20051219IPC response to 1st ICIP request.pdf

8:8 IDAHO POWER COMPANY
O. BOX 70
BOISE, IDAHO 83707
BARTON L. KLINE
Senior Attorney
An IDACORP Company
December 16, 2005
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Jean D. Jewell , Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise , Idaho 83720-0074
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Re:Case No. IPC-05-
Idaho Power Company s Response to the
First Production Request of the Industrial
Customers of Idaho
Dear Ms. Jewell:
Please find enclosed for filing an original and two (2) copies of the
Company s Response to the First Production Request of the Industrial Customers of
Idaho Power regarding the above-described case.
I would appreciate it if you would return a stamped copy of this transmittal
letter to me in the enclosed self-addressed stamped envelope.
Barton L. Kline
BLK:jb
Enclosures
Telephone [phone] Fax [phone], E-mail BKline&Jidahopower.com
BARTON L. KLINE ISB #1526
MONICA B. MOEN ISB #5734
Idaho Power Company
O. Box 70
Boise, Idaho 83707
Telephone: [phone]
FAX Telephone: [phone]
BKline (Q? idahopower.com
MMoen (Q? idahopower.com
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Attorneys for Idaho Power Company
Street Address for Express Mail
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS BASE
RATES AND CHARGES FOR ELECTRIC
SERVICE IN THE STATE OF IDAHO
CASE NO. IPC-05-
IDAHO POWER COMPANY'
RESPONSE TO FI RST PRODUCTION
REQUEST OF INDUSTRIAL
CUSTOMERS OF IDAHO POWER
COMES NOW, Idaho Power Company ("Idaho Power" or "the Company
and in response to the First Data Request of the Industrial Customers of Idaho Power to
Idaho Power Company dated November 28, 2005 , herewith submits the following
information:
REQUEST NO.1: Please provide any and alllPC data and analyses
regarding the impact of time of use rates has had on its Schedule 19 customers since they
were implemented. If no such analysis has been conducted by the Company please
explain why not.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page
RESPONSE TO REQUEST NO.1: Idaho Power has not conducted any
analyses regarding the impact of time-of-use rates on its Schedule 19 customers since
these rates were implemented. At the time Idaho Power began preparing its general rate
case , which was filed on October 28, 2005 , the Schedule 19 time-of-use rates had been in
place for only about six or seven months. This short period of time provides limited data for
analysis. Given the limited data available and the decision that the Company would
propose a uniform increase for each of the time-of-use periods for customers taking
service under Schedule 19 at each of the three service levels, it was decided that an
analysis of any impact of time-of-use rates on Schedule 19 customers would be neither
meaningful nor necessary in this case.
In response to a production request from the Oregon Industrial Customers of
Idaho Power in Idaho Power s Oregon general rate case filed in September, 2004 , Docket
No. UE 167, a bill comparison was done for the Idaho Schedule 19 customers in
aggregate for January 2005. This bill comparison compared January 2005 Schedule 19
total bills under the flat rates that were in effect until December 1 , 2004 and the time-of-
use rates that went into effect on December 1 , 2004. This bill comparison showed that in
aggregate Schedule 19 customers' total charges were $559 less under the time-of-use
rates. The source data for this bill comparison is no longer available.
The response to this request was prepared by Peter Pengilly, Senior
Analyst, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney,
Idaho Power Company.
REQUEST NO.2: On page 20 of Maggie Brilz Direct Testimony she
states the Company s marginal cost study has been updated since Case No. I PC-
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 2
03-13. A copy of that update has been provided in Ms. Brilz s workpapers. Please
provide a copy of the Company s marginal cost study used in Case No. IPC-03-13.
RESPONSE TO REQUEST NO.2: The marginal cost analysis used in
Case No. IPC-03-13 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.
REQUEST NO.3: On page 21 of Maggie Brilz Direct Testimony she states
Since the conclusion of the Company s last general rate case it has
been determined that the deficit months of June, July, August, November, and
December used in the 2003 marginal cost analysis were primarily determined by
firm generation supply acquisition needs rather than determination of months in
which peak-hour deficiency occurred. The deficit months of January, May, June
July, August, September, November, and December used in the current marginal
cost analysis are directly tied to peak-hour deficiency months identified in the 2004
IRP.
Please explain in greater detail the change in the philosophy for defining
deficit months. Please explain why the Company feels this change is necessary. Please
explain why the deficit months would not be the same months as when the Company
would be need to purchase firm generation supply.
RESPONSE TO REQUEST NO.3: The Company relies on its Integrated
Resource Plan (IRP) to identify months where capacity and/or energy deficiencies occur.
This "philosophy" has not changed. Based upon the 2000 IRP, the Company targeted
acquisition of seasonal firm generation resources through an RFP geared to address the
Company s identified resource needs. Subsequent to the Company s last general rate
case it was determined that the 2003 marginal cost analysis utilized as deficit months the
same months as those for which the Company was seeking to acquire new firm
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 3
generation supply rather than the deficit months identified in the 2002 IRP. The use of the
deficit months for which the Company was seeking to acquire new firm generation supply
rather than the deficit months identified in the 2002 IRP was not intentional.As stated in
the testimony of Company witness Ms. Brilz, the deficit months used in the 2005 marginal
cost analysis are directly tied to the peak-hour deficiencies identified in the 2004 IRP.
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.4: Schedule 1 of Idaho Power s marginal cost study filed
with Maggie Brilz s workpapers are values for the Marginal Generation Cost at Generation.
TDese vqlueswere developed from the Aurora Power Supply Model 2005 to 2009. PI~ase
provide:
Copies of the model output that were used to find these values
All model input assumptions used to find these values
All formula and algorithms used to find these values
Is the same model run used to find these values the same model run
used to find normalized power supply values found in Exhibit 20?
RESPONSE TO REQUEST NO.a: As described in the Company
marginal cost analysis , submitted as workpapers by Ms. Brilz, the marginal generation
cost at generation was produced from the results of AURORA model runs for the years
2005 through 2009. Both a base case and a case with a 50 megawatt increase in load
were run. Attached to this response are the results of these runs. Included also is the
report that summarizes the monthly totals by year and the average of the five years.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 4
RESPONSE TO PRODUCTION REQUEST b: Idaho Power Company
is prevented by its license agreement with EPIS from furnishing the Aurora input
databases to those who are not licensed users of Aurora. We can , however, provide
Idaho Power Company input data that was used in the simulations. This data is
attached. Some of the data is entered into the model as shown , while other data is
used to develop factors in a format accepted by Aurora.
To ensure compliance with FERC's Standards of Conduct , the
transmission inputs , in addition to being provided in the response to this production
request, are posted on the Idaho Power Company OASIS in the folder entitled 2005
Idaho Retail Rate Case Documents.
RESPONSE TO PRODUCTION REQUEST 4 c: Idaho Power Company
is prevented by its license agreement with EPIS from furnishing the Aurora formulas
and algorithms that produced the model results to persons that are not licensed users of
Aurora.
RESPONSE TO PRODUCTION REQUEST d: As stated in Ms Brilz
work papers:
The marginal cost of energy was determined from the
simulated operation of the Company s power supply system for
the five-year period 2005 through 2009. Base case net power
supply expenses were quantified and the model was run a
second time with fifty megawatts of load added across all
hours.
And:
Test year net power supply expenses , which are the
average of expenses developed over 78 stream flow conditions
were used for the 2005 base.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 5
The same run was used for both the development of test year net power supply
expenses shown on Exhibit 20 and the 2005 base values used in the development of
marginal energy cost.
The response to this request was prepared by Maggie Brilz, Director of
Pricing and Gregory W. Said, Director of Revenue Requirement, Idaho Power
Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO.5: On page 4 of Greg Said's Direct Testimony he states
Under my supervision and at my request power supply
simulation that is representative of the test year 2005 power supply
expenses associated with 78 separate water conditions was prepared.
These are the same values found in Exhibit 20. Please provide:
Copies of the model output that were used to find these values
All model input assumptions used to find these values
All formula and algorithms used to find these values
Is the model run used to find these values the same model run used
to find Marginal Generation Cost at Generation used in the marginal
cost study provided in Maggie Brilz s workpapers?
RESPONSE TO REQUEST NO.a: Pages 2 through 79 of Exhibit 20 is
the model output, formatted by an Excel macro into the report as seen in the exhibit. Page
1 of Exhibit 20 is the average of the following 78 pages of the report and is also produced
by the macro.
RESPONSE TO REQUEST NO.5 b: Idaho Power Company is prevented
by its license agreement with EPIS from furnishing the Aurora input databases to those
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 6
who are not licensed users of Aurora. We can , however, provide Idaho Power Company
input data that was used in the simulations. That information is attached.
To ensure compliance with FERC's Standards of Conduct, the transmission
inputs, in addition to being provided in the response to this production request, are posted
on the Idaho Power Company OASIS in the folder entitled 2005 Idaho Retail Rate Case
Documents.
RESPONSE TO PRODUCTION REQUEST NO.c: Idaho Power
Company is prevented by its license agreement with EPIS from furnishing the Aurora
formulas and algorithms that produced the results shown on Exhibit 20 to persons that
are not licensed to use AURORA.
RESPONSE TO PRODUCTION REQUEST NO.d: As stated in the
marginal cost study provided in Ms Brilz' work papers:
The marginal cost of energy was determined from the
simulated operation of the Company s power supply system for
the five-year period 2005 through 2009. Base case net power
supply expenses were quantified and the model was run a
second time with fifty megawatts of load added across all
hours.
And:
Test year net power supply expenses, which are the average of
expenses developed over 78 stream flow conditions , were used for
the 2005 base.
The same run was used for both the development of test year net power supply
expenses shown on Exhibit 20 and the 2005 base values used in the development of
marginal energy cost.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 7
The response to Request No.5 was prepared by Maggie Brilz, Director of
Pricing and Gregory W. Said , Director of Revenue Requirement , Idaho Power
Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power Company.
REQUEST NO.6: Please provide copies of all of Dr. Avera s prefiled
testimony before any public utility commission in the United States on the issue of cost of
capital in the last five years.
RESPONSE TO REQUEST NO.6: Electronic copies of all of the prefiled
testimony are included on the enclosed CD labeled "First Production Request of ICIP
Response No.
The response to this request was prepared by Dennis C. Gribble , Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO.7: Please provide a copy of the research report referenced
by Mr. Gribble at page 8 of his prefiled testimony.
RESPONSE TO REQUEST NO.7: A copy of the requested research report
is attached.
The response to this request was prepared by Dennis C. Gribble, Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO.8: Please provide a copy of the research report referenced
by Mr. Gribble at page 9 of his prefiled testimony.
RESPONSE TO REQUEST NO.8: A copy of the requested research report
is attached to this response.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 8
The response to this request was prepared by Dennis C. Gribble , Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO.9: Please provide a copy of the summary opinion update
referenced on page 13 of Mr. Gribble s prefiled testimony.
RESPONSE TO REQUEST NO.9: A copy of the requested information is
attached to this response.
The response to this request was prepared by Dennis C. Gribble, Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO.1 0: Please provide a copy of the research report
referenced by Mr. Gribble on page 14 of his testimony.
RESPONSE TO REQUEST NO.0: The requested information is attached
to this response.
The response to this request was prepared by Dennis C. Gribble, Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO. 11: Please provide a copy of the publication referenced by
Mr. Gribble on page 19 of his prefiled testimony.
RESPONSE TO REQUEST NO. 11: The requested information is attached
to this response.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 9
The response to this request was prepared by Dennis C. Gribble , Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO. 12: Please provide the documentation supporting Mr.
Gribble s assertion at page 16 of his prefiled testimony to the effect that "The mere dollar
for dollar recovery of QF expenditures , but no return for the use of the Company s balance
sheet and liquidity in managing QF programs, is viewed as a significant risk by the rating
agencies.
RESPONSE TO REQUEST NO. 12: In addition to Mr. Gribble s knowledge
and experience dealing with rating agencies, the article provided for the Response to
Request No. 11 ("Buy Versus Build": Debt Aspects of Purchased-Power Agreements)
supports Mr. Gribble s testimony on this issue.
The response to this request was prepared by Dennis C. Gribble, Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
REQUEST NO. 13: Please provide the construction budgets referenced at
page 15 of Mr. Gribble s prefiled testimony.
RESPONSE TO REQUEST NO. 13: The 2005 2nd Quarter 10Q page
referencing the construction budget is attached to this response.
The response to this request was prepared by Dennis C. Gribble, Vice
President & Treasurer, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 10
DATED this 16th day of December, 2005.
BARTON .. KLINE
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION
REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 11
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IDAHO POWER COMPANy's C()Tt\isslO::
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
OF IDAHO POWER
ATTACHMENT TO
RESPONSE TO
REQUEST NO.
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PONE R
IDAHO POWER COMPANY
O. BOX 70
BOISE, IDAHO B3707
An IDACORP Companv
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Pete Pengilly
Senior Analyst
Pricing Regulatory Services
Chq-
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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 Co!=;t 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 Capacity Marginal Costs
The annual "generation capacity marginal costs were derived from data contained in Idaho
Power s 2002 lAP. 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 lAP. 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 lAP 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.
Seasonali78tion of Generation Capacity Marginal Costs
The seasonalization of the generation capacity marginal costs is based on information from the
2002 lAP 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 lAP 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.
Tmnsmission 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 $92 per kw for a
230 kv line and a small amount of 138 kv line to connect to distribution voltage. These costs were
obtained from the Company s Grid Operations and Planning Department. This cost was then
treated similarly to the generation capacity marginal costs. The cost was loaded with General
Plant loadings. The economic carrying charge rate was calculated using the same inputs as the
generation capacity costs except a dif1erent asset life (50 years) was used. The asset life was
obtained from Idaho Power s 2003 depreciation study. Operation & Maintenance and
Administrative & General loadings were added to this cost. Materials & Supplies loadings that
were derived from historic five-year averages and grossed up for revenue requirement and taxes
were then added to complete the transmission marginal cost.
Seasonali7ation of Transmission Marginal Costs
The 2002 IRP identifies June, July, and August as the months that transmission constraints can
be expected in future years. Since the IRP identifies these months as the ones with transmission
constraints, the marginal cost of transmission capacity was allocated to these months based on
average monthly CP as compared to the annual CP for the years 1998 to 2002 using the same
method as was used for the generation capacity marginal costs.
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IDAHO POWER COMPANY
MARGINAL COST Analysis 2003
ANNUAL GENERATION CAPACITY COST: DOLLARS PER KW
(1) Investment ($/kw)(A)
(2) General Plant Loading (1) x 1.07 (B)
(3) Economic Carrying Charge Rate (C) %
(4) A&G Loading
(0) .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%)
IA) Estimated cost 01 a simple cycle combustion turbine, IPCo lAP Technical Appendix p. 46
(6) Average general plant loading 1998 - 2002
IC) Financial assumptions Irom the IPCo lAP Technical Appendix p. 46
(D) Average A & G expenses 1998 - 2002 applicable to plant related expenses
(E) Estimated cost 01 a simple cycle combustion turbine, IPCo lAP 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
0/0 Share $$/kw/year MarQinal
of Total* $90.72 Cost
(1) x (2 A)
19.
20.
19.
15.
15.
90.
(A)
(5)
(C)
(D)
(E)
(F)
(G)
(H)
(1)
(J)
(K)
(L)
(M)
(N)
Month
Jan
Dee
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dee
Sum
00%
00%
00%
00%
00%
21.74%
22.82%
21.14%
00%
00%
16.78%
17.53%
100.00%
Seasonalized based on monthly CP 1998-2002
and 2002 1RP deficit months
-----'--------'--'- -------
IDAHO POWER COMPANY
Marginal Cost Analysis 2003
Annual Transmission Marginal Costs
Dollars/kw
(1) Investment ($/kW)(A)
(2) With General Plant Loading (1) x 1.07 (8)
(3) Economic Carrying Charge Rate (C) 7.10 %
(4) A&G Loading (D) .42%
(5) Total Carrying Charge
(6) Annual Cost ($/kw) (2) x (5)
(7) Demand related O&M (E)
(8) With A&G loading (7) x 1.35 (F)
(9) Marginal Demand Related Costs (6) + (8)
$92.
$98.44
0.42
$7.40
$4.
$6.
$13.
Working Capital
(10) Materials & Supplies (2) x .88%
(11) Revenue Requirement and Taxes for Materials & Supplies (10) x 11.91%(G)
(12) Total Marginal Demand Related Costs (9) + (10) + (11) Rounded
(13) Total Annual transmission marginal Costs (rounded)
$0.
$0.
$14.
$14.
(A) Estimated cost to integrate approximately 170 MW generation,
(5) Average general plant loading 1998 - 2002
(C) Financial assumptions from the IPCo IRP Technical Appendix p. 46 and the 2003 depreciation study.
(0) Average A & G expenses 1998 - 2002 applicable to plant related expenses
(E) Average 0& M loading 1998 - 2002 wlo accts. 565 & 567
(F) Average A & G expenses 1998 - 2002 applicable to non-plant related expenses
(G) December 31,2002
-----,..
IDAHO POWER COMPANY
Marginal Cost Analysis 2003
Seasonalized Transmission Marginal Costs
(1)(2)(3)
Monthlv
Share $$/kw /vear MarQinal
(A)of Total*$14.Cost
(B)Month (1) X (2 A)
(C)Jan 00%$0.
(D)Feb 00%$0.
(E)Mar 00%$0.
(F)Apr 00%$0.
(G)May 00%$0.
(H)Jun 33.09%$4.
(1)Jul 34.73%$4.
(J)Aug 32.18%$4.
(K)Sep 00%$0.
(L)oct 00%$0.
(M)Nov 00%$0.
(N)Dee 00%$0.
Sum 100.00%$14.
