville Power Administration 29,000
Grant County P.U.D.22,750
IDACORP Energy LP.550 18.198
IDACORP Energy LP.180 35.330
Morgan Stanley Capital Group Inc.22.750
Morgan Stanley Capital Group Inc,22.750
Morgan Stanley Capital Group Inc.27.750
Jul 2002 1600 Bonneville Power Administration 35.250
Bonneville Power Administration 35.250
Bonneville Power Administration 35.250
IDACORP Energy LP.600 15.156
Morgan Stanley Capital Group Inc,33.500
Morgan Stanley Capital Group Inc,33,500
Morgan Stanley Capital Group Inc,33.250
Morgan Stanley Capital Group Inc.33,250
Aug 2002 1800 EI Paso Merchant Energy, LP.20,750
EI Paso Merchant Energy, LP.20.750
EI Paso Merchant Energy, LP,20.750
Bonneville Power Administration 24.000
Bonneville Power Administration 24,000
Bonneville Power Administration 24,000
Puget Sound Energy, Inc.100 28.000
Tacoma Power 24,000
Sep 2002 1800 IDACORP Energy LP.21.000
PPL Montana, LLC 21,000
Puget Sound Energy, Inc.21.000
Oct 2002 0800 IDACORP Energy LP.43,000
Page 3 of 8
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Purchases
Seller MWH Price
PacifiCorp Inc.44.000
TransAlta Energy Marketing (U.) Inc.42.000
TransAlta Energy Marketing (U.) Inc.41.500
TransAlta Energy Marketing (U.) Inc.41.500
Utah Associated Municipal Power Systems 43.000
Nov 2002 0800 IDACORP Energy loP.43.630
Pinnacle West Capital Corporation 42.000
PPL Montana, LLC 42,000
Dec 2002 1900 Morgan Stanley Capital Group Inc.37.250
Morgan Stanley Capital Group Inc.36.000
Morgan Stanley Capital Group Inc.36.000
Morgan Stanley Capital Group Inc.36.000
Morgan Stanley Capital Group Inc.36.000
NorthWestern Energy, loloC.37.000
Pinnacle West Capital Corporation 38.000
Pinnacle West Capital Corporation 37.950
Portland General Electric Company 37.000
Portland General Electric Company 36.000
Portland General Electric Company 37.000
PPL Montana, LLC 42.250
PPL Montana, LLC 42.250
Tractebel Energy Marketing, Inc.36.250
Utah Associated Municipal Power Systems 37.000
Utah Associated Municipal Power Systems 34.000
Jan 2003 0800 BP Energy Company 36.000
BP Energy Company 35.500
Constellation Power Source, Inc.35.500
Morgan Stanley Capital Group Inc.42.350
Morgan Stanley Capital Group Inc.42.350
Pinnacle West Capital Corporation 42.500
PPL Montana, LLC 34.000
PPL Montana, LLC 34.000
Puget Sound Energy, Inc.35.500
Utah Associated Municipal Power Systems 32.000
Feb 2003 0800 NorthWestern Energy, loloC.48.919
Mar 2003 0800
Apr 2003 0800 Bonneville Power Administration 36.750
BP Energy Company 36.500
BP Energy Company 37.500
Coral Power, LLC 36.250
Entergy-Koch Trading, LP 36.500
Eugene Water & Electric Board 36.750
Morgan Stanley Capital Group Inc.36.750
Portland General Electric Company 36.250
Portland General Electric Company 36.250
Portland General Electric Company 37.500
PPL Montana, LLC 35.750
Puget Sound Energy, Inc.36.250
Puget Sound Energy, Inc.37.000
May 2003 1700 Arizona Public Service Co.38.000
Page 4 of 8
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Purchases
Seller MWH Price
Cargill-Alliant, LLC 30.000
Bonneville Power Administration 35.000
Public Service Company of New Mexico 100 61.000
Salt River Project 95.000
Jun 2003 1800 AEP Service Corp.29.000
AEP Service Corp.44.000
Avista Energy, Inc.43.250
Bonneville Power Administration 28.500
Bonneville Power Administration 30.000
Douglas County PUD 29.000
Morgan Stanley Capital Group Inc.29.750
Morgan Stanley Capital Group Inc.30.000
Morgan Stanley Capital Group Inc.31,000
Morgan Stanley Capital Group Inc.41.000
Morgan Stanley Capital Group Inc.42,000
Morgan Stanley Capital Group Inc.44.000
PacifiCorp Inc.30.500
PacifiCorp Inc.30.500
Portland General Electric Company 28.000
Portland General Electric Company 30.000
Portland General Electric Company 30.000
Portland General Electric Company 30.000
Portland General Electric Company 40.500
Portland General Electric Company 40.500
