20070910IPC to DOE 1-1 to 1-21.pdf

REGE!\"
IDAHO~POWER~
An IDACORP Company
ZGUl SEP - 7 Pr" l\; 56
~. ,.\L~.'~1O
)~,
~~5~
~ \
~ S 1 0 .
G I ill I Lv V'~I" ..
BARTON L. KLINE
Senior Attorney
September 2007
Jean D. Jewell , Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise, Idaho 83720-0074
Re:Case No. IPC-07-
General Rate Case Filing
Dear Ms. Jewell:
Please find enclosed an original and two (2) copies of Idaho Power s Response to
the First Production Request of the United States Department of Energy in the above-
referenced matter.
I would appreciate it if you would return a stamped copy of this transmittal letter
in the enclosed self-addressed , stamped envelope.
~y y~~rs
~ -tl. (L----
Barton L. Kline
BLK:sh
Enclosure
O. Box 70 (83707)
1221 W. Idaho St.
Boise, 10 83702
I~ECE!\/
BARTON L. KLINE ISB #1526
LISA D. NORDSTROM ISB #5733
Idaho Power Company
O. Box 70
Boise , Idaho 83707
Telephone: [phone]
FAX Telephone: [phone]
'\nr'~
Wul SEP - 7 " f,. I -
~lillFd;jj(~i,~I~S!
Attorney for Idaho Power Company
Street Address for Express Mail:
1221 West Idaho Street
Boise , Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC
SERVICE TO ELECTRIC CUSTOMERS
IN THE STATE OF IDAHO
) CASE NO. IPC-07-
RESPONSE OF IDAHO POWER TO
THE FIRST PRODUCTION REQUEST
OF THE UNITED STATES
DEPARTMENT OF ENERGY
COMES NOW, Idaho Power Company ("Idaho Power" or "the Company ) and, in
response to the United States Department of Energy s First Set of Interrogatories and
Production Requests to Idaho Power Company dated August 10, 2007 , herewith submits
the following information:
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 1
REQUEST FOR PRODUCTION NO. 1-Please provide copies of all of the
Company s responses to requests for information which were submitted to it by other
parties in this docket. This is an ongoing request.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
Idaho Power has provided the Department of Energy with copies of all of the
Company s responses to requests for information which were submitted to it by other
parties in this docket. It is the standard practice in IPUC proceedings to supply copies
of responses to interrogatories and production requests to all parties to the case. Idaho
Power has followed that practice in this case and will continue to do so.
The response to this request was prepared by Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom , Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 2
REQUEST FOR PRODUCTION NO. 1-Referring to the direct testimony of
Timothy Tatum at 10: 15-11 :2:
(a)
(b)
Please identify the specific generation resources referenced at 10:16-17.
For each generation resource identified in response (a) above, please
specify the resource type, and its installed cost, in-service date , and nameplate or rated
capacity.
(c)For each generation resource identified in response (a) above , please
provide by month , from January 2006 to the present, the resource s total hours of
operation, total kWh output, and total operating cost.
(d)Please quantify the ... increased investment in generation resou rces
necessary to meet the summer peak load..." and state the time period over which this
increased investment occurred.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
The specific generation resources referenced at 10:16-17 of Mr. Tatum
testimony include the Bennett Mountain and Evander Andrews (Danskin) natural gas
power plants.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 3
The requested information is provided in the following table:
Namplate
Resource Resource In-Service Capacity
Name Type Installed Cost Date (Gross kW) *
Bennett Natural Gas
$ 51 340 628 3/31/2005 172 800MountainPower Plant
Evander Natural GasAndrews $ 48,574 320 9/30/2001 000
(Danskin)Power Plant
Notes:
* Appendix D - Technical Appendix For the 2006 Integrated Resource Plan, page 46.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 4
The requested information provided the following two tables.
However, the total energy output of the two plants is presented in terms of megawatt-
hours.
Bennett Mountain
Hours of
Year Month Operation Output (MWh)Operating Cost *
2006 January
2006 February 214.
2006 March 14.338 144 582.
2006 April 233.
2006 May 62.9,491 518 587.
2006 June 98.15,404 866,123.
2006 July 50.206 387 288.
2006 August
2006 September 37.148 289,179.
2006 October 13.947 186 094.
2006 November 23.985 334 803.
2006 December 28.007 336 255.
2007 January 39.661 308,953.
2007 February
2007 March 49.40 786 516 589.
2007 April 36.103 476,372.
2007 May 62.311 680 205.
2007 June 128.19,091 315,266.
2007 July 407.111 656,722.
Notes:
Operating Cost includes the cost of natural gas plus transportation costs.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 5
Evander Andrews (Danskin) Unit Nos. 2 &
Unit No.Unit No.
Hours of Hours of Total Plant
Year Month Operation Operation Output (MWh)Operating Cost *
2006 January 258.
2006 February 358 35,703.
2006 March 369 19,930.
2006 April 525.
2006 May 39.36.023 198 122.
2006 June 53.53.126 271 556.
2006 July 184.185.334 984 855.
2006 August 15.14.149 510.48
2006 September 15.17.319 66,413.
2006 October
2006 November 12.952 40,741.
2006 December
2007 January
2007 February
2007 March 15.837 031.
2007 April 17.17.554 132 075.
2007 May 10.10.833 010.
2007 June 48.47.179 260 370.
2007 July 254.244.19,227 $ 1 369 703.46
Notes:
Operating Cost includes the cost of natural gas plus transportation costs.
As stated in Mr. Tatum s testimony on page 12, lines 16 and 17 FERC
Accounts 340-346, Other Production, contain the Company s investment in gas-fueled
production plant. Specifically, the Company s investment in the Bennett Mountain and
Evander Andrews (Danskin) power plants is booked to Accounts 340-346. Attached to
this response are two Summary of Investments reports detailing the year-end account
balances for those accounts in the years 2000 and 2006. As can be seen by comparing
the two reports , the Company s investment in "Other Production" has grown by
$110 313 880 between 2000 and 2006 , which is mostly attributable to the Bennett
Mountain and Evander Andrews (Danskin) plant investment.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 6
The response to this request was prepared by Timothy Tatum , Senior Pricing
Analyst , Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom , Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 7
REQUEST FOR PRODUCTION NO. 1-Referring to the direct testimony of
Timothy Tatum at 11 :7-20:
(a)Please provide all workpapaers , studies, analyses , and documents
supporting and/or underlying the statement that"
... .
Idaho Power has three distinct time-
based production costing periods that are driven by customer load.
(b)For the intermediate production costing period , please specify by month
the daily hours that define the costing period.
(c)For the peak production costing period , please specify by month the daily
hours that define the costing period.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
The costing periods used to determine the cost-effectiveness of demand-side
management programs in the Company s resource planning process best illustrate the
costing periods referenced by Mr. Tatum in his testimony. Attached to this response are
two charts that detail the time of day, day of the week and seasonality of each costing
period. The three costing periods of base , intermediate and peak referenced in Mr.
Tatum s testimony are represented on the attached charts as off-peak, mid-peak, and
on-peak respectively for the summer and non-summer seasons. These charts can also
be found on pages 66 and 67 of the 2006 Integrated Resource Plan Appendix D -
Technical Appendix.
The response to this request was prepared by Timothy Tatum, Senior Pricing
Analyst, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom, Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 8
REQUEST FOR PRODUCTION NO. 1-Referring to the direct testimony of
Timothy Tatum at 11 :20-, please provide all workpapers, studies , analyses , and
documents supporting and/or underlying the statement that "
...
the same generation
resources are typically utilized to serve both the base and intermediate loads....
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
The statement"... the same generation resources are typically utilized to serve
both the base and intermediate loads....was made in the context of a
recommendation that the Company allocate its fixed investment in steam production
plant and hydro production plant differently than its fixed investment in combustion
turbines. This statement is based on the notion that, although the combined output of
the Company s steam and hydro resources is driven by customer loads, stream flow
conditions significantly influence the proportionate share of output provided by each of
the two resource categories throughout the year. Since hydro-electric output is highly
dependent upon steam flows, steam production is ramped up or down according to the
production capability of the hydro. Therefore , throughout the year, hydro and steam
production plant are utilized at varying proportions to serve base and intermediate loads
according to the production capabilities of the hydro plants. However, the combined
monthly output of these two resource types does not vary significantly between the
summer and non-summer months as does the output of the combustion turbines.
The utilization of the Company s generation resources is detailed in a file
provided in Response to Request No. 22 of Micron s First Request for Production. This
file contains the monthly output , in megawatt-hours, of each of the Company
generation resources over the last five years. The relationship between the monthly
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 9
output of the hydro resources and steam resources is illustrated by the data within the
file.
The response to this request was prepared by Timothy Tatum , Senior Pricing
Analyst, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom , Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 10
REQUEST FOR PRODUCTION NO. 1-Please provide the marginal cost
study(ies) used to develop Exhibit No. 39.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
There were no marginal costs used in the development of Exhibit No. 39.
However, the Company 2007 Marginal Cost Analysis is provided in Mr. Tatum
workpapers, pages 48 through 55. A description of how the marginal costs were used in
the current rate case proceeding is provided in Mr. Tatum s testimony, pages
through 29.
The response to this request was prepared by Timothy Tatum, Senior Pricing
Analyst, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom , Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY -
REQUEST FOR PRODUCTION NO. 1-: Please provide in electronic format all
workpapers for the direct testimony of Idaho Power witnesses Gregory Said, Maggie
Brilz, and Timothy Tatum.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
All workpapers for the direct testimony of Gregory Said, Maggie Brilz and
Timothy Tatum were provided to all interested parties with the initial filing of Case No.
IPC-07-08. Hard copies along with a compact disc containing all workpapers were
sent to the Department of labor by Federal Express , Priority Overnight Delivery on June
, 2007. The package was delivered on June 11 , 2007 and signed for by Donna
Williams.
The response to this request was prepared by Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom , Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 12
REQUEST FOR PRODUCTION NO. 1-: Please provide Exhibit Nos. 20-37 and
58-60 in Excel format with all formulas and links intact.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
The requested information is provided on the CD enclosed with this response.
The response to this request was prepared by Greg Said, Manager of Revenue
Requirement, Pricing and Regulatory Services Department, Celeste Schwendiman
Senior Pricing Analyst, and Maggie Brilz, Pricing Director , Idaho Power Company, in
consultation with Barton L. Kline, Senior Attorney and/or Lisa D. Nordstrom , Attorney II
Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 13
REQUEST FOR PRODUCTION NO. 1-Referring to Exhibit No. 47, please
explain in detail why transmission capacity marginal costs are significantly greater than
generation capacity marginal costs in the months of May-September and December?
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
The Company s 2007 Marginal Cost Analysis is provided in Mr. Tatum
workpapers, pages 48 through 55. This analysis details the method used to derive the
seasonalized transmission capacity and generation capacity marginal costs that appear
on Exhibit 47.
As can be seen on page 54 of Mr. Tatum s workpapers, the Annual Transmission
Marginal Cost is $136/kW as compared to the Annual Generation Capacity Cost of
$69/kW shown on page 52.The seasonalization of the annual generation and
transmission capacity marginal costs is shown on Mr. Tatum s workpapers, pages 53
and 55 respectively. The annual generation capacity marginal cost is seasonalized
based on the average monthly share of peak hour deficiencies for a five-year period
2007 through 2011. These data are detailed on page 78 of the 2006 IRP , Appendix
Technical Appendix and are also provided on page 57 of Mr. Tatum s workpapers.
The annual transmission marginal costs contain two separate components that
are seasonalized using different factors. Transmission capacity costs related to the
backbone and resource integration are seasonalized using the same factors used to
seasonalize the generation marginal costs. The seasonalization of transmission costs
related to planned system expansion is based on the monthly share of peak hour load
growth between 2006 through 2011 detailed on pages 25 through 30 of the 2006 IRP
Appendix D - Technical Appendix included with this response. Although the methods
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 14
used to seasonalize the annual transmission and generation marginal costs differ
slightly, the significant difference between the two categories of marginal costs during
the months of May-September and December is mostly attributable to the fact that the
annual transmission marginal cost per kW is almost double the annual generation
marginal cost per kW.
The response to this request was prepared by Timothy Tatum , Senior Pricing
Analyst, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom , Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 15
REQUEST FOR PRODUCTION NO. 1-Referring to the direct testimony of
Timothy Tatum at 39:1-
(a) Please identify the 3 combustion turbines and state the in-service date and
nameplate capacity for each CT.
(b)For each CT identified in response (a) above , please provide by month for
each CT its kWh output since its in-service date.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-
The 3 combustion turbines Mr. Tatum was referring to in his testimony at
39: 1-3 include the two combustion turbine units at the Evander Andrews (Danskin)
power plant and the single unit at the Bennett Mountain power plant. The nameplate
capacity and in-service dates for each of these power plants is provided in the
Company s Response to Request No. 1-2 of this production request.
The requested information is attached to this response. However, the total
energy output of the two plants is presented in terms of megawatt-hours.
The response to this request was prepared by Timothy Tatum , Senior Pricing
Analyst, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom , Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 16
REQUEST FOR PRODUCTION NO. 1-Referring to Exhibit No. 41 at 36:258:
(a)
(b)
Please define and explain in detail "Adjustment to Revenue/Refunds.
Please provide the justification for I PC's functionalization and classification
of these revenues.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-10:
The revenue category "Adjustments to Sales Revenues/Refunds
explained by Mr. Said in his testimony, pages 30 and 31. The calculation of the amount
$328 357 listed on Exhibit No. 41 , page 36, line 258 is detailed on Exhibit No. 39.
The revenue category "Adjustments to Sales Revenues/Refunds
functionalized and classified in the same manner as general plant; that is , according to
the combined functionalization and classification of production , transmission and
distribution plant investment. As Mr. Said describes in his testimony, this adjustment
was made to recognize the estimated revenue associated with load growth to be served
by the facilities additions. Since the additional facilities are considered to be "general
plant" in nature, the associated revenues were functionalized and classified in the same
manner to match the revenue with the investment.
The response to this request was prepared by Timothy Tatum , Senior Pricing
Analyst, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom, Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 17
REQUEST FOR PRODUCTION NO. 1-Referring to Exhibit No. 41 at 36:260:
(a)Please provide the justification for IPC'classification of Account 447
revenues.
(b)Please provide in Excel format Account 447 Opportunity Sales by month
from Janaury 2002 through the present showing for each transaction the total kWh sold
total revenue received , and whether the transaction was priced using a one-or multi-part
rate.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-11:
FERC Account 447 , System Opportunity Sales, was classified as energy-
related and allocated on that basis in the Company s jurisdictional separation study and
the class cost-of-service study. The revenues booked to Account 447 are revenues
resulting from the sale of energy and , therefore, are allocated on that basis.
The requested information is provided on the CD enclosed with this
response.
The response to this request was prepared by Timothy Tatum , Senior Pricing
Analyst , Idaho Power Company, in consultation with Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom , Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 18
REQUEST FOR PRODUCTION NO. 1-Referring to IPUC Tariff No. 29:
(a)Please provide all workpapers , studies, analyses, and documents
supporting and/or underlying the proposed voltage-differentiated demand charges in
Schedules 9 and 19.
(b)Please provide all studies and/or analyses of system losses by service
voltage prepared by or for Idaho Power in the past five years.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-12:
(a)The Company proposed the implementation of voltage-differentiated
charges for Schedules 9 and 19 as part of its 1994 general rate case proceeding, Case
No. IPC-94-The Company s proposed rate structure was authorized by the
Commission through Order No. 25880 and service-level , or voltage-differentiated , rates
were implemented effective May 16, 1995. The testimony and exhibits of Company
witness Ms. Brilz in that case detailed and supported the proposed service-level pricing
for Schedules 9 and 19. Attached to this response are pages 41 through 54 of the
testimony of Ms. Brilz from Case No. IPC-94-5 which detail the proposed service-level
pricing for Schedules 9 and 19. Also attached to this response is Exhibit No. 39
Summary of Charges and Basis for Rates, from Case No. IPC-94-5 which illustrates
in summary format the proposed rates for metered service and the basis for those
proposed rates. Finally, pages 93 and 94 of Ms. Brilz s workpapers from Case No. IPC-
94-5 are attached to this response. These workpapers show the calculations made to
determine the proposed demand and energy charges for the Schedule 9 and Schedule
19 service levels taking system loss factors into account.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 19
As part of each general rate case proceeding since the adoption of service-level
pricing in 1995 (Case No. IPC-03-, Case No. IPC-05-, and Case No. IPC-
07-8), the Company has proposed that the pricing relationship between service levels
for Schedules 9 and 19 be maintained. Consequently, no additional analyses taking
system loss factors into account in the determination of voltage-differentiated demand
charges have been performed since 1995.
(b)Idaho Power last updated its system loss analysis is 2003. The tables
summarizing the results of the Company s 2003 loss study are enclosed with this
response. No other studies or analyses of system losses by service voltage have been
prepared in the past five years.
The response to this request was prepared by Maggie Brilz , Pricing Director
Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney and/or Lisa
D. Nordstrom, Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 20
REQUEST FOR PRODUCTION NO. 1-: Please provide copies of Mr. Avera
direct and rebuttal testimony (and supporting exhibits) on cost of capital in IPC Docket
IPC-03-13.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-13:
Copies of the requested testimony and exhibits are enclosed.
The response to this request was prepared by Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom, Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 21
REQUEST FOR PRODUCTION NO. 1-Please provide copies of all credit
rating reports pertaining to I PC that have been issued since January 1 , 2006.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-14:
Copies of the requested credit rating reports are enclosed.
The response to this request was prepared by Steve Keen , Vice President and
Treasurer, Idaho Power Company, in consultation with Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom , Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 22
REQUEST FOR PRODUCTION NO. 1-: Please provide a copy of IPC's most
recent presentation to credit rating agencies.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-15:
Idaho Power objects to this request on the grounds that it would require
disclosure of material non-public information in violation of Securities and Exchange
Commission Regulation FD. Regulation FD prohibits disclosure of material non-public
information to selected market participants thereby giving them an advantage in the
buying and selling of the Company s stock. Without waiving that objection, Idaho Power
has enclosed a copy of the requested information with the material non-public
information redacted.
The response to this request was prepared by Steve Keen , Vice President and
Treasurer, Idaho Power Company, in consultation with Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom , Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 23
REQUEST FOR PRODUCTION NO. 1-16:Please provide copies of all
presentations by IPC and/or Ida/Corp management to securities analysts since January
2007.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-16:
The requested presentation, dated November 2006 , has been used thus far in
2007 and is enclosed.
The response to this request was prepared by Steve Keen, Vice President and
Treasurer, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom , Attorney II , Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 24
REQUEST FOR PRODUCTION NO. 1-Please provide Dr. Avera s opinion
regarding I PC's business risk today as compared to its business risk at the time of its
2003 rate case.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-17:
Pursuant to IPUC Rule of Procedure 225.01 (a), Idaho Power objects to this
request as it calls for a statement of opinion that has not been previously written or
published.
The response to this request was prepared by Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom , Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 25
REQUEST FOR PRODUCTION NO. 1-18:Please provide any supporting
calculations (including an identification of key assumptions) concerning IPC'
projections of its year-end common equity balance.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-18:
Idaho Power seeks to maintain, to the extent possible , a 50%-50% balance
between debt and equity. The issuance of common equity depends on multiple factors
including, but not limited to, market receptivity, debt issuance and capital expenditures.
Because these factors are not static, Idaho Power has no formal plan or timetable for
the issuance of common equity.
The response to this request was prepared by Steve Keen , Vice President and
Treasurer, Idaho Power Company, in consultation with Barton L. Kline , Senior Attorney
and/or Lisa D. Nordstrom , Attorney II, Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 26
REQUEST FOR PRODUCTION NO. 1-19:Please provide the following
concerning any public issuance of common stock by IdaCorp parent company, 2004
2005,2006 and 2007 (to date):
(a)
(b)
date of issuance;
net proceeds; and
(c)expenses associated with issuance , including underwriting fees.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-19:
The requested information is below:
Year of Issuance Description Net Proceeds Issuance
Expenses
2004 Secondary Offering Issuance 115 520,392.211 769.
2004 Other Issuance *169,608.
2005 Other Issuance *296 000.470 166.
2006 Continuous Equity Issuance 20,841 762.210,495.
2006 Other Issuance *623 238.189,460.
2007 - YTD through Continuous Equity Issuance 040 859.212.
June.
2007 - YTD through Other Issuance *4,410 140.306.
June.
Other Issuance includes original issue shares for Dividend Reinvestment Program
and various employee plans.
The response to this request was prepared by Steve Keen, Vice President and
Treasurer and Randy Mills , Finance Team Leader, Idaho Power Company,
consultation with Barton L. Kline , Senior Attorney and/or Lisa D. Nordstrom, Attorney II
Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 27
REQUEST FOR PRODUCTION NO. 1-Please provide any plans for a public
common stock issuance by IdaCorp during 2007-2009 , indicating approximate amount
of issuance.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-20:
Idaho Power seeks to maintain , to the extent possible, a 50%-50% balance
between debt and equity. The issuance of common equity depends on multiple factors
including, but not limited to, market receptivity, debt issuance and capital expenditures.
Because these factors are not static, Idaho Power has no formal plan or timetable for
the issuance of common equity.
The response to this request was prepared by Steve Keen , Vice President and
Treasurer, Idaho Power Company, in consultation with Barton L. Kline, Senior Attorney
and/or Lisa D. Nordstrom , Attorney Idaho Power Company.
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 28
REQUEST FOR PRODUCTION NO. 1-21: Please indicate Standard & Poor
current Business Profile rating for IPC.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1-21:
Please see attached Standard & Poor s current Business Profile rating for IPC.
The response to this request was prepared by Lawrence F. Spencer, Director of
Investor Relations , Idaho Power Company, in consultation with Barton L. Kline, Senior
Attorney and/or Lisa D. Nordstrom , Attorney II , Idaho Power Company.
DATED at Boise, Idaho, this 7-1---day of September, 2007.
l~J~
BARTON L. KLINE
Attorney for Idaho Power Company
LISA D. NORDSTROM
Attorney for Idaho Power Company
RESPONSE OF IDAHO POWER TO THE FIRST PRODUCTION REQUEST OF
THE UNITED STATES DEPARTMENT OF ENERGY - 29
CERTIFICATE OF SERVICE
. \"
I HEREBY CERTIFY that on this day of September, 2007, I served a true
and correct copy of the within and foregoing document upon the following named
parties by the method indicated below, and addressed to the following:
Commission Staff
Weldon Stutzman
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington (83702)
O. Box 83720
Boise, Idaho 83720-0074
Donovan Walker
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington (83702)
O. Box 83720
Boise, Idaho 83720-0074
Industrial Customers of Idaho Power
Peter J. Richardson , Esq.
Richardson & O'Leary
515 N. 2ih Street
O. Box 7218
Boise , Idaho 83702
Don Reading
Ben Johnson Associates
6070 Hill Road
Boise, Idaho 83702
Idaho Irrigation Pumpers
Association, Inc.
Eric L. Olsen
Racine, Olson , Nye, Budge & Bailey
O. Box 1391
201 E. Center
Pocatello , Idaho 83204
-LHand Delivered
- U.S. Mail
Overnight Mail
FAX
-X. Email Weldon. stutzman C9? puc.idaho.Qov
-LHand Delivered
- U.S. Mail
Overnight Mail
FAX
-X. Email Donovan.walkerC9?puc.idaho.Qov
Hand Delivered
---2LU.S. Mail
Overnight Mail
FAX
Email peterC9? richardsonandolearv.com
Hand Delivered
---2LU.S. Mail
Overnight Mail
FAX
Email dreadinq C9? mindsprinQ.com
Hand Delivered
---2LU.S. Mail
Overnight Mail
FAX
Email eloC9?racinelaw.net
Anthony Yankel
29814 Lake Road
Bay Village , OH 444140
Kroger Co. Fred Meyer and Smiths
Michael L. Kurtz
Kurt J. Boehm
Boehm, Kurtz & Lowry
36 East Seventh Street, Suite 1510
Cincinnati, Ohio 45202
The Kroger Co.
Attn: Corporate Energy Manager (G09)
1014 Vine Street
Cincinnati , Ohio 45202
Micron Technology
Conley Ward
Michael C. Creamer
Givens Pursley
601 W. Bannock Street
O. Box 2720
Boise , Idaho 83701
Dennis E. Peseau, Ph.
Utility Resources, Inc.
1500 Liberty Street SE, Suite 250
Salem, OR 97302
Department of Energy
Lot Cooke
Arthur Perry Bruder
Office of the Attorney General
United States Department of Energy
1000 Independence Ave., SW
Washington , DC 20585
Routing Symbol GC- 76
Hand Delivered~U.S. Mail
Overnight Mail
FAX..x Email tonV(g)yankel.net
Hand Delivered~U.S. Mail
Overnight Mail
FAX..x Email mkurtz(g)bkllawfirm.com
kboehm (g) bkllawfirm.com
Hand Delivered~U.S. Mail
Overnight Mail
FAX
Email
Hand Delivered~U.S. Mail
Overnight Mail
FAX
Email cew(g)qivenspursleV.com
mcc
(g)
qivenspu rslev .com
Hand Delivered
~ U.S. Mail
Overnight Mail
FAX
--X Email dpeseau(g)excite.com
Hand Delivered
- U.S. Mail
Overnight Mail
FAX
--X Email lotcooke(g)hq.doe.qov
arthur.bruder(g) hq.doe.qov
Dennis Goins
Potomac Management Group
5801 Westchester Street
O. Box 30225
Alexandria, VA 22310-8225
Hand Delivered
- U.S. Mail
Overnight Mail
FAX
Email DGoinsPMG ~cox.net
Dale Swan
Ammar Ansari
Exeter Associates
5565 Sterrett Place, Suite 310
Columbia, MD 20904
Hand Delivered
1- U.S. Mail
Overnight Mail
FAX
Email dswan~exeterassociates.com
aansari ~ exeterassociates.com
+jCL-.
Barton L. Kline
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O7-
IDAHO POWER COMPANY
TT A CHMENT 1-
Lo
c
a
t
i
o
n
Sa
l
m
o
n