*Seasonalized based on monthly CP 1998-2002
and 2002 lRP months with transmission constraints
;;:
:IVEU
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: ; C P;1 4: 52
, ,
IDAHO POWER COMP*N~Ti SSlo;J
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
OF IDAHO POWER
TT A CHMENT TO
RESPONSE TO
REQUEST NO.4 a
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IDAHO POWER COMPANY
CASE NO. IPC-05-
TRANSMISSION INPUTS TO AURORA
Provided in Response to the First Production Request of the Idaho Irrigation
Pumpers Association, Inc. Request No.7 and the First Production Request of the
Industrial Customers of Idaho Power Company Request No.'s 4 and 5.
The following transmission inputs are posted on the Idaho Power Company
OASIS in the folder entitled 2005 Idaho Retail Rate Case Documents
Transmission capacities in both directions between areas within Aurora are shown , as modeled by
the Company for the rate case, The number in parentheses following the name of each area
represents the area number in Aurora.
FROM TO I MW FROM TO I MW
IPC (84)OWl (44)894
IPC (84)Nevada (55)500
IPC (84)Utah (54)
IPC (84)Id East (48)600
IPC (84)Montana (49)167
OWl (44)IPC (84)356 - 579
Nevada (55)IPC (84)262
Utah (54)IPC (84)
Id East (48)IPC (84)733
Montana (49)IPC (84)171
Id East (48)OWl (44)1410
Id East (48)Utah (54)820
Id East (48)IPC (84)733
Id East (48)Montana (49)170
OWl (44)Id East (48)90 - 200
Utah (54)Id East (48)825
IPC (84)Id East (48)600
Montana (49)Id East (48)166
Wyoming (50)Id East (48)2200
Area Name Key:
IPC: The Idaho Power Company service territory
Id East: Eastern Idaho
OWl: Oregon, Washington and Northern Idaho
Nevada: Nevada
Utah: Utah
Montana: Montana
Wyoming: Wyoming
: C E i \/ r= 0
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IDAHO POWER COMpiXN~Vo ,ii!SS!OH
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
OF IDAHO POWER
TT A CHMENT TO
RESPONSE TO
REQUEST NO.
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IDAHO POWER COMPANY
CASE NO. IPC-05-
TRANSMISSION INPUTS TO AURORA
Provided in Response to the First Production Request of the Idaho Irrigation
Pumpers Association , Inc. Request No.7 and the First Production Request of the
Industrial Customers of Idaho Power Company Request No.s 4 and 5.
The following transmission inputs are posted on the Idaho Power Company
OASIS in the folder entitled 2005 Idaho Retail Rate Case Documents
Transmission capacities in both directions between areas within Aurora are shown, as modeled by
the Company for the rate case. The number in parentheses following the name of each area
represents the area number in Aurora,
FROM TO I MW FROM TO I MW
IPC (84)OWl (44)894
IPC (84)Nevada (55)500
IPC (84)Utah (54)
IPC (84)Id East (48)600
IPC (84)Montana (49)167
OWl (44)IPC (84)356 - 579
Nevada (55)IPC (84)262
Utah (54)IPC (84)
Id East (48)IPC (84)733
Montana (49)IPC (84)171
Id East (48)OWl (44)1410
Id East (48)Utah (54)820
Id East (48)IPC (84)733
Id East (48)Montana (49)170
OWl (44)Id East (48)90 - 200
Utah (54)Id East (48)825
IPC (84)Id East (48)600
Montana (49)Id East (48)166
Wyoming (50)Id East (48)2200
Area Name Key:
IPC: The Idaho Power Company service territory
Id East: Eastern Idaho
OWl: Oregon, Washington and Northern Idaho
Nevada: Nevada
Utah: Utah
Montana: Montana
Wyoming: Wyoming
;, :
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jL :'16 P;)I,:52
IDAHO POWER COMPANY:~: CD::i'iiSS!mJ
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
OF IDAHO POWER
ATTACHMENT TO
RESPONSE TO
REQUEST NO.
ATTACHMENT TO
RESPONSE TO
REQUEST NO.
IS ON A COMPACT DISC
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IDAHO POWER COMPANy
i!;
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CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
0 F THE INDUS TRIAL CUS TO MERS
OF IDAHO POWER
TT A CHMENT TO
RESPONSE TO
REQUEST NO.
, "',..
,co,'C'
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i~j
W ACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
IDACORP , Inc. (IDA-NYSE)
IDA: Initiating Coverage Of IDACORP With A Market Perform Rating
Long-Tenn Value In Hydro Assets, Technology Investments
&V~wB~ ~fili;E~ J~~ Tii~1t!iJ~J&!ifi~! W iZ ;i..TlE' 2~ .
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Market Perform QI (Mar.50.50.A NC 50.5196.5206.4 MM
May 23, 2005 Q2 (June)0.35 216.228.
Q3 (Sep.252.265.
Price $27.Q4 (Dee,202.212,
52 Wk. Rng.$33-FullFY 51.90 51.70 51.90 5868.5913,0 MM
FYPrE 14.16.3x 14.
FullCY 51.90 51.70 51.90
CY PrE 14,16.14.
. c
""'
7~h
Initiation of Coverage
, ,,..,.' .,',..'
;:i
Thomas Hamlin, CFA
[phone]
thomas, ham I i n(!Ywachovia,com
Darin Conti, CFA
[phone]
darin,conti~wachovia.com
Source: Com "I' data ami W'CM. LLC eslimates NA Not Available. NC No Chon e, NE No Estimate. NM Not Meanin rul
Shares Out.: (MM)
Market Cap.: (MM)
Avg, Daily Vol,
S&P 500:
Float: (MM)
Div.Nield:
LT Debt:(MM)
LT DebtffotaICap.
ROE:
5 Yr. Est. Grth. Rate:
CY 2005 Est P/E-to-Grth.
Last Reporting Date:
109.
52.
5.4x
5/512005
Before Open
42.4
177,
222,990
189,
42,
51.20/4.3%
Key Points
. IDACORP is a public utility holding company, formed in 1998 and headquartered in Boise, Idaho.
Its principal subsidiary is Idaho Power Company, an integrated electric utility serving most of the
state of Idaho and a small portion of Oregon. Non-utility operations include investments in
affordable housing that generate tax credits, a developer of integrated fuel cell systems, and a
provider of telecommunications and Internet services. Utility operations accounted for 97% of
consolidated operating revenue and 90% of consolidated net income in 2004.
Electricity Plus - The company s stated operating strategy is called "Electricity Plus," a back-to-
basics strategy that emphasizes IDACORP's utility operations as its core business while retaining
the potential future value from its investments in electricity-related technologies.
Power Supply - IDA owns and operates 17 hydroelectric power plants with a combined generating
capacity of 1 707 MW. All of these facilities are located along the Snake River, which crosses the
southern and western portions of the state, It also owns 1 378 MW of thermal generating capacity,
principally coal-fired.
Initiating EPS Estimates of$1.70 for 2005 and $1.90 for 2006 - Hydro conditions are below
nonnal for the sixth consecutive year, estimated to be just 35% of normal. Higher prices for fossil
fuels and for purchased power will likely offset underlying service area sales growth in 2005.
Initiating Coverage of IDA with Market Perform Rating - In light of the EPS decline for 2005
and that IDA shares are trading at the high end of our valuation range, we expect the stock to trade
in line with the industry averages,
Valuation Range: $25 to $27
Over the next 12 months, we believe that IDA shares warrant a valuation range of $25-27 based on
our EPS estimate for 2006, our 3-5 year earnings growth rate estimate of 3%, and a normal PIE
multiple for mid-cap electric utilities of 13-14x, Risks to achieving our valuation range include a lack
of improvement in future stream flow conditions, adverse regulatory decisions, burdensome
conditions placed on hyro license renewals, and higher purchased power prices.
Please see page 12 for rating definitions, important disclosures and required analyst
certifications.
WCM does and seeks to do business witb companioo conreel in its rooearcb report5. As a rooult, investon sbould be aware that tbe firm may have a conflld of interesttbat could affect
tbe objectivity of the report "nd Investon should consider this report 85 only a single f.ctor In making tbeir Investment decision.
II WACHOVIA SECURITIES
Page 1
Utilities
WACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
Investment Thesis
IDACORP represents a relatively unique investment among utility companies. It is one of the
only investor-owned electric utilities which, during normal weather conditions, derives the
majority of its electricity from hydroelectric plants. The service area of its principal subsidiary,
Idaho Power, is growing faster than the national average and requires the company to invest in
new thermal generating capacity. Sales growth and rate base growth should yield above-average
earnings growth. Furthermore, as wholesale power markets become increasingly competitive and
the cost of fossil fuels continue to rise, the value of the company s hydroelectric plants, a
renewable, non-polluting source of power, should increase. IDA shares are currently trading at
the high end of our valuation range and therefore offer no better than average relative attraction, in
our view.
Company Description
IDACORP is a public utility holding company, formed in 1998 and headquartered in Boise, Idaho.
Its principal subsidiary is Idaho Power Company, an integrated electric utility serving most of the
state of Idaho and a small portion of Oregon. Non-utility operations include investments in
affordable housing that generate tax credits, a developer of integrated fuel cell systems and a
provider of telecommunications and Internet services.
Discussion
IDACORP is a public utility holding company, formed in 1998 and headquartered in Boise, Idaho.
Its principal subsidiary is Idaho Power Company, an integrated electric utility serving most of the
state of Idaho and a small portion of Oregon. Non-utility operations include investments in
affordable housing that generate tax credits, a developer of integrated fuel cell systems, and a
provider of telecommunications and Internet services. The company had been involved in
electricity and natural gas marketing, but wound down its operations in 2003. It continues to
manage its investments in several small independent hydroelectric plants, but has discontinued its
project development operations. Utility operations accounted for 97% of consolidated operating
revenues and 90% of consolidated net income in 2004.
Management Strategy
The company s stated operating strategy is called "Electricity Plus " a back-to-basics strategy that
emphasizes IDACORP's utility operations as its core business while retaining the potential future
value from its investments in electricity-related technologies.
Although this strategy was formally announced in 2003, the company had been winding down its
power marketing activities since the middle of2002. This was attributed to changing liquidity
requirements brought on by the rating agencies, continued uncertainty in the regulatory and
political environment, and a reduction in credit-worthy counterparties. In November 2002, IDA
announced that it was ending its interest in investing in the mid-stream natural gas market and
would shut down its natural gas trading operations, closing offices in Denver and Houston and
reducing its work force in Boise. In August 2003, the company announced the sale of its forward
book of electricity trading contracts, which closed a month later. Implementing this change in
strategy resulted in several charges to earnings in 2002 and 2003.
In 2004, the company moved forward with its strategy, obtaining a base rate increase for its Idaho
utility business and selling new shares of common stock through a public offering to improve its
balance sheet. Earnings for the year were relatively free from costs related to the shutdown of
merchant power activities, with the exception of a $2 million gain from the settlement of legal
disputes.
For 2005, IDA CORP plans to make significant investments to its utility infrastructure to ensure
adequate supplies of power and reliable service. Customer growth continues to exceed the
national average, and a sixth consecutive year of below-normal hydro conditions likely will
Page 2
IDACORP, Inc.
WACHOVIA CAPITAL MARKETS, HC
EQUITY RESEARCH DEPARTMENT
require an increased reliance on thermal power resources. Idaho Power plans to add 164
megawatts (MW) of generating capacity in mid-2005 with the completion of the gas-fired Bennett
Mountain plant A request for rate relief related to this investment was filed in March 2005. The
company also plans to file another general rate case in Idaho in the fall.
Utility Operations
Idaho Power Company is an electric utility serving about 440 000 customers in a 24 000 square
mile area in southern Idaho and eastern Oregon, with an estimated population of 895,000. It is a
fully integrated electric company, involved in the generation, purchase, transmission, distribution
and sale of electricity.
Service Area
The company s service territory covers about two-thirds of the state s population. A little less
than one-half of the service area population lives in and around the city of Boise, Idaho.
According to the U.S. Census Bureau, Idaho s population growth during the I 990s was the fifth
highest among the states, increasing nearly 29%. This compares to a 13% increase for the United
States. Population growth has continued at nearly twice the national average since the 2000
census. As of February 2005, the state s unemployment rate was 4.1% compared to a national rate
of 5.4%. Principal commercial and industrial customers are involved in food processing,
electronics and general manufacturing, forest product production, beet sugar refining and the
skiing industry.
Regulation
Idaho Power is under the regulatory jurisdiction of the Idaho Public Utilities Commission (IPUC)
and the Oregon Public Utility Commission (OPUC) with regard to its retail rates and other
matters. About 96% of the company s general business revenue is derived from Idaho customers.
Wholesale power activities, and other matters, are under the jurisdiction of the Federal Energy
Regulatory Commission (FERC). Importantly, the company s licensed hydroelectric projects are
subject to the provisions of the Federal Power Act, under the jurisdiction of the FERc.
addition, both Idaho and Oregon have their own hydroelectric-license regulations.
Under normal stream flow conditions, Idaho Power is able to generate about 55% of its energy
requirements from its hydroelectric plants, which provide power at virtually no marginal cost. The
balance of energy requirements come from the company s thermal plants or purchases from other
producers. Because stream flow conditions can vary substantially from year to year, the
company s annual fuel costs likely will also vary substantially. The IPUC has a Power Cost
Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to Idaho
retail customers. These adjustments are based on forecasts of net power supply costs, which are
fuel and purchased power net of off-system sales, as well as the "true-up" of the prior year
forecast. During the year, 90% of the difference between the actual and forecasted costs is
deferred, with interest, and added or subtracted from the unrecovered portion from prior years to
calculate the true-up component of the PCA.
In October 2003, Idaho Power filed for an increase in its base rates (a general rate case) of 17.7%,
designed to increase annual revenue by $86 million. The company s last general rate case was
filed in 1994. The increase reflected a proposed return on equity of 11.2%. Incorporated in the
filing was a request that a portion of the increase ($20 million or 4.2%) be implemented within 30
days on an interim basis until the resolution of the general case. The IPUC denied the request for
the interim rate increase.
In its rebuttal testimony in the proceeding, the company modified its request to 14.5%, or $70
million in revenue. The reduced amount reflected changes in test-year expenses, including the
resolution of a separate depreciation case, lower payroll-related expenses and a change in the
Page 3
Utilities
WACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
method of recovering pension costs. In May 2004, the IPUC issued its decision in the general rate
case, approving an average increase in base rates of 5 ., designed to raise annual revenues by
$25.3 million, a little over one-third of the modified request. The commission approved a return
on equity of 10.25% (request was 11.2%) and an Idaho jurisdictional rate base of $1.52 billion
about $30 million below the company s filing. Test-year operating expenses used by the
commission to compute revenue requirements were about $27 million below the level used in the
company s filing.
The company filed a request with the IPUC for reconsideration of a number of expense items used
in the commission s computation of the allowed increase. In July, the IPUC granted the company
another $3 million in additional annual revenue based on computational errors made by the IPUC
stafTrelating to income tax expenses. In September, the IPUC approved settlement agreements
related to the income tax and a nwnber of other issues adding another $12 million to the rate
increase. As a result, the company was able to secure a total rate increase of $40 million, or 57%
of the modified request.
Along with its order in the general rate case, the IPUC approved the full amount of the company
request to recover $71 million in its annual PCA filing. The commission also approved an
adjustment to the PCA mechanism that would eliminate any over- or under-collections of revenue
due to changes in customer consumption.
In September 2004, Idaho Power filed a general rate case with the Oregon PUC, requesting a
17.5% increase in customer rates, designed to raise annual revenues by $4 million. A decision
from the OPUC is expected in late July 2005.
As mentioned in the Business Strategy section of this report, the company has requested a 1.84%
increase in rates from the IPUC specifically to reflect the completion and commercial operation of
the 164 MW Bennett Mountain generating plant. Idaho Power has invested $58 million in the gas-
fired peaking facility and related transmission equipment. The request was filed on March 3, and
amended March 23,2005. The rate increase would raise annual revenue by $9.4 million based on
the cost of capital adopted in the last general rate case. The proposed increase would go into
effect on June 1. The Staff of the IPUC has recommended that the company s filing qualify for
specific consideration in a modified rate proceeding.
Power Supply - Overview
Idaho Power (lPC) is one of the nation s few investor-owned electric utilities with a
predominantly hydroelectric generating base. It owns and operates 17 hydroelectric power plants
with a combined generating capacity of 1 707 MW. All of these facilities are located along the
Snake River, which crosses the southern and western portions of the state. It also owns 1 378 MW
ofthennal generating capacity, consisting of partial interests in three coal-fired plants (1,110
MW), two gas-fired plants (263 MW) and one diesel unit (5 MW).
The company s generating facilities are interconnected with those of other utilities in the region
through an integrated electric transmission system, which is operated on a coordinated basis to
maximize its capability and reliability. Idaho Power is a member of the Western Electricity
Coordinating Council (WECC), the Western Systems Power Pool, the Northwest Power Pool and
the Northwest Regional Transmission Association, all of which operate to optimize the use of the
system.
The company meets its load requirements using a combination of its own generating units
mandated purchases from private developers and market-driven purchases from other utilities and
independent producers. The primary influences on electric demand are weather, customer growth
and economic conditions. The company experiences peak demand on its system in both the
summer and winter, largely driven by weather. Peak demand in 2004 was 2 843 MW in the
summer (June 24) and 2 196 MW in the winter (January 5). The all-time record peak demand of
Page 4
IDACORP, Inc.
WACHOVIA CAPITAL MARKETS, lLC
EQUITY RESEARCH DEPARTMENT
963 MW was set in July 2002. Consistent with growth in customers and the economy, the
company estimates peak demand growth of2.5% per year over the next three years.
Power Supply - Integrated Resource Plan
In August 2004, the company filed its bi-annuallntegrated Resource Plan (IRP) with the utility
commissions in Idaho and Oregon. The IRP reviews the expected growth in energy demand and
identifies resources available to meet that demand over the next ten years. The report analyzes
potential supply-side and demand-side options and identifies short-tenD and long-tenD actions.