Portland General Electric Company 40.500
Portland General Electric Company 40.500
Portland General Electric Company 50.000
Powerex Corp.43.000
Powerex Corp.44.000
Powerex Corp.44.000
Powerex Corp.44.000
Powerex Corp.44.000
PPM Energy, Inc.31.500
Puget Sound Energy, Inc.31.500
Puget Sound Energy, Inc.32.500
Puget Sound Energy, Inc.33.500
PacifiCorp Inc.69.000
Jul 2003 1700 Arizona Public Service Co.66.500
Arizona Public Service Co.68.000
Bonneville Power Administration 41.500
Bonneville Power Administration 45.000
Bonneville Power Administration 45.250
Bonneville Power Administration 50.750
Morgan Stanley Capital Group Inc.41.200
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.42.500
Morgan Stanley Capital Group Inc.43.250
Morgan Stanley Capital Group Inc.43.250
Page 5 of 8
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Purchases
Seller MWH Price
Morgan Stanley Capital Group Inc.45.750
Morgan Stanley Capital Group Inc.54.000
Morgan Stanley Capital Group Inc.54.000
Portland General Electric Company 42.500
Portland General Electric Company 42.500
Portland General Electric Company 42.500
Portland General Electric Company 42.500
Portland General Electric Company 42.500
Portland General Electric Company 43.250
PPL Montana, LLC 48.750
PPL Montana, LLC 41.000
PPL Montana, LLC 41.000
PPL Montana, LLC 41.000
Seattle City Light 50.500
Sempra Energy Trading Corporation 44.850
Sempra Energy Trading Corporation 49.250
Portland General Electric Company 55.000
Aug 2003 1700 NorthWestern Energy, LLC,40.367
Coral Power, LLC 54.750
Coral Power, LLC 54.550
Coral Power, LLC 54.550
Coral Power, LLC 54.550
Douglas County PUD 42.500
Mirant Americas Energy Marketing, LP 42.500
Mirant Americas Energy Marketing, LP 42.500
Mirant Americas Energy Marketing, LP 42.750
Mirant Americas Energy Marketing, LP 42.750
Mirant Americas Energy Marketing, LP 42.750
Morgan Stanley Capital Group Inc.41.200
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.54.750
Morgan Stanley Capital Group Inc.47.250
Morgan Stanley Capital Group Inc.47.000
Morgan Stanley Capital Group Inc.47.000
PacifiCorp Inc.43.750
PacifiCorp Inc.43.750
PacifiCorp Inc.43.750
Portland General Electric Company 54.750
PPL Montana, LLC 42.750
PPL Montana, LLC 42.750
Public Service Co. of Colorado 43.000
Snohomish County PUD 44.000
Snohomish County PUD 44.000
TransAlta Energy Marketing (U.) Inc.52.000
TransAlta Energy Marketing (U,) Inc.52.000
Nevada Power Company 40.000
Portland General Electric Company 44.000
Page 6 of 8
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Purchases
Seller -MWH Price
PPM Energy, Inc.48,000
TransAlta Energy Marketing (U.) Inc.49,000
Sep 2003 1900 AEP Service Corp.47.000
Chelan Co PUD 46.750
Chelan Co PUD 47,000
Chelan Co PUD 47,000
Chelan Co PUD 47.000
Chelan Co PUD 47.000
Chelan Co PUD 47,250
Entergy-Koch Trading, LP 47,000
Eugene Water & Electric Board 46.750
Morgan Stanley Capital Group Inc,41,200
Morgan Stanley Capital Group Inc,40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Morgan Stanley Capital Group Inc.40.750
Powerex Corp.47.250
Powerex Corp.47.250
Powerex Corp.47.000
Powerex Corp.47,000
Sierra Pacific Power Company 47.000
Snohomish County PUD 47,000
Tractebel Energy Marketing, Inc.47.250
TransAlta Energy Marketing (U.) Inc.46.750
Bonneville Power Administration 52,000
Bonneville Power Administration 52,000
Bonneville Power Administration 52.000
Oct 2003 1800 NorthWestern Energy, LLC.38.031
AEP Service Corp.40.750
AEP Service Corp.40.750
AEP Service Corp.40.700
Bonneville Power Administration 40.750
PacifiCorp Inc,100 36.000
PPL Montana , LLC 36.000
Public Service Company of New Mexico 36.000
Nov 2003 0900 Cargill Power Markets LLC 39.750
Douglas County PUD 39.500
NorthWestern Energy, LLC.37,259
PPL Montana, LLC 38,000
PPL Montana, LLC 38.000
Tractebel Energy Marketing, Inc.41.500
Tractebel Energy Marketing, Inc.41,500