D
i
e
s
e
l

P
o
w
e
r

P
l
a
n
t

GP
S
A
D
P
0
1

$
TO
T
A
L

O
T
H
E
R
TO
T
A
L

G
E
N
E
R
A
T
I
N
G

S
Y
S
T
E
M
Lo
c
La
n
d

&
La
n
d

R
i
g
h
t
s
Ac
c
t

3
4
0
St
r
u
c
t
u
r
e
s
&
I
m
p
r
o
v
Ac
c
t

3
4
1
$1
1
95
9
.
08

$
ID
A
H
O

P
O
W
E
R

C
O
M
P
A
N
Y
OT
H
E
R

G
E
N
E
R
A
T
I
N
G

S
T
A
T
I
O
N
S
SU
M
M
A
R
Y

O
F

I
N
V
E
S
T
M
E
N
T
S

A
S

O
F

D
E
C
E
M
B
E
R

3
1
,

2
0
0
0
Fu
e
l

H
d
r
s
,
Pr
o
d

&

A
c
c
Ac
c
t

3
4
2
30
6
.
39

$
Pr
i
m
e
Mo
v
e
r
s
Ac
c
t

3
4
3
$1
1
95
9
.
08

$
61
,
30
6
.
39

$
Ge
n
e
r
a
t
o
r
s
Ac
c
t

3
4
4
Ac
c
e
s
s
o
r
y

M
l
s
c

El
e
c
t

E
q
u
i
p

Eq
u
i
p
Ac
c
t

3
4
5

Ac
c
t

3
4
6
To
t
a
l
St
e
a
m
Pl
a
n
t
St
r
u
c
t
u
r
e
s
&
I
m
p
r
o
v
Ac
c
t

3
5
2
52
1
94
6
.
84

$

3
7
05
5
.
54

$

1
4
2
.
64

$

63
2
,
4
1
0
.
4
9

$
52
1
94
6
.
84

$

3
7
05
5
.
54

$

1
4
2
.
64

$

6
3
2
41
0
.
4
9

$
NO
T
E
:

T
h
e
r
e

i
s

a
n

a
d
d
R
l
o
n
a
l

s
t
e
p
-
u
p

I
n
v
e
s
t
m
e
n
t

o
f

$
3
3
8
17
7
.
57

r
e
p
r
e
s
e
n
t
i
n
g

i
n
-
pl
a
n
t

e
q
u
i
p
m
e
n
t

s
t
o
r
e
d

a
t

n
o
n
-
pr
o
d
u
c
t
i
o
n

l
o
c
a
t
i
o
n
s
.
St
a
t
i
o
n
Eq
u
i
p
m
e
n
t
Ac
c
t

3
5
3
To
t
a
l
St
e
p
-
u
p
Eq
u
i
p
m
e
n
t
To
t
a
l
Pl
a
n
t
63
2
,
4
1
0
.
63
2
41
0
.
4
9
$
1
38
6
78
0
.
11
9
.
II
)C1
)
...
.
.
Lo
c
a
t
i
o
n
Be
n
n
e
t
t

M
t

P
o
w
e
r

P
l
a
n
t
Da
n
s
k
l
n

P
o
w
e
r

P
l
a
n
t
Sa
l
m
o
n

D
i
e
s
e
l

P
o
w
e
r

P
l
a
n
t
TO
T
A
L

O
T
H
E
R
"-
.
.
,,
'
ID
A
H
O

P
O
W
E
R

C
O
M
P
A
N
Y
OT
H
E
R

G
E
N
E
R
A
T
I
N
G

S
T
A
T
I
O
N
S
SU
M
M
A
R
Y

O
F

I
N
V
E
S
T
M
E
N
T
S

A
S

O
F

D
E
C
E
M
B
E
R

3
1
,

2
0
0
6
La
n
d

&
La
n
d

R
i
g
h
t
s
Ac
c
t

3
4
0
Fu
e
l

H
d
r
s
,
Pr
o
d

&

A
c
e
Ac
c
t

3
4
2
Pr
i
m
e
Mo
v
e
r
s
Ac
c
t

3
4
3
Ac
c
e
s
s
o
r
y
Ele
c
t

E
q
u
i
p
Ac
c
t

3
4
5
Mi
s
e

P
P
Eq
u
i
p
Ac
c
t

3
4
8
To
t
a
l
St
e
a
m
Pl
a
n
t
23
5
38
7
.
01
2
,
94
0
.
02
5
,
88
1
.
28
0
,
07
5
.
47
,
97
7
,
78
1
.
51
9
,
41
0
.
13
2
.
53
,
82
0
,
22
3
.
37
0
,
63
6
.
04
4
,
52
7
.
41
5
,
16
4
.
40
2
,
74
5
.
27
6
83
2
.
1,
4
3
3
42
3
.
28
,
67
6
95
8
.
16
6
,
03
4
.
87
7
,
12
7
.
38
0
,
10
7
.
52
,
21
3
,
22
9
.
44
6
,
82
6
.
14
9
,
79
3
.
59
6
,
61
9
.
11
,
95
9
.
61
,
30
6
.
54
1
64
4
.
28
5
,
13
9
.
00
4
.
90
1
,
05
4
.
St
r
u
c
t
u
r
e
s
&
I
m
p
r
o
v
Ac
c
t

3
4
1
Ge
n
e
r
a
t
o
r
s
Ac
c
t

3
4
4
St
r
u
c
t
u
r
e
s
&
I
m
p
r
o
v
Ac
c
t

3
5
2
$
4
0
2
,
74
5
.
39

$

5
,
30
1
73
2
.
54

$

3
,
52
0
,
61
1
.
44

$

2
9
95
7
,
03
3
.
95

$

6
1
68
5
,
46
1
.
58

$

4
68
1
,
67
8
.
28

$
38
5
,
24
4
.
04

$

1
0
6
,
93
4
,
50
7
.
22

$
81
7
,
46
2
.
66

$
St
a
t
i
o
n
Eq
u
i
p
m
e
n
t
Ac
c
l

3
5
3
To
t
a
l
St
e
p
-
u
p
Eq
u
i
p
m
e
n
t
To
t
a
l
Pl
a
n
t
80
9
,
84
8
.
90
1
,
05
4
.
19
4
,
32
0
.
80

$

4
,
01
1
,
78
3
.
4
6

$
11
0
94
6
29
0
.
(t
)
:I
:
"t
J
:s
=
-
:I
:
"t
J
:J
J
:J
J
"t
J
:I
:
"t
J
:s
=
-
. ,Appendix D- Technical Appendix Idaho Power Company
The following tables illustrate the time of day and time of year costing period definitions used in the
peak static program screening analysis:
SUMMER SEASON
June 1 through August 35
Hour Sunday Monday Tuesday Wednesday Thursday Friday Saturday Holiday
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SONP SONP SONP SONP SONP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SMP SMP SMP SMP SMP SMP SMP SMP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP SOFP SOFP SOFP SOFP SOFP SOFP SOFP
SOFP = Summer Off-Peak
SMP = Summer Mid-Peak
...
SONP = Summer On-Peak
Page 66 2006 Integrated Resource Plan
\Ii.
...
NSOFP = Non-Summer Off-Peak
1ft
"'-loana t""ower l,;ompany Appendix D- Technical Appendix
NON-SUMMER SEASON
September 01 through May
Hour
NSMP = Non-Summer Mid-Peak
Market prices were developed within Aurora using the Preferred Portfolio as a resource basis (May
Aurora - 2006IRP - P3 - hrly _zone J'rices - 20yr So Idaho). The values beyond 20 years are extended by
escalating the final year of the forward market price schedule for the additional years needed for the
analysis using the Company s escalation rate of 3.0% for capital investments.
The costing period prices are calculated using the following method:
. NSMP = Average of heavy load prices in January-May and September-December.
. NSOFP = Average of light load prices in January-May and September-December.
SOFP = Average of light load prices in June-August.
SMP = Average of heavy load prices in June-August.
SONP = IPC variable energy and operating cost ofa 162 MW Simple-Cycle Gas Turbine
Annual = IPC variable energy and operating cost of thermal coal plant
2006 InteQrated Resource Plan D~~~ ~7
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O7-
IDAHO POWER COMPANY
TT A CHMENT 1-
(j
)
..
.
.
..
,
..
.
.
::
u
fJ
I..,
, "
U ::J
Re
s
i
d
e
n
t
i
a
l
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Co
m
m
e
r
c
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Ir
r
i
g
a
t
i
o
n
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
In
d
u
s
t
r
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
,
.
.
.
Ad
d
i
t
i
o
n
a
l

F
i
r
m
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Lo
s
s
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
Fi
r
m

L
o
a
d
Ja
n
.

2
0
0
7
79
7
48
4
28
2
13
6
15
0
84
9
Fe
b
.

2
0
0
7

71
5
46
5
27
7
13
7
14
0
73
4
Ma
r
.

2
0
0
7
61
0
44
2
27
1
13
2
12
8
58
7
70
t
h

P
e
r
c
e
n
t
i
l
e

S
a
l
e
s

a
n
d

L
o
a
d

F
o
r
e
c
a
s
t
::
J
-.:
:
Av
e
r
a
g
e

L
o
a
d

(
A
v
e
r
a
g
e

M
e
g
a
w
a
t
t
s
)
r.

2
0
0
7

Ma
y
.

2
0
0
7

Ju
n
.

2
0
0
7

Ju
l
.

2
0
0
7

Au
g
.

2
0
0
7

Se
p
.

2
0
0
7

Oc
t
.

2
0
0
7

No
v
.

2
0
0
7

De
c
.

2
0
0
7
47
4

44
5

50
4

58
2

57
9

47
8

48
8

61
9

79
8
39
5

41
3

45
9

49
4

49
7

44
2

42
9

44
7

49
1
10
6

29
4

54
3

61
8

47
7

30
1

81

27
4

27
2

28
4

28
4

28
6

30
0

30
1

29
5

28
2
13
0

12
7

12
0

13
1

13
0

12
6

12
8

13
3

13
7
15
6

17
9

19
0

21
1

19
6

16
1

13
6

14
4

16
7
53
5

1
72
9

2
,
10
1

2
,
32
1

2
,
16
6

1
,
80
8

1
,
56
4

1
,
64
2

1
,
87
6
Li
g
h
t

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
71
0
1
,
4
6
8
38
3
55
2
89
9
08
0
93
9
61
4
40
1
52
5
74
1
He
a
v
y

L
o
a
d
.
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
95
9
82
2
67
3
65
6
86
9
24
8
52
8
32
9
97
8
68
2
73
5
99
2
Sy
s
t
e
m

L
o
a
d
84
9
73
4
58
7
53
5
72
9
10
1
32
1
16
6
80
8
56
4
64
2
87
6
Fi
r
m

O
f
f
-
Sy
s
t
e
m

L
o
a
d
.
.
.
.
.
.
.
.
.
To
t
a
l

L
o
a
d
84
9
73
4
58
7
53
5
72
9
10
1
32
1
16
6
80
8
56
4
64
2
87
6
Ja
n
.

2
0
0
7
Fe
b
.

2
0
0
7

Ma
r
.

2
0
0
7
En
e
r
g
y

E
f
f
i
c
i
e
n
c
y

(
M
W
)
.
.
.
.
.
.
.
De
m
a
n
d

R
e
s
p
o
n
s
e

(
M
W
)
.
.
.
.
Fi
r
m

P
e
a
k

L
o
a
d
53
0
44
5
34
2
Sy
s
t
e
m

P
e
a
k

(
1

H
o
u
r
)
53
0
2,
4
4
5
34
2
Fir
m

O
f
f
-
Sy
s
t
e
m

P
e
a
k
.
.
.
.
.
.
.
.
.
Lo
s
s
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
To
t
a
l

P
e
a
k

L
o
a
d
53
0
2,
4
4
5
34
2
Pe
a
k

L
o
a
d

(
M
e
g
a
w
a
~
t
s
)
Ap
r
.
2
0
0
7

M
a
y
.
20
0
7

Ju
n
.

2
0
0
7

Ju
l
.

2
0
0
7

Au
g
.

2
0
0
7

S
e
p
.
20
0
7

Oc
t
.

2
0
0
7

No
v
.

2
0
0
7

De
c
.

2
0
0
7

5
-
9
-
13

-
14

-
12

-
9
-
7
-
5'

-
0
-
44

-
46

-
44

97
1

2
,
72
1

3
,
18
6
25
1

2
,
97
5

2
66
2

2
,
05
6

2
,
35
5

2
,
83
2
97
1
72
1
18
6
25
1
97
5
66
2
05
6
35
5
83
2
97
1
72
1
18
6
25
1
97
5
66
2
05
6
35
5
83
2
::
J ::
r
::
J ::J
:::
J
...
.
.
ii3...
.
.
;:
0
..
,
("
)
:::
J
--
-
"
-

-
-
'
.
.
-
-
,
-
-,

,
-
-
.
--
-
_
.
--

--
-
-
-
-
"
"
70
t
h

P
e
r
c
e
n
t
i
l
e

S
a
l
e
s

a
n
d

L
o
a
d

F
o
r
e
c
a
s
t
D:
I
Av
e
r
a
g
e

L
o
a
d

(
A
v
e
r
a
g
e

M
e
g
a
w
a
t
t
s
)
Ja
n
.

2
0
0
8
Fe
b
.

2
0
0
8
Ma
r
.

2
0
0
8
Ap
r
.

2
0
0
8
Ma
y
.

2
0
0
8
Ju
n
.

2
0
0
8
Ju
t

2
0
0
8
Au
g
.

2
0
0
8

Se
p
.

2
0
0
8
Oc
t
.

2
0
0
8
No
v
.

2
0
0
8

De
c
.

2
0
0
8
Re
s
i
d
e
n
t
i
a
l
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
81
0
72
6
61
9
48
1
45
3
51
8
60
0
59
7
49
0
49
8
63
0
81
0
Co
m
m
e
r
c
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
49
7
47
8
45
6
40
8
42
6
47
5
51
2
51
4
45
7
44
2
45
9
50
4
Ir
r
i
g
a
t
i
o
n
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
10
6
;2
9
2
54
1
61
6
47
6
30
0
("
)
:::
J
In
d
u
s
t
r
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
28
8
28
3
27
7
28
0
27
7
29
0
29
0
29
2
30
6
30
8
30
2
28
8
:::
J
Ad
d
i
t
i
o
n
a
l

F
i
r
m
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
13
9
13
7
13
5
13
1
12
9
12
2
13
3
13
1
12
9
13
0
13
5
13
9
Lo
s
s
.
.
,
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
15
3
14
3
13
0
15
9
18
2
19
4
21
6
20
0
16
4
13
9
14
7
17
0
Fi
r
m

L
o
a
d
88
6
76
7
62
1
56
5
76
1
14
0
36
7
84
5
59
8
67
6
91
2
21
1
:::
J
Lig
h
t

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
55
7
74
4
64
8
50
0
1,
4
1
0
58
1
93
4
12
1
98
0
64
8
1,
4
3
1
77
4
He
a
v
y

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
99
9
85
6
71
6
67
8
90
3
30
4
56
0
39
4
00
4
71
8
78
0
02
0
Sy
s
t
e
m

L
o
a
d
88
6
76
7
62
1
56
5
76
1
14
0
36
7
21
1
84
5
59
8
67
6
91
2
Fi
r
m

O
f
f
-
Sy
s
t
e
m

L
o
a
d
.
.
.
.
.
.
.
.
.
To
t
a
l

L
o
a
d
88
6
76
7
62
1
56
5
76
1
14
0
36
7
21
1
84
5
59
8
67
6
91
2
Pe
a
k

L
o
a
d

(
M
e
g
a
w
a
t
t
s
)
Ja
n
.

2
0
0
8
Fe
b
.

2
0
0
8

Ma
r
.

2
0
0
8
Ap
r
.

2
0
0
8
Ma
y
.

2
0
0
8

Ju
n
.

2
0
0
8
Ju
l
.

2
0
0
8
Au
g
.

2
0
0
8
Se
p
.
20
0
8
Oc
t
.

2
0
0
8
No
v
.

2
0
0
8

De
c
.

2
0
0
8
En
e
r
g
y

E
f
f
i
c
i
e
n
c
y

(
M
W
)
.
.
.
.
.
.
.
De
m
a
n
d

R
e
s
p
o
n
s
e

(
M
W
)
.
.
.
.
Fi
r
m

P
e
a
k

L
o
a
d
56
7
2,
4
6
9
38
0
99
3
77
7
23
5
31
2
02
0
71
6
08
8
39
0
85
9
Sy
s
t
e
m

P
e
a
k

(
1

H
o
u
r
)
56
7
2,
4
6
9
38
0
99
3
77
7
23
5
31
2
02
0
71
6
08
8
39
0
85
9
Fi
r
m

O
f
f
-
Sy
s
t
e
m

P
e
a
k
.
.
.
.
.
.
.
.
.
Lo
s
s
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
To
t
a
l

P
e
a
k

L
o
a
d
56
7
2,
4
6
9
38
0
99
3
77
7
23
5
31
2
02
0
71
6
08
8
39
0
85
9
D:I
;;
:
r
D:
I
::
:
J
0.
.
0
:
:
:
-
-

-

-

-

-

-

-

-

-

-

-

-

--
-
-

-

-

-

-

-
I\
.
)
70
t
h

P
e
r
c
e
n
t
i
l
e

S
a
l
e
s

a
n
d

L
o
a
d

F
o
r
e
c
a
s
t
II
)
(j
)
::
:
:
:
I
Av
e
r
a
g
e

L
o
a
d

(
A
v
e
r
a
g
e

M
e
g
a
w
a
t
t
s
)
"'U
Ja
n
.

2
0
0
9

Fe
b
.

2
0
0
9

Ma
r
.

2
0
0
9
r.

2
0
0
9
.
2
0
0
9
Ju
n
.

2
0
0
9
Ju
l
.

2
0
0
9
.
2
0
0
9
20
0
9
Oc
t
.

2
0
0
9
No
v
.

2
0
0
9
De
c
.

2
0
0
9

Re
s
i
d
e
n
t
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
82
1
73
5
62
7
48
7
46
0
53
0
61
6
61
3
50
1
50
6
63
9
82
2
(1
)
..
.
.
(1
)
Co
m
m
e
r
c
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
50
9
49
1
46
9
41
9
43
9
49
0
52
8
53
0
47
1
45
5
47
1
51
6
Ir
r
i
g
a
t
i
o
n
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
10
6
29
2
54
0
61
5
47
5
29
9
(1
)
In
d
u
s
t
r
i
a
l
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
29
4
28
9
28
3
28
7
28
4
29
7
29
7
29
9
31
4
31
5
30
9
29
5
(J
I
II
)
Ad
d
i
t
i
o
n
a
l

F
i
r
m
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
14
0
14
0
13
6
13
3
13
1
12
3
13
4
13
3
13
1
13
2
13
8
14
0
::
:
:
:
I
-..
:
:
..
,
Lo
s
s
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
15
6
14
6
13
3
16
1
18
6
19
8
22
0
20
5
16
7
14
2
15
0
17
3
(1
)
Fi
r
m

L
o
a
d
92
1
80
2
65
3
59
4
79
1
17
8
70
9
"'U
2,
4
1
2
25
6
88
2
63
0
94
7
:::
:
:
I
Lig
h
t

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
77
6
68
0
52
9
1,
4
3
6
60
8
96
9
16
1
02
0
68
0
1
,
4
6
0
58
8
80
7
He
a
v
y

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
03
5
89
4
75
0
70
9
94
9
33
0
60
9
2,
4
4
2
04
4
75
3
81
5
05
8
Sy
s
t
e
m

L
o
a
d
92
1
80
2
65
3
59
4
79
1
17
8
2,
4
1
2
25
6
88
2
63
0
70
9
94
7
Fir
m

O
f
f
-
Sy
s
t
e
m

L
o
a
d
.
.
.
.
.
.
.
.
.
To
t
a
l

L
o
a
d
92
1
80
2
65
3
59
4
79
1
17
8
2,
4
1
2
25
6
88
2
63
0
70
9
94
7
Pe
a
k

L
o
a
d

(
M
e
g
a
w
a
t
t
s
)
Ja
n
.

2
0
0
9
Fe
b
.

2
0
0
9

Ma
r
.

2
0
0
9
Ap
r
.

2
0
0
9
Ma
y
.
20
0
9
Ju
n
.

2
0
0
9
Ju
l
.

2
0
0
9
Au
g
.

2
0
0
9
Se
p
.
20
0
9
Oc
t
.

2
0
0
9
No
v
.

2
0
0
9
De
c
.

2
0
0
9
En
e
r
g
y

E
f
f
i
c
i
e
n
c
y

(
M
W
)
.
.
.
.
.
.
.
De
m
a
n
d

R
e
s
p
o
n
s
e

(
M
W
)
.
.
.
.
Fir
m

P
e
a
k

L
o
a
d
59
6
2,
4
9
7
41
0
00
7
83
4
28
9
37
2
07
3
76
9
11
8
2,
4
2
3
90
9
Sy
s
t
e
m

P
e
a
k

(
1

H
o
u
r
)
59
6
49
7
2,
4
1
0
00
7
83
4
28
9
37
2
07
3
76
9
11
8
2,
4
2
3
90
9
Fi
r
m

O
f
f
-
Sy
s
t
e
m

P
e
a
k
.
.
.
.
.
.
.
.
.
Lo
s
s
.
.
.
.
.
.
.
.
.
.
:.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
To
t
a
l

P
e
a
k

L
o
a
d
59
6
2,
4
9
7
2,
4
1
0
00
7
83
4
28
9
37
2
07
3
76
9
11
8
2,
4
2
3
90
9
"'U (1
)
I\
.
)
'"
"
):
-
(1
)
:::
:
:
I
(1
)
::
:
:
:
I
('5
'
):
-
(1
)
::
:
:
:
I
70
t
h

P
e
r
c
e
n
t
i
l
e

S
a
l
e
s

a
n
d

L
o
a
d

F
o
r
e
c
a
s
t
):
.
t\
)
Av
e
r
a
g
e

L
o
a
d

(
A
v
e
r
a
g
e

M
e
g
a
w
a
t
t
s
)
Ja
n
.

2
0
1
0

Fe
b
.

2
0
1
0
Ma
r
.

2
0
1
0

Ap
r
.

2
0
1
0
Ma
y
.