The goals of the IRP process are to balance cost, risk and environmental concerns and involve the
public in the resource planning process. Significant external involvement is part of the process
before and after the initial filing. The 2004 plan identifies the following additional energy
resources to meet demand growth:
. 76-MW demand response programs
. 48-MW energy efficiency programs
. 350-MW wind-powered generation
100- MW geothennal-powered generation
. 48-MW combined heat and power (co-generation) at customer facilities
. 88-MW simple-cycle natural gas-fired combustion turbine
. 62-MW combustion turbine, distributed generation or market purchases
. 500-MW coal-fired generation
The company has begun implementing some of the steps outlined in the plan. It has issued a
Request For Proposal (RFP) associated with an air conditioning cycling program as wen as an
RFP for 200 MW of wind-powered generation. It also plans to issue RFPs for the combustion
turbine, co-generation and geothennal-powered generation.
Power Supply - Hydroelectric Plants
IPC's portfolio of hydroelectric power resources is a relatively unique feature of the company and
a key component of its long-tenD value. It owns and operates 17 hydroelectric plants, located on
the Snake River, which crosses the southern part of the state, then turns and flows north until it
combines with the Columbia River in Washington. These projects operate under licenses issued
by the FERC, which last for 30-50 years.
The largest concentration of hydroelectric plants is located along the Idaho-Oregon border. Three
projects, referred to as the Hel\'s Canyon Complex, comprise over two-thirds oflPC'
hydroelectric capacity with 1 167 MW. The most upstream (and largest) of the three facilities is
the Brownlee Dam and Reservoir, whose five generating units have 585.5 MW of generating
capacity. The remaining hydroelectric facilities are located in the south-central portion of the
state.
The relicensing oflPC's hydroelectric projects is a significant near-tenD and long-tenD issue, in
our view. In August 2004, the company received new 30-year licenses for five of its middle
Snake River projects, covering about 235 MW. An important component of each of these licenses
is a settlement agreement between the company and the U.S. Fish and Wildlife Service regarding
five snail species that inhabit the middle Snake River, which are listed as threatened or endangered
under the Endangered Species Act. The agreement provides for six years of studies and analyses
of the impact of project operations on the listed species followed by joint development of a plan
for the remaining tenD of the license. Conservation groups have filed challenges to the new
licenses, some of which remain outstanding.
A component of the new licenses (and likely a part of any future license) is a requirement for IPC
to develop comprehensive plans for Protection, Migration & Enhancement (PM&E) measures and
submit them to the FERC within six months after receiving a new license. IPC is required to
consult with external agencies, both governmental and non-governmental, in developing these
Page 5
Utilities
WACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
plans. The company owns and finances the operation of anadromous fish hatcheries and related
facilities to mitigate the effects of its hydroelectric dams on fish populations. At year-end 2004
IPC had invested $11 million in such facilities and incurs $3 million in annual operating costs.
The estimated cost to implement new PM&E measures are estimated to be $10 million in capital
and $2 million in operating expenses.
The licenses for two plants (22 MW combined capacity) expired in 2004. The projects are to
operate under annual licenses until the tenns of a new long-tenn license can be reached. IPC
anticipates a new multiyear license will be issued in 2005
The July 2005 expiration of the licenses for its Hell's Canyon Complex is a major issue for the
company, in our view. The application for a new license was filed with the FERC in July 2003. It
includes the continuation of existing PM&E measures, as well as new measures, estimated to cost
$106 million in the first five years of a new license and $218 million over the remaining 25 years.
Additional measures to address water quality issues may add another $62 million to the total cost.
Various government agencies, environmental groups, Native American Indian Tribes and other
private interests have filed comments and suggested PM&E measures, which could add to these
costs if adopted. As of year-end 2004, $66 million of relicensing costs for the Hell's Canyon
Complex relicensing had been capitalized as construction work in progress.
Because of its low cost, the company seeks to maximize the value of its hydroelectric resources.
Under nonnal stream flow conditions, the hydroelectric plants account for 55% of IPC's annual
electric supply, or about 9.2 million megawatt-hours. The amount of electricity that can be
produced from these plants depends on a number of factors, primarily snow pack in the mountains
upstream from its facilities, reservoir storage and stream flow conditions.
Below-nonnal stream flow conditions in 2004 limited hydroelectric production to 6,04 million
megawatt-hours, equivalent to just 45% of total system generation for the year. It was the fifth
consecutive year of below-normal stream flow conditions. The production in 2004 was 1.
below the 6.15 million megawatt-hours (47%) produced in 2003.
The outlook for stream flow conditions in 2005 are for another below-average year. The United
States Weather Service Northwest River Forecast Center (RFC) estimates that water flows into the
Brownlee Reservoir will be 2.3 million acre-feet from April through July, which is only 36% of
nonnal and below the 3.2 million acre-feet in 2004. Snow pack accumulation was only 60% of
average as of early March. Storage in selected federal reservoirs upstream from Brownlee was
only 60% of average.
Thermal Plants
Idaho Power relies on its thermal plants for 45-55% of its annual energy requirements. Thennal
generating capacity of 1 378 MW is 81% coal-fired steam and 19% gas-fired combustion turbines
(including the Bennett Mountain plant schedulea for June 2005). Thermal generation in 2004 was
3 million megawatt-hours, equivalent to 55% of total system generation.
Coal-fired generating capacity of 1 110 ?\1W cernes frem pa.~ial interests in three plants. This
ownership structure enables the company to derive the economies of scale inherent in larger
generating plants while spreading its operating risk over multiple plant sites. IPC owns a one-
third interest (770.5 MW) in the Jim Bridger plant, a four-unit facility located in western
Wyoming. The rest of the plant is owned by PacifiCorp, a subsidiary of Scottish Power. The
plant consumes over 1 000 tons of coal per hour. Fuel for the plant comes from a dedicated mine
and delivered via conveyor belt, rail and truck. IPC owns a 50% interest (283.5 MW) in the
Valmy plant located in northern Nevada. The plant is operated by its co-owner, Sierra Pacific
Power. The third source is a 10% interest (56 MW) in the Boardman coal plant in northern
Oregon, operated by its 65% owner, Portland General Electric.
Page 6
IDACORP, Inc.
WACHOVIA CAPITAL MARKETS, liC
EQUITY RESEARCH DEPARTMENT
Non-Regulated Operations
IDA's non-regulated operations consist of:
IDACORP Financial Services - A holder of affordable housing and other real estate
investments
ldaTech - A developer of integrated fuel cell systems
IDACOMM - A provider of telecommunications services and commercial and
residential Internet services
IDACORP Financial Services
IDACORP Financial Services (IFS) invests primarily in affordable housing developments. At
year-end 2004, the gross amount ofIFS's portfolio exceeded $165 million. These investments
reduce income taxes through tax credits and accelerated tax depreciation. Over 90% ofIFS'
investments have been made through syndicated transactions in order to limit geographical and
operational risk. The underlying investments include over 700 individual properties in 49 states
Puerto Rico and the U.S. Virgin Islands, all but three of which are administered through
syndicated funds.
For 2004, 2003 and 2002, these investments produced tax credits of $22 million, $20 million and
$21 million, respectively. IFS contributed $0.35 per share in 2004, $0.27 per share in 2003 and
$0.23 per share in 2002, In 2004, the company recognized a $5 million gain on the sale of one of
its investments.
IdaTech
IdaTech is a global fuel cell provider focused on the commercialization of fuel processor
technology and integrated proton exchange membrane (PEM) fuel cell systems. It was originally
founded in 1996 as Northwest Power Systems, LLC to develop and bring fuel cell technology to
market. IDACORP purchased a majority interest in IdaTech in 1999. CUITent products under
development include:
Complete systems, such as ElectraGen, its five kilowatt electrical emergency back-
up power fuel cell unit that is targeted to replace valve regulated lead acid batteries
in applications such as cellular communications towers and portable power systems.
. On-board refonning capability, which provides auxiliary power to high-end
consumer applications such as marine and recreational vehicles and premium power
for special military operations.
Components such as multi-fuel fuel processors, fuel cell stack technology and
automated fuel cell systems, which target longer-tenn commercial applications in
vehicular auxiliary power units and Combined Heat and Power units.
The company has also integrated its multi-fuel processors with a number ofPEM fuel cell stacks
into one to ten kilowatt for stationary and portable electric power generation. IdaTech's systems
are being field-tested and evaluated with European utilities, the Propane Education and Research
Council, the U.S. Anny Communications Electronics Command and other customers in North
America, Europe and Asia.
IdaTech's research and development program is focused on the adaptation of its fuel processor
technology to operate on all commercially important fuels, as well as the development of fully
integrated fuel cell systems. In 2004, it spent about $5 million for research and development of
fuel cell technology. The company pursues patent protection of its technology in North America
Europe, South America, Asia and Australia. In 2004, it received its first three Japanese patents
and its first European patent. It has 35 U.S. patents lasting 20 years (expiration dates are 2016 to
2025) and has about 150 pending domestic and foreign patent applications. These patents should
help ldaTech commercialize its technology and provide the potential for its licensing in the future.
Page 7
Utilities
WACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
With the substantial increase in the cost of fossil fuels, there has been a renewed interest in new
energy technologies such as fuel cells. Investments in these technologies fell out of favor in the
United States after the collapse of the merchant power sector and the drop in power prices and
widespread commercial development stalled. However, European investors continued to support
their development and several products are close to commercial development. Although IdaTech
does not make a current contribution to IDACORP's operating earnings, we believe it has the
potential to add to shareholder value.
IDACOMM
IDACOMM provides a wide range of integrated communication services to business and
residential customers in 22 markets in eight western states, Virginia and New York. In August
2004, IDACORP acquired Velocitus, a Boise-based Internet service provider founded in 1992.
Ownership ofVelocitus was transferred to IDACOMM in 2004 and the two merged in January
2005. IDACOMM's fiber optic networks provide high-speed connectivity in Boise, Idaho, as well
as networks acquired in June 2004 in Las Vegas and Reno, Nevada. Its Internet services unit
enables high-speed voice, Internet and data communications, including video conferencing, voice-
over Internet protocol, ofT-site training, gigabit Ethernehervice, virtual private networks, firewalls
and web hosting. The Internet services unit had 20,000 customers at year-end 2004.
Broadband-over-powerline (BPL) is a developing technology that transports data over medium-
voltage and low-voltage power lines directly to the end-user s computer. IDACOMM is currently
conducting equipment trials and evaluating the potential commercial deployment ofBPL in Boise.
Like IdaTech, IDACOMM does not make a contribution to IDACORP's operating earnings, but it
has the potential to add to shareholder value in the future. The growth characteristics of both the
Idaho and Nevada areas where its fiber optic networks are located may, at some future date, be of
value to a larger telecom operator looking to expand.
Capital Spending
IDACORP's capital spending requirements are primarily for its utility operations. Of$200
million in property, plant and equipment additions in 2004, $190 million (95%) were for Idaho
Power Company. The company estimates utility construction expenditures of $202 mill ion for
2005 and $470 million total for the following two years. In addition to utility spending, the
company anticipates additional investments of$82 million over the three years in IFS,
The prolonged period of below-average hydro conditions has increased the usage of the thennal
plants, requiring the upgrade and replacement of some of the equipment at the plants. Other
spending increases are related to connecting new customers, adding new peaking capacity and
relicensing the hydroelectric plants. As mentioned previously, the 2004 Integrated Resource Plan
includes $79 million of construction costs for a 160 MW combustion turbine peaking plant for
operation in 2007.
Environmental-related spending is estimated at $ 18 million for 2005 and $40 million total for the
following two years. Construction spending will likely rise after this period if Idaho Power
proceeds with plans to construct a 500 MW coal-fired plant to be operational in 2011 , at an
estimated cost of $532 million.
Credit Profile
IDACORP currently carries a corporate credit rating ofBBB+/Baal from Standard & Poor s and
Moody , respectively. The senior unsecured debt at the parent company carries a BBB/Baa2
rating from the two agencies as well as a BBB rating from Fitch. The senior secured debt of the
utility is rated A-/A3/A-
Page 8
IDA CORP, Inl:.
WACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
In January 2005, Fitch announced that it had lowered its ratings to the above-mentioned levels
because of increased earnings volatility and debt burden relative to cash flows, primarily due to
the effect of ongoing drought conditions in southern Idaho and the lower than expected rate
increase approved by the Idaho PUC in 2004. The outlook for its ratings was stable.
Earnings and Dividends
In 2004, IDACORP reported earnings of $1.90 per share, a 56% increase over the $1.22 per share
earned in 2003. The increase was attributable to higher earnings from utility operations, higher
tax benefits and a gain on an assel sale at IFS in 2004. Earnings for 2003 included the impact of
exiling the energy trading business as well as asset impainnent charges.
Earnings at Idaho Power were $1.71 per share, an 18% increase over the prior year s $1.44 per
share. The following items were significant factors in the improvement:
+$12 million - Reversal of2002 charge due to settlement of the irrigation lost
revenue case
. +
2 million - Interest related to the above settlement
. +
7 million - Settlement with IPUC over calculation of IPC's income taxes
. +
10 million - Reduction in unrecovered power costs
. +
IS million - Lower income tax expense due to reversal of a 2002 regulatory
liability charge
- 35 million - Higher payroll costs and write-off of disallowed costs in general rate
case
IFS contributed $0.35 per share compared to $0.27 per share for 2003, These results included a
$2 million ($0.05 per share) gain on the sale ofIFS's investment in the EI Cortez Hotel in San
Diego.
Earnings from Ida-West were $0.08 per share iti 2004, compared to' a net loss of$O.13 per share in
2003. The company recorded a $3.5 million gain in 2004 on the purchase of debt from a 50%-
owned consolidated joint venture. Results for 2003 also included the write-off of an investment in
a power project and the recording of a reserve on a note receivable.
IDACORP Energy earned $0.06 per share in 2004, primarily from gains on settlements oflegal
disputes. In 2003, the company had a net loss of$0.25 per share due to losses on legal settlements
and the costs of winding down its business, partially offset by a gain on the sale of its forward
book of electricity trading contracts.
With the exit from the merchant energy businesses complete, we look for earnings from Idaho
Power and IFS to comprise IDACORP's earnings for 2005 and 2006. Our projections are detailed
in the table attached to this report.
As mentioned previously, the company expects 2005 to be the sixth consecutive year of below-
average hydro conditions. Higher prices for coal, natural gas and purchased power will also likely
be negative influences on earnings. Offsetting these factors likely will be the full-year s impact of
the general rate increase received in 2004, higher PCA revenues, and the benefits ofnonnal
weather and an improving economy.
Our EPS estimates are $1.70 for 2005 and $1.90 for 2006.
In September 2003, IDACORP's annual dividend was reduced to $1.20 per share from $1.86. The
action was taken to help the company strengthen its financial condition and improve its ability to
fund the growing capital spending requirements of the utility. We look for the company to
maintain the dividend at its current level over the next few years. The $1.20 dividend represents a
67% payout of our 2005 EPS estimate, which is comparable with other integrated electric utilities.
Page 9
Utilities
WACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
Risks
The following factors could have a significant impact on the operations and financial results of
lDACORP.
Reduced hydro conditions - As mentioned above, because of its significant reliance on
hydroelectric generation, the company s earnings are directly influenced by winter weather and its
impact on streamflows into the Snake River. During low water years, the company increases its
use of more expensive power from its thennal plants and purchases from other producers. The
company is unable to recover the full cost of this power through the Power Cost Adjustment
mechanism. The region is in its sixth consecutive year of below nonnal hydro conditions.
State regulatory commission actions - The company s ability to earn an adequate return on its
investment in utility assets is dependent on the receipt of timely and adequate rate increases. This
is particularly true when the utility's capital spending requirements rise. As mentioned above,
Idaho Power has recently completed a new combustion turbine at Bennett Mountain. Capital
spending likely will continue to rise to meet environmental regulations, improve reliability and
renew the licenses for its hydro plants.
Conditions imposed on hydro license renewals - The company is in the process of renewing its
licenses for its Hells Canyon Complex, the largest of its hydroelectric facilities. These licenses
expire in July 2005. IPC's application identifies protection, mitigation and enhancement measures
(PM&E) that would require an investment of $386 million. Proposals for PM&E measures by
other parties to the proceedings could require as much as an estimated $2.5 billion of new
investment over the 50-year life of the license.
Litigation -lDACORP Energy s involvement in western power markets during the 2000-2002
time period has made the company a party to a number of federal investigations and lawsuits.
Many of these proceedings have been concluded or dismissed but remain under appeal by various
parties. Two securities shareholder lawsuits have been filed against lDACORP.
Environmental regulations - As the owner of several thennal electric generating plants, the
company is subject to changing standards regarding air and water quality. These changes often
require the installation of new emission control equipment. The issue of carbon dioxide emissions
(greenhouse gasses) and their impact on global climate conditions has become increasingly public
and could result in new regulations that could significantly impact electric power producers.
Page 10
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Utilities
W ACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
$!iOO-
t: S2i!D-::I
~~m
Required Disclosures
IDPCCH', Inc. ODA) 3-yr. Price Perfamn:e
I i
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Additional In/ormation Available Upon Request
I certify that:
I) All views expressed in this research report accurately reflect my personal views about any and all of the subject securities or issuers discussed; and
2) No part of my compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressed by me in this
research report.
Wachovia Capital Markets, LLC or its affiliates managed or comnnaged a public offering of securities for IDA CORP, Inc. within the past 12 months.
Wachovia Capital Markets, LLC or its affiliates intends to seek or expects to receive compensation for investment banking services in the next three
months from IDACORP, Inc.
Wachovia Capital Markets, LLC or its affiliates received compensation for investment banking services from IDACORP, Inc. in the past 12 months.