Tractebel Energy Marketing, Inc.41.500
TransAlta Energy Marketing (U.) Inc.41.500
Dec 2003 0800 AEP Service Corp.43.500
Arizona Public Service Co.45.000
Coral Power, LLC 41.750
Coral Power, LLC 41.750
Coral Power, LLC 41.750
Page 7 of 8
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 F
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Time PurchasesDavYear
Seller
Coral Power, LLC
Eugene Water & Electric Board
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Morgan Stanley Capital Group Inc.
Powerex Corp.
Powerex Corp.
PPL Montana, LLC
PPL Montana, LLC
PPL Montana, LLC
PPM Energy, Inc.
PPM Energy, Inc.
PPM Energy, Inc.
Silicon Valley Power
Silicon Valley Power
TransAlta Energy Marketing (U.) Inc.
Page 8 of 8
MWH Price
44.250
49.250
59.250
46.000
46.000
46.000
46.000
41.500
41.500
41.250
48.000
46.750
46.750
41.000
41.000
41.000
55.000
55.000
42.000
46.000
46.000
44.500
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 G
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Sales
Purchaser MWH Price
Jan 2001 0800 EI Paso Merchant Energy, L.P.(25)193.000
Enron Power Marketing (50)15.900
Enron Power Marketing (25)210.000
Enron Power Marketing (25)215,000
Sierra Pacific Power Company (25)195,000
Oregon Trail Electric Consumers Coop (10)18,640
Oregon Trail Electric Consumers Coop (1)18,970
Colton , City of (3)25.480
Utah Associated Municipal Power Systems (10)14.625
Utah Associated Municipal Power Systems (8)14.625
Utah Associated Municipal Power Systems (25)14,625
Utah Associated Municipal Power Systems (3)14,625
Utah Associated Municipal Power Systems (4)14,625
Washington, UT, City of (7)14,625
Feb 2001 0800 EI Paso Merchant Energy, L.P.(25)193,000
Enron Power Marketing (50)15,900
Enron Power Marketing (25)210.000
Enron Power Marketing (25)215,000
Sierra Pacific Power Company (25)195,000
Oregon Trail Electric Consumers Coop (10)18.640
Oregon Trail Electric Consumers Coop (1)18.970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (1)14.625
Utah Associated Municipal Power Systems (20)14.625
Utah Associated Municipal Power Systems (8)14,625
Washington, UT, City of (8)14.625
Mar 2001 0800 EI Paso Merchant Energy, L.P.(25)193,000
Enron Power Marketing (50)15,900
Enron Power Marketing (25)210,000
Enron Power Marketing (25)215,000
IDACORP Energy L.P.(108)325.000
Sierra Pacific Power Company (25)195.000
Oregon Trail Electric Consumers Coop (10)18,640
Oregon Trail Electric Consumers Coop (1)18,970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (12)14,625
Utah Associated Municipal Power Systems (4)14.625
Utah Associated Municipal Power Systems (8)14.625
Washington, UT, City of (3)14.625
Washington, UT, City of (3)14.625
Apr 2001 0800 Enron Power Marketing (50)15,900
IDACORP Energy L.P.(75)303,520
Oregon Trail Electric Consumers Coop (10)18,640
Oregon Trail Electric Consumers Coop (1)18.970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (31)14.625
Washington, UT, City of (2)14.625
Washington, UT, City of (3)14,625
May 2001 1900 Enron Power Marketing (50)15.900
Oregon Trail Electric Consumers Coop (10)18.640
Page 1 of 6
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 G
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Dav Year Time Sales
Purchaser MWH Price
Oregon Trail Electric Consumers Coop (1)18.970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (25)14.625
Utah Associated Municipal Power Systems (4)14.625
Utah Associated Municipal Power Systems (5)14.625
Utah Associated Municipal Power Systems (5)14,625
Utah Associated Municipal Power Systems (10)14,625
Utah Associated Municipal Power Systems (2)14.625
Washington , UT , City of (10)14.625
Jun 2001 1800 Enron Power Marketing (50)15.900
Oregon Trail Electric Consumers Coop (10)18.640
Oregon Trail Electric Consumers Coop (1)18.970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (18)14.625
Utah Associated Municipal Power Systems (4)14.625