2
0
1
0

Ju
n
.

2
0
1
0

Ju
t

2
0
1
0
Au
g
.

2
0
1
0
Se
p
.
20
1
0
Oc
t
.

2
0
1
0
No
v
.

2
0
1
0

De
c
.

2
0
1
0

Re
s
i
d
e
n
t
i
a
l
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
83
3
74
6
63
6
49
3
46
8
54
2
63
4
63
0
51
3
51
5
64
9
83
1
Co
m
m
e
r
c
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
52
2
50
3
48
2
43
1
45
2
50
6
54
5
54
7
48
4
46
7
.
4
8
3
52
6
Ir
r
i
g
a
t
i
o
n
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
10
6
29
1
53
9
61
4
47
5
29
9
In
d
u
s
t
r
i
a
l
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
30
1
29
6
29
0
29
3
29
0
30
4
30
4
30
6
32
1
32
2
31
6
30
1
Ad
d
i
t
i
o
n
a
l

F
i
r
m
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
14
2
14
2
13
8
13
5
13
3
12
6
13
8
13
6
13
2
13
3
14
0
14
2
Lo
s
s
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
15
9
14
9
13
6
16
4
18
9
20
1
22
5
20
9
17
1
14
5
15
3
17
6
):
.
74
2
97
7
Fi
r
m

L
o
a
d
95
7
83
6
68
5
62
3
82
3
21
7
45
9
30
2
92
0
66
4
61
9
Li
g
h
t

L
o
a
d
.
.
.
.
.
.
.
.
,.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
80
9
71
2
55
9
1
,
4
6
3
63
6
00
5
20
3
06
1
71
4
1,
4
9
0
83
5
He
a
v
y

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
08
4
92
9
77
6
74
1
98
3
37
3
64
3
2,
4
9
2
08
5
80
0
84
1
08
9
Sy
s
t
e
m

L
o
a
d
95
7
83
6
68
5
62
3
82
3
21
7
2,
4
5
9
30
2
92
0
66
4
74
2
1;
9
7
7
Fi
r
m

O
f
f
-
Sy
s
t
e
m

L
o
a
d
.
.
.
.
.
.
.
.
.
To
t
a
l

L
o
a
d
95
7
83
6
68
5
62
3
82
3
21
7
2,
4
5
9
30
2
92
0
66
4
74
2
97
7
Pe
a
k

L
o
a
d

(
M
e
g
a
w
a
t
t
s
)
Ja
n
.

2
0
1
0
Fe
b
.

2
0
1
0

Ma
r
.

2
0
1
0

Ap
r
.

2
0
1
0
Ma
y
.

2
0
1
0

Ju
n
.

2
0
1
0

Ju
l
.

2
0
1
0

Au
g
.

2
0
1
0
Se
p
.
20
1
0
Oc
t
.

2
0
1
0
No
v
.

2
0
1
0

De
c
.

2
0
1
0
En
e
r
g
y

E
f
f
i
c
i
e
n
c
y

(
M
W
)
.
.
.
.
.
.
.
De
m
a
n
d

R
e
s
p
o
n
s
e

(
M
W
)
.
.
.
.
Fi
r
m

P
e
a
k

L
o
a
d
63
4
52
6
2,
4
5
0
03
2
89
1
34
8
3,
4
4
2
14
0
82
3
14
9
2,
4
5
7
94
8
Sy
s
t
e
m

P
e
a
k

(
1

H
o
u
r
)
63
4
52
6
2,
4
5
0
03
2
89
1
34
8
3,
4
4
2
14
0
82
3
14
9
2,
4
5
7
94
8
Fir
m

O
f
f
-
Sy
s
t
e
m

P
e
a
k
.
.
.
.
.
.
.
.
.
Lo
s
s
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
To
t
a
l

P
e
a
k

L
o
a
d
63
4
52
6
2,
4
5
0
03
2
89
1
34
8
3,
4
4
2
14
0
82
3
14
9
2,
4
5
7
94
8
..
,
t\
)
::
:
0
(J
)
..
,
..
,
('
)
t\
)
-.
:
:
--
-

-
-

-

-

-

-

-

-

,
-
-

-

-

-

-

-

-

..
.
.
.

-
-

-

-

-

-

f\
.
)
70
t
h

P
e
r
c
e
n
t
i
l
e

S
a
l
e
s

a
n
d

L
o
a
d

F
o
r
e
c
a
s
t
t\
)
:3
'
Av
e
r
a
g
e

L
o
a
d

(
A
v
e
r
a
e
M
e
g
a
w
a
t
t
s
...
.
.
Ja
n
.

2
0
1
1

Fe
b
.

2
0
1
1
Ma
r
.
20
1
1
,
r.

2
0
1
1
.
2
0
1
1

Ju
n
.

2
0
1
1
Ju
l
.

2
0
1
1
.
2
0
1
1

20
1
1
Oc
t
.

2
0
1
1
No
v
.

2
0
1
1

De
c
.

2
0
1
1

ii3
Re
s
i
d
e
n
t
i
a
l
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
83
9
75
0
64
0
49
6
47
2
55
2
64
7
64
4
52
1
52
1
65
5
83
6
..
,
...
.
.
Co
m
m
e
r
c
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
53
1
51
2
49
2
44
0
46
2
51
8
55
9
56
0
49
5
47
7
49
1
53
4
Ir
r
i
g
a
t
i
o
n
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
..
.
.
.
.
.
.
.
.
.
.
.
.
.
10
6
29
0
53
6
61
2
47
2
29
8
In
d
u
s
t
r
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
30
7
30
2
29
5
29
9
29
6
31
0
30
9
31
2
32
7
32
8
32
2
30
7
t\
)
Ad
d
i
t
i
o
n
a
l

F
i
r
m
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
14
3
14
3
14
0
13
7
13
4
12
8
14
0
13
7
13
4
13
6
14
1
14
4
-.:
:
:
..
,
Lo
s
s
.
.
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
16
1
15
0
13
7
16
6
19
1
20
4
22
8
21
2
17
3
14
7
15
5
17
8
Fi
r
m

L
o
a
d
98
1
86
0
70
9
64
5
84
5
24
6
2,
4
9
4
33
7
94
9
68
9
76
6
00
0
Li
g
h
t

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
83
2
73
4
58
1
1
,
4
8
2
65
7
03
1
23
5
09
3
74
0
51
3
64
1
85
6
He
a
v
y

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
11
0
95
4
80
1
76
4
00
8
40
4
71
7
51
4
11
6
82
7
86
6
10
3
Sy
s
t
e
m

L
o
a
d
98
1
86
0
70
9
64
5
84
5
24
6
2,
4
9
4
33
7
94
9
68
9
76
6
00
0
Fi
r
m

O
f
f
-
Sy
s
t
e
m

L
o
a
d
.
.
.
.
.
.
.
.
.
To
t
a
l

L
o
a
d
98
1
86
0
70
9
64
5
84
5
24
6
49
4
33
7
94
9
68
9
7G
6
00
0
Pe
a
k

L
o
a
d

(
M
e
g
a
w
a
t
t
s
)
Ja
n
.

2
0
1
1
Fe
b
.

2
0
1
1
Ma
r
.

2
0
1
1

Ap
r
.

2
0
1
1

Ma
y
.

2
0
1
1
Ju
n
.

2
0
1
1
Ju
l
.

2
0
1
1
Au
g
.

2
0
1
1

Se
p
.
20
1
1
Oc
t
.

2
0
1
1
No
v
.

2
0
1
1

De
c
.

2
0
1
1
En
e
r
g
y

E
f
f
i
c
i
e
n
c
y

(
M
W
)
.
.
.
.
.
.
.
De
m
a
n
d

R
e
s
p
o
n
s
e

(
M
W
)
.
.
.
.
Fi
r
m

P
e
a
k

L
o
a
d
65
9
54
5
2,
4
7
5
04
9
94
5
39
6
50
6
17
3
87
7
17
2
48
1
91
8
Sy
s
t
e
m

P
e
a
k

(
1

H
o
u
r
)
65
9
54
5
2,
4
7
5
'2
,
04
9
94
5
39
6
50
6
17
3
87
7
17
2
2,
4
8
1
91
8
Fi
r
m

O
f
f
-
Sy
s
t
e
m

P
e
a
k
.
.
.
.
.
.
.
.
.
Lo
s
s
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
To
t
a
l

P
e
a
k

L
o
a
d
65
9
54
5
2,
4
7
5
04
9
94
5
39
6
50
6
17
3
87
7
17
2
2,
4
8
1
91
8
t\
)f\.
)
):
-
.
-
c
:3
'
('j
'
):
-
70
t
h

P
e
r
c
e
n
t
i
l
e

S
a
l
e
s

a
n
d

L
o
a
d

F
o
r
e
c
a
s
t
-6
'
Av
e
r
a
g
e

L
o
a
d

(
A
v
e
r
a
g
e

M
e
g
a
w
a
t
t
s
)
f:
J
Ja
n
.

2
0
1
2
Fe
b
.

2
0
1
2

Ma
r
.

2
0
1
2
Ap
r
.

2
0
1
2

Ma
y
.
20
1
2
Ju
n
.

2
0
1
2

Ju
l
.

2
0
1
2
Au
g
.

2
0
1
2

Sa
p
.

2
0
1
2
Oc
t
.

2
0
1
2
No
v
.

2
0
1
2

De
c
.

2
0
1
2

Re
s
i
d
e
n
t
i
a
l
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
84
1
75
2
64
2
49
7
47
4
55
8
65
8
65
4
52
7
52
4
65
8
84
4
Co
m
m
e
r
c
i
a
L
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
53
9
52
1
50
1
44
9
47
2
53
0
57
2
57
2
50
6
48
6
50
0
54
4
en
'
Ir
r
i
g
a
t
i
o
n
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
10
6
28
9
53
5
61
1
47
2
29
7
::
r
In
d
u
s
t
r
i
a
l
.
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
31
3
30
8
30
2
30
5
30
2
31
6
.3
1
6
31
9
33
4
33
5
32
9
31
3
Ad
d
i
t
i
o
n
a
l

F
i
r
m
.
.
.
.
,
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
14
5
14
4
14
1
13
9
13
6
12
9
14
2
13
9
13
6
13
8
14
4
14
5
Lo
s
s
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
16
3
15
2
13
9
16
8
19
3
20
7
23
1
21
5
17
6
14
9
15
6
18
0
Fi
r
m

L
o
a
d
00
2
87
7
72
9
66
4
86
7
27
5
52
9
97
6
71
1
78
8
02
9
37
1
Li
g
h
t

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
~..
.
85
0
75
0
60
0
1
,
4
9
9
67
6
05
7
26
6
12
3
76
4
53
3
66
1
88
3
He
a
v
y

L
o
a
d
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
12
1
97
1
82
3
79
6
01
7
2,
4
3
5
75
4
55
0
16
1
84
0
88
9
15
4
Sy
s
t
e
m

L
o
a
d
00
2
87
7
72
9
66
4
86
7
27
5
52
9
37
1
97
6
71
1
78
8
02
9
Fi
r
m

O
f
f
-
Sy
s
t
e
m

L
o
a
d
.
.
.
.
.
.
.
.
.
To
t
a
l

L
o
a
d
00
2
87
7
72
9
66
4
86
7
27
5
52
9
37
1
97
6
71
1
78
8

'
02
9
Pe
a
k

L
o
a
d

(
M
e
g
a
w
a
t
t
s
)
Ja
n
.

2
0
1
2
Fe
b
.

2
0
1
2

Ma
r
.

2
0
1
2

Ap
r
.

2
0
1
2
Ma
y
.
20
1
2
Ju
n
.

2
0
1
2

Ju
l
.

2
0
1
2
Au
g
.
20
1
2
Se
p
.

2
0
1
2
Oc
t
.

2
0
1
2

No
v
.

2
0
1
2

De
c
.

2
0
1
2
En
e
r
g
y

E
f
f
i
c
i
e
n
c
y

(
M
W
)
.
.
.
.
.
.
.
-4
1
-4
3
De
m
a
n
d

R
e
s
p
o
n
s
e

(
M
W
)
.
.
.
.
Fi
r
m

P
e
a
k

L
o
a
d
66
4
56
0
2,
4
7
2
03
7
99
9
3,
4
5
8
57
0
23
4
93
1
19
3
50
3
96
3
Sy
s
t
e
m

P
e
a
k

(
1

H
o
u
r
)
66
4
56
0
2,
4
7
2
03
7
99
9
3,
4
5
8
57
0
23
4
93
1
19
3
50
3
96
3
Fi
r
m

O
f
f
-
Sy
s
t
e
m

P
e
a
k
.
.
.
.
.
.
.
.
.
Lo
s
s
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
,
.
.
.
To
t
a
l

P
e
a
k

L
o
a
d
66
4
56
0
2,
4
7
2
03
7
99
9
3,
4
5
8
57
0
23
4
93
1
19
3
50
3
96
3
..
.
,
:::
0
...
,
::
r
::
E
.,
.
,
,
(
)
-..
:
:
:t
:
-
::
E
:
"t
J
:t
:
-
::
J
:
:t
:
-
"t
J
"t
J
::
J
:
"t
J
:t
:
-
Response To Request for Production DOE 1-9 b
Bennett Mountain
Hours of
Year Month Operation Output (MWh)
2005 January
2005 February 16.101
2005 March 57.053
2005 April 183
2005 May 3.42 501
2005 June 28.918
2005 July 145.41 605
2005 August 89.022
2005 Septem ber 667
2005 October
2005 November
2005 December 19.844
2006 January
2006 February
2006 March 14.338
2006 April
2006 May 62.9,491
2006 June 98.15,404
2006 July 50.206
2006 August
2006 September 37.148
2006 October 13.947
2006 November 23.985
2006 December 28.007
2007 January 39.661
2007 February
2007 March 49.40 786
2007 April 36.103
2007 May 62.311
2007 June 128.19,091
2007 July 407.60,111
Response to Request for Production DOE 1-9 b
Evander Andrews (Dans kin) Unit Nos. 2 & 3
Unit No.Unit No.
Hours of Hours of Total Plant
Year Month Operation Operation Output (MWh)
2005 July 33.29.363
2005 August 37,15.120
2005 September 11.487
2005 October 13.539
2005 November 82.675
2005 December 26.312
2006 January
2006 February 358
2006 March 369
2006 April
2006 May 39.36.023
2006 June 53.53.126
2006 July 184.185.334
2006 August 15.14.149
2006 September 15.17.319
2006 October
2006 November 12.952
2006 December
2007 January
2007 February
2007 March 15.837
2007 April 17.17,554
2007 May 10,10.833
2007 June 48.47.179
2007 Jul 254.244.19,227
Response to Request for Production DOE 1-9 b
Evander Andrews (Dans kin) Unit Nos. 2 & 3
Unit No.Unit No.
Hours of Hours of Total Plant
Year Month Operation Operation Output (MWh)
2001 September 15.344
2001 October 97.112.185
2001 November 43.57.048
2001 December 82.76.601
2002 January 18,24.902
2002 February 23.35.2,411
2002 March 50.85.164
2002 April 20,048
2002 May 35.1 ,439
2002 June 67.85.789
2002 July 242,238,19,097
2002 August 14,14.136
2002 September 24.40 917
2002 October 72.260
2002 November
2002 December 19.47 16.500
2003 January
2003 February 18.789
2003 March 693
2003 April 1.43
2003 May 68.44.244
2003 June 52.48.080
2003 July 284.281.22,629
2003 August 120.120.44 696
2003 September 666
2003 October
2003 November 15.15.394
2003 December
2004 January
2004 February 697
2004 March 163
2004 April 256
2004 May
2004 June 36.31.46 564
2004 July 125.135.10,110
2004 August 74.81.942
2004 September 14.410
2004 October 37.22.786
2004 November 29.27 17.49 294
2004 December
2005 January
2005 February 12.623
2005 March
2005 April
2005 May 253
2005 June 8.41 541
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O7-8
IDAHO POWER COMPANY
ATTACHMENT 1-12a
; I
vol ts less or where the definitions of Primary
service and Transmission Service do not apply.Pr imary
service is service taken at 12 500 volts or 34 500 volts.
Transmission Service is service taken at 44, 000 volts or
higher.
Why is the Company proposing to add service
levels to Schedules 9 and 19?
The Company is proposing to add service
levels for several First the costsreasons.
providing service are associated with the voltage level
at which service is received.For example , customers
receiving service at transmission voltage do not impose
the same distribution-related costs on the Company I
system that recei ving pr imaryservicecustomers
voltage impose.the prices charged toAs a result
Transmission theServiceshouldreflectcustomers
differences in costs.The Company I s current practice of
giving high voltage customers a credit on their billed
demand does not adequately reflect the differences in the
costs providing service transmission versus
distr ibution voltage.By establishing service levels
based on voltage, prices can be established which more
accurately and fairly reflect the costs of providing
service.
Second , establishing voltage based service
BRILZ, Di
Idaho Power Company
levels will improve the Company's ability to provide
service to customers both from an administrative and
customer service line extensionperspective.Any
payments or facilities beyond the point of delivery will
be determined at the time service is established.There
will be no need for any. adjustments or refunds at a later
date should the customer subsequently qualify for a
different schedule.As a result , transitions between
Schedules 9 and 19 , as customers' loads change , will be
simplified since customers will move to the same service
level under the appropriate schedule.
Finally,service levelsvoltagebased
coupled with a cost-of-service aligned revenue allocation
to the classes , should reduce the wide discrepancy in
prices now experienced by customers who transfer between
Schedules 9 and 19.
How will customers currently taking service
under Schedule 9 and Schedule 19 be classified as either
Secondary, Primary, or Transmission Service customers?
Customers currently taking service under
Schedule will classified ServiceSecondary
customers.The 41 current Schedule 19 customers who no
longer qualify for service under that schedule with the
000 kW threshold will be classified as Schedule 9
Primary Service customers.There are no customers at
BRILZ , Di
Idaho Power Company
this time who will qualify for Schedule 9 Transmission
Service .The five Schedule 19 customers who currently
are receiving service at 44 000 volts or higher will be
classified as Schedule 19 Transmission Service customers.
All remaining Schedule 19 customers will be classified as
Primary Service customers.No customers qualify at this
time for Schedule 19 Secondary Service.
What is the present rate structure for
Schedule 9?
Customers taking service under Schedule 9
pay both an Energy Charge and a Demand Charge for the
metered usage.In addition , Schedule 9 customers are
subj ect to a $15. 00 minimum charge.Approximately two
percent of the total billings for Schedule 9 during the
1993 test year were minimum billings representing about
one-half of one percent of the total class revenue.
What is the present rate structure for
Schedule 19?
Customers taking service under Schedule 19
pay an Energy Charge and a BasicDemand Charge
Charge.The Energy Charge is applied to the actual
metered energy for the billing period.The Demand Charge
is applied to the metered demand; however, the minimum
billing demand is 750 kW.The Basic Charge is applied to
the Basic Load Capacity which is the average of the two
BRILZ , Di
Idaho Power Company
highest billing demands during the current 12-month
period but not less than 750 kW.In addition , customers
pay a Facilities Charge of 1. 7 percent per month on any
Company-owned facilities beyond the point of delivery.
Please describe the rate design proposal
for Schedule
In addition to raising the ceiling for
service eligibility from 750 kW to 1,000 kW and to
creating Secondary,Primary,and Transmission Service
levels , the Company is proposing to add a Customer Charge
and a Basic Charge to Schedule For customers taking
Primary Service or Transmission Service , a Facilities
Charge of 1. 7 percent is also being added.The rate
design proposals for Schedule 9 are shown on pages 4
through 6 of Exhibit No. 36.
What is the Customer Charge for Schedule 9?
The Custome~ Charge for Secondary Service
under Schedule This amount represents$5.50.
approximately 15 percent of the cost-of-service result of
$35.81 shown at line 420 on page 3 of Exhibit No. 35.
The Customer Charge for Primary and Transmission Service
is $85.This amount is the same charge established for
Schedule 19 Primary Service and Schedule 19 Transmission
Service associated with thethecostandref lects
electronic .metering of customers at these voltage levels.
BRILZ, Di
Idaho Power Company
What is the Company s proposal for adding
a Basic charge to Schedule
The propos ing tha t BasicCompany
Charge to be applied to each kW of Basic Load Capacity be
added to Schedule
What is Basic Load Capacity?
Basic Load Capacity is a demand-related
billing component which is computed at the time the
customer's bill is prepared by averaging the two highest
non-zero billing demands during the 12-month period
ending with the current billing period.
What is the Basic Charge for Schedule 9?
The Basic Charge for Secondary Service is
$ . 36 per kW of Basic Load Capacity.The $. 36 charge
reflects the cost of service for distribution lines and
transformers as shown at line 420 on page 3 of Exhibit
No. 35.For Primary Service, the Basic Charge is $.
per kW of Basic Load Capaci ty .The Basic Charge for
Transmission Service is $.39.The Basic Charge for
primary Service and the Basic Charge for Transmission
Service are the same as those for Schedule 19.The
derivation of the $.76 and $.39 charges is detailed later
in my discussion of the Schedule 19 rate design.
What is the Demand Charge for Schedule 9?
The Demand Charge for Secondary Service is
BRILZ , Di
Idaho Power Company
decreased from $ 3 . 2 2 $3.For pr imaryper kW
Service , the Demand Charge is $3.04 per kW.The Demand
Charge for Transmission Service is $2.95 per kW.Again,
the charges for Secondary,Pr imary ,and Transmission
Service are the same as those for Schedule 19 and are
detailed in my discussion of the Schedule 19 rate design.
What is the Energy Charge for Schedule 9?
The Energy Charge for Secondary Service is
decreased from 2.93469 to 2.61559 per kWh.For Pr imary
Service the Energy Charge is 2.14909 per kWh.The
Energy Charge for Transmission Service is 2.10119 per
kWh.
How were the Energy Charges derived?
The Energy Charge for Secondary Service was
derived to recover the residual revenue requirement once
the Customer, Basic , and Demand Charges were established.
The Primary Service Energy Charge is set at 5 percent
over the Schedule 19 Primary Service Energy Charge.The
Transmission Service Energy Charge is set equal to the
Schedule 9 Primary Service Energy Charge adjusted to
reflect losses avoided taking servicethe
transmission voltage.
Why was the Primary Service Energy Charge
set at 5 percent over the Schedule 19 Primary Service
Energy Charge?
BRILZ, Di
Idaho Power Company
The Company wants to ensure that a price
signal given there limitedcustomers
incentive to use additional energy in order to qualify
for Schedule 19.The Energy Charge was set at 5 percent
over the Schedule 19 Primary Service Energy Charge to
provide differential prices between the two
schedules which, when considered with the minimum Billing
Demand and Basic Load capacity provisions under Schedule
, provides the appropriate price signal.
What provision for a Facilities Charge is
included in your rate design proposal for Schedule
Customers taking Service andPr imary
Transmission Service will be responsible ei therfor
owning all facilities , including the transformers , beyond
the point delivery paying the Company
facilities charge in the amount of 1.7 percent times the
Company s investment in the facilities beyond the point
of delivery.
What requirementtherevenue
recovered from Schedule 9?
Based on Mr. Gales's Exhibit No.4 6 , the
total annual revenue to be collected from customers
taking service under Schedule 9 is $78 042 429.This
revenue requirement includes the revenue to be collected
from existing Schedule 33 customers moved to Schedule 9
BRILZ, Di
Idaho Power Company
,,-
as well as from existing Schedule 19 customers targeted
to be Schedule 9 Pr imary Service customers.
What is the impact of this rate design on
Large General Service customers?
As can be seen from page 4 of Exhibit No.
37, approximately 69 percent of the existing customers
taking service under (Secondary Service)Schedule
receive a reduction in their annual bills as a result
the proposed rate design.Of the customers receiving a
reduction, approximately 40% receive a decrease greater
than the 3.78 percent recommended by the Company for the
Secondary Service customers as a whole.
What are the usage characteristics of the
Secondary Service decreases andreceivingcustomers
increases under your proposal?
Page 4 of Exhibit No. 37 shows the average
load factoI;"' for customers in each "percent range " group.
As can be seen from this Exhibit , the percent decrease or
increase received through the rate design is associated
with the customer I s load factor.Specif ically, customers
whose monthly demand remains fairly steady and close to
the Basic Load Capacity will tend to receive a decrease
in their annual billings.Conversely, customers whose
monthly demand throughout the year varies relatively
widely from the Basic capaci ty willLoad generally
BRILZ , Di
Idaho Power Company
receive an increase in their annual billings.Examples
the usage characteristics receivingcustomers
decreases and increases under the rate design proposed
are included in my workpapers.
What is the impact of your rate design
proposal on customers transferring from Schedule 33 to
Schedule 9?
All customers transferring from Schedule 33
to Schedule 9 will be served at Secondary Service.Page
5 of Exhibit No.3 7 shows the impact of the proposed rate
design by range of percent change.As can be seen from
this Exhibit approximately 45 percent of the Schedule
customers receive a decrease in their annual billing
under the Schedule 9 rate design.Of the remaining 226
customers who recei ve an increase under Schedule 9 , 52
percent receive an increase of less than 5 percent which
is the overall class increase which would be required to
bring the existing Schedule 33 customers to cost of
service as shown on Mr. Gales' Exhibit No.4 6.
What is the impact of your rate design
proposal customers taking underpr imary Service
Schedule 9?
Page 6 of Exhibit No.3 7 shows the impact
of the rate design proposal on Primary Service customers
by range of percent change.Page 7 of Exhibit No.3 7
BRILZ, Di
Idaho Power Company
shows the impact of the rate design proposal on each
Primary Service customer.Compared to the existing
Schedule the proposed Pr imaryratesSchedule
Service rates result in an increase in annual billings
for all but one customer.Page 8 of Exhibit No.3 7 shows
the impact of the rate design proposal compared to the
proposed rates for Schedule 19 Primary Service.As can
be seen on page 8 of Exhibit No. 37 , all but 5 customers
have lower annual bills under the proposed Schedule 9
Primary Service than under the proposed ' Schedule
Primary Service.Page 9 of Exhibit No. 37 shows the
impact of the proposed rate design compared with the
proposed ~chedule 19 Primary service rate design by
individual customer.
What fordes igntherate proposal
Schedule 19?
In addition to raising the threshold from
750 kW to 1 , 000 kW and adding Secondary, pr imary , and
Transmission Service levels to Schedule 19 , a Customer
Charge is being added. There are no other changes in rate
structure proposed for Schedule 19.The rate design
proposals are shown on pages 8 through 10 of Exhibit No.
36.
What is the Customer Charge for Schedule
19?
BRILZ , Di
Idaho Power Company
For Primary and Transmission Service the
Customer Charge is $85.Eighty-five dollars reflects
approximately 30 percent of the $292.74 amount supported
by cost of service as shown at line 480 on page 4 of
Exhibi t No.For Secondary Service the Customer35.
Charge is $5.50.This amount is the same as that for
Schedule 9 Secondary Service.
You stated earlier that one of the pricing
objectives of your rate design proposal was to establish
the Customer Charge at 15 percent of cost of service.
Why are you proposing the Customer Charge be set at 30
percent for Primary and Transmission service?
All of the customers who will be classified
Primary and Transmission customers underService
ei ther Schedule 9 or Schedule 19 are currently taking
service under Schedule 19.These customers are among the
Company I S largest and most sophisticated users.
placing more emphasis on the Customer Charge for this
group of customers , the Energy Charge and Demand Charge
can be set closer to cost of service than they otherwise
would be , thus benefitting the most efficient customers.
What is the Basic Charge for Schedule 19?
The Basic Charge for Secondary Service is
36, the same as that for Schedule 9 Secondary Service.
For Primary Service the Basic Charge is $. 76 which
BRILZ, Di
Idaho Power Company
reflects the cost of service for distribution facilities
as shown at line 480 on page 4 of Exhibit No. 35.For
Transmission Service the Basic Charge is $.39.Again
this service forrepresentscostchargethe
distribution facilities used to serve customers taking
service at transmission voltage.
What is the Demand Charge for Schedule 19?
The Demand Charge for primary Service is
$3.04.This Demand Charge was computed to recover the
residual revenue requirement once the Customer, Basic
and Energy Charges were determined.For Transmission
Service the Demand Charge is $2.95.This Demand Charge
was derived by deducting from the $3.04 Primary Service
Demand Charge the losses which are avoided by service
being taken at the transmission level.The Demand Charge
for Secondary Service is $3.13 which was derived by
adding to the $3.04 Primary Service Demand Charge losses
incurred by service being taken at secondary voltage.
Consistent with increase the threshold forthe
eligibility from 750 kW to 1,000 kW, the minimum billing
demand is also increased from 750 kW to 1,000 kW.
What is the Energy Charge for Schedule 19?
The for Pr imary ServiceEnergyCharge
remains unchanged from its current level of 2.0467(:.The
Energy Charge for Transmission Service is 2.0011(: per
BRILZ , Di
Idaho Power Company
kWh.This amount reflects an adjustment to the 2. 0467C
to take into account the losses which are avoided by
service being taken at transmission voltage.The Energy
Charge for Secondary Service is set at the Schedule 9
secondary Service Energy Charge less 4 . 75 percent to
reflect the same degree of difference in Energy Charges
as is established for Schedule 9 Primary Service and
Schedule 19 Primary Service.
Does your rate design proposal include any
revisions to the provision for a Facilities Charge under
Schedule 19?
No.Customers taking Primary Service and
Transmission Service will continue to be required to
either own all facilities , including transformers , beyond
the point of delivery or pay the Company a Facilities
Charge of 1. 7 percent times the Company's investment in
those facilities.Customers taking Secondary Service
will not be subject to a Facilities Charge.
What revenueannualthetota I
requirement to be collected from Large Power Service
customers?
Based on Mr. Gales's Exhibit No. 46, the
total annual revenue requirement to be collected from
Schedule 19 is $44 860,097.
What is the impact of the rate design on
BRILZ , Di
Idaho Power Company
Large Power Service customers?
Pages 10 through 12 of Exhibit No.show
the impact the rate design for Pr imary Service
customers.the Schedule Pr imary Service
customers , . 37 receive an increase of less than 5. 75
percent, which is the overall increase for the Primary
Service customer group as a whole.The impact on the
Schedule 19 Transmission Service customers is detailed on
page Exhibit No.37.Of the five customers
receiving Transmission Service , two receive an increase
less than the overall increase for the group of. 5.
percent.
What are the usage characteristics of the
customers receiving increases less than and greater than
the overall increases for the respective groups as a
whole?
general pr imary and Transmiss ion
Service customers who have monthly billing demands which
remain fairly steady and close to the Basic Load Capacity
tend to have less of an increase in their annual billing
than do customers whose monthly demand throughout the
year varies from the Basic Load Capacity.Also , because
the rate design proposal places an increased emphasis on
capaci ty, the higher the customer's load factor , the more
beneficial the rate structure tends to be in terms of the
BRILZ, Di
Idaho Power Company
Sc
h
e
d
u
l
e