IDA CORP, Inc, cun-enlly is, or during the 12-month period preceding the date of distribution of the research report was, a client ofWachovia Capital
Markets, LLc. Wachovia Capital Markets, LLC provided investment banking services to IDACORP, Inc.
IDACORP, Inc. cun-enlly is, or during the 12-month period preceding the date of distribution of the research report was, a client ofWachovia Capital
Markets, LLc. Wachovia Capital Markets, LLC provided nonsecurities services to IDACORP, Inc.
Wachovia Capital Markets, LLC received compensation for products or services other than investment banking services from IDACORP, Inc. in the
past 12 months.
Risks to achieving our valuation range include a lack of improvement in future stream flow conditions, adverse regulatory decisions, burdensome
Page 12
IDACORP, Inc.
W ACHOVIA CAPITAL MARKETS, LLC
EQUITY RESEARCH DEPARTMENT
conditions placed on hyro license renewals, and higher purchased power prices.
Wachovia Capital Markets, LLC does not compensate its research analysts based on specific investment banking transactions. WCM's research
analysts receive compensation that is based upon and impacted by the overall profitability and revenue of the firm, which includes, but is not limited to
investment banking revenue.
1 = Outperform: The stock appears attractively valued, and we believe the stock's total return will exceed that of the market over the next 12 months.
BUY
2 = Market Perform: The stock appears appropriately valued, and we believe the stock's total return will be in line with the market over the next 12
months. HOLD
3 = Underperform: The stock appears overvalued, and we believe the stock's total return will be below the market over the next 12 months. SELL
As of: May 23, 2005
42% of companies covered by Wachovia Equity Research are
rated Outperfonn.
52% of companies covered by Wachovia Equity Research are
rated Market Perfonn.
6% of companies covered by Wachovia Equity Research are
rated Underperfonn.
Wachovia has provided investment banking services for 36% of its
Outperform-rated companies.
Wachovia has provided investment banking services for 34% of its Market
Perfonn-rated companies.
Wachovia has provided investment banking services for 38% of its
Underperform-rated companies.
Important Disclosure For International Clients
The securities and related financial instruments described herein may not be eligible for sale in all jurisdictions or to certain categories
investors. For certain non-S. institutional readers (including readers in the EEA), this report is distributed by Wachovia Securities
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customers, Please consult your Financial Advisor or the Wachovia Securities office in your area for additional infonnation. U.
residents are directed to wachovia,com for investment and related services.
Page 13
Utilities
W ACHOVIA CAPITAL MARKETS,
EQUITY RESEARCH DEPARTMENT
Additional Disclosures
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This report is for your information only and is not an offer to sell, or a solicitation of an offer to buy, the securities or instruments named
or described in this report. Interested parties are advised to contact the entity with which they deal, or the entity that provided this report
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and are subject to change without notice. Wachovia Capital Markets, LLC, and its affiliates may from time to time provide advice with
respect to, acquire, hold, or sell a position in, the securities or instruments named or described in this report. For the purposes of the U.
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I SECURIT\ES:
NOT FDIC-INSURED/NOT BANK-GUARANfEEDIMA Y LOSE V AWE
Page 14
: ;, !
i \/ C D
'" ! 6 Pi) 11:
IDAHO POWER cOlVIpAN r(~sIOiJ
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
0 F ID AH PO WE R
TT A CHMENT TO
RESPONSE TO
REQUEST NO.
'--
Page 15
KeyBanc
Capital Markets
o-w.
KeyBanc: Capital Marlcets
A Division 01 McDonald Investmero ItIC.
Equity Research
A DMsaI of McDonaIIIIIwes1nIeIIIS he.
Basic Report
IDACORP, Inc.
(lDA-NYSE)
RECENT EQUITY OFFERING STRENGTHENED BALANCE SHEET
MANAGEMENT REFOCUSED ON CORE UTILITY BUSINESS
58% RETAIL STOCK OWNERSHIP OFFERS STABILITY
LARGE HYDROELECTRIC FLEET AND REGULATORY FRAMEWORK MAKE EARNINGS SENSITIVE TO
PRECIPITATION
WE ARE INITIATING COVERAGE WITH A HOLD RATING
Investors should assLllle that we are seeking or wig seek investment banking
or other business relationshi s with the com a described in this re Oft.
KeyBanc Capital Martets is the trade name under which the corporate and investment banking products and services KeyCorp and its subsidiaries.
including McDonald Investments loc., member NYSEINASD/SIPC, are marketed to instjutional clients.
The irlormalion conlained in lhis report is based on SOll"ces considCled to be reiable b~ is not represenled to be complete and ~s acClfacy is not guaranteed, The opinions expressed reflect the
judgmenl oIlhe author as 01 the date 01 publicalion and are subject to change without notice. This report does not constilute an offer to seW or a soic~alion 01 an offer to 00y any SetlfitieS. We
proliM 011" resea-ch analysts and members 01 their lamiies from ownng sea.rilies 01 81I'J company 10Bowed by lhat analyst Ou" offICers, directors, sha"ehoklers and other empoyees, and
members 01 thei" lamiies may ha~ posilions in lhese securities and may. as principal or agenl. buy and seU such seclfities before, alter or concurrently with the publcalion 01 this report, In
some instances, such investments may be inconsistenl wiIh the opinior1s expressed herein, One or more 01 011 employees, other than the resea-ch analyst responsible for the preparation 01 this
report. may be a merroer oIlhe Board 01 Di'ectors 01 81I'J company referred to in this report. The resea-ch analyst responsible for the preparation 01 tM report is compensaled, based in pa1. (11
investmert baOOng revel\Je which may include reveille deri'led from the Firm's performartte 01 investmert batting services for comparies re/erred 10 in this report. a.hough such compensation
is not based specifIC inves1menl banking servi:es transactions for these or any OIher comparies. n accordance with recently adopled industry practices. our analys1s a-e prohilited from
soiciti1g investment batting business lor Olf Firm, 'M1ere tRs documert is distributed in or Irorn the U.K, "has been approved by McDonakl \nvestmerrlS Inc. which is aUthorized and regulated
in London as a Inoch by the FSA. The sewRies descriled in this documert are not available to persons other 1han ma'kel COUnlerpaties or l1O~vate customers as these terms a-e defiled in
the rutes lithe FSA.
"Copyright 2005, McDonald Investments Inc. AI righIs reserved.
Securities, mUbJai funds and other investment products are:
Not Insured by the FDIC.
Not deposits or other obligations of, or guaranteed by McDonald Investments Inc., Key Bank or any of their affiliates.
Subject to investment risks, including possible loss of the principal amount invested.
Page 16
KeyBanc Capital MarlIets
A Division 01 McDonald Investmems Inc.
EtPIJ Research
Contents
IDACORP, Inc. at a Glance ..........................................................................................................................
Summary and Recommendation...... .......".. ..........
....... .................. ................... ......."... ......... ......................
Key Investment Points..... ...................... .................... ...................... ........., ...... ...... ..........."........ ..".. ............ 5
Primary Risk Factors...................... ................... ....... .............". ............. ..........,.
........... ..... ........ ...... .............
Business Segments.. ....... .................. ......"............... ......................,... .............. ........, ........ ...... ............ ......... 5
Power Cost Adjustment Mechanism and Regulatory Issues.......................................................................... 9
Regional Transmission Organizations (RTO)...............................................................................................
California Energy Proceedings. ..... ...... .................
........ .......... .......................... .......... ..... ............ ....... ....,.. ..
Additional Security Offerings ........ .......... ..............
.....................,................................ ...... ........... .............. ..
Credit Facilities ........................................................ ................................................. ................................ ..
Earnings and Dividend Outlook ...................................................................................................................
Tables
Quarterty Sales Distribution .........................................................................................................................
Generating Capacity.................................................................. ................................................ .........."...... 6
Hydrology Variation ......... ........ ....... .........
..................................... ........... .......... ........
..........,....................... 6
Efficiency of Fuel Sources .............,.........................................................................".................................. 8
Detail of Annual PCA Outcomes .................................................................................................................. 9
Reconciliation of Rate Order ...... ............ ......... .................... ................ ..... ...................................................1 0
2003 Earnings Reconciliation....................................... .......................................... .................................... .
Income Statement..................................................................................................................................... .
Page 17
IDACORP Inc. is a holding company
headquartered in Boise, Idaho. Idaho Power
Company (JPC), its largest subsidiary, is a
regulated utility engaged in the generation
transmission and distribution of electricity. Of
JPC's 2 912 megawatts (MW) of generation
capacity, 59% is hydroelectric power. JPC has
more than $2.8 billion in assets. Other IDA
subsidiaries include IDACORP Financial
Services, IDACOMM, ldaTech and Ida-West.
ldaTech is a developer of fuel cell technology
with a number of patents surrounding the fuel
reformer component. IDACOMMNelocitus, the
communications subsidiary, services customers
with fiber-based voice Internet and data
communications needs. The subsidiary has
launched trial projects to investigate Broadband
over Power Line (BPL), a technology allowing
Internet connection through standard wall outlets.
IDACORP Financial Services invests in
affordable housing and historic restoration
projects, creating tax advantages at the holding
company level. The Company is winding down the operations of IDACORP Energy, its electric trading
and marketing ann, which was a key driver in IDA's earnings growth in recent years. With the collapse of
trading, IDA has decided to exit this busil"leSS and has sold its rern..aining book to Sempra Energy Trading in
a transaction that closed in 3Q03. Ida-West, which focused on independent power projects, has ceased
development activities. Management is currently exploring options for the existing assets, which comprise
45 MW of generation capacity.
IDA CORP, Inc.
(IDA-NYSE)
January 6, 2005
Initiating Coverage
IDACORP, INC. AT A GLANCE
SUMMARY AND RECOMMENDATION
KeyBanc Capital Mar/(e/s
Division of McDonald Investments loc
Equity Research
Paul T. Ridzon
[phone]
pridzo n~ keybanccrn.com
Scott W. Hamann
[phone]
shamann~keybanccm.com
Price ............ ............. ...........
...................."... .
$29.
52 Week Price Range ..................................$25-$33
Rating....................................................... HOLD (3)
Fiscal Year Ends...................................... December
Book Value ....................................................$23.
DividendNield ........ ....... ....... ..... ............ $1.20/4.
EV/EBITDA 2004E.............................................. NA
EPS 2005E ....................................... ............... $1.
EPS 2004E ..... ................................................. $1.
EPS 2003A ............ ......".......................... ........ $1.
PIE 2005E .......................................................15.
PIE 2004E .......................................................15.
E.............................................................. 8.20/0
S&P 500 ..................... ......................... .......183.
PIE S&P 500 LTM............................................20.4x
Headquarters ...................... .................. Boise, Idaho
Business...... ....................................... Electric Utility
Long-Term Debt (mils) ...................................$985.
Shareholders' Equity (mils).............................$887.
Shares Outstanding (mils) ..................................41.
Market Cap. (mils)....................................... $1 ,224.
Closely Held..................................................... 1.30/0
Shares Traded (dly avg)...............................198,933
On January 3, 2005, we initiated coverage of IDA with a HOLD (3) rating at an opening price of
$30.58. Based on our 2005 estimate of $1.90 per share, IDA shares sell at an 11 % premium to the group
average PIE ratio of 14.1x. However, our 2005 estimate assumes that the utility company will be negatively
impacted by continuing pressure stemming nom long drought conditions. Normalizing for more historical
streamflow conditions, which we believe could total $0.10-$0.15 per share, shares would trade at only a
Page 18
KeyBanc Capilal MarlIets
Division of McDonald InvestmenlS Inc.
Equity Research
slight premium to the group average. We think this valuation is consistent with the stability offered by a
large retail shareholder base (58%) and the potential value of IDA's fuel cell subsidiary. This subsidiary
holds a number of patents and has a foothold on the fuel reformer component, an important and teclmically
challenging component. As fuel cells did previously, BPL technology has recently captured investor
interest.
KEY INVESTMENT POINTS
Our 2004 and 2005 estimates are both $1.90, although we note that our 2004 estimate includes
roughly $0.23 of unusual items. Our improved operational earnings for 2005 include a full year
rate relief and the assumption of normal precipitation for the primarily hydro generation fleet. These
are partly offset by a higher share count.
While our 2005 estimate assumes normal precipitation, a prolonged drought will preclude normal
streamflow, which we estimate could negatively impact earnings by $0.10-$0.15 per share relative to
normal streamflow.
Based on our 2005 estimate, IDA shares sell at an 11 % premium to the group average PIE ratio.
However, assuming more normal hydrology conditions, this premium drops to 3%, which we assume is
reasonable and is the basis of our HOLD (3) rating.
PRIMARY RISK FACTORS
We consider IDA's primary investment risk to be earnings volatility related to the impact of variable
precipitation levels on its sizable (1,700 MW) hydroelectric generation fleet. During periods of reduced
streamflow, IDA depends on more costly sources of power to meet its load requirements. IDA absorbs or
retains the first 10% of higher power supply costs (or benefit) relative to a benchmark stemming from
variations in power supply costs. This risk has been highlighted by five consecutive years of below normal
precipitation.
In addition, IDA was active in energy trading during the power crisis in the western United States and, as
such, has been named in a number of legal proceedings stemming from this situation. In addition, a decline
in power trading has reduced IDA's earnings, which has triggered a shareholder lawsuit alleging IDA
management did not offer adequate disclosure regarding the risk associated with energy trading.
An additional source of risk surrounds IDA's ability to renew licenses for its hydro facilities and the
potential costs associated with these license renewals. IDA has recently renewed a number of licenses at
smaller facilities.
BUSINESS SEGMENTS
iDAHO POWER COMPANY (iPC)
IPC has traditionally been the largest eamings contributor to IDA. IPC's operations cover a 20 000 square-
mile area and serve 436 400 residential and business customers in southern Idaho and eastern Oregon. The
majority of its general business revenue comes from customers within Idaho (95%). The rates charged to
these customers are adjusted annually based on a power cost adjustment (PCA) mechanism. The projected
growth rate for new customer additions going forward is 2-3%. IPC owns and operates 17 hydroelectric
power plants and shares ownership in three coal-flTed generating plants as well as natural gas and diesel-
fired capacity. IPC also has access to all major electric systems in the western United States through
interconnections with Bonneville Power Administration, A vista Corporation, PacificCorp, The Montana
Power Company and Sierra Pacific Power Company. IPC's system is dual-peaking with the winter-peaking
northern regions and the summer-peaking southern regions of the western interconnected power system.
Page 19
KeyBanc Capital Marltels
Division 01 McDonald Investments Inc.
EqiiIy Research
This dual-peaking system, along with the interconnections to the west, allow IPC to reach a broader power
sales market.
TABLE 1. UARTERLY SALES DISTRIBUTION
Electric Sales Electric Sales Electric Sales %of Year
Volume 2003 % of 2002 Volume 2002 % Of 2001 Volume 2001 2000 Average %
(GWh)Sales (GWh)Sales (GWh)Sales of Sales
813 21.010 23.3"10 248 25.23.30/0
191 24.60/.180 24.7"10 201 24.24.
974 30.738 29.0"10 525 27.1"10 28.9"10
002 23.964 23.022 23.2"10 23.1"10
Source: Compmy dale
IPC indicated that planned capital expenditure for 2004 is on track with the previously forecasted level of
$207 million. Utility capital expenditure is expected to be $643 million for the period 2004-2006. This
level exceeds IDA's forecast of internaIly generated funds after the payment of dividends. Management
expects that this $643 million wiIl be aIlocated approximately as follows: thermal generation (21%); hydro
generation (17%); transmission (20%); distribution (29%) and general plant (13%).
Principal commercial and industrial customers are involved in elemental phosphorus production, food
processing, phosphate fertilizer production, electronics and general manufacturing. Main drivers of the
business are the number of customers served, the rates that are charged and weather conditions.
Because of IPC's reliance upon hydroelectric generation to meet its generating needs, earnings can be
significantly affected by weather and water availability. In the past, under normal weather conditions
hydroelectric power supplies approximately 56% of generation, thermal generation 33%, and purchased
power and other interchanges supply approximately 11
%.
Table 2 breaks down IPC'stotal possible
regulated generation by source.
TABLE 2. GENERATING CAPACITY
Fuel
Hydroelectric
Coal
Natural Gas and Diesel
Total
Source: Canpanydata
acit
y (
1707
1110
2912
% of Total
58.
38.
100.
Over the past five years, IDA has experienced well below normal precipitation levels, adversely impacting
its low-cost hydro fleet and forcing the Company to fulfiIl its needs with higher cost fossil-flfed plants or
purchases. Power pricing volatility has dropped in recent years, mitigating the problem for IPC (and
negatively impacting the results of the now shuttered trading unit IDACORP Energy). Table 3 illustrates
the variability IDA has experienced in its markets.
TABLE 3. HYDROLOGY VARIATION
1999
% Normal Hydro 125%
Hydro Generation GWh 10,652Purchase Costs $IMWh $34
Off-System Sales $/MWh $20
Source: Canpeny data and McOonoJd Investmenls Inc,
2000
70%
500
$92
$51
2001
38%
638
$125
$92
2002
51%
069
$31
$27
2003
57%
200
$44
$39
2004E
52%
114
$45
$41
Purchases are generally made during peak demand periods and power is typically sold during off-peak
periods, resulting in the spreads between purchase costs and off-system sales pricing.
Page 20
KeyBanc Capital Markets
Division of McDonakllnvestments Inc.
Ecpily Research
IPC has identified a need to satisfy demand during peak periods. In February 2003 , IPC issued a request for
proposals for bids to construct up to 200 MW of capacity. The winning bid calls for construction of
Bennett Mountain Power Plant, a 160 MW gas-fIred turn-key unit to be developed for $61 million. This
unit was not included in IPC's recently concluded general rate case, so it is expected to be subject to
regulatory lag. IPC's latest resource plan, filed in August 2004, looks to increasingly utilize conservation
and demand side management. With regards to incremental need for physical resources, IDA looks to
utilize equally renewable resources and traditional thermal sources.