Utah Associated Municipal Power Systems (25)14.625
Utah Associated Municipal Power Systems (17)87.120
Washington, UT, City of (12)14.625
Jul 2001 1900 AEP Service Corp.(25)480.000
Aquila Energy Marketing Corporation (25)155.000
Avista Corp. - WWP Div.(25)159.000
Enron Power Marketing (25)18.400
Enron Power Marketing (25)155.000
Enron Power Marketing (25)143.000
Enron Power Marketing (25)481.000
Enron Power Marketing (50)481.000
Oregon Trail Electric Consumers Coop (10)18.640
Oregon Trail Electric Consumers Coop (1)18.970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (17)90.310
Utah Associated Municipal Power Systems (45)14.625
Utah Associated Municipal Power Systems (25)14.625
Washington , UT, City of.(13)14.625
Aug 2001 1900 AEP Service Corp.(25)480.000
Aquila Energy Marketing Corporation (25)155.000
Avista Corp. - WWP Div.(25)159.000
Enron Power Marketing (25)18.400
Enron Power Marketing (25)155.000
Enron Power Marketing (25)143.000
Enron Power Marketing (25)481.000
Enron Power Marketing (50)481.000
IDACORP Energy L.P.(211)62.880
Oregon Trail Electric Consumers Coop (1)18.970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (17)72.440
Utah Associated Municipal Power Systems (65)14.625
Washington, UT, City of (14)14.625
Sep 2001 1700 AEP Service Corp.(25)480.000
Aquila Energy Marketing Corporation (25)155.000
Avista Corp. - WWP Div.(25)159.000
Enron Power Marketing (25)18.400
Page 2 of 6
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 G
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Dav Year Time Sales
Purchaser MWH Price
Enron Power Marketing (25)155,000
Enron Power Marketing (25)143.000
Enron Power Marketing (75)481.000
IDACORP Energy L.P.(135)40.719
Oregon Trail Electric Consumers Coop (1)18.970
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (54)14.625
Utah Associated Municipal Power Systems (15)14.625
Utah Associated Municipal Power Systems (6)14,625
Utah Associated Municipal Power Systems (17)33,370
Washington, UT, City of (12)14.625
Oct 2001 0800 AEP Service Corp,(25)42.500
IDACORP Energy L,(30)24.540
Morgan Stanley Capital Group Inc.(50)38.000
Morgan Stanley Capital Group Inc.(25)38.000
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (13)14,625
Utah Associated Municipal Power Systems (15)14.625
Utah Associated Municipal Power Systems (7)14.625
Washington, UT, City of (6)14.625
Nov 2001 1900 IDACORP Energy L.P.(65)23.900
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (30)14.625
Utah Associated Municipal Power Systems (8)14.625
Washington, UT, City of (7)14.625
Dec 2001 0800 Enron Power Marketing (100)32.000
Enron Power Marketing (50)30.000
IDACORP Energy L.P,(26)23.390
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (41)14,625
Utah Associated Municipal Power Systems (8)14.625
Washington , UT, City of (7)14.625
Jan 2002 0800 Enron Power Marketing (100)28.750
IDACORP Energy L.P.(414)16.552
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (8)14.625
Utah Associated Municipal Power Systems (42)14.625
Washington, UT, City of (9)14.625
Feb 2002 0800 IDACORP Energy L.(107)15.952
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (21)14.625
Utah Associated Municipal Power Systems (8)14.625
Washington, UT, City of (9)14.625
Mar 2002 0800 IDACORP Energy L.P.(403)22.684
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (17)14.625
Utah Associated Municipal Power Systems (7)14,625
Washington, UT, City of (7)14.625
Apr 2002 0800 AEP Service Corp.(25)23.500
Dynegy Power Marketing, Inc.(25)23.500
Dynegy Power Marketing, Inc.(25)23.500
Page 3 of 6
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 G
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Sales
Purchaser MWH Price
IDACORP Energy LP.(205)12.610
Williams Energy Marketing & Trading Camp (25)23.500
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (32)14.625