1
Sc
h
e
d
u
l
e

7
Sc
h
e
d
u
l
e

9
Sc
h
e
d
u
l
e

1
9
Sc
h
e
d
u
l
e

2
4
(I
n
-
Se
a
s
o
n
)
mb
.
8/
2
7
/
9
4
.
RA
T
E
S
U
M
.
XL
S
ID
A
H
O

P
O
W
E
R

C
O
M
P
A
N
Y
SU
M
M
A
R
Y

O
F

C
H
A
R
G
E
S

A
N
D

B
A
S
I
S

F
O
R

R
A
T
E
S
ME
T
E
R
E
D

S
C
H
E
D
U
L
E
S
Ch
a
r
g
e
Se
c
o
n
d
a
r
y
Ra
t
e

Ba
s
i
s
Pr
i
m
m
Ba
s
i
s
Tr
a
n
s
m
i
s
s
i
o
n
Ra
t
e

Ba
s
i
s
Ra
t
e
Cu
s
t
o
m
e
r
15
%

o
f

C
O
S
En
e
r
g
y
05
0
2
1
1
Re
s
i
d
u
a
l
Cu
s
t
o
m
e
r
15
%

o
f

c
a
s
En
e
r
g
y
06
0
1
4
6
Re
s
i
d
u
a
l
Cu
s
t
o
m
e
r
15
%

o
f

C
O
S
85
.
R1
9
P
85
.
R1
9
T
Ba
s
i
c
Eq
u
a
l

t
o

ca
s
R1
9
P
R1
9
T
De
m
a
n
d
R1
9
S
R1
9
P
R1
9
T
En
e
r
g
y
02
6
1
5
5
Re
s
i
d
u
a
l
02
1
4
9
0
R1
9
P

+

5
%
02
1
0
1
1
R9
P

-

l
o
s
s
e
s
Cu
s
t
o
m
e
r
R9
S
85
.
30
%

o
f

c
a
s
85
.
R1
9
P
Ba
s
i
c
R9
S
Eq
u
a
l

t
o

ca
s
Eq
u
a
l

t
o

ca
s
De
m
a
n
d
R1
9
P

+

l
o
s
s
e
s
Re
s
i
d
u
a
l
9,
5
R1
9
P

-

l
o
s
s
e
s
En
e
r
g
y
02
4
9
1
3
R9
S

-

4
.
75
%
02
0
4
6
7
No

C
h
a
n
g
e
02
0
0
1
1
R1
9
P

-

l
o
s
s
e
s
Cu
s
t
o
m
e
r
10
.
15
%

o
f

c
a
s
nl
a
85
.
R1
9
T
Ba
s
i
c
5.
4
5
8%

o
f

R
e
v
.

R
e
q
.
nl
a
%
o
f

R
2
4
S

D
m
d
De
m
a
n
d
.
R
1
9
S
nl
a
R1
9
T
En
e
r
g
y
02
8
3
9
7
Re
s
i
d
u
a
l
nl
a
02
6
9
8
8
R2
4
S

-

l
o
s
s
e
s
EX
H
I
B
I
T

N
O
.

3
9
CA
S
E

N
O
.

I
P
C
-
94
-
M.

B
R
I
L
l
,

I
P
C
O
PA
G
E

1
O
F

1
Ge
n
e
r
a
t
i
o
n

l
e
v
e
l
Tr
a
n
s
m
i
s
s
i
o
n
St
a
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n

P
r
i
m
a
r
y
Al
l

O
t
h
e
r
Ge
n
e
r
a
t
i
o
n

l
e
v
e
l
Tr
a
n
s
m
i
s
s
i
o
n
St
a
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n

P
r
i
m
a
r
y
Al
l

O
t
h
e
r
mb
.
B/
2
7
/
9
4
.
R9
R
T
C
O
M
P
.
XL
S
--
-
-
-
"
Sc
h
e
d
u
l
e

9
Bi
l
l
i
n
g

C
o
m
p
o
n
e
n
t

C
h
a
r
g
e
s

C
a
l
c
u
l
a
t
i
o
n
Ca
l
c
u
l
a
t
i
o
n

o
f

S
e
r
v
i
c
e

L
e
v
e
l

E
n
e
r
g
y

C
h
a
r
g
e
s
lo
s
s
e
s
En
e
r
g
y
%
C
h
a
n
g
e
En
e
r
g
y

$
00
0
04
7
1.
0
4
7
04
4
8
9
0
02
0
8
9
1
05
3
05
3
00
5
6
9
8
02
1
0
1
1
07
7
07
7
02
2
2
8
4
02
1
4
9
0
10
8
10
8
02
7
9
7
8
02
6
1
5
5
Ca
l
c
u
l
a
t
i
o
n

o
f

S
e
r
v
i
c
e

L
e
v
e
l

D
e
m
a
n
d

C
h
a
r
g
e
s
05
3
06
7
10
1
13
3
00
0
05
3
06
7
10
1
13
3
05
0
3
3
2
01
3
1
2
1
03
0
8
8
1
02
8
2
4
4
Pa
g
e

3
,r
-
'
"
'--
-
-
"
"
"-
-
"
,
,
Sc
h
e
d
u
l
e

1
9
Bil
l
i
n
g

C
o
m
p
o
n
e
n
t

C
h
a
r
g
e
s

C
a
l
c
u
l
a
t
i
o
n
Ca
l
c
u
l
a
t
i
o
n

o
f

S
e
r
v
i
c
e

L
e
v
e
l

E
n
e
r
g
y

C
h
a
r
g
e
s
Ge
n
e
r
a
t
i
o
n

L
e
v
e
l
Tr
a
n
s
m
i
s
s
i
o
n
St
a
t
i
o
n
Di
s
t
r
i
b
u
t
i
o
n

P
r
i
m
a
r
y
Al
l

O
t
h
e
r
Lo
s
s
e
s
En
e
r
g
y
%
C
h
a
n
g
e
En
e
r
g
y

$
00
0
04
7
04
7
04
4
8
9
0
01
9
8
9
7
05
3
05
3
00
5
6
9
8
02
0
0
1
1
01
7
07
7
02
2
2
8
4
02
0
4
6
7
10
8
10
8
02
7
9
7
8
02
1
0
4
0
Ca
l
c
u
l
a
t
i
o
n

o
f

S
e
r
v
o
c
e

L
e
v
e
l

D
e
m
a
n
d

C
h
a
r
g
e
s
Ge
n
e
r
a
t
i
o
n

L
e
v
e
l
00
0
Tr
a
n
s
m
i
s
s
i
o
n
05
3
05
3
05
0
3
3
2
St
a
t
i
o
n
06
7
06
7
01
3
1
2
1
Di
s
t
r
i
b
u
t
i
o
n

P
r
i
m
a
r
y
10
1
10
1
03
0
8
8
1
Al
l

O
t
h
e
r
13
3
13
3
02
8
2
4
4
3.