During the power crisis in the western United States, high purchased power costs due to drought conditions
and other issues in California skewed earnings to IDACORP Energy, which thrived on the uncertainty and
volatility in the markets. During this period of high pricing and poor hydrological conditions, IPC instituted
innovative programs to reduce demand, such as power buyback programs under which IPC essentially paid
customers (primarily irrigation customers) not to use power. This program has since expired and would be
unlikely to be repeated absent more extreme volatility. Another program instituted in 2001 was the Green
Energy Purchase Program. This is a voluntary program available to Idaho customers that allows them to
pay a premium for energy that is generated using alternative sources such as wind and solar. This program
is viewed as a way to pique customer interest in alternative sources of energy and their development.
IPC contributed $1.44 per share in 2003 vs. $2.24 in 2002. 2003 results included a $0.16 per share benefit
from the resolution of tax issues. However, 2002 results reflected a change in accounting methodologies
that produced a tax benefit of $0.92 per share and a regulatory charge of $0.19 per share.
IDACORP ENERGY
IDA is in the final stages of winding down its gas and electric trading operations under IDACORP Energy.
During the western U.S. power crisis, IDACORP Energy was able to add substantially to IDA's earnings
through geographic arbitrage, as the subsidiary was able to capitalize on transmission rights and move
power from lower cost regions into those areas experiencing power shortages. As volatility subsided and
credit issues impacted the trading sector, IDA management no longer considered IDACORP Energy
strategic and started winding down operations in 2002. The remaining book of business was sold to Sempra
Energy Trading in 3Q03. Remaining issues at energy trading include ongoing exposure to the credit risk of
one counterparty, with the maximum amount payable by IDA totaling $20 million, and ongoing litigation
surrounding the western U.S. energy crisis. IDACORP Energy s earnings were a loss of $0.25 per share in
2003, including a $0.19 loss on a legal settlement offset by a $0.26 gain on the sale of energy contracts.
IDA-WEST
Ida-West Energy is IDA's independent power subsidiary focused on the development of umegulated
electric power projects. Currently, Ida-West owns nine hydroelectric projects with total generating capacity
of 45 MW. As part of a strategic refocusing, IDA has ceased further development in merchant generation.
IDA management is now contemplating whether to divest the business or continue operation of the existing
projects. Ida-West lost $0.13 per share in 2003 , including a $0.13 writedown ofassets.
IDACORP FINANCIAL SERVICES
IDACORP Financial Services invests in affordable housing and historic preservation projects that provide a
return by reducing federal income taxes through tax credits and tax depreciation benefits. IDACORP
Financial Services contributed $0.27 per share to 2003 earnings. IDA has de-emphasized growing this
segment, instead directing capital toward utility infrastructure investment. IDA has targeted 2004
investment of $20 million in this business segment. Investment in this subsidiary totaled $160 million at
the end of2003 , including more than 700 properties geographically diversified throughout the United States
and its territories.
Page 21
KeyBanc Caplal Marlcets
Divisioo 01 McDonald Inves1IIIents Inc.
Equity Research
IDACOMMNELOCITUS
IDACOMM, originally a business unit of IPC, acquired Internet service provider Rocky Mountain
Communications, Inc. (RMCI) in August 2000 to provide telecommunications services using fiber optic
technology. IDACOMM focuses on custom fiber networking solutions. Products offered are voice-over-
IP, video conferencing, training services and ethernet service. IDACOMM serves various industries,
including manufacturing, healthcare, food processing, retail, government and education. Currently, the
Company is exploring technical feasibility and marketability of Broadband over Power Line (BPL)
technology. The Company is interested in this technology because much of the necessary infrastructure is
already in place (existing power lines), allowing access to a large market. The technology could also offer
improved customer service by allowing more pinpointed system monitoring.
Velocitus offers high-speed Internet access as well as support and other services in both residential and
business markets to approximately 20 000 customers. Velocitus is a managed service provider of IP
service, private networks, Internet hosting, flTewalls and last mile solutions such as DSL, Tl, ISDN, frame
relay and DS3. IDACOMMNelocitus has established markets in 22 medium-sized western u.S. cities and
continues to look for expansion opportunities. IDACOMM lost $0.05 per share in 2003.
ICATECH
In March 1999, IDA purchased a majority interest in IdaTech, formerly known as Northwest Power
Systems. The Company currently has two main product lines: fuel processors and fuel cell systems.
IdaTech's fuel processor allows for the processing of a number of fuels into hydrogen that is then used for
the generation of electricity. The fuel processor is a significant development for IdaTech due to its small
size, efficiency and the high-quality hydrogen it produces. The fuel processor can produce hydrogen from
most common fuels, including methanol, ethanol, natural gas, propane, kerosene and diesel. IdaTech
employs a steam reforming process through which it is able to produce hydrogen that is 99.95% pure. This
is better than other processes, such as partial oxidation with steam reforming and partial oxidation, which
can only produce hydrogen that is 50-60% pure and 40-50% pure, respectively. IdaTech currently has 21
patents in the United States and abroad.
The fuel reformer operates at very high efficiencies, which also contributes to greater fuel cell performance.
Since waste gases from the steam reforming process serve as fuel to heat the reformer and raise steam, the
efficiency is close to its theoretical limit. The numbers from IdaTech in Table 4 show that there is very
little room for improvement on efficiency as the processor is well insulated and heat loss is minimal.
IdaTech lost $0.04 per share in 2003 including a $0.06 per share gain related to a contract settlement.
IdaTech also sells its fuel processors to other fuel cell companies.
TABLE 4. EFFICIENCY OF FUEL SOURCES
Fuel
Methanol
Methane
Biodiesel
Diesel
Sow,,": Company data
Experimental
Efficiency
86-90%
67%
55%
65%
Theoretical
Efficienc
87%
66%
61%
66%
The fuel cell system IdaTech developed has experienced successes in recent years. In 2000, testing was
completed for its fIrst patented alpha fuel cell system for residential applications. That same year the first
of 110 fuel cell systems was delivered to Bonneville Power Administration. The Company recently was
awarded a Department of Energy program for the development of a 50 kilowatt (kW) fuel cell system
suitable for powering large facilities including multi-family dwellings and office buildings. Three
prototype units will be tested In November 2003, IDA unveiled a 5 kW system capable of operating with
natural gas and liquid propane fuels. IdaTech has been awarded two Department of Energy grants for fuel
Page 22
KeyBanc Capital Marlcets
Division ri McDonald Investments Inc.
EQIity Research
cell development. In October 2003 , Ida Tech was awarded $9.6 million to develop a 50 kW system suitable
to power large facilities. A second $1.4 mil1ion award in November 2004 was to fund exploring fuel cell
solutions to power off-road vehicles, which operate in a chal1enging environment of dirt, varying weather
and shock and vibration. Significant IdaTech partnerships include an agreement with Volkswagen to work
on a diesel fuel automotive fuel cell and an agreement between Bosch subsidiary Buderus and German
utility RWE subsidiary RWE Fuel Cells to develop a 5 kW combined heat and power system. IdaTech and
RWE had a previous agreement to develop multi-unit residential and light commercial systems up to 50
kW.
POWER COST ADJUSTMENT MECHANISM AND REGULATORY ISSUES
The annual variability in precipitation has a significant impact on the amount of IDA's hydroelectric
generation output. In years with little precipitation, IDA must rely on more expensive thermal generation
and purchased power. When forced to obtain power from the wholesale market, IDA's purchase costs are
above the embedded cost of its 1 707 MW hydroelectric fleet.
In its Idaho jurisdiction, IDA is permitted to recover most (90%) of these higher costs from customers
through its Power Cost Adjustment (PCA) mechanism. Conversely, in years with high levels of
precipitation and streamflow, IDA retains 10% of the benefit of this low-cost power. Customers receive a
surcharge or credit on their bills to account for any undercollections or overcollections, respectively. The
PCA will adjust customer rates to show the changes of the costs incurred by IPC to supply power.
Adjustments to the PCA are generally made annually and take effect on June I. Adjustments are made of
two components; one is based on a prospective forecast for power costs for the coming period that is
analyzed throughout the year, and the second is a true-up for the prior year s forecast (with accrued
interest). The variance between the actual costs incurred and the forecasted cost is then deferred, with
interest and trued-up expenses in the next annual rate adjustment.
Table 5 indicates the 1998-2004 PCA filing outcomes (relative to base rates in 1993, when the PCA
program was instituted) and true-up components.
TABLE 5. DETAIL OF ANNUAL PCA OUTCOMES
Rate Period
1998-1999
1999-2000
2000-2001
2001-2002
2002-2003
2003-2004
2004-2005
Source: Company data
PCA Level
$17,3 million
$23.3 million
$14,8 million
$219.9 million
$255.9 million
$81.2 million
$70,1 million
True-Com onent
$15.5 million
$0.3 million
$5.0 million
$170.9 million
$227.4 million
$38.7 million
. $42.8 million
The combination of low hydrology and the related run-up in wholesale power prices during 2000 and 2001
caused actual power costs to vary meaningful1y from forecasts. In May 2001 , the Idaho Public Utilities
Commission (IPUC) authorized $168.3 mil1ion of IDA's $227.4 million request and deferred the balance
until it had the opportunity to more closely examine the request. The IPUC indicated that it wished to look
more closely at transactions between IPC (the regulated utility) and IDAHO Energy (the unregulated
marketing and trading arm). In late September 200 I, the IPUC authorized IDA to collect $47.7 million of
the deferred $59.1 million balance (with $1.2 million in accrued interest). The remaining $11.4 million has
been written off.
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KeyBanc Capital MarlcelS
Division of McDonald Investments Inc.
Equity Research
We view this ruling by the IPUC favorably for two reasons. Firstly, we believe that the decision clears the
Company of any questions regarding the propriety of its intercompany transactions. Secondly, and more
importantly, we believe that the concept of the PCA has been stress-tested under the severe conditions
imposed by the unprecedented volatility witnessed in the impacted periods.
At September 30 2004, IDA's deferred PCA balance was rougWy $57 million, comprised of the following:
Remaining balance from May 151 PC A rate adjustment: $21.5 million
Costs incurred to be trued up in 2005-2006 rate year: $23.2 million
Oregon Deferral: $12.5 million
In its Oregon jurisdiction, IDA's ability to collect underrecovery of purchased power costs was limited to
arumal increases of 6% of gross Oregon revenues, which is rougWy $2 million. During 2003, the law was
changed to permit 10% annual increases. IDA requested and received this higher increase (approximately
$3 million) in 2004, which will allow more rapid recovery of the $12.5 million balance.
On October 16 2003 , IPC filed a general rate case with the IPUC. IPC's last general rate case was filed in
1994. The filing requested a revenue increase of $85.6 million annually. The request was based on a
proposed return on equity (ROE) of 11.2% and rate base of $1.547 billion, of which $692 million is
comprised of equity. Previously the utility was permitted to earn a ROE of 11 %. In the 1994 rate case, the
equity component of utility capitalization was determined to be approximately $600 million. IPC
subsequently lowered its request for rate relief to an increase of $70.7 million when projections were
updated.
On May 25, 2004, the IPUC authorized a $25.3 million rate increase based on a 10.25% ROE and $1.52
billion rate base, of which $698 million is equity financed. The difference between the requested $70.
million and $25.3 million granted is outlined in Table 6.
TABLE 6. RECONCILIATION OF RATE ORDER
Item
Rate of Return
Update Projections to Actual Results
Prepaid Pension and Pension Adjustments
Payroll-Related Adjustments
Tax Normalization
Other
Source: Company data and McDonald In""Slmen.. Inc.
Impact
$12 million
$4 million
$7 million
$8 million
$12 million
$2 million
The tax normalization item relates to the 2002 change in IDA's tax accounting methodology that resulted in
a $41 million tax refund, which would be reflected in higher future taxes. The IPUC opted to hold IDA
accountable for the resulting higher taxes, rather than the ratepayers.
IDA requested rehearing of the IPUC order for the tax issue, clarification of certain calculations and
reconsideration of a legal expense disallowance. The IPUC agreed to reconsider the tax issue and granted
an additional $2.7 million relating to certain calculations. IPC reached a settlement with parties to the case
allowing $11.5 million of the disputed tax issue to be included in rates.
Under this settlement, these revenues would be deferred from June 1 , 2004 until May 31 , 2005 for recovery
under the PCA mechanism for one year starting in spring 2005, after which the tax amount would be
collected in base rates.
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KeyBanc capital Markels
Division 01 McDonald Inveslments Inc.
fqlily Resean:h
A second settlement relates to summer 2003 replacement power costs stemming from an unplanned outage.
Under this agreement, which was approved by the IPUC, IPC will issue a $19 million credit to ratepayers
through the PCA during the June 2004 to May 2006 period.
On September 21, 2004, IDA filed with the Oregon commission an application to raise rates 17.5%, or
roughly $4 million. In late October 2004, the commission suspended the request for no more than nine
months to consider the propriety and reasonableness of the requested rate increase.
REGIONAL TRANSMISSION ORGANIZATIONS (RTO)
In December 1999 the Federal Energy Regulatory Commission (FERC) issued order 2000, which is a
follow-up to orders 888 and 889 stating that each public utility that owns, operates or controls facilities for
the transmission of electric energy in interstate commerce make certain filings with respect to forming and
participating in an RTO or state why it cannot. The FERC's goal is to promote efficiency in wholesale
electricity markets and ensure that electricity consumers pay the lowest price possible for reliable service.
In response to the proposed FERC Order 2000, IPC and other regional providers filed in October 2000 a
plan to form RTO West (since renamed Grid West) to operate the grid in the northwest United States and
British Columbia. The group has since responded to FERC comments and refined its proposals. Cun-ently
the Grid West is preparing for an implementation order by creating bylaws. An executive search is
anticipated to identify potential members of the board
CALIFORNIA ENERGY PROCEEDINGS
IDA is the subject of multiple proceedings related to the western u.S. power crisis. In January 1999, IPC
entered into a participation agreement with the California Power Exchange (Ca1PX). At the time, the
CaIPX acted as a clearinghouse through which wholesale electricity was bought and sold. Under this
agreement IPC was able to sell energy to CalPX under the terms and conditions set forth by the CaIPX
Tariff. The participation agreement stated that if a participant in the exchange defaults on a payment to the
exchange, the other participants would pay their allocated share of the default amount to the exchange. The
allocated share was based on the level of trading activity, which includes both power sales and purchases
for the preceding three months. The FERC ordered that chargeback actions be rescinded, and a
methodology for refunding funds is awaited from the FERC.
California has made efforts to collect refunds for power purchases, claiming prices were not just and
reasonable. The FERC issued an order on refund liability and ordered the California Independent System
Operator (Cal ISO) to make a filing regarding refund amounts. At December 31 , 2003, CaIPX and Cal ISO
owed IDA $44 million ($14 million and $30 million, respectively). IDA has established a $42 million
reserve against this amount. IDA believes that the impact of net receivables or potential refund will not
have material fmancial impact.
Additional proceedings were initiated in the northwest United States based on the argument that
dysfunctional market conditions warranted refunds. The FERC rejected ibis claim and a subsequent request
to rehear the matter. The matter is currently under appeal.
In two separate cases, an appeals court has ruled that the FERC pennits parties to submit information
demonstrating market manipulation. The FERC ordered that parties, including IDA, demonstrate that they
did not engage in manipulation. IDA reached a settlement with the FERC on the matter. The FERC
dismissed a proceeding related to "anomalous market behavior." These matters are the subject of review
petitions, but IDA's settlement does not fall under this request.
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KeyBanc Capital Marllets
Division 01 McDonald Inveslmen/s Inc.
Equiry Research
The FERC has issued an order to investigate bidding behavior in the western U.S. markets, to which IDA
has responded with all requested information. IDA believes that any action by the FERC on this matter is
unlikely to have a material financial impact.
ADDITIONAL SECURITY OFFERINGS
IDA currently has two shelf securities registration statements totaling $800 million. These securities may
take the form of unsecured debt, preferred stock or common equity. Of a $300 million first mortgage shelf
filed in early 2003, $55 million remained at September 30, 2004. IPC plans to me an incremental $300
million fITst mortgage bond shelf statement in 4QO4. IDA management recently announced that it is
considering issuing incremental equity to provide capital for IPC utility investment and to strengthen the
balance sheet. At September 30, 2004, IDA's debt-to-capital stood at 56%. Management has indicated that
it sought to bring this ratio to a range of 50-56%. On December IS, 2004, IDA issued 3.5 million shares at
$30 per share. We expect that with an over allotment exercise, total proceeds will utilize approximately
$120 million of the securities registrations.
CREDIT FACILITIES
IDA's credit facilities include a three-year, $150 million facility entered into in March 2004, replacing a
$175 million facility expiring March 2004 and a $140 million facility that would have expired in March
2005. The $150 million facility is at the parent level and provides funding for general corporate purposes
and backing up commercial paper. At September 30, 2004, the facility was undrawn, IDA had $60 million
of commercial paper outstanding, and the Company had approximately $21 million in cash and equivalents
on its balance sheet.
IPC entered a three-year, $200 million credit facility in March 2004, replacing an existing $200 million
facility. The facility is for general corporate purposes and backing up commercial paper. At September 30
2004, the facility was undrawn and IPC had $22 million of commercial paper outstanding.
EARNINGS AND DIVIDEND OUTLOOK
GAAP earnings in 2003 were $1.22 per share. Earnings by business segment are shown in Table 7.
TABLE 7. 2003 EARNINGS RECONCILIATION
Segment
Utility
IDACORP Energy
IDACORP Financial
Ida-West
IdaTech
Other (Holding Company)
Source: Company Data and McDonald Inveslry1anls Inc,
GAAP
$1.