Utah Associated Municipal Power Systems (7)14.625
Utah Associated Municipal Power Systems (1)14.625
Washington, UT, City of (5)14.625
May 2002 1700 Colton, City of (3)25.480
IDACORP Energy LP,(80)14.276
Utah Associated Municipal Power Systems (45)14.625
Utah Associated Municipal Power Systems (10)14.625
Utah Associated Municipal Power Systems (2)14,625
Washington, UT, City of (9)14.625
Jun 2002 1600 Colton, City of (3)25.480
Utah Associated Municipal Power Systems (18)47.060
Utah Associated Municipal Power Systems (45)14.625
Washington, UT, City of (13)14.625
Jul 2002 1600 IDACORP Energy LP,(188)10.000
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (6)56.030
Utah Associated Municipal Power Systems (12)56.030
Utah Associated Municipal Power Systems (66)14.625
Aug 2002 1800 Chelan Co PUD (25)36.500
IDACORP Energy LP.(22)22.320
Morgan Stanley Capital Group Inc.(25)36.500
Morgan Stanley Capital Group Inc,(25)36.500
Pinnacle West Capital Corporation (50)25.750
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (71)14.625
Utah Associated Municipal Power Systems (5)37.930
Utah Associated Municipal Power Systems (13)37.930
Sep 2002 1800 Colton, City of (3)25.480
Utah Associated Municipal Power Systems (5)32.810
Utah Associated Municipal Power Systems (12)32.810
Utah Associated Municipal Power Systems (1)32.810
Utah Associated Municipal Power Systems (71)14.625
Oct 2002 0800 AEP Service Corp.(25)26.750
Pinnacle West Capital Corporation (25)28.750
Utah Associated Municipal Power Systems (29)14.625
Utah Associated Municipal Power Systems (7)14.625
Nov 2002 0800 Colton , City of (3)25.480
Utah Associated Municipal Power Systems (25)14.625
Utah Associated Municipal Power Systems (7)14.625
Dec 2002 1900 BP Energy Company (25)37.950
IDACORP Energy LP.(13)43.050
Portland General Electric Company (25)38.000
Portland General Electric Company (25)38.000
Portland General Electric Company (25)38.000
Morgan Stanley Capital Group Inc.(25)43.250
Morgan Stanley Capital Group Inc.(25)42.000
Sempra Energy Trading Corporation (25)42.000
Page 4 of 6
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 G
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Dav Year Time Sales
Purchaser MWH Price
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (15)14,625
Utah Associated Municipal Power Systems (5)14.625
Utah Associated Municipal Power Systems (30)14.625
Utah Associated Municipal Power Systems (10)14.625
Utah Associated Municipal Power Systems (1)14,625
Jan 2003 0800 NorthWestern Energy, LLC.(25)36.788
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (35)14.625
Utah Associated Municipal Power Systems (7)14,625
Utah Associated Municipal Power Systems (8)14.625
Feb 2003 0800 Arizona Public Service Co.(50)43.000
Arizona Public Service Co.(25)43.000
Colton , City of (3)25.480
Utah Associated Municipal Power Systems (25)14.625
Utah Associated Municipal Power Systems (8)14.625
Mar 2003 0800 Duke Energy Trading and Marketing, LLC (25)75,000
Morgan Stanley Capital Group Inc.(25)33.250
Morgan Stanley Capital Group Inc.(25)42.250
Morgan Stanley Capital Group Inc.(20)66.000
Morgan Stanley Capital Group Inc.(5)66.000
Portland General Electric Company (25)32,500
Powerex Corp.(25)32.750
Powerex Corp,(25)32,800
NorthWestern Energy, LLC.(21)73,805
Colton , City of (3)25.480
Utah Associated Municipal Power Systems (17)14.625
Apr 2003 0800 Arizona Public Service Co.(75)30.000
BP Energy Company (25)46.750
Duke Energy Trading and Marketing, LL,(25)47.250
Duke Energy Trading and Marketing, LLC (25)67,000
Morgan Stanley Capital Group Inc.(25)40.500
Morgan Stanley Capital Group Inc.(25)43.250
Morgan Stanley Capital Group Inc.(25)66.000
Portland General Electric Company (25)41.250
Portland General Electric Company (25)47.250
Portland General Electric Company (25)47.200
Portland General Electric Company (25)66.750
NorthWestern Energy, LLC.(7)37.855
Colton
, .