t

3
mb
.
6/
2
4
/
8
4
.
R 1
8
P
R
I

C
P

.
XL
S
Pa
g
e

2
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O7-
IDAHO POWER COMPANY
ATTACHMENT 1-12b
.. '
System Level
Transmission
Distribution Station
Distribution Primary
Distribution Secondary
System Level
Transmission
Distribution Station
Distribution Primary
Distribution Secondary
Idaho Power Company
Average System Loss Coefficients
Typical Peak Demand Coefficients
1985 1986 1987
050
063
104
139
061
072
099
128
059
066
100
131
2001 Average
old
average
050
058
095
123
055
065
100 '
130 .
057
067
101
133
Annual Energy Coefficients
1985 1986 1987 2001 Average
041 038 046 040 041 041
052 049 053 048 051 051
079 066 078 070 073 074
110 093 115 1.111 107 106
. Distribution Secondary includes distribution line transformers
DLS 5/30/03
Exchange In
Utility Purchases
PS Generation
Utility Purchases
PS Generation
Utility Purchases
PS Generation
564 954
168,337
251,969
277 ,579
515
Figure 1:
Idaho Power Company
2001
Energy Loss Coefficients Diagram
Values in MWh
Transmission System
Input -985,260
Losses =657 609
:::
Output 16,327,651
Loss Coefficient =0403
13,432,375 To Distribution
Distribution Stations
Input -13,432 375
:::
Losses =102 178
Output =330,197
Loss Coefficient =0077
575 000 To Distribution Prim
Distribution Primary
Input 860 094
Losses =254 222
Output =11,605,872
Loss Coefficient =1.0219
033,111 To Distribution Sec
Distribution Secondary
Input =033,111
Losses =330,044
Output =703 067
Loss Coefficient =0379
Exchange In =
Utility Purchases =
PS Generation =
Total Input =
Exchange Out =
HV Sales =
Station Sales =
Dist. Secondary Sales =
Total Output =
Total Losses =
Totals
564 954
445,916
259,484
270,354
508 070
387,206
755 197
275 828
15,926,301
344 053
508 070 Exchange Out
387 206 HV Sales
691 711 Direct Station Sales
63,486 Irrigation Sales
ary
572,761 Direct Sales
ondary
703 067 Distribution Sales
,,-
Exchange In
Utility Purchases
PS Generation
Utility Purchases
PS Generation
Utility Purchases
PS Generation
430.
363.
556.
Figure 2:
Idaho Power Company
2001
Typical Peak Loss Coefficients
Values in MW
Transmission System
Input -349.
...
Losses =112.
Output 237.
Loss Coefficient =0504
161.9 To Distribution
Distribution Stations
Input 161.
Losses =16.
Output =145.
Loss Coefficient =0075
042.3 To Distribution Prima
Distribution Primary
Input 067.
Losses =70.4
Output =996.
Loss Coefficient =0353
996.9 To Distribution Seco
Distribution Secondary
Input =996.
. Losses =50.
...
Output =946.
Loss Coefficient =0261
25.
Totals
Exchange In = 430.
Utility Purchases = 388.
PS Generation = 556.
Total Input = 2,374.
Exchange Out = 0,
HV Sales = 75.4
Station Sales = 103.
Dist. Secondary Sales = 946.
Total Output = 2,125.
Total Losses = 249.
0 Exchange Out
75.4 HV Sales
92.7 Direct Station Sales
10.8 Irrigation Sales
0 Direct Sales
ndary
946.1 Distribution Sales
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-O7-
IDAHO POWER COMPANY
TT A CHMENT 1-
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATE
OF IDAHO.
) CASE NO. IPC-O3-
IDAHO POWER COMPANY
DIRECT TESTIMONY
WILLIAM E. AVERA
TABLE OF CONTENTS
(For Convenience of Reader)
I: .I:NT!lODUCTI:ON ......................................... 1
Qualifications .....................................Overview..
............ ...... ....... ....
..........'. 4
C. Summary of Conclusions ............................. 6
I:I: .~AL ANALYSES
....
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
A. Idaho Power Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
B. Electric Power Industry. . . . . . . . . . . . . . . . . . . . . . . . . . . 13
C. Capi tal Markets and Economy. . . . . . . . . . . . . . . . . . . . . . . 26
I: I: I: . CAPI:TAL MARKET EST~TES ............................ 30
Economic Standards ....................
~...........
B. Discounted Cash Flow Analyses. . . . . . . . . . . . . . . . . . . . . 37
C. Risk Premium Analyses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
D. Proxy Group Cost of Equity....... . . . . . . . . . . . . . . . . . 63
:IV .RETORN ON EQUI:TY FOR I:DAHO POWER COMPANY............ 66
Capital Structure .................................
Other Factors .....................................
C. Implications for Financial Integrity.............. 76
Conclusions .......................................
Exhibi t
Exhibi t
Exhibi t
Exhibi t
Exhibi t
Exhibi t
Exhibi t
No.
No.
No.
No.
No.
No. 10
No. 11
- DCF Model - Dividend Yield
- DCF Model - proj ected Earnings Growth
- DCF Model - li b x r " Growth
- Risk Premium Method - Authorized Returns
- Risk Premium Method - Realized Returns
- Ri sk Premium Method - CAPM
- Qualifications of William E. Avera
INTRODUCTION
Please state your name and bu~iness address.
William E. Avera, 3907 Red River, Austin,
Texas, 78751.
What is your present occupation?
I am a financial, economic, and policy
consultant to business and government.
A. Qua1ificatioDS
What are your qualifications?
I received a B. A. degree wi th a maj or in
economics from Emory Uni versi ty .After serving in the
Uni ted States Navy, I entered the doctoral program in
economics at the University of North Carolina at Chapel
Hill.Upon receiving my Ph.D., I joined the faculty at the
Uni versi ty of North Carolina and taught finance in the
Graduate School of Business.I subsequently accepted a
position at the University of Texas at Austin where I
taught courses in financial management and investment
analysis.I then went to work for International Paper
Company in New York City as Manager of Financial Education,
a position in which I had responsibility for all corporate
education programs in finance, accounting, and economics.
In 1977, I joined the staff of the Public Utility
Commission of Texas ("PUCT") as Director of the Economic
AVERA, DI
Idaho Power Company
Research Division.During my tenure at the POCT, I managed
a division responsible for financial analysis, cost
allocation and rate design, economic and financial
research, and data processing systems, and I testified in
cases on a variety of financial and economic issues.Since
leaving the POCT in 1979, I have been engaged as a
consul tant. I have participated in a wide range of
assignments involving utility-related matters on behalf of
utilities, industrial customers, municipalities, and
regulatory commissions.I have previously testified before
the Federal Energy Regulatory Commission ("FERC") , as well
as the Federal Communications Commission ("FCC"), the
Surface Transportation Board (and its predecessor, the
Interstate Commerce Commission), the Canadian Radio-
Television and Telecommunications Commission, and
regulatory agencies, courts, and legislative committees in
30 states, including the Idaho Public Utilities Commission
the Co~ssion " or "IPUC"
Wi th the approval of then-Governor George W. Bush, I
was appointed by the PUCT to the Synchronous
Interconnection Committee to advise the Texas legislature
on the costs and benefits of connecting Texas to the
national electric transmission grid.Currently, I serve
an outside director of Georgia System Operations
Corporation, the system operator for electric cooperatives
AVERA, DI
Idaho Power Company
in Georgia.
I have served as Lecturer in the Finance Department
at the University of Texas at Austin and taught in the
evening graduate program at St. Edward's University for
In addition, I have lectured on economic andtwenty years.
regulatory topics in programs sponsored by universities and
industry groups.I have taught in hundreds of educational
programs for financial analysts in programs sponsored by
the Association for Investment Management and Research, the
Financial Analysts Review, and local financial analysts
societies.These programs have been presented in Asia,
Europe, and North America, including the Financial Analysts
Seminar at Northwes tern Uni vers i ty .I hold the Chartered
Financial Analyst (CFA ) designation and have served as Vice
President for Membership of the Financial Management
Association. I have also served on the Board of Directors
of the North Carolina Society of Financial Analysts.I was
elected Vice Chairman of the National Association of
Regulatory Commissioners ("NARUC") Subcommittee on
Economics and appointed to NARUC's Technical Subcommittee
on the National Energy Act.I have also served as an
officer of various other professional organizations and
societies.A resume containing the details of my
experience and qualifications is attached as Exhibit No.
11.
AVERA, DI
Idaho Power Company
case?
B. Overview
What is the purpose of your testimony in this
The purpose of my testimony is to present to
the Commission my independent evaluation of a fair rate of
return on equity ("ROE") range for Idaho Power Company
Idaho jurisdictional electric utility operations.
Please summarize the basis of your knowledge
and conclusions concerning the issues to which you are
testifying in this case.
To prepare my testimony, I used information
from a variety of sources that would customarily be relied
on by a person in my area of expertise.I am familiar with
the organization and operations of Idaho Power from my
prior participation before the Commission on behalf of the
Company in Case No. IPC-94-In connection with the
present filing, I considered information relevant to Idaho
Power obtained through discussions with corporate
management and from my review of numerous documents
relating to the Company and its parent, IDACORP, Inc.
IDACORP"
) .
These included financial reports and filings,
prior regulatory proceedings and orders, as well as bond
rating agency reports.I also reviewed information
relating generally to current capital market conditions and
specifically to investor perceptions, requirements, and
AVERA, DI
Idaho Power Company
expectations for vertically integrated electric utilities
like Idaho Power.These sources, coupled wi th
experience in the fields of finance and utility regulation,
have given me a working knowledge of investors ' ROE
requirements confronting Idaho Power as it competes to
attract capital, and form the basis of my analyses and
conclusions.
What is the role of ROE in setting a utility
rates?
The rate of return on common equity serves to
compensate investors for the use of their capital to
finance the plant and equipment necessary to provide
utility service.Investors only commit money in
anticipation of earning a return on their investment
commensurate with that available from other investment
alternatives having comparable risks.Consistent with both
sound regulatory economics and the standards specified in
the Bluefield (Bluefield Water Works Improvement Co. v.
Pub. Serv. Comm ' n, 2 62 u. s. 679 ( 1923 )) and Hope Fed.
Power Comm n v. Hope Natural Gas Co., 320 u.s. 591 (1944))
cases, the return on investment allowed a utility should be
sufficient to: 1) fairly compensate capital invested in the
utility, 2) enable the utility to offer a return adequate
to attract new capital on reasonable terms, and 3) maintain
the utility s financial integrity.
AVERA, DI
Idaho Power Company
How did you go about developing your
conclusions regarding a fair rate of return on equity range
for Idaho Power?
I first reviewed the operations and finances
of Idaho Power and the general conditions in the electric
utility industry and the economy.With this as a
background, I developed the principles underlying the cost
of equity concept and then conducted various generally
accepted quantitative analyses to estimate the Company
current cost of equity.These included discounted cash
flow DCFn analyses and risk premium methods applied to a
reference group of electric utili ties, as well as reference
to earned rates of return expected for utilities and
industrial firms.Based on the cost of equity estimates
indicated by my analyses, the Company s ROE was evaluated
taking into account the relative strengths and weaknesses
of the al ternati ve methods, as well as other factors (e. g.
flotation costs) that are properly considered in setting
the ROE for Idaho Power s electric utility operations in
Idaho.
C. U1lllftAry of Conclusions
Please summarize your findings regarding the
fair rate of return on equity for Idaho Power.
My quantitative analyses of the cost of equity
included applications of the DCF model and risk premium
AVERA, DI
Idaho Power Company
methods to a benchmark group of eight electric utili ties
opera ting in the wes tern U. S .Based on the results of
these approaches, I concluded that the fair rate of return
on common equity for Idaho Power is presently in the range
of 10.6 to 11.9 percent.
In evaluating the ROE for Idaho Power, it is
important to consider investors I continued focus on the
unsettled conditions in western power markets and the
unique risks imposed by the Company s much greater reliance
on hydroelectric generation to meet its energy needs.
Regulatory uncertainties, along with unfavorable capital
market conditions, compound the investment risks associated
with the jurisdictional utility operations of Idaho Power.
Coupled with investors ' expectations for higher utility
bond yields going forward, these greater risks support the
reasonableness of my 10.6 to 11.9 percent ROE range.
The cost of fully funding the Company s return on
common equity is small relative to the potential benefits
that a financially sound utility can have in providing
reliable service at reasonable rates and supporting
economic growth.Considering the importance of ensuring
investor confidence and maintaining Idaho Power s financial
flexibility and the ability to attract needed capital, an
ROE in the 10.6 to 11.9 percent range is both necessary and
reasonable at this critical juncture.
AVERA, DI
Idaho Power Company
II. FUNDAMENTAL ANALYSES
What is the purpose of this section?
This section examines the risks and prospects
for the electric utility industry as a whole and conditions
in the capi tal markets and the general economy.
understanding of these fundamental factors that drive the
risks and prospects of electric utilities is essential to
developing an informed opinion about current investor
expectations and requirements that form the basis of a fair
rate of return on equity.In addition, as a predicate to
my economic and capital market analyses, this section
briefly describes Idaho Power and reviews its operations
and finances.
A. :Idaho Power Company
Briefly describe Idaho Power.
Headquartered in Boise, Idaho Power is a
wholly-owned subsidiary of IDACORP and is principally
engaged in providing integrated retail electric utility
service in a 20,000 square mile area in southern Idaho and
During the most recent fiscal year, Idahoeastern Oregon.
Power s energy deliveries totaled 15.0 million megawatt
hours ("mWh Sales to residential customers comprised 34
percent of retail sales, with 27 percent to commercial, 25
percent to industrial end-users and 14 percent
attributable to irrigation pumping.Idaho Power also
AVERA, DI
Idaho Power Company
supplies firm wholesale power service to various utili ties
and municipalities, as well as three large customers under
sales contracts.Idaho Power s service area has
experienced strong population growth, expanding over 10
percent in the last decade compared with the national
average of 3.8 percent.
At year-end 2002, Idaho Power had total assets of
$2.7 billion and during the most recent fiscal year total
electric revenues amounted to approximately $867 million.
Principal industries in the area include food processing,
lumber, electronics and general manufacturing, fertilizer
production, and year-round recreational facilities, such as
those in the Sun Valley resort area.Idaho Power
anticipates total capi tal expenditures of approximately
$675 million over the next three years.The Company
recently approved a development contract, subj ect to
Commission approval, for construction of a 160 megawatt
MW") gas-fired generating plant near Mountain Home,
Idaho.Total cost of the project, which includes plant
construction and necessary transmiss1on system upgrades,
$61 million,with Idaho Power taking ownership once the
faci Ii ty has been fully tested and operational.In order
to provide addi tional support for its capi tal expenditure
program, Idaho Power s Board of Directors ("Board") voted
to cut its common stock dividends for the next quarter by
AVERA, DI
Idaho Power Company
more than $6 million, prompting IDACORP to announced that
it was reducing annual common dividends some 35 percent
from $1.86 to $1.20 per share. 1
With a combined capacity of approximately 3,117 MW,
Idaho Power s existing generating units include
hydroelectric generating plants located in southern Idaho
and interests in three coal-fired plants located in Oregon,
Nevada, and Wyoming.During 2002, company-owned generation
accounted for 82.1 percent of the electric energy provided
by Idaho Power, wi th the balance being obtained through
power purchases.The electrical output of its
hydroelectric plants is dependent on streamflows, which
have fallen below normal levels for the last three years.
As a result, approximately 45 percent of Idaho Power
total system generation in 2002 was provided by
hydroelectric generation, as compared with 57 percent under
normal conditions.Snowpack and upstream reservoir storage
for 2003 have fallen below measurements for the previous
year and Idaho Power is experiencing its fourth consecutive
year of below-normal water condi tions .
Idaho Power I s transmission system interconnects the
Company with other western electric utilities.Coupled
wi th Idaho Power s membership in the Western Electricity
Coordinating Council, the Western Systems Power Pool, the
Northwest Power Pool and the Northwest Regional
AVERA, DI
Idaho Power Company
Transmission Association, these transmission
interconnections permit the interchange, purchase, and sale
of power among all major electric systems in the west.
Idaho Power is subject to state retail regulation in
Idaho and Oregon and at the federal level by FERC.
Addi tionally, Idaho Power s hydroelectric facilities are
subject to licensing under the Federal Power Act, which is
administered by FERC, as well as the Oregon Hydroelectric
Act.Currently, the permanent licenses for five of Idaho
Power s hydroelectric facilities have expired.Idaho Power
is actively seeking relicensing under a process that could
continue for up to 15 years.Relicensing is not automatic
under federal law, and Idaho Power must demonstrate that it
has operated its facilities in the public interest, which
includes adequately addressing environmental concerns.The
most significant of Idaho Power's relicensing efforts
concerns its Hells Canyon Complex, which represent 68
percent of the Company s hydro capacity and 40 percent of
its total generating capability.After a prolonged period
of planning and consultation with interested parties, Idaho
Power has developed a draft license application that
includes various protection, mitigation, and enhancement
measures in order to address environmental concerns while
preserving the peak and load following operations of the
facili ties.The estimated cost of these measures is $78
AVERA, DI
Idaho Power Company
million in the first five years of the license.
How are fluctuations in Idaho Power
operating expenses caused by varying hydro and power market
conditions accommodated in its rates?
Beginning in May 1993, Idaho Power implemented
a power cost adjustment mechanism ("PCA"), under which
rates are adjusted annually to reflect changes in variable
power production and supply costs.When hydroelectric
generation is reduced and power supply costs rise above
those included in base rates, the PCA allows Idaho Power to
increase rates to recover a portion of its additional
Conversely, if increased hydroelectric generationcosts.
were to lead to lower power supply costs, rates would be
reduced.Although the PCA provides for rates to be
adj us ted annually, it appl i es to 9 a percent 0 f the
deviation between actual power supply costs and normalized
As a result, the net amount of power supply costsrates.
not recovered through the PCA mechanism totaled
approximately $55.2 million over the past three years.
What credit ratings have been assigned to
Idaho Power and its parent, IDACORP?
Idaho Power and its parent, IDACORP are both
currently assigned a corporate credit rating of "" by
Standard & Poor's Corporation S&pn Meanwhi 1 e , Moody
Investors Service ("Moody s) has assigned issuer credit
AVERA, DI
Idaho Power Company
ratings of "A3" and "Baal" to Idaho Power and IDACORP,
respectively.S&P recently revised its outlook on both
companies downward from "positive " to "stable , primarily
due to expected weakness attributable to Idaho Power
ongoing recovery of deferred power costs, poor water
condi tions , and lower than expected sales.
B. Electric Power Xndustry
What are the general conditions in the
electric power industry?
For almost twenty years, electric utili ties
and their consumers have enj oyed a respi te from the
volatility characteristic of the late 1970s and early
1980s.More recently, however, these general economic
factors have been overshadowed by structural changes in the
electric utility industry resulting from market forces,
decontrol initiatives, and judicial decisions.
Please describe these structural changes.
At the federal level, FERC has been an
aggressive proponent of regulatory driven reforms designed
to foster greater competition in markets for wholesale
power supply.The National Energy Policy Act of 1992,
whi ch reformed the Public Utility Holding Company Act of
1935,and to a limited extent,the Federal Power Act,
greatly increased prospective competition for the
production and sale of power at the wholesale level.
AVERA, DI
Idaho Power Company
April 1996, FERC adopted Order No. 888, mandating "open
access " to the transmission facilities of jurisdictional
electric utili ties.FERC also has pushed for the
regionalization of transmission system control by
establishing frameworks for creation of Regional
Transmission Organizations ("RTOs") in its Order No. 2000
and through subsequent policy statements. Open access
has, in the view of most market observers, resulted in more
competi tion and competitors in wholesale power markets, but
not without the introduction of substantial risks.
policies affecting competition in the electric power
industry vary widely at the state level, but over 25
jurisdictions have enacted some form of industry
restructuring.This process of industry transition has led
to the disaggregation of many formerly integrated electric
utilities into three primary components - generation,
transmission, and distribution.Presently, however, Idaho
Power is, and is expected to remain, a fully integrated
public utility.
What impact has the western power crisis had
on investors ' risk perceptions for firms involved in the
electric power industry?
AVERA, DI
Idaho Power Company
During the course of the last several years,
investors have dramatically altered their assessment of the
relative risks associated with the electric 'power industry.
A well-publicized energy crisis throughout the west, which
originated in California, has wreaked havoc on the region
customers, utilities, and policymakers.It also has had
dramatic repercussions for western wholesale power markets
and investors and utili ties nationwide.Beyond causing
state regulators and legislators to re-evaluate their
restructuring initiatives for the retail sector of the
electric industry, the financial implications of the
California experience demonstrated the risks facing all
segments of the electric power industry.
. The massive debts owed by California s retail
utilities to banks, power producers and other creditors
shattered their financial integrity and the subsequent
bankruptcy filing of Pacific Gas and Electric Company
PG&E") brought the uncertainties associated with today
power markets into sharp focus for the investment
communi ty .Enron ' s, and now Mirant Corporation
bankruptcies only served to magnify the risks associated
with the power sector and increased investors I reluctance
to commit capital in the energy industry, as FERC
Commissioner Massey succinctly recognized:
Sadly, the tsunami of the western energy crisis,
AVERA, DI
Idaho Power Company
coupled with the collapse of Enron, have left a
devastating wake within the industry. Investor
confidence has been shaken by these events, by a
declining national economy, indictments of energy
traders, accounting irregularities, downgrades by
rating agencies, and continuing investigations by
the FERC, CFTC, the SEC, and the Justice
Department. ...The flight of capital from the
industry has been severe since the collapse of
Enron .
While the case of California and PG&E represents an
extreme example, there is every indication that investors
risk perceptions for electric utili ties have shifted
sharply upward as events in the western U. s. continued to
unfold.The resolution is far from over, as even today,
FERC, federal and state courts, and other agencies continue
their investigations to determine the underlying causes of
the volatility, high prices and erratic supply patterns
characteristic of western wholesale power markets in 2000
and 2001.
Have these events affected electric utili ties'
credit standing?
Yes.The last several years have witnessed a
steady erosion in credit quality throughout the electric
utility industry, both as a result of revised perceptions
of the risks in the industry and the weakened finances of
the utilities themselves.For example, during 2002, S&P
recorded 182 downgrades in the electric power industry,
versus only 15 upgrades, while Moody s downgraded 109
AVERA, DI
Idaho Power Company
utili ty issuers and upgraded one; an acceleration of the
trend in bond rating changes during the previous two years.
The fourth quarter of 2002 alone witnessed 48 downgrades as
the negative pressure on utility creditworthiness continued
unabated.
What is the impact of these capital and credit
market conditions on the ability of electric utilities to
raise funds?
Combined with a stagnant economy and global
uncertainties, the dramatic upward shift in investors' risk
perceptions and the weakened financial picture of most
industry participants, have combined to produce a severe
liquidity crunch in the electric power industry.S&P cited
the debilitating impact of these developments on investors
willingness to provide capital:
The last 24 months have witnessed extraordinary
turmoil for power and energy debt, unprecedented
since Samuel Insull' s utility empire collapsedduring the 1930s. Events ranging from the creditcollapse of the California utili ties, through the
Enron bankruptcy and subsequent marketdisruptions for u.s. energy merchant companies
have destroyed billions of dollars of value for
investors. Wall Street has virtually shut down
new investment in this sector.
Increasingly constrained capital market access as
a result of investor skepticism over accounting
practices and disclosure, more and more federal
and state investigations and subpoenas, audits,
and failing confidence in future financial
performance has created a liquidity crisis.
AVERA, DI
Idaho Power Company
utilities,
In light of the challenges faced by electric
financing acti vi ty actually declined some 14
percent in 2002, with many utilities being forced to rely
increasingly on bank debt.Access to the commercial paper
markets, long the low-cost staple of high-grade utility
credi ts for meeting working capital needs, virtually
disappeared for certain companies.S&P noted that the
falloff in financing activity was partly attributable to
capital market jitters, especially for those firms that
are most in need of capital market access. As a result,
at the same time that industry uncertainty and market
volatility has increased the importance of financial
flexibi1i ty, electric utili ties are facing limited access
and higher costs for the capital required to maintain
sufficient liquidity.Moreover, credi t qua1i ty has
continued to decline.S&P reported an unprecedented 88
ratings downgrades during the first half of 2003 alone, an
acceleration of the downward trend witnessed during the
previous year. Similarly, Moody s downgraded 51 utilities
between January and June 2003, while upgrading only one
firm.S&P also noted that constrained access to capital
markets and investor skepticism was contributing to the
bleak credi t picture.
How has Idaho Power been impacted by the
turmoil in the electric power industry?
AVERA, DI
Idaho Power Company
Like others, Idaho Power was swept up in the
maelstrom of the western energy crisis in 2000 and 2001.
Because of Idaho Power s dependence on hydroelectric
generation, it has always faced the uncertainties
associated with year-to-year fluctuations in water
condi tions .Nevertheless, the degree of price volatility
that participants in the western power markets were forced
to assume was unprecedented and variability in short-term
market prices bore no resemblance to fluctuations
encoun tered in the pas t .
Increased wholesale prices and rate structures that
did not capture full costs of acquiring fuel and purchased
power led to depressed earnings.As of December 31, 2001,
for example, Idaho Power had recorded a regulatory asset of
$290 million related primarily to power cost deferrals
resulting from low hydroelectric generation and higher
purchased power prices. To varying degrees, utili ties
throughout the western U. s. were confronted with the
difficult task of maintaining reliable service and
financial integrity in a power market characterized by
short supply and unprecedented price volatility.Municipal
utilities in the Northwest were also forced to approve or
propose significant rate increases to recover rising fuel
and purchased power costS.
Even for electric utili ties such as Idaho Power that
AVERA, DI
Idaho Power Company
have permanent fuel and purchased power adjustment
mechanisms in place, there can be a significant lag between
the time the utility actually incurs the expenditure and
when it is recovered from ratepayers.One example of this
regulatory lag was noted by The Value Line Investment
Survey (Value Line) ;
A lag in the recovery of sharply higher power
costs is hurting Sierra Pacific Resources. Power
prices in the West have soared since the second
quarter of 2000, and until recently, SPR' s two
utilities lacked a mechanism for recovering these
increases. The Nevada Commission has granted
one, but it won t solve the utilities' problem
right away. That's because the mechanism tracks
power costs over a trailing 12-month period and
because the amount by which the utili ties can
raise rates each month is capped.
Because Idaho Power was dependent on wholesale power
markets in the west to meet the gap in its resource needs
created by reduced hydro generation, the chaotic market
conditions were felt directly.The continuing prospect of
further turmoil in western power markets cannot be
discounted.From the standpoint of the capital markets,
the west is risky - and Idaho Power's exposure to wholesale
markets in meeting shortfalls in hydroelectric generation
compounds these uncertainties.
Investors recognize that volatile markets,
unpredictable stream flows, and Idaho Power s dependence on
wholesale purchases to meet the needs of its customers can
AVERA, DI
Idaho Power Company
create a "perfect storm , exposing the Company to the risk
of reduced cash flows and unrecovered power supply costs.
In response to the risks inherent in substantial reliance
on wholesale power markets for electricity supply, and
recognizing the continuing uncertainty concerning the
availability of hydroelectric generation, Idaho Power has
proposed a plan to expand its electric utility system,
including the construction of additional generating
resources at Mountain Home.Accordingly, maintaining Idaho
Power s financial integrity and flexibility will be
instrumental in attracting the capital necessary to fund
these projects in an effective manner.
What are the implications of the recent power
outages recently experienced in the upper Midwest and
Northeas t ?
These events underscore the continuing risks
inherent in the industry and the uncertain state of affairs
with respect to the industry s structure.The massive
blackout, which stretched from New York to Detroit and from
Ohio into Canada, was the largest power outage in U. s.
history .This single event has galvanized the attention of
all industry stakeholders - utilities, consumers,
regulators, and investors - on the urgent need to improve
the nation s electricity infrastructure, especially in
light of the additional stress that deregulated wholesale
AVERA, DI
Idaho Power Company
markets have placed on the network.The importance of
rapidly stimulating investment in electric power
infrastructure has been almost universally cited as the key
to ensuring that further outages are avoided.As FERC
Chairman Wood noted:
If we draw any conclusions from this blackout, it
is the urgent need for more investment in the
nation s transmission grid to serve broad
regional needs.
Indeed, as noted earlier, Idaho Power is committed to
expanding the scope and reliability of its utility system
in order to provide customers with reliable service while
attempting to insulate them from the potential impact of
power market anomalies.
Are investors likely to consider the impact of
industry uncertainty in assessing their required rate of
return for Idaho Power?
Absolutely.While electric utility
restructuring has not been actively pursued in Idaho, the
Company continues to face the prospect of FERC-driven
changes in the transmission sector of their business, as
well as fundamental reforms in the operation of wholesale
markets.Idaho Power is an active participant in the
formation of a proposed RTO ("RTO West"), an independent
enti ty that will operate the transmission grid in seven
While RTO West received Stage II approvalwestern states.
AVERA, DI
Idaho Power Company
from FERC, substantial additional filings will be necessary
before federal and state approval are received.
Indeed, the pace of policy evolution -in the
transmission area has been brisk.Investors' focus on
regulatory change in their assessment of risks and
prospects was exemplified by S&P:
The FERC is in the process of changing every
aspect of the electric utility landscape, with
industry sages anticipating further transmission
and wholesale market development guidance, which
could affect the segment I s credit prospects and
quality. ...Significant uncertainty still exists
for transmission companies that may operate under
an RTO or ISO structure, which will significantly
impact the full scope of capital expenditures
necessary to ensure reliability and increase
capacity in the future. Uncertainty will exist
until operating rules are in place and havestabilized.
Virtually all industry stakeholders have recognized that
regulatory uncertainty increases the risks associated with
the electric industry.FERC Commissioner Massey says that
regulatory uncertainty is "part of the problem " explaining
under-investment in electric utility infrastructure. The
Department of Energy ("DOE") identified "reducing
regulatory uncertainty " as critical in stimulating
increased investment in the power industry and has noted
that lack of clarity in the regulatory structure was
inhibi ting planning and investment. The DOE also
recognized the impact that this regulatory uncertainty has
AVERA, DI
Idaho Power Company
on investors ' required rates of return for electric
utilities;
Because transmission assets are long lived,
regulatory uncertainty increases the risks toinvestors and, therefore, increases the returns
they need to justify transmission system
investments.
In remarks before NARUC, a representative of MBIA Insurance
Corporation, the world's largest financial guaranty
insurance company, noted the increased risks posed by
inconsistent regulatory decision-making "have made access
to the capital markets very difficult and very expensive. ,,
Similarly, while the Consumer Energy Council of America
recognized that improvements in electric utility
infrastructure are necessary to ensure reliability and
support the economy, they concluded that regulatory
uncertainty "has contributed to a fear of instability for
the entire system . 22
The recent blackout has only served to reinforce the
importance of regulatory risks for investors.The Wall
Street Journal cited the debilitating impact of an
unsteady regulatory environment" and the "chaotic
combination of regulated and deregulated markets " in
explaining inhibitions to increased investment in the
electric utility system. Similarly, FERC Chairman Wood
concluded in his initial comments on the power outages
AVERA, DI
Idaho Power Company
that:
Clearly, we need regulatory certainty and other
incentives for investment.
Nevertheless, S&P recently warned investors that the
partial reforms presently characterizing wholesale power
markets invites dysfunction and that elevated risks will
discourage new capital, U or at least make it more
expensi ve. S&P observed:
Investors should not expect that such risk will
dissipate any time soon. Instead, credit risk
could actually intensify if the politically
charged debate over reform continues for years,
as it might very well do. And even if policy
makers succeed in crafting a comprehensive
solution to the problems of the nation s energy
grid, the regulatory treatment of the costs
needed to upgrade the infrastructure remains
uncertain.
Because of potential dependence on wholesale markets, the
risks of transmission uncertainties and potential market
volatility are intensified for utilities that must meet
shortfalls in resource needs through power purchases.
Thus, Idaho Power s greater dependence on hydroelectric
generation, which fluctuates with changes in streamflows,
exposes the Company and its investors to the ongoing
regulatory uncertainties and other risks imposed by federal
restructuring of wholesale power markets and magnifies the
importance of maintaining financial flexibility.
Are these uncertainties the only risks being
AVERA, DI
Idaho Power Company
faced by electric utilities?
Apart from these factors, the industryNo.
continues to face the normal risks inherent in operating
electric utility systems, including the potential adverse
effects of inflation, interest rate changes, growth, and
regulatory uncertainty and lag.Electric utili ties are
confronting increased environmental pressures that leave
them exposed to uncertainties regarding emissions and
potential contamination.S&P recognized the potential
financial challenges posed by such uncertainties:
Pension obligations, environmental liabilities,
and serious legal problems restrict flexibility,
apart from the obligations ' direct financial
implications.
Capi tal Markets and Economy
What has been the pattern of interest rates
over the last decade?
Average long-term public utility bond rates,
the monthly average prime rate, and inflation as measured
by the consumer price index since 1990 are plotted in the
graph below.After rising to approximately 10 percent in
mid-l990, the average yield on long-term public utility
bonds generally fell as economic conditions weakened in the
aftermath of the 1991 Gulf war, with rates dipping below 7
percent in late 1993.Yields subsequently rose again in
1994, before beginning a general decline, with investors
AVERA, DI
Idaho Power Company
requiring approximately 6.8 percent from average public
utility bonds in August 2003;
i:!8 6
Inflau
. ,\,. -, -"'...-' -- ....-- -' ,.......---- \"'.-,
oJ
Are investors likely to anticipate any