($0.25)
$0.
($0.13)
($0,04)
$0,
erational
$1.
($0.32)
$0.
$0.
($0.10)
$0.
These results also include a number of unusual items. The utility operations realized the benefit of a $0.
per share IRS settlement resolving tax years 1998-2000. Ida-West had further writedowns of $0.13 per
share. IDACORP Energy realized a $0.26 per share gain on the sale of energy contracts, partly offset by
$0.1 9 of losses stemming ITom settlements to resolve issues surrounding a power contract. Ida Tech realized
a gain of approximately $0.06 related to the design production and delivery of fuel cell systems. Absent
these items, earnings totaled $1.06 per share. However, included in this are elevated costs related to the
winding down of IDACORP Energy trading operations.
IDA management's 2004 earnings guidance is a range of $1.80-$2.00 per share, with utility operations
contributing $1.65-$1.75. This guidance includes the impact of several unusual items. In the 2Q, the utility
Page 26
KeyBanc Capital Markets
Division of McDonald InvestmelfS Inc.
Equily Research
wrote off $0.15 per share related to the disallowance of certain capitalized compensation and pension
spending in lPC's recent rate case , IDACORP Financial realized a $0.05 per share gain on the sale of a
property, Ida-West benefited by $0.05 from a debt extinguishment and IDACORP Energy earned $0.
related to settling outstanding litigation. In the 3Q, the utility recorded a $19.3 million regulatory liability
associated with its rate case settlement of purchased power costs stemming from plant outages in summer
2003, recorded a $4.4 million regulatory asset related to the settlement of its tax rate issues raised in the
recent rate case, and also reversed a tax liability of roughly $16.5 million, netting an earnings benefit of
$0.21 per share. These issues pushed earnings above an incentive compensation threshold, which resulted
in $0.06 per share of increased expenses. Results in the 3Q also had an additional $0.04 per share of
IDACORP Energy earnings stemming from litigation settlement. IDA's 3Q results also were adversely
impacted by a $0.05 per share premium related to retiring preferred stock. Included in the 2004 utility
earnings guidance of $1.65-$1.75 is approximately $0.19 (which nets to $0.11 per share after incentive
compensation) related to the expected 4Q reversal of a 2002 regulatory disallowance of the recovery of
revenues related to a program whereby irrigation customers were compensated to reduce power usage. IDA
has indicated that through 3Q04, poor hydro conditions have had an estimated negative impact of $0.18 per
share.
Our expectation for 2004 GAAP earnings is $1.90 per share. Adjusted for $0.22 per share of benefit
from unusual items discussed above, we look for operating earnings of $1.68 per share vs. $1.06 per share
the prior year. Major drivers for the earnings improvement vs. 2003 include the partial year benefit of the
IPC general rate case and elimination of expenses related to exiting the energy trading business at
IDACORP Energy. We expect that the benefit of rate relief from June I will add roughly $0.20 per share.
Also at the utility, net power supply costs are expected to be lower as higher volumes and pricing of off-
system sales should more than offset higher fuel and purchased power costs. The year has also seen very
strong customer growth. As Ida-West is de-emphasized and expenses decline, we look for the segment to
be modestly profitable for the year.
Our 2005 estimate is $1.90 per share. Drivers behind the year-over-year improvement include a full year
of rate relief stemming from the 2004 resolution of IPC's general rate case. We also assume that
precipitation for the year will be normal, after five years of drought. However, we assume that normal
precipitation does not translate into normal streamflow conditions, owing to the fact that aquifer recharging
will absorb much of the water before it reaches the river. Additionally, we expect IDA to seek rate relief
for the $61 million Bennett Mountain Power Plant, and look for a mid-year implementation into rates. We
look for these benefits to be partly offset by a higher share count stemming from IDA's recent equity issue.
Given IDA's recent dividend cut, we believe that management s near to mid-term focus will be allocating
capital to utility investment. We therefore would not expect to see dividend growth in the next few years.
Page 27
KeyBanc Capital Markets
A Division of McDonald Investments Inc.
Equity Research
TABLE 8.INCOME STATEMENT
($ in million, except per share items)
2001 2002 2003 2004E 2005E
OPERATING REVENUES
General Business 650,772.671.634.651.
Off-System Sales 220.0 55,71.119.114,
Other 43.42.40.2 51.34.
Total Electric UtiUty Revenues 914,869.782.805.800.
Energy Marlteting 348.46.19.-0,
Earnings in Unconsolidated Partnerships
Other 13.13,20.21.13.
Total Diversified Rewnues 361.59.40.20.13.
TOTAL OPERATING REVENUE 275.928.823,826.813.
OPERATING EXPENSES
Fuel 98.102.99.102.103.
Power Purchased 584.142.151.189.101.
Power Cost Adjustment 176,170.70,35.45.
Operation & Maintenance 211,207.221.236.249.
Depreciation & Amortization 87.93.97.102.108.
TiDIes Other than Income Taxes 19,20,20,20.20,
Energy Marlteting
Cost of Commodities and Services 105,42.
Selling, Administrative and General 66.30,24,
Loss on Legal Disputes 12.-4.
Other 37.44.40.35,28.
TOTAL OPERATING EXPENSES 033.853.738.718.657.
OPERATING INCOME
Electric Utility 90,132.121.119,172,
Energy Marltetlng 176.26.17.
Other 24,30.19,14.15.
OPERATING INCOME 242,75,84.107.155,
OTHER INCOME
AFUDC - Equity
Gain on Asset Sale
Other - Net 23.10,
TOTAL OTHER INCOME 23.10,
INTEREST AND OTHER CHARGES
Long-Term Debt 56.54,58.60.60,
Other Interest 14.10.
AFUDC - Debt
Preferred Dividends of Subsidiary
TOTAL INTEREST AND OTHER CHARGES 75,68.64.68.63.
INCOME BEFORE TAXES 189.10.25.49.97.
Income Taxes 64,51.21.23,17,
NET INCOME 125.61.46.73.80.
Discontinued Operations
Gain on Sale 01 Business 10.
Gain on IdaTach Contract Settlement
Net Result of Rate Case Settlements
Rate Case Disallowances
Premium for Refinancings
Gain on Debt Extinguishment
Tax Reserve Rewrsal 16,
Idacorp Energy Contract Settlements
ADJUSTED OPERATING EARNINGS 125.51.40.54.eO.
OPERATING EARNINGS PER SHARE $3.$1.$1.$1.68 $1.
EARNINGS PER SHARE $3.$1.$1.$1.90 $1.90
COMMON DMDENDS PER SHARE (PAID)$1.$1,$1.70 $1,$1.
COMMON DMDENDS PER SHARE (YEAR-ENDRATE)51,$1.51.20 $1.$1.20
PAYOUT RATIO 55.113,98.63.63.
SHARES OUTSTANDING. AVERAGE (MILLIONS)37,37.38.38.42,
SHARES OUTSTANDING - YEAR-END (MILLIONS)37,38.38.42.42.
Net Stock Issued 124
Stock Price
Shares 016 394 179 133 143
Page 28
KeyBanc Capital Markets
A Division 01 McDonald Investments Inc.
Equiry Research
IDACORP, ITIC. -IDA KeyBanc Capital Afarlrets Disclosures and Certifications
We have managed or co-managed a pub/c dfering d equity securities for this company oMthin the past 12 months.
This company is an investment barieing client 01 OIlS.
We have received compensation for investment banking servces from ttis company during the past 12 morths.
We expect to receive or intend to seek compensation for investment bankilg services from this company within the next three months.
During the past 12 months, this company has been a client d the linn or ts affiiates for non-secudies related servces.
Reg AIC Certification
The research analyst responsible for the preparation of this research report certifies that:(1) all the views expressed in this research report accurately
reflect the research analysts personal views about any and all d the suq;ect securities or issuers; and (2) no part d the research analysfs
compensation was, is, or will be directly or indirectly related to the SpecifIC recommendations or expressed by the research analyst in this
research repat.
IDA Three-Year lUting and Price Target "sICIlY
..'..'..,
~ 132
D'"_201M
---
HOU)f3)_1311,
-,-..,.........--.-
J--.2OCI2
lUting DiscloSIRS
48,3% d all equity securities that we cover are rated BUY'
47.8% d all equity securities that we cover are rated HOLD.
9% d all equity securities that we cover are rated SELL
33.7% d all equity securities that we rate BUY' are investment banking clients from which we have received compensation for investment banking
services during the past 12 months.
17.8% d all equity securities that we rate HOLD are investment banking clients from which we have received compensation for investment banking
services during the past 12 months.
7% d all equity securities that we rate SELL' are investment banking clients from which we have received compensation for investment banking
servces during the past 12 months.
Energy Rating Disclosures
38,8% d all Energy Industry equity securities that we cover are rated BUY'
59,7% d all Energy Industry equity securities that we cover are rated HOw.
5% d all Energy Industry equity securities that we cover are rated SELL
53,8% d all Energy Industry equity securities that we rate BUY' are investment banking clients from we have received compensation for investment
banking services cllling the past 12 months.
35.0% d all Energy Industry equity securities that we rate HOLD are investment banking clients from which we have received compensation for
investment banking services during the past 12 months.
0% d all Energy Industry equity secudies that we rate SELL' are investment banking clients from which we have received compensation for
investment banking services during the past 72 months.
Please Note: 'BUY" represents an aggregate of all AGGRESSIVE BUY (1) and BUY (2) rated equity securities,
SELL'represents an aggregate d all UNDERWEIGHT (4) and SELL (5) rated equity securities.
Rating System
AGGRESSIVE BUY (1) . The security is expected to outperform the market over the short tenn; investors should consider adding the security to their
portfolios, suq;ect to their overall dversification requirements.
The security is expected to outperform the market over the long tenn; investors should consider adding the security to their
holdings opportunistically, suq;ect to their overall diversifICation requirements.
HOLD (3) The security is expected to perform in line with general market indices; no buy or sell action is recommended at this time.
UNDERWEIGHT (4) - The security is expected to underperform the market investors should reduce their holdings opportunistcally.
SELL '5 Absolt1e downside risk is evident for the sec " ;rrvestors should uidate their hold;
KeyBanc Capital Markets is the trade name under which the corporate arK! investmert banking products and services KeyCorp and ks subsidiaries,
including McDonald Investmerts loc.. member NYSElNASDISIPC, are marketed to institutional dents.
BUY (2)
Page 29
- ':~. \'
/ E D
. "
, :~ c; \ (; PH L\: ~:; '3
' ,
:r.SS1 0\ I
IDAHO POWER COMPANY' ,
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
0 F ID AH PO WE R
ATTACHMENT TO
RESPONSE TO
REQUEST NO.
,.,
Global Credit Research
Summary Opinion
11 May 2005
Moody's Investors ServIce
Summary Opinion: Idaho Power Company
Idaho Power Company
Opinion
Credit Strengths
Credit Strengths for Idaho Power Company (IPC) are:
- Parent's common equity infusion supports capital program
- Parent's 35% lower dividend since September 2003 allows IPC to retain more cash
- Support provided by the power cost adjustment mechanism (PCA)
- low production costs under normal hydro conditions
- Ongoing cost control efforts
Credit Challenges
Credit Challenges for IPC are:
- Overcoming lower than requested rate increase approved against a backdrop of customer growth, additional capacity needs, and plans
to expand the T&D system
- Costs and potential operational changes tied to hydroelectric plant relicensing process
- Coping with effects of drought and unfavorable weather
- Obtaining supportive regulatory outcomes in expected future filings for rate increases
Rating Rationale
IPC's A3 senior secured rating reflects financial and operating challenges as it seeks relicensing of hydro plants and increases capital
expenditures to add capacity in 2005, The A3 rating also takes into account that IPC's utility rates remain below national averages, that it has
a generally low business risk profile, and that it is pursuing strategies to control operating expenses and conservatively finance utility
investments.
Under normal hydro conditions IPC's production costs are among the lowest of any in the U,S" reflecting a large hydroelectric capacity
base and shared ownership of reasonably economic coal-fired plants. Also, evidence of some supportive treatment from the Idaho Public
Utilities Commission (IPUG) is apparent from the PCA in Idaho, which minimizes negative effects on eamings and cash flow when net power
supply costs exceed forecast levels in existing rates.
The IPUC's reconsideration of the $25,3MM rate increase approved in May 2004 was resolved in September 2004 through settlements
that brought the total rate increase amount approved to roughly $40MM, Because the approved rate increase was still only a little more than
half of management's updated request, we expect that IPC will continue to consider delay of nonessential capital expenditures and look for
ways to further tighten its O&M expense budget.
Despite higher eamings in part due to the benefits of colder winter weather compared to 2003, IPC's contribution to IDACORP'
consolidated eamings and cash flow in 2004 were still adversely affected by lingering drought conditions. An added future challenge lies in
overcoming the lower than requested rate increase approved in 2004, as well as obtaining support in subsequent rate proceedings. IPC'
latest rate case was filed in early 2005 and includes a request for recovery of and retum on a new generation plant which was tested, ready
for operation, and provisionally accepted on March 31 , 2005, Meanwhile. IPC has previously issued long-term debt to reduce its overall cost
of capital. This activity and a late 2004 common equity infusion by IDACORP has reduced IPC's reliance on short-term debt and helped
maintain sound utility capitalization ratios, Moreover, IPC recently amended its bank credit facility to lengthen the term to expiration and
obtained less restrictive terms and conditions,
Rating Outlook
IPC's stable rating outlook reflects a continued focus on regulated electric utility operations, which have a relatively low business risk
profile and with the help of a PCA mechanism tend to be a stable source of earnings and cash flow. The outlook also assumes that IPC can
adequately cope with its remaining challenges, induding through prudent management of its large capital program such that state regulators
Page 32
( -'
are likely to be supportive of IPC's Mure requests for recovery of and return on those investments.
What Could Change the Rating. UP
Near term challenges related to a large capital program make an upgrade unlikely in that time frame, However, IPC's outlook or rating
could improve over the intermediate term through a combination of drought abatement, regulatory support in Mure rate proceedings, and
reduced capital spending that fosters positive free cash flow to be used for significant debt reduction.
What Could Change the Rating. DOWN
Continued delay in retum to more normal hydro conditions. Significant increases in relicensing costs and/or stringent operational
constraints imposed as part of the license renewal process. lack of IPUC support in future rate proceedings. Any unexpected change that
compromises the PCA mechanism. Any shift by IDACORP to pursue significant, debt-financed investment in more risky non-regulated
businesses that increases demand on IPC cash flow,
(!;) Copyright 2002 by Moody s Investors Service, 99 Church Street, New York, NY 10007, All rights reserved.
Copyright 2005, Moody s Investors Service, Inc, and/or its licensors including Moody s Assurance Company, Inc, (together, 'MOODY'S'). All
rights reserved,
Page 33
" ;\JFf-
' ,,-, , ~,-
r:!';
r l6 P;'j L!: 53
IDAHO POWER COMP ANY"!:s (:(;;""55101;
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
OF IDAHO POWER
ATTACHMENT TO
RESPONSE TO
REQUEST NO. to
\I I
. '
I D.A. DaVIdson & Co.
FY Dee
Revenue ($M)
Previous
PricelRevenue ratio
EPS Revised
Previous
PricelEPS ratio
EBITDA ($M)
EV IEBITDA ratio
Institutional Equity Research
IDACORP, INC.
IDA - NYSE
Y -0- Y y-o-Y
2004A 2005E Growth 2006E Growth
$844.5 $884.$929.4
$894.4 $928.
1.3x 1.4x 1.3x
$1.90 $1.60 16%$1.76 10%
$1.82 $1.92
14.17.16.
$256.$285.11%$302.
7.4x
EPS EPS Revenue Revenue EBITDA
Previous Previous
SO.$0.$203.$210.$77.
$0.$0.44 $232.$236.4 $63.
SO.$0.$252.$253.5 $78.
SO.$0.$196.$193.$65.
member SIPC
April 11,2005
Rating:
NEUTRAL
Price: (4/8/05) $28.
Price Targets:
12-18 month: $27..j..
year: $34
Industry:
Utilities
James L. Bellessa, Jr., CFA
406.791.7230
jbellessa~dadco.com
Company Description:
Boise, ID -- IDACORP, Inc. is the holding
company for the 90-year old Idaho Power
Company, an electric public utility that
serves an approximate 24 000 square mile
area in Southern Idaho !lid Eastern Oregon,
Company is wrapping up its exit from
IDACORP Energy, a previously importart
subsidiary engaged i1 the marketing of
energy and energy related products and
services, and its wind-down of
Ida-West, a power project development
company.
uarterl Data:
3/31/05E
6/30/05E
9/30/05E
12/31/05E
See details of foolnote on page
Valuation Data
Long-term growth rate (E)
Total Debt/Cap (12/31/04)
Cash per share (12/31104)
Book value per share (12/31/04)
Dividend (yield)
Return on E ui (f-
52,
$1.30
$23,
$1,20 (4.3%)
Tradin Data
Shares outstanding (M) 42,
Market Capitalization (SM) $1 186
52-week range $25.30 - $32,
Average daily volume (3 mos.) (K) 239Float 99%
Index Membershi S&P 400 MidC
Lowering EPS Projections Again for Drought and Cost Pressures.
Reducing Target Price to $27, but Maintaining NEUTRAL Rating.
We are significantly decreasing our 2005 and 2006 EPS projections for
IDACORP. We believe the effects of a 6-year drought are increasingly
combining with rising operating expenses to reduce the outlook for utility
earnings below our previous forecasts. Our new estimates are shown above.
We are also reducing our EPS estimates as a cautionary response to the
company s decision not to provide earnings guidance. Without such guidance
there are limited means by which to cross-check our forecasts.