City of (2)25.480
Colton, City of (1)25.480
May 2003 1700 Arizona Public Service Co.(25)50.000
Cargill-Alliant , LLC (25)31.000
Entergy-Koch Trading, LP (25)36.750
Entergy-Koch Trading, LP (25)37.500
Morgan Stanley Capital Group Inc.(25)38.000
Morgan Stanley Capital Group Inc.(25)37.750
PacifiCorp Inc.(25)37.250
Powerex Corp.(25)36.500
NorthWestern Energy, LLC.(25)38.591
Colton, City of (2)25.480
Page 5 of 6
IDAHO IRRIGATION PUMPERS SECOND DATA REQUEST TO IDAHO POWER COMPANY
QUESTION 36 G
YEARS 2001 THROUGH 2003 (HOURLY DATA NOT AVAILABLE PRIOR TO 2001)
Month Day Year Time Sales
Purchaser MWH Price
Colton, City of (1)25.480
Utah Associated Municipal Power Systems (35)14.625
Utah Associated Municipal Power Systems (10)14.625
Jun 2003 1800 NorthWestern Energy, L.L.C.(14)38.632
Colton, City of (2)25.480
Colton, City of (1)25.480
Utah Associated Municipal Power Systems (48)14.625
Jul 2003 1700 Colton, City of (2)25.480
Colton, City of (1)25.480
Utah Associated Municipal Power Systems (52)14.625
Utah Associated Municipal Power Systems (13)14.625
Utah Associated Municipal Power Systems (10)14.625
Aug 2003 1700 Morgan Stanley Capital Group Inc.(25)49.500
Morgan Stanley Capital Group Inc.(25)50.000
Morgan Stanley Capital Group Inc.(25)50.000
Portland General Electric Company (25)49.750
Powerex Corp.(25)50.250
Colton, City of (1)25.480
Colton, City of (2)25.480
Utah Associated Municipal Power Systems (52)14.625
Utah Associated Municipal Power Systems (13)14.625
Utah Associated Municipal Power Systems (10)14.625
Sep 2003 1900 Coral Power, LLC (25)54.250
Coral Power, LLC (25)54.250
Morgan Stanley Capital Group Inc.(25)46.000
Morgan Stanley Capital Group Inc.(25)47.000
Pacific Northwest Generating Cooperative (25)47.000
Portland General Electric Company (25)47.000
Portland General Electric Company (25)47.500
TransAlta Energy Marketing (U.) Inc.(25)51.400
NorthWestern Energy, L.L,(10)48.941
Colton, City of (3)25.480
Utah Associated Municipal Power Systems (10)14.625
Utah Associated Municipal Power Systems (56)14.625
Oct 2003 1800 Arizona Public Service Co.(50)48.000
Arizona Public Service Co.(50)47.000
Arizona Public Service Co.(25)45.000
Arizona Public Service Co.(25)45.000
Morgan Stanley Capital Group Inc.(25)46.500
Morgan Stanley Capital Group Inc.(25)46.500
Morgan Stanley Capital Group Inc.(25)46.500
PPM Energy, Inc.(25)48.750
Sempra Energy Trading Corporation (9)45.730
Colton, City of (2)25.480
Utah Associated Municipal Power Systems (32)14.625
Nov 2003 0900 Colton, City of (2)25.480
Utah Associated Municipal Power Systems (25)14.625
Dec 2003 0800 Arizona Public Service Co.(50)54.000
Colton, City of (2)25.480
Utah Associated Municipal Power Systems (43)14.625
NorthWestern Energy, L.L.C.(14)43.844
Page 6 of 6
IDAHO POWER COMPANY
CASE NO. IPC-O3-
SECOND PRODUCTION REQUEST
IDAHO IRRIGATION PUMPERS ASSN.