substantial decline in interest rates going forward?
Since early 2001, a great deal ofNo.
attention has been focused on the actions of the Federal
Reserve as they have moved successively to lower short-term
interest rates in response to weakness in the United States
But while interest rates are currently ateconomy.
relatively low levels, investors are unlikely to expect any
further significant declines going forward.The general
expectation is that, as econoncic growth strengthens,
interest rates will begin to rise.For example, the Energy
Information Administration ("ErA"), a statistical agency of
the DOE, routinely publishes a 25-year forecast for energy
markets and the nation I s economy.The most recent
forecast, released November 20, 2002, anticipates that the
double-A public utility bond yield will increase from 6.
AVERA, DI
Idaho Power Company
percent in 2002 to 8.10 percent by 2005, with the average
being 7.49 percent over the next 10 years. Similarly, the
most recent long-term projections from GlobalInsight
(formerly DRI/WEFA) anticipate that public utility bond
yields will increase to 8.19 percent by 2007 and average
approximately 7.8 percent over the intervening years.
How has the market for common equi ty capi tal
performed?
Between 1990 and early 2000 stock prices
pushed steadily higher as the longest bull market in United
States history continued unabated.While the S&P 500 had
increased over four times in value by August 2000, mounting
concerns regarding prospects for future growth,
particularly for firms in the high technology and
telecommunica tions sectors, pushed equity prices lower,
some cases precipitously.While equity prices have
recovered from recent lows, the market has become
increasingly volatile, with share values repeatedly
changing in full percentage points during a single day
trading.The graph below plots the performances of the
Dow-Jones Industrial Average, the S&P 500, and the New York
Stock Exchange Utility Index since 1990 (the latter two
indices were scaled for comparability);
AVERA, DI
Idaho Power Company
500
500
12,500
10,500
II)500
6,500
500
500
5()()
---~--'- ~
. NY~~ Uti lit (xlO "
""'
J-O2
What is the outlook for the United States
economy?
During the decade through the first quarter of
2001, the United States economy enjoyed the longest
Monetary and fiscalpeacetime expansion in history.
policies resulted in modest inflation during this period,
with unemployment rates falling to their lowest levels
since the 1960s.A revolution in information technology,
rising productivity, and vibrant international trade all
contributed to strong economic growth.However, even
before the events of September 11, 2001, there were
increasing signs that the economic expansion would not be
sustainable.Concerns regarding the slowing pace of
economic activity have been exemplified by the Federal
Reserve I S sequential lowering of interest rates.The
economy continues to chart an uneven course, corporate
profits remain under pressure, capital spending continues
to be weak, and businesses have been reluctant to expand
AVERA, DI
Idaho Power Company
hiring. More recently, uncertainties over the fragility
the economy have been magnified by the aftermath of war in
Iraq and ongoing instability in the Middle East, which
undermines consumer confidence and contributes to global
economic uncertainty.These factors cause the outlook to
remain tenuous, with persistent stock and bond price
volatility providing tangible evidence of the uncertainties
faced by the United States economy.
How do these economic uncertainties affect
electric utili ties?
The weakened state of the economy and the
uncertainty of recovery have combined to heighten the risks
faced by electric utili ties.Stagnant economic growth
would undoubtedly mean flat electric sales, while the
potential for higher inflation and interest rates that
would likely accompany an economic recovery would place
addi tional pressure on the adequacy of existing service
While the economy may ultimately return to a pathrates.
of steady growth and the volatility in the capital and
energy markets may abate, the underlying weaknesses now
present cause considerable uncertainties to persist, which
increase the risks faced by the electric utility industry.
I1:I. CAPITAL MARKET ESTIMATES
What is the purpose of this section?
AVERA, DI
Idaho Power Company,
In this section, capital market estimates of
the cost of equity are developed for a benchmark group of
electric utili ties.First, I examine the concept of the
cost of equity, along with the risk-return tradeoff
principle fundamental to capital markets. Next, DCF and
risk premium analyses are conducted to estimate the cost of
equi ty for a reference group of electric utili ties.
A. Economic Standards
What role does the rate of return on common
equity play in a utility's rates?
The return on common equity is the cost of
inducing and retaining investment in common shares.This
investment is necessary to finance the asset base needed to
provide utility service.Competition for investor funds is
intense and investors are free to invest their funds
wherever they choose.They will commit money to a
particular investment only if they expect it to produce a
return commensurate with those from other investments with
comparable risks.Moreover, the return on common equity is
integral in achieving the sound regulatory objectives of
rates that are sufficient to: 1) fairly compensate capital
investment in the utility, 2) enable the utility to offer a
return adequate to attract new capital on reasonable terms,
and 3) maintain the utility s financial integrity.
What fundamental economic principle underlies
AVERA, DI
Idaho Power Company
this cost of equity concept?
Unlike debt capital, there is no contractually
guaranteed return on common equity capital since
shareholders are the residual owners of the utility.
Nonetheless, common equity investors still require a return
on their investment, with the cost of equity being the
minimum rent" that must be paid for the use of their
This cost of equity typically serves as themoney.
starting point for determining a fair rate of return on
common equi ty .
The cost of equity concept is predicated on the
notion that investors are risk averse and willingly bear
addi tional risk only if paid for doing so.In capi tal
markets . where relatively risk-free assets are available
(e. g ., U. S. Treasury securi ties) investors can be induced
to hold more risky assets only if they are offered a
premium, or additional return, above the rate of return on
a risk-free asset.Since all assets - including debt and
equity - compete with each other for scarce investors'
funds, more risky assets must yield a higher expected rate
of return than less risky assets in order for investors to
be willing to hold them.
Given this risk-return tradeoff, the required rate
of return (k) from an asset (i) can be generally expressed
as:
AVERA, DI
Idaho Power Company
. 14
ki = Rf + RPi
where;Rf = Risk-free rate of return; and
RPi = Risk premium required to hold -risky
asset i.
Thus, the required rate of return for a particular asset at
any point in time is a function of: 1) the yield on risk-
free assets, and 2) its rela ti ve risk, with investors
demanding correspondingly larger risk premiums for assets
bearing greater risk.
Does the risk-return tradeoff principle
actually operate in the capital markets?
Yes.The risk-return tradeoff is observable
in certain segments of the capital markets where required
rates of return can be directly inferred from market data
and generally accepted measures of risk exist.Bond
yields, for example, reflect investors ' expected rates of
return, and bond ratings measure the risk of individual
bond issues.The observed yields on government securities,
which are considered free of default risk, and bonds of
various rating categories demonstrate that the risk-return
tradeoff does, in fact, exist in the capital markets.
Does the risk-return tradeoff observed with
fixed income securities extend to common stocks and other
assets?
It is generally accepted that the risk-return
tradeoff evidenced with long-term debt extends to all
AVERA, DI
Idaho Power Company
assets.Documenting the risk-return tradeoff for assets
other than fixed income securities, however, is complicated
by two factors.First, there is no standard-measure of
risk applicable to all assets.Second, for most assets -
including common stock - required rates of return cannot be
directly observed.Nevertheless, it is a fundamental tenet
that investors exhibit risk aversion in deciding whether or
not to hold common stocks and other assets, just as when
choosing among fixed income securities.This has been
supported and demonstrated by considerable empirical
research in the field of finance and is confirmed by
reference to historical earned rates of return, with
realized rates of return on common stocks exceeding those
on government and corporate bonds over the long-term.
Is this risk-return tradeoff limited to
differences between firms?
The risk-return tradeoff principleNo.
applies not only to investments in different firms, but
also to different securities issued by the same fi~.
Debt, preferred stock, and common equity vary considerably
in risk because they have different characteristics and
priori ties.
When investors loan money to a utility in the form
of long-term debt (or bonds), they enter into a contract
under which the utility agrees to pay a specified amount of
AVERA, DI
Idaho Power Company
interest and to repay the principal of the loan in full at
the maturity date.The bondholders have a senior claim on
a utility s available cash flow for these payments, and if
the utility fails to make them, they may force it into
bankruptcy. Following first mortgage bonds are other debt
instruments also holding contractual claims on the
utili ties cash flow, such as debentures and notes.
Similarly, when a utility sells investors preferred stock,
the utility promises to pay specified dividends and,
typically, to retire the preferred stock on a predetermined
schedule.The rights of preferred stockholders to
available cash flow for these payments are junior to
creditors, and preferred stockholders cannot compel
bankruptcy, their claims are senior to those of common
shareholders.
The last investors in line are common shareholders.
They receive only the cash flow, if any, that remains after
all other claimants - employees, suppliers, governments,
lenders, have been paid.Because cash flows to common
shareholders are not contractually defined, dividend
payments may be eliminated altogether or substantially
reduced, as illustrated by the recent actions of Idaho
Power s Board and IDACORP.As a result, the rate of return
that investors require from a utility s common stock, the
most junior and riskiest of its securities, is considerably
AVERA, DI
Idaho Power Company
higher than the yield on the utility s long-term debt.
What does the above discussion imply with
respect to estimating the cost of equity?
Although the cost of equity cannot be observed
directly, it is a function of the prospective returns
available from other investment al ternati ves and the risks
to which the equity capital is exposed.Because it is
unobservable, the cost of equity for a particular utility
must be estimated by analyzing information about capital
market conditions generally, assessing the relative risks
of the company specifically, and employing various
quantitative methods that focus on investors ' current
required rates of return.These various quantitative
methods typically attempt to infer investors' required
rates of return from stock prices, interest rates, or other
capi tal market data.
Have you relied on a single method to estimate
the cost of equity for Idaho Power?
No. In my opinion, no single method or model
should be relied upon to determine a utility s cost of
equi ty because no single approach can be regarded as wholly
reliable.As the Federal Communications Commission
recognized:
Equity prices are established in highly volatile
and uncertain capital markets... Different
forecasting methodologies compete wi th each other
AVERA, DI
Idaho Power Company
for eminence, only to be superceded by other
methodologies as conditions change... In these
circumstances, we should not restrict ourselves
to one methodology, or even a series of
methodologies, that would be appliedmechanically. Instead, we conclude that we
should adopt a more accommodating and flexible
posi tion.
Therefore, in addition to the DCF model, I applied
the risk premium method based on data for electric
utilities and using forward-looking estimates of required
rates of return.In addition, I also evaluated my results
using a comparable earnings approach based on investors'
current expectations in the capital markets.In my
opinion, comparing estimates produced by one method with
those produced by other approaches ensures that the
estimates of the cost of equity pass fundamental tests of
reasonableness and economic logic.
B. Discounted Cash Flow Analyses
How are DCF models used to estimate the cost
of equity?
The use of DCF models is essentially an
attempt to replicate the market valuation process that sets
the price investors are willing to pay for a share of a
company s stock.The model rests on the assumption that
investors evaluate the risks and expected rates of return
from all securities in the capital markets.Given these
expected rates of return, the price of each stock is
AVERA, DI
Idaho Power Company
adjusted by the market until investors are adequately
compensated for the risks they bear.Therefore, we can
look to the market to determine what investors believe a
share of common stock is worth.By estimating the cash
flows investors expect to receive from the stock in the way
of future dividends and capital gains, we can calculate
their required rate of return.In other words, the cash
flows that investors expect from a stock are estimated, and
given its current market price, we can "back-into " the
discount rate, or cost of equity, that investors
presumptively used in bidding the stock to that price.
What market valuation process underlies DCF
models?
DCF models are derived from a theory of
valuation which assumes that the price of a share of common
stock is equal to the present value of the expected cash
flows (i.e., future dividends and stock price) that will be
received while holding the stock, discounted at investors
required rate of return, or the cost of equity.
Notationally, the general form of the DCF model is as
follows;
1 O 2 O t P
+... +
0 (1+k )1 (1+k )2 (1+k )t (1+k
where:Po = Current price per share;
Pt = Expected future price per share in
period
AVERA, Dr
Idaho Power Company
Dt = Expected dividend per share in period
Ke = Cost of equity.
That is, the cost of equity is the discount rate that will
equate the current price of a share of stock with the
present value of all expected cash flows from the stock.
Has this general form of the DCF model
customarily been used to estimate the cost of equity in
rate cases?
No.In an effort to reduce the number of
required estimates and computational difficulties, the
general form of the DCF model has been simplified to a
constant growth" form.But converting the general form of
the DCF model to the constant growth DCF model requires a
number of strict assumptions.These include:
A constant growth rate for both dividends and
earnings;
A stable dividend payout ratio;
The discount rate exceeds the growth rate;
A constant growth rate for book value and price;
A constant earned rate of return on book value;
No sales of stock at a price above or below book
val ue ;
A constant price-earnings ratio;
A constant discount rate (i.e., no changes in risk or
interest rate levels and a flat yield curve); and
All of the above extend to infinity.
AVERA, DI
Idaho Power Company
Given these assumptions, the general form of the DCF model
can be reduced to the more manageable formula of;
p =
0 ke - 9
Where: g = Investors ' long-term growth
expectations.
The cost of equity (Ke) can be isolated by rearranging
terms :
k =
......!.+
e p
This constant growth form of the DCF model recognizes that
the rate of return to stockholders consists of two parts:
1) dividend yield (DdPo), and 2) growth (g).In 0 ther
words, investors expect to receive a portion of their total
return in the form of current dividends and the remainder
through price appreciation.
Are the assumptions underlying the constant
growth form of the DCF model always fully met?
In practice, none of the assumptions required
to convert the general form of the DCF model to the
constant growth form are ever strictly met.Nevertheless,
where earnings are derived from stable acti vi ties, and
earnings, dividends, and book value track fairly closely,
the constant growth form of the DCF model may be a
reasonable working approximation of stock valuation that
AVERA, DI
Idaho Power Company
can provide useful insight as to investors ' required rate
of return.
How did you implement the DCF model to
estimate the cost of equity for Idaho Power?
Application of the DCF model directly to Idaho
Power is hindered because, as a wholly-owned subsidiary,
the Company does not have publicly traded common stock.
Meanwhile, as discussed earlier, Idaho Power and, in turn,
IDACORP recently elected to cut common dividend payments
significantly in order to improve cash flow and help
maintain the strong credit ratings necessary to support the
Company s capital expansion plan.Under the DCF approach,
observable stock prices are a function of the cash flows
that investors ' expected to receive, discounted at their
required rate of return.Because dividend payments are a
key parameter required to apply DCF methods, this approach
is not well-suited for firms that do not pay common
dividends or have recently cut their payout.
As an alternative, the cost of equity is often
estimated by applying the DCF model to publicly traded
companies engaged in the same business acti vi ty .In order
to reflect the risks and prospects associated with Idaho
Power s jurisdictional utility operations, my DCF analyses
focused on a reference group of other electric utilities
composed of those companies included by Value Line in their
AVERA, DI
Idaho Power Company
Electric Utili ties (West) Industry group.Excluded from my
analyses were four firms that do not pay common dividends
and two that were rated below investment grade by S&P. 31
Given that these eight utilities are all engaged in
electric utility operations in the western region of the
u. S., investors are likely to regard this group as facing
similar market conditions and having comparable risks and
There are important factors distinguishingprospects.
western utilities from those located in other regions, as
the Electric Consumers Resource Council recently reported:
The West is different than the East in terms of
electricity grid operations, according to Marsha
Smith, a Commdssioner with the Idaho Public
Utilities Commission and Chair of (NARUC).
The vast geographic areas served by western
utilities mean electricity is being transmitted
over much longer distances that in other regions,particularly the East, and there are fewer
customers per mile of transmission line,
resul ting in greater line loss, Ms. Smith said.
She also said the West's reliance on
hydroelectric energy makes planning moredifficult than in the East. Hydropower cannot be
forecast, and the amount of winter snow
determines how much may be shipped each spring
and summer to power-dependent areas such asCalifornia. Reliance on hydropower makes long-
term planning difficult and plays havoc with the
day-ahead market, envisioned in FERC' s proposed
standard market design (SMD) rule.
Indeed, as noted earlier, the uncertainties associated with
relying on hydroelectric generation is an important
consideration in evaluating investors ' required rate of
AVERA, DI
Idaho Power Company
return for Idaho Power.
What other considerations support the use of a
proxy group in estimating the cost of equity for Idaho
Power?
Apart from recognizing the inherent risks and
prospects for an electric utility operating in the west,
reference to a proxy group of electric utili ties is
essential to insulate against vagaries that can result when
the stochastic process involved in estimating the cost
equity is applied to a single company.The cost of equity
is inherently unobservable and can only be inferred
indirectly by reference to available capital market data.
To the extent that the data used to apply the DCF model
does not capture the expectations that investors have
incorporated into current stock prices, the resulting cost
of equity estimates will be biased.For example, the
potential for mergers or acquisitions or the announced sale
of a major business segment would undoubtedly influence the
price investors would be willing to pay for a utility
common stock.But because such factors are not typically
reflected in the growth rates used to apply the DCF model,
cost of equity estimates for any single company may fail to
reflect investors' required rate of return.Indeed, using
even a limited group of companies increases the potential
for error, as the FERC noted in its July 3, 2003 Order on
AVERA, DI
Idaho Power Company
Initial Decision in Docket No. RPOO-107-000;
Both Staff and Williston agreed that a proxy
group of only three companies presented problems
because ~a single company will have a magnified
influence on the group results.It was with
those changing market dynamics in mind that
wi tnesses of both Staff and Williston proposed to
expand the group of proxy companies to determine
a zone of reasonableness.
A proxy group composed of western electric utili ties is
consistent not only with the shared circumstances of
electric power markets in the west, but also with the need
to ensure against the potential that a single cost of
equity estimate may not reflect investors' required rate of
return .
What form of the DCF model did you use?
I applied the constant growth DCF model to
estimate the cost of equity for Idaho Power, which is the
form of the model most commonly relied on to establish the
cost of equity for traditional regulated utilities and the
method most often referenced by regulators.
Other forms of the general, or non-constant DCF
model, such as ~two-stage n or ~multi-stage " analyses can be
used to estimate the cost of equity; however, such
approaches increase the number of inputs that must be
estimated and add to the computational difficulties.While
such methods might be warranted when investors expect a
discontinuity in the operations of a particular firm or
AVERA, DI
Idaho Power Company
industry, they generally require several very specific
assumptions regarding investors ' expected cash flows that
must occur at given points in the future.This makes the
results of non-constant growth DCF applications sensitive
to changes in assumptions and, therefore, subject to
greater controversy in a rate case setting.
Moreover, to the that extent each of these time-
specific suppositions about future cash flows do not
reflect what real-world investors actually anticipate, the
resulting cost of equity estimate will be biased. Indeed,
the benchmark for growth in a DCF model is what investors
expect when they purchase stock.Unless we replicate
investors I thinking, we cannot uncover their required
returns and thus the market cost of equity. In practice,
applying a non-constant DCF model would lead to error if it
ignores the requirements of real-world investors.
Are there circumstances where a multi-stage
DCF model might be preferable to the constant growth form?
The greater complexity of the non-Yes.
constant growth DCF model is sometimes warranted when it is
evident that investors anticipate a well-defined shift in
growth rates over the horizon of their expectations.For
example, in response to structural reforms introduced in
the early 1990s, it was widely anticipated that certain
segments of the electric power industry would transition
AVERA, DI
Idaho Power Company
from fully regulated to cornpeti ti ve businesses.Because of
the difficulty associated with capturing these expectations
in the single growth measure of the constant growth DCF
model, many witnesses, including myself, chose to apply a
mul ti-stage approach.A number of regulatory commissions
also departed from the simplicity of the constant growth
DCF model that they had traditionally favored in order to
recognize the transition to competition that was
anticipated by investors.
But acceptance of the multi-stage DCF model was
predicated on very specific assumptions tailored to
investors ' actual expectations at the time.As discussed
earlier, however, investors are no longer anticipating that
such a transi tion will take place going forward.Broad-
reaching structural changes once anticipated by investors
at the state and federal levels have been largely
effectuated to the extent investors expect them to occur.
In the minds of investors, any new initiatives focused. on
deregulation of the electric utility industry at the retail
level have been indefinitely postponed or abandoned
altogether.This is certainly true in Idaho, where retail
deregulation is not being actively pursued.
While the complexity of non-constant DCF models may
impart an aura of accuracy, there is no evidence that
investors ' current view of electric utili ties anticipates a
AVERA, DI
Idaho Power Company
series of discrete, clearly defined stages.As a result,
despi te the considerable uncertainties now confronting the
electric utility industry, there is no discernable
transition that would support use of the multi-stage DCF
approach.
How is the constant growth form of the DCF
model typically used to estimate the cost of equity?
The first step in implementing the constant
growth DCF model is to determine the expected dividend
yield (Dl/PO) for the firm in question.This is usually
calculated based on an estimate of dividends to be paid in
the coming year divided by the current price of the stock.
The second, and more controversial, step is to estimate
investors I long-term growth expectations (g) for the firm.
Since book value, dividends, earnings, and price are all
assumed to move in lock-step in the constant growth DCF
model, estimates of expected growth are sometimes derived
from historical rates of growth in these variables under
the presumption that investors expect these rates of growth
to continue into the future.Alternatively, a firm
internal growth can be estimated based on the product of
its earnings retention ratio and earned rate of return on
equi ty .This growth estimate may rely on either historical
or projected data, or both.A third approach is to rely on
securi ty analysts I proj ections of growth as proxies for
AVERA, DI
Idaho Power Company
investors I expectations.The final step is to sum the
firm s dividend yield and estimated growth rate to arrive
at an estimate of its cost of equity.
How was the dividend yield for the reference
group of electric utili ties determined?
Estimates of dividends to be paid by each of
these electric utilities over the next twelve months,
obtained from Value Line, served as Dl.This annual
dividend was then divided by the corresponding stock price
for each utility to arrive at the expected dividend yield.
The expected dividends, stock price, and resulting dividend
yields for the firms in the reference group of electric
utilities are presented on Exhibit No.As shown there,
dividend yields for the eight firms in the electric utility
proxy group ranged from 3.2 percent to 6.0 percent, with
the average being 4.4 percent.
What are investors most likely to consider in
developing their long-term growth expectations?
In constant growth DCF theory, earnings,
dividends, book value, and market price are all assumed to
grow in lockstep and the growth horizon of the DCF model is
inf ini te .But implementation of the DCF model is more than
just a theoretical exercise; it is an attempt to replicate
the mechanism investors used to arrive at observable stock
prices.Thus, the only "g" that matters in applying the
AVERA, DI
Idaho Power Company
DCF model is that which investors expect and have embodied
in current market prices.While the uncertainties inherent
with common stock make estimating investors ' growth
expectations a difficult task for any company, in the case
of electric utili ties, the problem is exacerbated due to
the ongoing turmoil in the power industry.
Are dividend growth rates likely to provide a
meaningful guide to investors I growth expectations for
electric utilities?
While the dividend yield is an importantNo.
component of DCF applications and investors look to
dividends as one indicator of a firm's financial health,
trends in dividends are unlikely to reflect the long-term
presumed by the DCF model.As illustrated by the
recent decision of the Board and IDACORP to significantly
reduce their payout, dividend policies for electric
utilities have become increasingly conservative as business
risks in the industry have become more accentuated.Thus,
while earnings may be expected to grow significantly,
dividends have remained largely stagnant as utilities
conserve financial resources to provide a hedge against
heightened uncertainties.Investors I focus has
increasingly shifted from dividends to earnings as a
measure of long-term growth as payout ratios for firms in
the electric utility industry have been trending downward
AVERA, DI
Idaho Power Company
from approximately 80 percent historically to on the order
of 65 percent. As a result, growth in earnings, which
ultimately support future dividends and share prices, is
likely to provide a more meaningful guide to investors
long-term growth expectations.
What other evidence suggests that investors
are more apt to consider trends in earnings in developing
growth expectations?
The importance of earnings in evaluating
investors I expectations and requirements is well accepted
in the investment communi ty .As noted in Finding Reali
in Reported Earnings published by the Association for
Investment Management and Research:
(E)arnings, presumably, are the basis for the
investment benefits that we all seek. "Healthy
earnings equal heal thy investment benefits " seems
a logical equation, but earnings are also a
scorecard by which we compare companies, a filter
through which we assess management, and a crystal
ball in which we try to foretell the future.
Value Line's near-term projections and its Timeliness Rank,
which is the principal investment rating assigned to each
individual stock, are also based primarily on various
quantitative analyses of earnings.As Value Line
explained;
The future earnings rank accounts for 65% in the
determination of relative price change in the
future; the other two variables (current earnings
AVERA, Dr
Idaho Power Company
rank and current price rank) explain 35%.
The fact that investment advisory services, such as Value
Line and I/B/E/S International, Inc. (~IBES~), focus on
growth in earnings indicates that the investment community
regards this as a superior indicator of future long-term
Indeed, Financial Analysts Journal reported thegrowth.
results of a survey conducted to determine what analytical
techniques investment analysts actually use. Respondents
were asked to rank the relative importance of earnings,
dividends, cash flow, and book value in analyzing
securi ties.Of the 297 analysts that responded, only 3
ranked dividends first while 276 ranked it last.The
article concluded:
Earnings and cash flow are considered far more
important than book value and dividends.
What are security analysts currently
projecting in the way of earnings growth for the firms in
the electric utility proxy group?
AVERA, DI
Idaho Power Company
The consensus earnings growth proj ections for
each of the firms in the reference group of electric
utilities reported by lBES and published in S&P's Earnings
Guide are shown on Exhibi t No.Also presented are the
earnings growth projections reported by Value Line, First
Call Corporation ("First Call"), and Mul tex Investor
Mult~x ), which is a service of Reuters.As shown there,
wi th the exception of Value Line s estimates, these
security analysts I projections suggested growth the order
of 5.0 to 5. 5 percent for the reference group of electric
utilities:
Electric Utility Proxy Group
Service
IBES
Value Line
First Call
Mul tex
Growth Rate
What other earnings growth rates might be
relevant in assessing investors ' current expectations for
electric utilities?
Short-term projected growth rates may be
colored by current uncertainties regarding the near-term
direction of the economy in general and the spate of
challenges faced in the electric power industry
specifically.Consider the example of Value Line, which
recently noted that the electric utility industry "is still
AVERA, Dl
Idaho Power Company
in a state of flux 39 and that:
...
this industry still faces problems. The after-
effects of the turbulence in the power markets
still exist, some companies are stressed
financially, and even for traditional utilities,
regulatory risk is often a potential problem.
Value Line also reduced its Timeliness ranking, a relative
measure of year-ahead stock price performance for the 98
industries it covers, for the electric utility industry
from 70 to 89.While this cautious outlook may explain the
fact that Value Line s near-term growth estimates are out
of line with other analysts' projections, it is not
necessarily indicative of investors ' long-term expectations
for the industry.
Given the unsettled conditions in the economy and
electric utility industry over the near-term, historical
growth in earnings might also provide a meaningful guide to
investors ' future expectations.Accordingly, earnings
growth rates for the past 10- and 5-year periods reported
by Value Line for the firms in the electric utility group
are also presented on Exhibit No.As shown there, 10-
year historical earnings growth rates for the group of
eight electric utili ties averaged 7.3 percent, or 8.
percent over the most recent 5 year period.
How else are investors I expectations of future
long-term growth prospects often estimated for use in the
AVERA, DI
Idaho Power Company
constant growth DCF model?
In cons tan t growth theory, growth in book
equity will be equal to the product of the earnings
retention ratio (one minus the dividend payout ratio) and
the earned rate of return on book equity.Furthermore, if
the earned rate of return and payout ratio are constant
over time, growth in earnings and dividends will be equal
to growth in book value.Al though these condi tions are
seldom, if ever, met in practice, this approach may provide
investors with a rough guide for evaluating a firm s growth
Accordingly, conventional applications of theprospects.
constant growth DCF model often examine the relationships
between retained earnings and earned rates of return as an
indication of the growth investors might expect from the
reinvestment of earnings within a firm.
What growth rate does the earnings retention
method suggest for the reference group of electric
utilities?
The sustainable, u b x r " growth rates for each
firm in the reference group is shown on Exhibit No.For
each firm, the expected retention ratio (b) was calculated
based on Value Line's projected dividends and earnings per
share.Likewise, each firm s expected earned rate of
return (r) was computed by dividing projected earnings per
share by projected net book value.As shown there, thi
AVERA, DI
Idaho Power Company
method resulted in an average expected growth rate for the
group of electric utilities of 4.7 percent.
What did you conclude with respect to
investors I growth expectations for the reference group of
electric utili ties?
I concluded that investors currently expect
growth on the order of 5.0 to 7.0 percent for the average
firm in the electric utility proxy group.This
determination was based on the growth proj ections discussed
above, but giving little weight to Value Line
projections, which deviated significantly from the more
broadly-based consensus growth rate projections reported by
IBES, First Call, and Mul tex, as well as past experience.
What cost of equity was implied for the
reference group of electric utili ties using the DCF model?
Combining the 4.4 percent average dividend
yield with the 6.0 percent midpoint of my representative
growth rate range implied a DCF cost of equity for this
group of electric utili ties of 10.4 percent.
C. Risk Premium Analyses
What other analyses did you conduct to
estimate the cost of equity?
As I have mentioned previously because the
cost of equity is inherently unobservable, no single method
should be considered a solely reliable guide to investors'
AVERA, DI
Idaho Power Company
required rate of return.Accordingly, I also evaluated the
cost of equity for Idaho Power using risk premium methods.
My applications of the risk premium method provide
alternative approaches to measure equity risk premiums that
focused specifically on data for electric utili ties and
forward-looking estimates of investors ' required rates of
return.
Briefly describe the risk pre~ um method.
The risk pre~um method of estimating
investors' required rate of return extends to common stocks
the risk-return tradeoff observed with bonds.The cost of
equity is estimated by first determining the additional
return investors require to forgo the relative safety of
bonds and to bear the greater risks associated with common
stock, and then adding this equity risk premium to the
current yield on bonds.Like the DCF model, the risk
premium method is capital market oriented.However, unlike
DCF models, which indirectly impute the cost of equity,
risk premium methods directly estimate investors ' required
rate of return by adding an equity risk premium to
observable bond yields.
How did you implement the risk premium method?
The actual measurement of equity risk premiums
is complicated by the inherently unobservable nature of the
cost of equi ty .In other words, like the cost of equi
AVERA, DI
Idaho Power Company
itself and the growth component of the DCF model, equity
risk premiums cannot be calculated precisely.Therefore,
equity risk premiums must be estimated, with adjustments
being required to reflect present capital market conditions
and the relative risks of the groups being evaluated.
I based my estimates of equity risk premiums for
electric utilities on (1) surveys of previously authorized
rates of return on common equity for electric utili ties,
(2) realized rates of return on electric utility common
stocks; and (3) forward-looking applications of the Capital
Asset Pricing Model ("CAPM"Authorized returns
presumably reflect regulatory commissions ' best estimates
of the cost of equity, however determined, at the time they
issued' their final order, and the returns provide a logical
basis for estimating equity risk premiums.Under the
realized-rate-of-return approach, equity risk premiums are
calculated by measuring the rate of return (including
dividends, interest, and capital gains and losses) actually
realized on an investment in common stocks and bonds over
historical periods.The realized rate of return on bonds
is then subtracted from the return earned on electric
utility common stocks to measure equity risk premiums.The
CAPM approach measures the market-expected return for a
security as the sum of a risk-free rate and a risk premium
based on the portion of a security s risk that cannot be