Our new earnings estimates for 2005 and 2006 assume a non-utility EPS
contribution of$0.08 and $0., respectively. Additionally, we assume a rate
increase of 10,,0-.2% for the rate basing of the Bennett Mountain Power Plant, and
a $0.02 per share annualized cost of adopting stock-based compensation.
Low streamflows and mild temperatures should hold back 2005 results. The
company s low cost hydrogeneration is now expected to be 5.5 million MWh in
2005, compared to nonnal generation of9.2 million MWh and 6.0 million MWh
in 2004. Also, 1 Q'05 temperatures, as measured by heating-degree days in
Boise, were 9% wanner than nonnal and 5% wanner than a year earlier.
We are lowering our short-tenn target price by two points to $27, or 15.3x our
revised 2006 EPS estimate. Given that the stock is trading near this target, we
are maintaining our rating of NEUTRAL. The company reports lQ'05 results
on May 5, 2005 and our EPS projection is $0.54 vs. $0.51.
Please refer to pages 5-6 of this report for detailed disclosure and certification information.Page 34
A. Davidson & Co.
Price Chart
' 92:,95 Dai Iy
Z7.IIZ
1. 311
1. 1M
B"!B ,ilia
" 6011,9111
3611, 9111
lZII,8aI
Source: ILX
31. .qe
""117
11111 11111111111111 111111111111111111111111111111111111111111111111111111011111111 111111111111 1IIIIIIIIIIIIII IIIIIIIIIIIIIIIIIII,IIIIdlllllllllllllllllllllllllilLI1111
4'1I"!
Footnote references from page 1 of this report
Includes 2Q'04 charge of$0.15/sh. for IPUC disallowance of incentive pay and pension costs. Includes 4Q'04 benefit of $0.2 I/sh.
from reversal of 2002 "lost revenue' charge , offset in part by a resulting $0. I 4/sh. increase in employee incentive costs.
31.1111
...
38.
31LZII
Z9.
Z9,
Z9.
ZB,
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Z7.BII
Z7."!B
5"11&1'11'1 1iVII"!1/11""85 VII711/111 1VB6
Page 35
A. Davidson & Co.
ACORP, Inc.Balance Sheet
mousands - Fiscal year ends 12/31
2000 2002 2004
ASSETS:
Electric Plant
In service (at original cost)$2,799 874 990 000 $3,086 965 $3,220,228 324 816
Accumulated provision for depreciation 1 1425721 1 2 0 0001 94 9611 604 (1 316 1251
In service - net 657,302 770,000 792,004 980,624 008,691
Construction worll in progress 136 388 96 ,000 209 96,091 152,427
Held for Mure use 167 000 335 2.438 838
Other property, net of accum. Deprecialior Uli 1M2QProperty, plant and equipment- net 805,038 886 000 906 498 088 319 209 462
Investments And Other Property 157 068 159 000 206,348 204,474 223 061
Current Assets:
Cash and cash equivalents 106 795 67,000 736 75,159 403
Receivables:
Customer 243,647 207 000 176,846 599 258
Gas operations
Allowance for uncollectible accounts (23,079)(43 000)(43 311)(43,210)(43 108)
Notes
Employee notes receivable 742 000 6'm 347 523
Other 15,611 000 881 209 806
Total Receivables
Energy marlleting assets 060 128 194 000 138 176 203
Derivative assets
Taxes receivable 000
Accrued unbilled revenues 825 000 35,714 30,869 832
Materials and supplies (at avg, cost)731 000 22,812 351 28,008
Fuel stock (at average cost)105 000 943 228 539
Prepayments 24,575 32,000 872 779 30,035
Regulatory assets associated with taxes MIZ .1l.lli 382 407
Regulatory assets - derivatives M1.Q
Other current assets
Total current assets 520,752 653 000 398 424 238 158 221 416
Total other assets 556 850 944 000 738,224 575 157 580,233
TOTAl ASSETS 039 706 $3,642 000 249 494 106,108 $3,234 172
CAPITAlIZATION AND lIABiliTIES:
Common stock equity
Total common stock equity 820 811 871 000 874 827 864 281 008 286
Preferred stock 105 066 104 000 393 366
Long-term debt 945834 979549
Total capitalization 789 991 818 000 826 896 862.481 987 835
Current Liabilities:
Total current liabilities 562 322 907,000 573 165 311 705 285 458
Other Liabilities:
Total other liabilities 687,393 917 000 849 433 931,922 960,879
TOTAl CAPITAliZATION AND
LIABiliTIES 039 706 $3,642,000 $3,249,494 $3,106,108 $3,234 172
Shares Outstanding (OOO'568 37,563 018 38,207 42,217
Book Value per Share $21,$23.$23,$22.$23.
Page 36
A. Davidson & Co.
IDACORP,lnc.Consolidated Statements of Income
$ thousands - Fiscal year ends 12/31 2003 1004 2004 3004 4004 2004 10O5E 2005E 300SE 40OSE 200SE 2OO6E
~ENUES:
drlc Utility:
General busnese $670,9611 $146 157 $158 305 5186 687 $144 686 5635 835 5158 462 S174 905 $199 463 S153,182 $684,012 57011,747
Off system saleS 71.573 28.121 36 , BO9 34 . 969 249 121,148 26,912 37,608 878 23,322 120,720 134,158
Other reve.....!2..m 11.1.9:i !J!,g!!!!
Total Electric Utility Revenues 782,720 183603 206 909 241 188 191 236 822,937 198 374 227 513 247 342 191 504 864,732 908,905
DIversified Operations:
Energy ma1c.eIing 111,918 (9)(152)(55)(131)
Other MIl MQ!1 1MH!
Total Diversified Op. Revenues i!!J!H!
Equity In Earnings of P..mershlpsTotalRe~823,002 188,189 211 872 246 677 197.752 844,491 203 074 232,313 252 242 196,504 884,132 929 405
EXPENSES:
Electric Utility:
P..chaS8d power 150,1180 18,505 766 79.607 765 195 642 23.840 72.390 80 . 998 29,845 207,074 211,632
Fuel expense 99,898 504 569 28,291 25.898 103,281 30,748 434 681 25.853 1011 716 112,704
Power cost adjusb11ent I!illi 1MZ!I MQ!I MQ!1 1I .1Q..QQQ ill!!!!!
ToI8I Power Supply 321,640 58.573 589 127 518 409 336,087 64 , OBB 98,824 110.679 698 339,289 352,338
Other Operations end Maintenance 220 963 146 63,193 243 596 246,111 59,512 68,254 61.835 537 2&4,136 268,127
Depreciation 97.650 890 25,271 25,229 395 100 855 750 000 26,250 500 104,500 107,000
Taxes other than income taxes 378 090 20,398
Impairment 01 assets !.1B
Total Electric Utility Expense.H!.2D ill.m lliJ!Il I.1J.lli 1.9.m
Energy Marketing:
Cost of energy commod~ies & services 250 (79)(2)(61)
Selling, adminislre\ive & general D.m 543 558 314
Net (gein) loss on legal disputes.L3..1.5!I1 W!Il
Total Energy MlO'keting 37,671 441 (1,105)(2,594)693 (2.565)
Other:40,243 Um!2.Q!IQ MQ2 .1Q..QQQ .1Q..QQQ 38,500
Total Diversified Op. Expenses Z!.!!1I L121 Il.ID 2.Q!IQ MQ2 1QJ!Q!I 1Q.!Kj!I
Total Operating Expenses 751,240 756 824 Z!!.m
OPERATING INCOME
Eleclrk: Utility 121,694 429 722 20.605 282 109,038 43,073 28,520 878 938 146 409 159 628
Energy Marketing (17,755)(355)096 442 (748)434
Other DIv...lfied Ope..Uona !1MI!I w.Ml IM1l)I.1!.ill1 W!I!I)(tiQQ)!MQ!I1 11t.1!!QI WU!!!!l
Equity In earnings of Partnership.
Operating Income M.!1I2 1M!II 22.ZlI 2M2Q 1!!!.1U
TOTAL OTHER INCOME:24,412 357 17.491 102 381 39.329 950 100 150 200 28,400 29 , 000
,)TAL OTHER EXPENSES:082 547 632 075 975 21,228 125 150 4A75 200 650 17,000
TEREST EXPENSE AND OTHER:
Interest on Iong-tenn debt 58,670 13.353 13,215 061 309 54,937 500 525 550 575 150 60,000
Other interest z.m 2!12 ill 1.!!!1!!
Net ntere,t charges 61,503 806 800 663 15,048 58,317 634 698 800 825 957 000
Dividends on preferred stock !.m
Total interest expense end other 64,933 14.660 653 779 048 63,140 634 698 800 825 68,957 61,000
INCOME BEFORE INCOME TAXES:469 344 613 181 075 48,213 963 072 26.953 113 102 128
INCOME TAXES:W.tl!I LUlli 1Jill.2..l1l .Y.!!1I 1Y!I
NET INCOME:48,578 659 12.992 26,067 26&72,984 22.919 10,261 22,910 996 68,086 75,181
Eamings per share (besic and diluted)S1,$0.50.$0,$0.S 1.90 $0.$0.50.$0,51.60 S1.
Dividends paid per share of common stock SUO $0.300 $0 . 300 50.300 $0.300 S1,SO.300 $0.300 $0 . 300 50.300 S1.20 S1.20
Avg. common shares outstanding (000)186 38.176 189 38.191 38,863 38,361 42,626 42.651 42.676 701 42,863 42,601
Segment breakdown of EPS
Idaho Power Company 51.44 $0.SO.SO.$0.S1,SO.$0.SO. 51 $0,S1.$1.
IDACORP Energy 1$0,25)($0,00)$0,SO.$0.SO.50.$0.$0.$0.SO.SO.
Ida-West Energy (SO.131 SO,
IDACORP Financial 50.SO.
IclaTEICh 1$0,04)(0,04)(0.04)iO.O4)(0,04)(SO,15)
IDACOMM (SO.05)(0,01)(0.01)(0.03)(SO,051
Holding Company !!I..Q2)!!I..!Ia1 1!I..!!2J J1!!jgl
51.22 $0.50.SO.$0.SUO $0,$0.$0.$0.S1.S1.76
"""
Page 37
. D.A. Davidson & Co.
Two Centerpointe Drive, Suite 400. Lake Oswego, Oregon 97035. [phone]. [phone]. www.dadavidson.com
Copyright D.A. Davidson & Co., 2005. AIl rights reserved.
A. Davidson & Co. participated as co-manager in a secondary offering of this company s shares in December 2004.
A. Davidson & Co. expects to receive, or intends to seek, compensation for investment banking services from this company in the
next three months.
A. Davidson & Co. is a full service investment finn that provides both brokerage and investment banking services. James L.
Bellessa, Jr., CF A, the research analyst principally responsible for the preparation of this report, will receive compensation that is
based upon (among other factors) D.A. Davidson & Co.'s investment banking revenue. However , D.A. Davidson & Co.'s analysts are
not directly compensated for involvement in specific investment banking transactions.
, James L. BeIlessa, Jr., CF A, attest that (i) all the views expressed in this research report accurately reflect my personal views about
the common stock of the subject company, and (ij) no part of my compensation was, is, or will be, directly or indirectly, related to the
specific recommendations or views expressed in this report.
Ratings Information
A. Davidson & Co. Ratines Buv Neutral Underperform
Risk adjusted return potential Over 15% total return ~0-15% return potential Likely to remain flat or lose
expected on a risk adjusted on a risk adjusted basis value on a risk adjusted basis
basis over next 12-18 months over next 12-18 months over next 12-18 months
Distribution of Ratines (as of 12/31/04)Buy Hold Sell
Correspondin! Institutional Research Ratin!Buy Neutral Underperform
Distribution ofInstitutional Research Ratings 42%45%13%
Correspond in! Retail Research Ratin!Buy, Core/Buy Hold, CorelHold Avoid
Distribution of Retail Research Ratin!s 71%29%
Distribution of combined ratines 47%42%11%
Distribution of companies from whom
'J.A. Davidson & Co. has received compensation
for investment bankin! services in last 12 mos
r--'
- .-- --,-- --- -.. .., --- -. -
, D ;A:cciFi-p" NC ,
-----' - -. - "-------'- ------. - '
A. of 2"""0,.2005 i
i '2.00 -----.--
----------
Cunoncy'U8D
, s~ 1
.. ~'" ~-.
! 2700
~~, ,
.,.t, .w'\ /-A ......---.4 ""I
! 2..0 ..
: ~'(
\fv,r'\...../L/~
;,..J ~21.00"
: '8,00 i
i ".00 -
12.00 "
! 0.00.
i 8,OO-i
::~L"_'/"'i---"-;:r'-'---'7--'---
/""'-""'--"'" ~;;'----'"...
.:1 of' _+0 ,
. ,-..- ,""""-",------,--,---,--,-,-_......_",_,,,
01' 01' ~ -r'e ~'/I it' ,
-CIo"'" P- -Pric. Two-!
--R...mmo.cIa""" C.ango-Uoap Co...,-
'---.--------,-..--.,--..,---.-. -._--,- "._---------,----_.__.._,--,---
IDACORP 1Ne.
C..renq. USOl18te Closing Price
16-.JLO- 2004 21.2326-Mey-2004 262101-J8n-2OO4 29.
~~
~r~12-Apr -2002 37.25
Ro!commend8llon Ch--
I\EUT RALLl'JDERPERFORMNEUTRAll.N)fRPERFORMNEUTRALBUY
Dete
16-FeI:I.200520-Dec-200404-Nov-200415-0cI-200404-Oc1-2004
5t~=01-Nov-2003oa-Aug-2003
~1:l.8t~OS-.u..200212.""'-2002
Clueing Price
30 .3130 .9232.2530.30 .os28 .3121.23262129.28.23,21,22.0025,21,21,31.25
P1ice hrgel
29,30.31.30.29.28.21.24.30,25,22,24.22.26.30.33.42.
"....,
A. Davidson & Co. has made one change to
its institutional ratings scale within the last
three years. The change occurred July 9, 2002
and the corresponding scales are reproduced
below.
A. Davidson & Co. Institutional Research
Rating Scale (beginning 7/9/02)
Buy, Neutral, Underperfonn
A. Davidson & Co. Institutional Research
Rating Scale (6/18/01 - 7/9/02)
Strong Buy, Buy, Neutral, Underperfonn
Page 38
~ D.A. Davidson & Co.
Two Centerpointe Drive, Suite 400 . Lake Oswego, Oregon 97035 . [phone] . [phone]. www.dadavidson.com
Copyright D.A. Davidson & Co., 2005. All rights reserved.
Co JTget prices are our Institutional Research Department's evaluation of price potential over the next 12-18 months and 5 years, based
upon our assessment of future earnings and cash flow, comparable company valuations, growth prospects and other fmancial criteria.
Certain risks may impede achievement of these price targets including, but not limited to, broader market and macroeconomic
fluctuations and unforeseen changes in the subject company s fundamentals or business trends.
Other Disclosures
Infonnation contained herein has been obtained by sources we consider reliable, but is not guaranteed and we are not soliciting any
action based upon it. Any opinions expressed are based on our interpretation of data available to us at the time ofthe original
publication of the report. These opinions are subject to change at any time without notice. Investors must bear in mind that inherent
in investments are the risks of fluctuating prices and the uncertainties of dividends, rates of return and yield. Investors should also
remember that past perfonnance is not necessarily an indicator of future perfonnance and D.A. Davidson & Co. makes no guarantee
express or implied, as to future perfonnance. Investors should note this report was prepared by DA. Davidson & Co.s Institutional
Research Department for distribution to D.A. Davidson & Co.s institutional investor clients and assumes a certain level of investment
sophistication on the part of the recipient. Readers, who are not institutional investors or other market professionals, should seek the
advice of their individual investment advisor for an explanation of this report s contents, and should always seek such advisor s advice
before making any investment decisions. Further infonnation and elaboration will be furnished upon request.
l""'-
Page 39
" L i~ i \/ ED
;" i'
! "
' ! 6 Pi-) L:;
IDAHO POWER COMP ANy.if;!c'Q lJ SIO!J
CASE NO. IPC-O5-
FIRST PRODUCTION REQUEST
OF THE INDUSTRIAL CUSTOMERS
OF IDAHO POWER
ATTACHMENT TO
RESPONSE TO
REQUEST NO.
DUY versus DU\lO : ueDl ASpeClS 01 rurcnaseo-rower Agreemems,...,~...,~,_..,....,-~_..",-,..."",...--,...."............"..",..,.."..",."..""
D A R D ~::R.-JJ-
~~~~
tp~':Ei'i.~
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I-.Yi-
-;'.~'
Publication date: 08-May-2003
Reprinted from RatingsDirect
Buy Versus Build": Debt Aspects of Purchased-Power Agreements
Credit Analysts: Jeffrey Wolinsky, CFA, New York (1) 212-438-2117; Dimitri Nikas, New York (1) 212-438-7807; Anthony Flintoff, London (44) 2C
7826-3874; Laurie Conheady, Melbourne (61) 3-9631-2036
Standard & Poor s Ratings Services views electric utility purchased-power
agreements (PPA) as debt-like in nature, and has historically capitalized these
obligations on a sliding scale known as a "risk spectrum." Standard & Poor's applies
a 0% to 100% "risk factor" to the net present value (NPV) of the PPA capacity
payments, and designates this amount as the debt equivalent.
While determination of the appropriate risk factor takes several variables into
consideration, including the economics of the power and regulatory treatment, the
overwhelming factor in selecting a risk factor has been a distinction in the likelihood
of payment by the buyer. Specifically, Standard & Poor s has divided the PPA
universe into two broad categories: take-or-pay contracts (TOP; hell or high water)
and take-and-pay contracts (TAP; performance based). To date, TAP contracts
have been treated far more leniently (e., a lower risk factor is applied) than TOP
contracts since failure of the seller to deliver energy, or perform, results in an
attendant reduction in payment by the buyer. Thus, TAP contracts were deemed
substantially less debt-like. In fact, the risk factor used for many TAP obligations
has been as low as 5% or 10% as opposed to TOPs, which have been typically at
least 50%.