TT A CHMENT TO
RESPO NSE TO
REQUEST NO. 45
IMHO
POWER
IDAHO POWER COMPANY
O, BOX 70
BOISE. IDAHO 83707
-----..----
[phone]
FAX (208) 38U936Joim R. Gale
. Manqer, PridD& It Replatol')' Senkes
April1 1997
Mrs. Myrna J. Walters
Secretary
Idaho Public Utilities Commission
PO Box 83720
Boise, 10 83720-0074
RE:Class Cost of Service Study
Compliance Filing per Order No. 25880
Dear Mrs. Walters:
Please find enclosed for filing an original and seven copies of Idaho Power
Company current Class Cost-Of-Service study pursuant to Order No. 25880. The
methodology utilized in the study is consistent with that which was used in the originaIIPC-
94-5 case and reflects Commission ordered adjustments in that case as well as the
adjustments associated with the Twin Falls tracker filing, Case No. IPC-95-5. I specifically
call to your attention that in order to reflect the authorized base revenue requirement for FMC
the D10 demand allocator was adjusted to match Mr. Hessing s results in IPC-94-
If you have any questions regarding this filing, please give me a call.
Cordially,
!~oh:!.1
JRG:ma
Enclosures
IPC-94-5 Service List
Keith Hessing, IPUC
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this day of April 1997, I served a true and correct copy
of the within and foregoing IDAHO POWER COMPANY CLASS COST OF SERVICE STUDY
upon the parties of record by the method indicated below, and addressed to the following:
Mr. Brad Purdy
Deputy Attorney General
472 West Washington Street
Boise, Idaho 83702
Hand Delivered
--L U,S. Mail
Overnight Mail
FAX [phone]
Peter J. Richardson, Esq.
DAVIS WRIGHT TREMAINE
999 Main Street - Suite 911-
Boise, Idaho 83702-90112
Hand Delivered
-2L U,S. Mail
Overnight Mail
FAX [phone]
Mr. Randall C. Budge, Esq.
RACINE OLSON NYE COOPER & BUDGE
201 East Center Street - Suite A2
Pocatello, Idaho 83204-1391
Hand Delivered
-2L U.S. Mail
Overnight Mail
FAX [phone]
Lawrence A. Gollomp
S. Department of Energy - Room 6D-003
1000 Independence Avenue Southwest
Washington D. C. 20585
Hand Delivered
-2L U.S. Mail
Overnight Mail
FAX [phone]
Conley Ward, Esq.
GIVENS PURSLEY & HUNTLEY
277 North 6th Street - Suite 200
PO Box 2720
Boise, Idaho 83701-2710
Hand Delivered
-2L U.S. Mail
Overnight Mail
FAX [phone]
Mr. Ronald L. Williams
Attorney at Law
PO Box 2128
Boise, Idaho 83702-1368
Hand Delivered
-2L U.S. Mail
Overnight Mail
FAX [phone]
John J, McFadden
MOORE & MCFADDEN, Chrtd.
999 Main Street - Suite 910
Boise, Idaho 83702
Hand Delivered
-L U.S. Mail
Overnight Mail
FAX [phone]
Alan Richey, Esq.
MICRON TECHNOLOGY, INC.
8000 South Federal Way - PO Box 6
Boise, Idaho 83707-0006
Hand Delivery
-L U.S. Mail
Overnight Mail
FAX [phone]
IDAHO POWER COMPANY
COMPLIANCE FILING
CLASS COST OF SERVICE STUDY
APRIL 1, 1997
IDAHO POWER COMPANY
COMPLIANCE FILING
CLASS COST OF SERVICE STUDY
INDEX
FUNCTIONALIZA TION AND CLASSIFICATION OF COSTS
SUMMARY OF FUNCTIONALIZED COSTS
ALLOCATION TO CLASSES
WEIGHTED DEMAND AND ENERGY ALLOCA TORS
REVENUE REQUIREMENT SUMMARY
1 - 125
126 - 128
129 -166
167 - 175
176 - 177
IDAHO POWER COMPANY
COMPLIANCE FILING
FUNCTIONALIZA TION AND
CLASSIFICATION OF COSTS
APRIL 1, 1997
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