AVERA, Dr
Idaho Power Company
eliminated by holding a well-diversified portfolio.Under
the CAPM, risk is represented by the beta coefficient
(~),
which measures the volatility of a security s price
relative to the market at a whole.Even before the widely
cited study by Eugene F. Fama and Kenneth R. French,
considerable controversy surrounded the validity of beta as
a relevant measure of a utility s investment risk.
Nevertheless, the CAPM is routinely referenced in the
financial literature and in regulatory proceedings.
While these methods are premised on different
assumptions, each having their own strengths and
weaknesses, they are widely accepted approaches that have
been routinely referenced in estimating the cost of equity
for regulated utilities.
How did you implement the risk premium
approach using surveys of allowed rates of return?
While the purest form of the survey approach
would involve querying investors directly, surveys of
previously authorized rates of return on common equity are
frequently referenced as the basis for estimating equity
risk premiums.The rates of return on common equity
authorized electric utilities by regulatory commissions
across the U. S. are compiled by Regulatory Research
Associates ("RRA") and published in its Regulatory Focus
In Exhibi t No.8, the average yield on publicreport.
AVERA, DI
Idaho Power Company
utility bonds is subtracted from the average allowed rate
of return on common equity for electric utili ties to
calculate equity risk premiums for each year between 1974
and 2002.Over this 29-year period, these equity risk
premiums for electric utili ties averaged 3.08 percent, and
the yield on public utility bonds averaged 9.81 percent.
Is there any risk premium behavior that needs
to be considered when implementing the risk premium method?
Yes.There is considerable evidence that the
magnitude of equity risk premiums is not constant and that
equity risk premiums tend to move inversely with interest
In other words, when interest rate levels arera tes .
relatively high, equity risk premiums narrow, and when
interest rates are relatively low, equity risk premiums
widen.To illustrate, the graph below plots the yields on
public utility bonds (shaded bars) and equity risk premiums
(solid bars) shown on Exhibi t No.
15%
~ l l.,III L l
00 0 oo:t oo:tr- 0\
10%
I 8 Bond Yield 8 Equity Risk Premium I
AVERA, DI
Idaho Power Company
The graph clearly illustrates that the higher the level
interest rates, the lower the equity risk premium, and vice
The implication of this inverse relationship isversa.
that the cost of equity does not move as much as, or in
lockstep with, interest rates.Accordingly, for a 1
percent increase or decrease in interest rates, the cost of
equi ty may only rise or fall, say, 50 basis points.
Therefore, when implementing the risk premium method,
adjustments may be required to incorporate this inverse
relationship if current interest rate levels have changed
since the equity risk premiums were estimated.
What cost of equity is implied by surveys of
allowed rates of return on equity?
As illustrated above, the inverse relationship
between interest rates and equity risk premiums is evident.
Based on the regression output between the interest rates
and equity risk premiums displayed at the bottom of Exhibit
No.8, the equity risk premium for electric utilities
increased approximately 43 basis points for each percentage
point drop in the yield on average public utility bonds.
As shown there, with the yield on public utility bonds in
August 2003 being 302 basis points lower than the average
for the study period, this implied a current equity risk
premium of 4.39 percent for electric utilities.Adding
this equity risk premium to the August 2003 yield on
AVERA, DI
Idaho Power Company
single-A public utility bonds of 6.79 percent implies a
current cost of equity for Idaho Power of approximately
11. 2 percent.
How did you apply the realized-rate-of-return
approach?
Widely used in academia, the realized-rate-of-
return approach is based on the assumption that, given a
sufficiently large number of observations over long
historical periods, average realized market rates of return
will converge to investors ' required rates of return.From
a more practical perspective, investors may base their
expectations for the future on, or may have come to expect
that they will earn, rates of return corresponding to those
realized in the past. By focusing on data for electric
utilities specifically, my realized rate of return approach
avoided the need to make assumptions regarding relative
risk (e. g., beta) that are often embodied in applications
of this method.
Stock price and dividend data for the electric
utilities included in the S&P 500 composite Index ("S&P
500") are available since 1946.Exhibi t No.9 presents
annual realized rates of return for these electric
utilities in each year between 1946 and 2002.As shown
there, over this 57-year period realized rates of return
for these utili ties have exceeded those on single-A public
AVERA, DI
Idaho Power Company
utility bonds by an average of 4.01 percent.The realized-
rate-of-return method ignores the inverse relationship
between equity risk premiums and interest rates and assumes
that equity risk premiums are stationary over time;
therefore, no adjustment for differences between historical
and current interest rate levels was made.Adding thi s
4. 01-percent equity risk premium to the August 2003 yield
of 6.79 percent on single-A public utility bonds suggests a
current cost of equity for Idaho Power of approximately
10.8 percent.
Please describe your application of the CAPM.
The CAPM is a theory of market equilibrium
that measures risk using the beta coefficient.Under the
CAPM, investors are assumed to be fully diversified, so the
relevant risk of an individual asset (e.
g.
common stock)
is its volatility relative to the market as a whole.Beta
reflects the tendency of a stocks price to follow changes
in the market.A stock that tends to respond less to
market movements has a beta less than 1.00, while stocks
that tend to move more than the market have betas greater
than 1. 00.The CAPM is mathematically expressed as:
Rj = Rf +~j (Rm -
Where:Rj = required rate of return for stock
Rf = risk-free rate;
Rm = expected return on the marketportfolio; and,
AVERA, DI
Idaho Power Company
~j = beta, or systematic risk, for stock
Exhibit No. 10 presents an application of the CAPM
to the eleven companies in the electric utility proxy group
based on a forward-looking estimate for investors I required
rates of return from common stocks.Ra ther than us ing
historical data, the expected market rate of return was
estimated by conducting a DCF analysis on the firms in the
S&P 500.The dividend yield was obtained from S&P, wi th
the growth rate equal to the average of the composite
earnings growth proj ections published by IBES for each
firm.As shown there, subtracting a 5.39 percent risk-free
rate based on the August 2003 average yield on 20-year
government bonds from the 14.24 percent forward-looking
rate of return produced a market equity risk premium of
85 percent.Mul tip lying this risk premium by the average
Value Line beta of 0.71 for the firms in the electric
utility group, and then adding the resulting risk premium
to the long-term Treasury bond yield, resulted in a current
cost of equity of approximately 11.7 percent.
D. Proxy Group Return on Equity
What did you conclude with respect to the cost
of equity for the benchmark group of electric utilities?
Consistent with the results of my quantitative
analyses, I concluded that the cost of equity for the proxy
AVERA, DI
Idaho Power Company
group is presently in the 10.4 to 11.7 percent range.
What other considerations are relevant in
setting the return on equity for a utility?
The common equi ty used to finance the
investment in utility assets is provided from either the
sale of stock in the capital markets or from retained
earnings not paid out as dividends.When equity is raised
through the sale of common stock, there are costs
associated with "floating " the new equity securities.
These flotation costs include services such as legal,
accounting, and printing, as well as the fees and discounts
paid to compensate brokers for selling the stock to the
public.Also, some argue that the "market pressure " from
the additional supply of common stock and other market
factors may further reduce the amount of funds a utility
nets when it issues common equity.
Is there an established mechanism for a
utility to recognize equity issuance costs?
No.While debt flotation costs are recorded
on the books of the utility, amortized over the life of the
issue, and thus increase the effective cost of debt
capital, there is no similar accounting treatment to ensure
that equity flotation costs are recorded and ultimately
recognized.Alternatively, no rate of return is authorized
on flotation costs necessarily incurred to obtain a portion
AVERA, DI
Idaho Power Company
of the equity capital used to finance plant.In other
words, equity flotation costs are not included in a
utility s rate base because neither that portion of the
gross proceeds from the sale of common stock used to pay
flotation costs is available to invest in plant and
equipment, nor are flotation costs capitalized as an
intangible asset.Unless some provision is made to
recognize these issuance costs, a utility s revenue
requirements will not fully reflect all of the costs
incurred for the use of investors ' funds.Because there is
no accounting convention to accumulate the flotation costs
associated with equity issues, they must be accounted for
indirectly, with an upward adjustment to the cost of equity
being the most logical mechanism.
What is the magnitude of the adjustment to the
bare bones " cost of equity to account for issuance costs?
There are any number of ways in which a
flotation cost adjustment can be calculated, and the
adjustment can range from just a few basis points to more
than a full percent.One of the most common methods used
to account for flotation costs in regulatory proceedings is
to apply an average flotation-cost percentage to a
utility s dividend yield.Based on a review of the finance
literature, Roger A. Morin concluded;
The flotation allowance requirescost
AVERA, DI
Idaho Power Company
estimated adjustment to the return on equity of
approximately 5% to 10%, depending on the size
and risk of the issue.
Applying these expense percentages to a representative
dividend yield for an electric utility of 4.4 percent
implies a flotation cost adjustment on the order of 20 to
40 basis points.
What then is your conclusion regarding a fair
rate of return on equity for the companies in your
benchmark group?
After incorporating a minimum adjustment for
flotation costs of 20 basis points to my "bare bones " cost
of equity range, I concluded that a fair rate of return on
equi ty for the proxy group of electric utili ties is
currently in the 10.6 to 11.9 percent range.
:IV. RETURN ON EQU:ITY FOR :IDAHO POWER COMPANY
What is the purpose of this section?
This section addresses the economic
requirements for Idaho Power's return on equity.
examines other factors properly considered in determining a
fair rate of return, such as market perceptions of Idaho
Power s relative investment risks and comparable earnings
for utilities and industrial firms.This section also
discusses the relationship between ROE and preservation of
a utility s financial integrity and the ability to attract
AVERA, DI
Idaho Power Company
capital.
A. Capital Structure
Is an evaluation of the capital structure
maintained by a utility relevant in assessing its return on
equi ty?
Other things equal, a higher debt ratio,Yes.
or lower common equity ratio, translates into increased
financial risk for all investors.A greater amount of debt
means more investors have a senior claim on available cash
flow, thereby reducing the certainty that each will receive
his contractual payments.This increases the risks to
which lenders are exposed, and they require correspondingly
higher rates of interest.From common shareholders
standpoint, a higher debt ratio means that there are
proportionately more investors ahead of them, thereby
increasing the uncertainty as to the amount of cash flow,
if any, that will remain.
What common equity ratio is implicit in Idaho
Power s requested capital structure?
Idaho Power s capital structure is presented
in the testimony of Dennis C. Gribble.As summarized in
his testimony, the common equity ratio used to compute
Idaho Power's overall rate of return was approximately 44.
percent.
How does Idaho Power s common equi ty ratio
AVERA, DI
Idaho Power Company
compare with those maintained by the reference group of
utilities?
For the eight firms in the Electric Utility
(West) group, common equity ratios at year-end 2002 ranged
from 37.4 percent to 60.6 percent and averaged 45.
percent.
How does Idaho Power's capital structure
compare with other widely cited financial benchmarks for
electric utili ties?
The financial ratio guidelines published by
S&P specify a range for a utility s total debt ratio that
corresponds to each specific bond rating.Widely cited
the investment community these ratios are viewed in
conjunction with a utility business profile ranking,
which ranges from 1 (strong) to 10 (weak) depending on a
utility s relative business risks.Thus, S&P' s guideline
financial ratios for a given rating category (e.g., triple-
B) vary with the business or operating risk of the utility.
In other words, a firm with a business profile of "2"
(i.e., relatively lower business risk) could presumably
employ more financial leverage than a utility with a
business profile assessment of "9" while maintaining the
same credi t rating.
Consistent with S&P' s current guidelines and Idaho
Power s S&P business profile ranking of ", a utility
AVERA, DI
Idaho Power Company
would be required to maintain a ratio of total debt
total capital of 46.0 percent to qualify for a single-
bond rating. This benchmark equates to total equity ratio
of 54.0 percent.
What implication does the increasing risk of
the electric power industry have for the capital structures
maintained by utili ties like Idaho Power?
The challenges imposed by evolving structural
changes in the industry imply that utili ties will be
required to incorporate relatively greater amounts of
equi ty in their capital structures.Moody s noted early on
that utilities must adopt a more conservative financial
posture if credit ratings are to be maintained:
The key issue," says the analysts in a recent
special comment, "is that the competitive
industries have much lower operating andfinancial leverage and that utili ties must
streamline both in order to be effective
competitors.Analysts say the utilities must do
this in order to post stronger financial
indicators and maintain their current ratingslevel.
More recently, Value Line reported that the average common
equity ratio for all firms in the electric utility industry
is expected to increase from 43 percent in 2003 to 50
percent over the next three to five years. Indeed,
continued pressure on credit quality in the electric
industry is indicative of the need for utilities to
AVERA, DI
Idaho Power Company
strengthen financial profiles to deal with an increasingly
uncertain market.S&P ci ted the inadequacy of current
balance sheets in the electric industry as one of the key
factors explaining this deterioration:
The downward slope in the power industry s credit
picture can be traced to higher debt leverage andoverall deterioration in financial profiles,
constrained access to capital markets as a result
of investor skepticism over accounting practices
and disclosure, liquidity problems, financial
insolvency, and investments outside the
traditional regulated utility business,
principally merchant generation facilities and
related energy marketing and trading acti vi ties.
A more conservative financial profile is consistent with
the increasing uncertainties associated with restructuring
in wholesale power markets and the imperative of
maintaining continuous access to capital, even during times
of adverse capital market and industry condi tions .
What other indications confirm the
reasonableness of Idaho Power s capital structure policies?
In the wake of Enron ' s collapse, bond rating
agencies and investors are closely scrutinizing debt
levels.For those firms with higher leverage, this intense
focus has led not only to ratings downgrades, but to
reduced access to capital and increased borrowing costs.
The Wall Street Journal reported that even firms with stock
prices at recent lows have been forced to issue new common
equi ty and quoted a credit analyst with Fitch, Inc.
AVERA, DI
Idaho Power Company
" (B) anks are fearful to put more money into the
sector " and it is making credit analysts nervousas well. The smart companies, he says, are the
ones that voluntarily "get their balance sheets
in line " and the let the market know they I re
charge of their destiny...since the market clearly
has the heebie-jeebies. "
The article went on to note the crucial role that financial
flexibility plays in ensuring that the utility has the
wherewi thaI to meet the needs of customers;
All the belt tightening spells bad news for the
continued development of the nation' s energyinfrastructure. Companies that can borrow more
money and stretch their dollars, quite simply,
can build more plants and equipment. Companies
that are increasingly dependent on equity
financing - particularly in a bear market - can
do less.
What did you conclude with respect to Idaho
Power s requested capitalization?
Idaho Power's proposed capital structure is
in-line with the ranges maintained by the comparable group
of electric utilities, although its equity ratio falls
somewhat below the guideline specified by S&P for a single-
A rated utility.The reasonableness of Idaho Power
requested capital structure is reinforced by the ongoing
uncertainties associated with the electric power industry,
the need to support system expansion, and the imperative of
maintaining continuous access to capital, even during times
of adverse industry and market conditions.
AVERA, DI
Idaho Power Company
B. Other Factors
How does Idaho Power s credi t rating compare
to those of the reference groups?
Corporate credit ratings for the eight firms
in the Electric Utility (West) group used to estimate the
cost of equity range from "BBB-" to "As noted
earlier, Idaho Power s senior debt is also currently rated
, comparable to the firms in the benchmark group.
What else should be considered in evaluating
the relative risks of Idaho Power?
Because approximately one-half of Idaho
Power s total energy requirements are provided by
hydroelectric facilities, the Company is exposed to a level
of uncertainty not faced by other utili ties, which are less
dependent on hydro generation.While hydropower confers
advantages in terms of fuel cost savings and diversity,
investors also associated hydro facilities with risks that
are not encountered with other sources of generation.
Reduced hydroelectric generation due to below-average water
condi tions forces Idaho Power to rely on less efficient
thermal generating capacity and purchased power to meet its
resource needs.As noted earlier, in the minds of
investors, this dependence on wholesale markets entails
significant risk, especially for a utility located in the
Indeed, the ongoing risks associated withwest.
AVERA, DI
Idaho Power Company
uncertainty in western power markets has been recognized by
the Commission.In dec ining to spread recovery 0 f power
cost deferrals over multiple years, the Commission
recognized that;
...
the Commission is very concerned about the
unknown water and market conditions that lie
ahead. ...A one-year recovery will take care of
nearly all the deferred costs remaining from a
sustained period of extraordinarily high
wholesale prices at the same time that hydro-
dependent Idaho Power customers were experiencing
the second worst drought in 75 years. ...However,
as we have learned over the past two years, there
are no guarantees about future stream flows or
market prices.
Apart from exposure to market uncertainties, Idaho
Power also confronts the complexities associated with
obtaining the necessary licenses to operate its
hydroelectric stations.The process of relicensing is
prolonged and involved and often includes the
implementation of various measures to address environmental
and stakeholder concerns.These measures can impose
significant additional costs and/or lead to reduced
generating capacity and flexibility.Moody s recently
noted that " (Idaho Power s) rating outlook is negative as
the utility continues to cope with difficult power supply
markets in its region 51 and concluded the Company s bond
ratings could be reduced based on the following factors:
Continued delay in return to more normal hydro
AVERA, DI
Idaho Power Company
and weather conditions in combination with
unexpected harsh treatment from Idaho regulators
in the upcoming general rate proceedings.
Significant increases in relicensing costs and/or
stringent operational constraints impose as part
of the license renewal process.
Similarly, S&P recently observed that:
Utili ties in the Pacific Northwest continue to
face a host of challenges. If the western power
crisis left a large number of them, investor-
owned as well as publicly-owned, in dire
financial straits, weak economic conditions and
the uncertain hydro situation have hamperedrecovery prospects.
S&P went on to note the significant potential costs and
risks imposed by uncertainty over fish-conservation
measures that might be required to meet federal law and
continued volatility in wholesale power markets, concluding
that "managing hydro risk has assumed a critical importance
to credit quality.
What other factors would investors likely
consider in evaluating their required rate of return for
Idaho Power?
Investors have clearly recognized that
structural change and market evolution in the electric
power industry have led to a significant increase in the
risks faced by industry participants. For a firm caught
between expanding wholesale competition in the industry and
the constraints of regulation, as are electric utilities,
these risks are further magnified.As S&P recognized:
AVERA, DI
Idaho Power Company
Al though the move to competi tion from regulationis obviously negative for credit quality
general, the transition period can often be worse
for bondholders than would be a fully competitiveindustry. In the interim, companies can be
saddled with many of the disadvantages of being
regulated (e.
g.,
limits on return on capital and
higher costs to comply with regulatory mandates)
while simultaneously being gradually exposed to
marketplace risks.
Similarly, the Wall Street Journal recently highlighted the
risks that investors associate with the interface between
competition and regulation in the power industry;
Now, with the power industry hovering uneasily
between regulation and deregulation, it faces the
prospect of a market that combines the worstfeatures of both; return to governmentrestrictions, mixed with volatility and price
spikes as companies struggle to meet the nation
energy needs.
Moreover, investors recognize that regulation has
its own risks.In some circumstances regulatory
uncertainty can eclipse all of the other risk factors
facing particular utili ties.Considering the magni tude of
the events that have transpired since the third quarter of
2000, investors ' sensitivity to market and regulatory
uncertainties has increased dramatically.The sharpened
focus on the risks associated with unrecoverable wholesale
power costs, for example, was noted by RRA:
The potential for volatility in wholesale powerelectrici ty markets, as highlighted by the
temporary price spikes experienced in the Midwest
in June 1999 and, more recently, by the ongoing
AVERA, DI
Idaho Power Company
severe capacity shortage/pricing crisis in
California, has raised investors I level of
awareness and concern with regard to the ability
of electric utilities to recover increased
wholesale power costs and fuel expenses- from
customers.
Investors ' required rates of return for utilities
are premised on the regulatory compact that allows the
utili ty an opportunity to recover reasonable and necessary
costs. By sheltering utilities from exposure to
extraordinary power cost volatility, ratepayers benefit
from lower capital costs than they would otherwise bear.
Of course, the corollary implies that, if investors believe
that the utility might face continued exposure to
potentially extreme fluctuations in power supply costs
while remaining obligated to provide service at regulated
rates, their required return would be considerably
increased.As S&P noted, the August 14th blackout is
unlikely to ease investors ' concerns;
Clearly, the blackout has highlighted the
complexity of the system, the diversity of its
many stakeholders and the susceptibility of the
industry to political and regulatory risk.
C. Implications for Financial Integrity
Why is it important to allow Idaho Power an
adequate rate of return on equity?
Gi ven the social and economic importance of
the electric utility industry, it is essential to maintain
AVERA, DI
Idaho Power Company
reliable and economical service to all consumers.While
Idaho Power remains commi t ted to deliver reliable electric
service at the lowest possible price, a utility s ability
to fulfill its mandate can be compromised if it lacks the
necessary financial wherewithal.
What lessons can be learned from recent events
in the energy industry?
Events in the western U. S. provide a dramatic
illustration of the high costs that all stakeholders must
bear when a utility s financial integrity is compromised.
California s failed market structure led to unprecedented
volatili ty in the region s wholesale power costs.For many
utili ties, recovery of purchased energy costs that they
were forced to buy to serve their customers was either
prevented and/or postponed.As a result, they were denied
the opportunity to earn risk-equivalent rates of return and
access to capital was cut off.Regional economies have
been jolted and consumers have suffered the results of
higher cost power and reduced reliability.Moreover, while
the impact of the utilities ' deteriorating financial
condition was felt swiftly, stakeholders have discovered
first hand how difficult and complex it can be to remedy
the situation after the fact.
Do you have any personal experience regarding
the damage to customers that can result when a utility
AVERA, DI
Idaho Power Company
financial integrity deteriorates?
Yes.I was a staff member of the PUCT when
the financial condition of El Paso Electric Company ("EPE"
began to suffer in the late 1970s.I later observed first-
hand the difficulties in reversing this slide as a
consul tant to Asarco Mining, EPE I S largest single customer.
EPE's ultimate bankruptcy imposed enormous costs on
customers and absorbed an undue amount of the PUCT'
resources, as well as those of the Attorneys General and
other state agencies.Now I am serving as a consultant to
the utility as it continues its struggle to fully recover
its financial health.There is no question that customers
and other stakeholders would have been far better off had
EPE avoided bankruptcy by maintaining its financial
resilience.
What danger does an inadequate rate of return
pose to Idaho Power?
AVERA, DI
Idaho Power Company
While Idaho Power has been successful in
maintaining its financial flexibility, it is important to
remember that, once lost, investor confidence is difficult
to recover and the damage is not easily reversible.
Consider the example of bond ratings.To res tore a
company s rating to a previous, higher level, rating
agencies generally require the company to maintain its
financial indicators above the minimum levels required for
the higher rating over a period of time.Considering
investors ' sharp focus on the risks associated with the
west and the uncertainties imposed by the Company
relative reliance on hydroelectric generation, the
perception of a lack of regulatory support would almost
certainly lead to a decline in Idaho Power s credit quality
and financial flexibility.
At the same time, Idaho Power plans to add
significant plant investment, such as the Mountain Home
generating facility, to ensure that the energy needs of its
service terri tory are met.While providing the
infrastructure necessary to support economic growth is
certainly desirable, it imposes significant
responsibilities on Idaho Power.To meet these challenges
successfully and economically, it is crucial that the
Company receive adequate support for its credit standing.
Finally, maintaining Idaho Power s access to capital on
AVERA, DI
Idaho Power Company
reasonable terms has the added benefit of preserving the
Company s independence and ability to maintain quality
service based on the interests of Idaho ratepayers.
D. Conc1usions
What is your conclusion regarding a fair rate
of return on equi ty range for Idaho Power?
Based on the capital market research presented
earlier and the economic requirements discussed above, it
is my conclusion that a return on equity in the range
10.6 to 11.9 percent represents a conservative estimate of
investors ' required rate of return for Idaho Power in
today ' s capi tal markets.
In evaluating the rate of return for Idaho Power, it
is important to consider investors I continued focus on the
unsettled conditions in western power markets.These
uncertainties are compounded by the Company s continued
reliance on hydroelectric power for a relatively greater
portion of its energy supply, as well as other risks
associated with the power industry, such as heightened
exposure to regulatory uncertainties.
How does your recommended fair rate of return
on equity range for Idaho Power compare wi th other
benchmarks that investors would consider?
Reference to rates of return available from
alternative investments can also provide a useful guideline
AVERA, DI
Idaho Power Company
in assessing the return necessary to assure confidence in
the financial integrity of a firm and its ability to
a t tract capi tal.This comparable earnings approach avoids
the complexities and limitations of capital market methods
and instead focuses on the returns earned on book equity,
which are readily available to investors.
Indeed, the most recent edition of Value Line
reports that its analysts expect average rates of return on
common equity for the electric utility industry of 11.
percent and 11.8 percent for 2003 and 2004, respectively,
with their three to five year projections anticipating a
return on equity of 12.0 percent. Similarly, expected
rates of return for gas distribution utilities are expected
to average 11.5 percent over Value Line ' s forecast
horizon,60 while the 696 industrial, retail, and
transportation companies included in Value Line s Composite
Index are expected to earn 16.0 percent on book equity
during the 2006-2008 time frame. Accordingly, these
expected earned rates of return confirm the reasonableness
of my recommended rate of return on equity range for Idaho
Power.
My recommended ROE range is further supported by the
fact that investors are likely to anticipate increases in
utility bond yields going forward.Moreover, an ROE in the
10.6 percent to 11.9 percent range is reasonable at this
AVERA, DI
Idaho Power Company
critical juncture, given the importance of supporting the
financial capability of Idaho Power as it invests the
capi tal that is needed to develop and enhance utility
infrastructure.As the recent power failures amply
demonstrated, the cost of providing Idaho Power an adequate
return is small relative to the potential benefits that a
strong utility can have in providing reliable service and
fostering growth.Considering investors ' heightened
awareness of the risks associated with the electric power
industry and the damage that results when a utility
financial flexibility is compromised, supportive regulation
is perhaps more crucial now than at any time in the past.
Does this conclude your direct testimony in
this case?
Yes, it does.
AVERA, DI
Idaho Power Company
ENDNOTES
1 IDACORP, Inc., "IDACORP Reduces Dividend To Strengthen
Balance Sheet, n News Scans (Sep. 18, 2003).
2 Standard & Poor's Corporation, "IDACORP and Unit Ratings
Affirmed; Outlook Revised to Stable,RatingsDirect (Oct.
2003).
Regional Transmission Organizations, Order No. 2000 (Dec.
2 0, 1999), 89 FERC i 61, 2 8 5 .
4 Remedying Undue Discrimination through Open Access
Transmission Service and Standard Electricity Market
Design, Notice of Proposed Rulemaking, IV FERC Stats. &
Regs. i 32,563 (2002) ("SMD NOPRn ); FERC White Paper,
Wholesale Power Market Platform, April 28, 2003, available
at http: / /www. ferc. gov /Electric/RTO/Mrkt-Strct-comments/
Whi te paper. pdf .
Remarks by William L. Massey, Center for Public Utilities
Advisory Council, "The Santa Fe Conference " (March 17,
2003) .
6 Standard & Poor s Corporation, 2002 Power Energy Credit
Conference: Beyond the Crisis (Jun. 12, 2002).
7 Standard & Poor s Corporation, "S. Power Industry
Experiences Precipitous Credit Decline in 2002; Negative
Slope Likely to Continue RatingsDirect (Jan. 15, 2003).
Id.
9 Standard & Poor s Corporation, "Credit Quality For U.
Utilities Continues Negative Trend,RatingsDirect (Jul.
24, 2003).
10 Moody
s Investors Service, Moody s Credi Perspectives
(Jul. 14, 2003) at 33-34.
11 Standard & Poor's Corporation, "Credit Quality For U.
Utilities Continues Negative Trend,
n RatingsDirect (Jul.
24, 2003).12 Idaho Power Company, Form 10-K Report (2001).
13
Standard & Poor'Corporation, Public Power Companies in
Northwest Increase Rates Due to Low Water, Skyrocketing
Prices , Infrastructure Finance, p. 1 (January 18, 2001).
14
The Value Line Investment Survey, p. 1758 (November 17,
2000) .
AVERA, DI
Idaho Power Company
15 Statement of Pat Wood, III, Chairman, Federal Energy
Regulatory Commission, On the Power Failure in the u.S. and
Canada, Press Release (Aug. 15, 2003).
16 See, g., Remedying Undue Discrimination through Open
Access Transmission Service and Standard Electrici ty Market
Design, 67 Fed. Reg. 55,451, FERC Stats. & Regs. ~ 32,563
(2002) ("SMD NOPR") and FERC White Paper, Wholesale Power
Market Platform, April 28, 2003, available
http: / /www.ferc.gov/Electric/RTO/Mrkt-Strct-
comments /Whi te-paper . pdf 17 Standard & Poor I s Corporation, "Electric Transmission at
the Starting Gate RatingsDirect (May 10, 2002).
18 Massey, William L., "Restoring Confidence in Energy
Markets , Remarks at the 9th Annual Spring Conference for
the New England Energy Industry (May 21, 2002).
19 U.S. Department of Energy, National Transmission Grid
Study (May 2002), at 24 and 31.
20
Id. at 31.
21
Draft Remarks of Kara M. Silva, Vice President, MBIA
Insurance Corporation, NARUC Joint Committee onElectricity, Gas, and Finance and Technology (Feb. 26,
2003).
22 Consumer Energy Council of America, "Positioning the
Consumer for the Future: A Roadrnap to an Optimal Electric
Power System (Apr. 2003) at XVII.
23 Smith, Rebecca, "Overloaded Circuits Blackout Signals
Maj or Weakness in U. S. Power Grid," The Wall Street Journal
(Aug. 18, 2003).
24 Statement of Pat Wood, III, Chairman, Federal Energy
Regulatory Commission, On the Power Failure in the u.S. and
Canada, Press Release (Aug. 15, 2003).
25 Standard & Poor s Corporation, "Electric Utility
Blackouts Put Spotlight on Political and Regulatory Credit
Risk"RatingsDirect (Aug. 21, 2003).
26 Id.27 Standard & Poor s Corporation, Corporate Ratings Cri teria
at 29, available at www. standardandpoors. com/ratings.
28 Energy Information Administration, Annual Energy Outlook
2003, at Table 20, Nov. 20, 2002, available
ht tp; / /www . eia. doe. gov / oiaf / aeo /pdf / aeo base . pdf .
AVERA, DI
Idaho Power Company
29 Global Insight The U.S. Economy, The 25-Year Focus
(Winter 2003) at Table 33.
30 Federal Communications Commission, Report .and Order 42-
43, CC Docket No. 92-133 (1995).
31 The financial stress and lack of stability that
accompanies below investment grade bond ratings greatly
complicates any determination of investors ' long-term
expectations that form the basis for DCF applications to
estimate the cost of equity.
32
Idaho Commissioner Meets with ELCON, ELCON Report (No.
2003) at 7.
33
Williston Basin Interstate Pipeline Co., 104 FERC i
61,036, at 14-15 (Jul. 3, 2003).
34 See,
g.,
The Value Line Investment Survey (Sep. 15,
1995 at 161, Sep. 5, 2003 at 154).
35 Association for Investment Management and Research,
Finding Reality in Reported Earnings; An Overview , p. 1
(Dec. 4 , 199 6)
36 The Value Line Investment Survey, Subscriber s Guide,
53.
37 Block, Stanley B., "A Study of Financial Analysts:
Practice and Theory Financial Analysts Journal
(July/August 1999) .
38 Id. at 88.
39 The Value Line Investment Survey (July 4, 2003) at 695.
40 The Value Line Investment Survey (Aug. 15, 2003) at 1776.
41 Fama, Eugene F. and French, Kenneth R., "The Cross-
Section of Expected Stock Returns The Journal of Finance
(June 1992).
42 Indeed, average realized rates of return for historical
periods are widely reported to investors in the financial
press and by investment advisory services as a guide to
future performance.
43 Roger A. Morin, Regulatory Finance: Utilities ' Cost
Capi tal, 1994, at 166.
44 Standard & Poor s, Corporate Ratings Criteria at 58,
available at www. standaredandpoors. com/ratings.
45 Moody s Investors Service, Credit Risk Commentary, p. 3
(July 29, 1996).
AVERA, DI
Idaho Power Company
46 The Value Line Investment Survey, p. 1776 (Aug. 15,
2003) .
47 Standard & Poor s Corporation, Credit Quality For U.Utili ties Continues Negative Trend, RatingsDirect, Jul. 24,
2003.48 Smith, Rebecca, "Rating Agencies Crack Down on
Utilities , The Wall Street Journal, p. Cl (December 19,
2001) .
49 Id.
50
Idaho Power granted $256 million deferral, but bond plan
denied, Idaho Public Utili ties Commission (May 13, 2002).
51 Moody s Investors Service, Opinion Update: Idaho Power
Company (Jun. 20, 2003).
52 Id.
53 Standard & Poor s Corporation, "Legal Developments Add to
Utilities ' Disquiet in u.S. Northwest,Utilities
Perspectives (July 21, 2003) at 2-
54 Id.55 Standard & Poor 's, CreditWeek, Nov. I, 2000, at 31.
56 Rebecca Smith, Shock Waves, The Wall Street Journal, Nov.
30, 2001, at AI.
57 Regulatory Research Associates, "Recovery of Wholesale
Power Costs: Who is at Risk and Who is Not?"Regulatory
Focus, p. 1 (February 28, 2001).
58 Standard & Poor s Corporation, "Electric Utility Blackout
Puts Spotlight on Political and Regulatory Credit Risk,
RatingsDirect (Aug. 21, 2003).
59 The Value Line Investment Survey (Aug. 15, 2003) at i 776.
60 The Value Line Investment Survey (June 20, 2003) at 458.
61 The Value Line Investment Survey, Selection Opinion
(July 18, 2003) at 2857.
AVERA, DI
Idaho Power Company
DISCOUNTED CASH FLOW MODEL Exhibit WEA-5
Page 1 of 1
EXPECTED DIVIDEND YIELD
(a)(a)
Estimated
Stock Dividends Implied
Sym Com Price Next 12 Mos.Dividend Yield
BKH Black Hills Corp.$ 31.$1.
Hawaiian Electric $ 41.$2.
MDU MDU Resources Group $ 32.$1.
PNM PNM Resources Group $ 26.$0.
PNW Pinnacle West Capital $ 33.$1.
PSD Puget Energy, Inc.$ 21 .$1.
SRE Sempra Energy $ 28.$1.
XEL Xcel Energy $ 14.$0.
Average
(b)Summary and Index, The Value Line Investment Survev (August 22.2003).
EXHBIIT NO.
CASE NO. IPC-03-
W. AVERA, IPCo
PAGE 1 OF 1
DI
S
C
O
U
N
T
E
D