Standard & Poor s originally published its purchased-power criteria in 1990, and
updated it in 1993. Over the past decade, the industry underwent significant
changes related to deregulation and acquired a history with regard to the
performance and reliability of third-party generators. In general, independent
generation has performed well; the likelihood of nondelivery--and thus release from
the payment obligation--is low. As a result, Standard & Poor's believes that the
distinction between TOPs and TAPs is minimal , the result being that the risk factor
for TAPs will become more stringent. This article reiterates Standard & Poor's views
on purchased power as a fixed obligation, how to quantify this risk, and the credit
ramifications of purchasing power in light of updated observations.
Why Capitalize PPAs?
Standard & Poor s evaluates the benefits and risks of purchased power by adjusting
a purchasing utility's reported financial statements to allow for more meaningful
comparisons with utilities that build generation. Utilities that build typically finance
construction with a mix of debt and equity. A utility that leases a power plant has
entered into a debt transaction for that facility; a capital lease appears on the
utility's balance sheet as debt. A PPA is a similar fixed commitment. When a utility
enters into a long-term PPA with a fixed-cost component, it takes on financial risk.
Furthermore, utilities are typically not financially compensated for the risks they
assume in purchasing power, as purchased power is usually recovered dollar-for-
dollar as an operating expense.
Buy Versus Build": Debt Aspects of Purchased-Power Agreements
As electricity deregulation has progressed in some countries, states, and regions,
the line has blurred between traditional utilities, vertically integrated utilities, and
merchant energy companies, all of which are in the generation business. A
common contract that has emerged is the tolling agreement, which gives an energy
merchant company the right to purchase power from a specific power plant. (see
Evaluating Debt Aspects of Power Tolling Agreements," published Aug. 26, 2002).
The energy merchant, or toller, is typically responsible for procuring and delivering
gas to the plant when it wants the plant to generate power. The power plant
operator must maintain plant availability and produce electricity at a contractual
heat rate. Thus, tolling contracts exhibit characteristics of both PPAs and leases.
However, toilers are typically unregulated entities competing in a competitive
marketplace. Standard & Poor s has determined that a 70% risk factor should be
applied to the NPV of the fixed tolling payments, reflecting its assessment of the
risks borne by the toller, which are:
Fixed payments that cover debt financing of power plant (typically highly
leveraged at about 70%),
. Commodity price of inputs,
. Energy sales (price and volume), and
Counterparty risk.
Determining the Risk Factor for PPAs
Alternatively, most entities entering into long-term PPAs, as an alternative to
building and owning power plants, continue to be regulated utilities. Observations
over time indicate the high likelihood of performance on TAP commitments and,
thus, the high likelihood that utilities must make fixed payments. However, Standard
& Poor s believes that vertically integrated, regulated utilities are afforded greater
protection in the recovery of PPAs, compared with the recovery of fixed tolling
charges by merchant generators. There are two reasons for this. First, tariffs are
typically set by regulators to recover costs. Second, most vertically integrated
utilities continue to have captive customers and an obligation to serve. At a
minimum, purchased power, similar to capital costs and fuel costs, is included in
tariffs as a cost of service.
As a generic guideline for utilities with PPAs included as an operating expense in
base tariffs, Standard & Poor's believes that a 50% risk factor is appropriate for lon~
term commitments (e.g. tenors greater than three years). This risk factor assumes
adequate regulatory treatment, including recognition of the PPA in tariffs; otherwise
a higher risk factor could be adopted to indicate greater risk of recovery. Standard 8
Poor's will apply a 50% risk factor to the capacity component of both TAP and TOP
PPAs. Where the capacity component is not broken out separately, we will assume
that 50% of the payment is the capacity payment. Furthermore, Standard & Poor
will take counterparty risk into account when considering the risk factor. If a utility
relies on any individual seller for a material portion of its energy needs, the risk of
nondelivery will be assessed. To the extent that energy is not delivered, the utility
will be exposed to replacing this power, potentially at market rates that could be
higher than contracted rates and potentially not recoverable in tariffs.
Standard & Poor s continues to view the recovery of purchased-power costs via a
fuel-adjustment clause, as opposed to base tariffs, as a material risk mitigant. A
monthly or quarterly adjustment mechanism would ensure dollar-for-dollar recovery
of fixed payments without having to receive approval from regulators for changes in
DUY versus DUIIO : ueor f\specrs 0( run;naseu-ruwt:r t-\gnxmt:lIl:;
fuel costs. This is superior to base tariff treatment, where variations in volume sales
could result in under-recovery if demand is sluggish or contracting. For utilities in
supportive regulatory jurisdictions with a precedent for timely and full cost recovery
of fuel and purchased-power costs, a risk factor of as low as 30% could be used. In
certain cases, Standard & Poor's may consider a lower risk factor of 10% to 20% fo,
distribution utilities where recovery of certain costs, including stranded assets, has
been legislated. Qualifying facilities that are blessed by overarching federal
legislation may also fall into this category. This situation would be more typical of a
utility that is transitioning from a vertically integrated to a disaggregated distribution
company. Still, it is unlikely that no portion of a PPA would be capitalized (zero risk
factor) under any circumstances.
The previous scenarios address how purchased power is quantified for a vertically
integrated utility with a bundled tariff. However, as the industry transitions to
disaggregation and deregulation, various hybrid models have emerged. For
example, a utility can have a deregulated merchant energy subsidiary, which buys
power and off-sells it to the regulated utility. The utility in turn passes this power
through to customers via a fuel-adjustment mechanism. For the merchant entity, a
70% risk factor would likely be applied to such a TAP or tolling scheme. But for the
utility, a 30% risk factor would be used. What would be the appropriate treatment
here? In part, the decision would be driven by the ratings methodology for the
family of companies. Starting from a consolidated perspective, Standard & Poor's
would use a 30% risk factor to calculate one debt equivalent on the consolidated
balance sheet given that for the consolidated entity the risk of recovery would
ultimately be through the utility's tariff. However, if the merchant energy company
were deemed noncore and its rating was more a reflection of its stand-alone
creditworthiness, Standard & Poor s would impute a debt equivalent using a 70%
risk factor to its balance sheet, as well as a 30% risk-adjusted debt equivalent to the
utility. Indeed , this is how the purchases would be reflected for both companies if
there were no ownership relationship. This example is perhaps overly simplistic
because there will be many variations on this theme. However, Standard & Poor
will apply this logic as a starting point, and modify the analysis case-by-case
commensurate with the risk to the various participants.
Adjusting Financial Ratios
Standard & Poor s begins by taking the NPV of the annual capacity payments over
the life of the contract. The rationale for not capitalizing the energy component,
even though it is also a nondiscretionary fixed payment, is to equate the
comparison between utilities that buy versus build--Le., Standard & Poor's does not
capitalize utility fuel contracts. In cases where the capacity and energy components
of the fixed payment are not specified, half of the fixed payment is used as a proxy
for the capacity payment. The discount rate is 10%. To determine the debt
equivalent, the NPV is multiplied by the risk factor. The resulting amount is added to
a utility's reported debt to calculate adjusted debt. Similarly, Standard & Poor
imputes an associated interest expense equivalent of 10%--10% of the debt
equivalent is added to reported interest expense to calculate adjusted interest
coverage ratios. Key ratios affected include debt as a percentage of total capital
funds from operations (FFO) to debt, pretax interest coverage, and FFO interest
coverage. Clearly, the higher the risk factor, the greater the effect on adjusted
financial ratios. When analyzing forecasts, the NPV of the PPA will typically
decrease as the maturity of the contract approaches.
Utility Company Example
To illustrate some of the financial adjustments, consider the simple example of ABC
lmy versus )julia": ueO! ASpeCtS or l'Urcnaseo-t'ower Agreements
Utility CO. buying power from XYZ Independent Power Co. Under the terms of the
contract, annual payments made by ABC Utility start at $90 million in 2003 and rise
5% per year through the contract's expiration in 2023. The NPV of these obligations
over the life of the contract discounted at 10% is $1.09 billion. In ABC's case,
Standard & Poor s chose a 30% risk factor, which when multiplied by the obligation
results in $327 million. Table 1 illustrates the adjustment to ABC's capital structure
where the $327 million debt equivalent is added as debt, causing ABC's total debt
to capitalization to rise to 59% from 54% (11 plus 48). Table 2 shows that ABC'
pretax interest coverage was 2., without adjusting for off-balance-sheet
obligations. To adjust for the XYZ capacity payments, the $327 million debt
adjustment is multiplied by a 10% interest rate to arrive at about $33 million. When
this amount is added to both the numerator and the denominator, adjusted pretax
interest coverage falls to 2.3x.
~1ABC Uti I n;c~; st~entt~ c;PJ;I-Stru~fu;;'~
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,=.,,
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Credit Implications
The credit implications of the updated criteria are that Standard & Poor s now
believes that historical risk factors applied to TAP contracts with favorable recovery
mechanisms are insufficient to capture the financial risk of these fixed obligations.
Indeed, in many cases where 5% and 10% risk factors were applied , the change in
adjusted financial ratios (from unadjusted) was negligible and had no effect on
ratings. Standard & Poor's views the high probability of energy delivery and
attendant payment warrants recognition of a higher debt equivalent when
capitalizing PPAs. Standard & Poor s will attempt to identify utilities that are more
vulnerable to modifications in purchased-power adjustments. Utilities can offset
these financial adjustments by recognizing purchased power as a debt equivalent
and incorporating more common equity in their capital structures. However,
Standard & Poor s is aware that utilities have been reluctant to take this action
because many regulators will not recognize the necessity for, and authorize a retun
, this additional wedge of common equity. Alternatively, regulators could
authorize higher returns on existing common equity or provide an incentive return
tSuy versus tSUlIQ : ueo! f\Spel:1S UI r-url:IlC1Seu-r-uWel ""1:\1=1l"""~, .
mechanism for economic purchases. Notwithstanding unsupportive regulators, the
burden will still fall on utilities to offset the financial risk associated with purchases
by either qualitative or quantitative means.
Published by Standard & Poor's, a Division of The McGraw-Hili Companies, Inc. Executive offices:
1221 Avenue of the Americas, New York, NY 10020. Editorial offices: 55 Water Street, New York,
NY 10041. Subscriber services: (1) 212-438-7280. Copyright 2003 by The McGraw-Hili Companies
Inc. Reproduction in whole or in part prohibited except by permission. All rights reserved. Informatior
has been obtained by Standard & Poor's from sources believed to be reliable. However, because of
the possibility of human or mechanical error by our sources, Standard & Poor's or others, Standard
& Poor's does not guarantee the accuracy, adequacy, or completeness of any information and is not
responsible for any errors or omissions or the result obtained from the use of such information.
Ratings are statements of opinion, not statements of fact or recommendations to buy, hold, or sell
any securities.
The McGraw-Hili Companies.
..
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:,J
IDAHO POWER COMP~N'
\*j
r;':jiss'Oi'
CASE NO. IPC-O5-
FIRS T PROD U CTI ON REQ UES T
0 F THE INDUS TRIAL CUS TO MERS
OF IDAHO POWER
ATTACHMENT TO
RESPONSE TO
REQUEST NO. 13
~ou~;Jj1J Q.fr /6-
(;(,
IDA CORP's and IPCs operating cash flows decreased $24 million and $20 million, respectively, compared to 2004.
The decreases were mainly related to the timing of cash disbursements made in 2005 for December 2004 payable
balances, including $9 million in employee incentive compensation paid during the first quarter of 2005. There was
no similar employee incentive plan payout in 2004.
In 2005, net cash provided by operating activities will be driven by IPC, where general business revenues and the
costs to supply power to general business customers have the greatest impact on operating cash flows. As IPCs
service territory continues to experience below normal water conditions, IPC expects to continue to rely on higher-
cost thermal generation and wholesale power purchases to meet its energy needs for the rest of 2005. While
significant portion of the deferred power supply costs are expected to be recovered through IPCs PCA mechanism,
recovery will not take place until the 2006-2007 PCA year.
Working Capital
Changes in working capital are due primarily to timing and normal business activity.
Contractual Obligations
IDACORP's contractual cash obligations have increased from $3.0 billion at December 31, 2004 to $3.3 billion at
June 30, 2005. This change is primarily due to an increase in IPC's contractual cash obligations, which increased
from $2.9 billion at December 31, 2004 to $3.2 billion at June 30, 2005. The most significant changes from IPC'
December 31. 2004 reported amounts are cogeneration and small power production (CSPP), which increased $246
million, and fuel supply agreements, which increased $34 million. The increase in CSPP is primarily due to the
addition of six wind energy contracts. The increase in fuel supply agreements is due to new multi-year coal supply
agreements for the Valmy generating facility as well as natural gas contracts to supply IPCs Bennett Mountain
facility. Of IPC's overall increase in contractual cash obligations from December 31 , 2004, to June 30, 2005, $41
million will be due in one year or less, $41 million will be due between one and three years, $27 million will be due
between three and five years and $186 million will be due in more than five years.
Capital Requirements
IDACORP's internal cash generation after dividends is expected to provide less than the full amount of total capital
requirements for 2005 through 2007. The contribution from internal cash generation is dependent primarily upon
IPCs cash flows from operations, which are subject to risks and uncertainties relating to weather and water
conditions, and IPC's ability to obtain rate relief to cover its operating costs. IDACORP's internally generated cash
after dividends, is expected to provide approximately 70 percent of2005 capital requirements, where capital
requirements are defined as utility construction expenditures, excluding Allowance for Funds Used During
Construction (AFDC), plus other regulated and non-regulated investments. This excludes mandatory or optional
principal payments on debt obligations. IDA CORP and IPC expect to continue financing the utility construction
program and other capital requirements with internally generated funds and with increased reliance on externally
financed capital.
The current expectation of approximately 70 percent of 2005 capital requirements is an increase from the 60 percent
reported in IDA CORP's and IPC's Quarterly Report on Form IO-Q for the quarter ended March 31 , 2005. This
increase is due to more favorable precipitation occurring in late spring.
Utility Construction Program: Utility construction expenditures were $86 million for the six months ended June
30, 2005 compared to $83 million for the six months ended June 30, 2004. The increase is due to expenditures
related to the Bennett Mountain Power Plant, which was operational and provisionally accepted on March 31 , 2005.
This plant is discussed in more detail later in "REGULATORY MATIERS - IPUC Rate Proceedings - Bennett
Mountain Power Plant"
As reported in IDA CORP's and IPC's Annual Report on Form IO-K for the year ended December 31 , 2004, IPC's
total construct ion ex pe n d i tu~,x,peSled_lo..be..S612-mH I itm,-exclndingt\ fDe;ii"onr 2005~at
time, 1~€::--expeeted'1tn;pemJ approximately $202 million, excluding AFDC , in 2005. IPC currently expects to spend
,"""
betWeen $190 million and $200 million, excluding AFDc. The decrease is due to the timing of certain construction
expenditures; however, the estimate of $672 million over the three-year period has not changed.
IPC' 4 IRP includes several elements requiring significant capital expenditures in the future. Two of these
projects are included in the 2005-2007 utility capital expenditure forecast: (I) $79 million of construction costs for a
combustion turbine peaking resource expected to be operational in mid-2007 and (2) $2 million of planning costs for
Page 40
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 16th day of December, 2005 , I served a
true and correct copy of the within and foregoing IDAHO POWER COMPANY'
RESPONSE TO FIRST PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS OF
IDAHO POWER upon the following named parties by the method indicated below , and
addressed to the following:
Donald L. Howell, II
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise, Idaho 83720-0074
don.howell (Q? puc.idaho.qov
Hand Delivered
S. Mail
Overnight Mail
FAX [phone]
E-mail
Randall C. Budge
Eric L. Olsen
Racine, Olson , Nye , Budge & Bailey
O. Box 1391; 201 E. Center
Pocatello , ID 83204-1391
rcb(Q? racinelaw.net
elo(Q? racinelaw.net
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]~E-mail
Anthony Yankel
29814 Lake Road
Bay Village, OH 44140
vankel (Q? attbLcom
Hand Delivered
x U.S. Mail
Overnight Mail
FAX [phone]
E-mail
Peter J. Richardson
Richardson & O'Leary
515 N. 27th Street
O. Box 7218
Boise ,. ID 83702
peter(Q? richardsonandolearV.com
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x U.S. Mail
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FAX [phone]
E-mail
Dr. Don Reading
Ben Johnson Associates
6070 Hill Road
Boise , I D 83703
dreadinq (Q? mindsprinq.com
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x U.S. Mail
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FAX [phone]
E-mail
Lawrence A. Gollomp
Assistant General Counsel
United States Dept. of Energy
1000 Independence Avenue , SW
Washington , D.C. 20585
Lawrence.Gollomp(Q? hq.doe,qov
CERTIFICATE OF SERVICE , Page
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Dennis Goins
Potomac Management Group
O. Box 30225
Alexandria, VA 22310-8552
dqoinsPMG ~aol.com
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FAX [phone]
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Conley E. Ward
Givens, Pursley LLP
601 W. Bannock Street
O. Box 2720
Boise, ID 83701-2720
cew ~ qivenspu rslev .com
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Dennis E. Peseau , Ph.D.
Utility Resources , Inc.
1500 Liberty Street S., Suite 250
Salem , OR 97302
dpeseau (Q? excite.com
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William M. Eddie
Advocates for the West
1320 W. Franklin Street
O. Box 1612
Boise , ID 83701
billeddie ~ rmcLnet
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Ken Miller
NW Energy Coalition
5400 W. Franklin , Suite G
Boise, ID 83705
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E-mail
CJ11~BARTON L. KLINE
CERTIFICATE OF SERVICE, Page 2