C
A
S
H

F
L
O
W

M
O
D
E
L
Ex
h
i
b
i
t

W
E
A
-
Pa
g
e

1

o
f

1
EA
R
N
I
N
G
S

G
R
O
W
T
H

R
A
T
E
S
Pr
o
j
e
c
t
e
d
Hi
s
t
o
r
i
c
a
l
(a
)
(b
)
(c
)
(d
)
(b
)
(b
)
Va
l
u
e
Fi
r
s
t
Mu
l
t
e
x
Pa
s
t
Pa
s
t
Sv
m
Co
m
IB
E
S
Li
n
e
Ca
l
l
In
v
e
s
t
o
r
10

Y
r
5
Y
r
BK
H
Bl
a
c
k

H
i
l
l
s

C
o
r
p
.
8.
0
%
8.
0
%
15
.
Ha
w
a
i
i
a
n

E
l
e
c
t
r
i
c
MD
U
MD
U

R
e
s
o
u
r
c
e
s

G
r
o
u
p
12
.
PN
M
PN
M

R
e
s
o
u
r
c
e
s

G
r
o
u
p
NM
F
19
.
PN
W
Pi
n
n
a
c
l
e

W
e
s
t

C
a
p
i
t
a
l
NM
F
PS
D
Pu
g
e
t

E
n
e
r
g
y
,

I
n
c
.
NM
F
NM
F
SR
E
Se
m
p
r
a

E
n
e
r
g
y
XE
L
Xc
e
l

E
n
e
r
g
y
NM
F
1.
4
%
NM
F
Av
e
r
a
g
e
NM
F

-
-

N
o

M
e
a
n
i
n
g
f
u
l

F
i
g
u
r
e
NA

-
-

N
o
t

A
v
a
i
l
a
b
l
e
(a
)
(b
)
(c
)
(d
)
I/
B
/
E
/
S

I
n
t
e
r
n
a
t
i
o
n
a
l

g
r
o
w
t
h

r
a
t
e
s

f
r
o
m

S
t
a
n
d
a
r
d

&

P
o
o
r
Ea
r
n
i
n
a
s

G
u
i
d
e
,
(
A
u
g
u
s
t

2
0
0
3
)
.
Th
e

V
a
l
u
e

L
i
n
e

I
n
v
e
s
t
m
e
n
t

S
u
r
v
e
y

(
A
u
g
u
s
t

1
5
,

2
0
0
3
)
.

N
e
g
a
t
i
v
e

g
r
o
w
t
h

r
a
t
e
s

r
e
c
o
r
d
e
d

No

M
e
a
n
i
n
g
f
u
l

F
i
g
u
r
e
.
Fi
r
s
t

C
a
l
l

E
a
r
n
i
n
g
s

E
s
t
i
m
a
t
e
s

f
r
o
m

w
w
w
.
f
i
n
a
n
c
e
.
ya
h
o
o
.
co
m

(
S
e
p
t
e
m
b
e
r

1
,

2
0
0
3
)
.
Mu
l
t
e
x

I
n
v
e
s
t
o
r

e
a
r
n
i
n
g
s

g
r
o
w
t
h

r
a
t
e
s

f
r
o
m

w
w
w
.
mu
i
t
e
x
i
n
v
e
s
t
o
r
.
co
m

(
S
e
p
t
e
m
b
e
r

1
,

2
0
0
3
)
.
EX
H
B
I
I
T

N
O
.
CA
S
E

N
O
.

I
P
C
-
03
-
W.

A
V
E
R
A
,

I
P
C
o
PA
G
E

1

O
F

1
DISCOUNTED CASH FLOW MODEL Exhibit WEA-7
Page 1 of
PROJECTED "B x R" GROWTH
(a)(a)(a)
Proj.Proj.Proj.b" x "
Svm Com EPS DPS BVS Growth
BKH Black Hills Corp.$2.$1.$26.50.55%10.
Hawaiian Electric $3.$2.$33.17.33%
MDU MDU Resources Group $2.$1.$26.58.55%10.
PNM PNM Resources Group $2.$1.$30.50.23%
PNW Pinnacle West Capital $3.$2.$35.35.45%
PSD Puget Energy, Inc.$2.$1.$20.44.00%
SRE Sempra Energy $3.$1.$24.69.23%13.
XEL Xcel Energy $1.$0.$14.40.74%
Average
(a)The Value Line Investment Survey (August 15, 2003).
EXHBIIT NO.
CASE NO. IPC-03-13
W. AVERA, IPCo
PAGE 1 OF 1
RISK PREMIUM APPROACH
Page 1 of 1
ANALYSIS OF AUTHORIZED RATES OF RETURN ON EQUITY
FOR ELECTRIC UTILITIES
(a)(b)
AVERAGE
PUBLIC UTILITY
BOND YIELD
RISK
PREMIUMYEAR
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
Average
ALLOWED
ROE
13.10%
13.20%
13.10%
13.30%
13.20%
13.50%
14.23%
15.22%
15.78%
15.36%
15.32%
15.20%
13.93%
12.99%
12.79%
12.97%
12.70%
12.55%
12.09%
11.41 %
11.34%
11.55%
11.39%
11.40%
11.66%
10.77%
11.43%
11.08%
11.16%
27%
88%
17%
58%
22%
10.39%
13.15%
15.62%
15.33%
13.31%
14.03%
12.29%
46%
98%
10.45%
66%
76%
21%
57%
56%
30%
91%
74%
63%
00%
55%
09%
72%
53%
81%
83%
32%
93%
72%
98%
11%
08%
0.40%
45%
05%
29%
91%
4.47%
01%
34%
31%
94%
34%
52%
85%
04%
64%
65%
77%
66%
22%
34%
36%
63%
08%
Constant
Std Err of Y Est
R Squared
No. of Observations
Degrees of Freedom
07343
00576
77401
Current EQuity Risk Premium
Avg. Yield over Study Period 81%
Aug. 2003 Avg. Utility Bond Yield 79%
Change in Bond Yield 02%
Risk Premium/Interest Rate Relationship 43.46%
Adjustment to Average Risk Premium 31%
Average Risk Premium over Study Period 08%
Adjusted Risk Premium 39%
Regression Output
X Coefficient(s)
Std Err of Coet.
-0.43462
04520
(a)
Major Rate Case Decisions, Regulatory Focus, Regulatory Research Associates (January 22, 2003
January 24,2001 & January 16 1990); UtnityScope Reaulatorv Service, Argus (January 1986).
(b) Moody's Public Utility Manual (2001); Moody's Credit Perspectives (various editions).
EXHBIIT NO.
CASE NO. IPC-E-Q3-
W. AVERA,lPCo
PAGE 1 OF 1
RISK PREMIUM APPROACH Exhibit WEA-9
Page1of1
ANALYSIS OF REALIZED RATES OF RETURN ON EQUITY
FOR THE S&P ELECTRIC POWER COMPANIES
S&P ELECTRIC COMPANIES S&P SINGLE.A PUBLIC UTILITY BONDS /b\
CLOSE ANNUAL CLOSE ANNUAl,
PRICE DIV REALIZED RETURN YIELD PRICE REALIZED RETURN
1945 $16.(c)73%(d)
1946 $15.$0.49%72%$100.91%
1947 $12.$0.12.17%04%$94.41%
1948 $12.$0.1.47%05%$99.86%
1949 $14.$0.24.49%70%$105.93%
1950 $14.49 $0,27%81%$98.75%
1951 $16.$0.17.25%31%$92.03%
1952 $18.$0.19.66%25%$101.37%
1953 $18.$0.19%33%$98.93%
1954 $22.$1.23.46%15%$102.18%
1955 $24.$1.12.33%39%$96.-0.61%
1956 $23.$1.83%19%$88.01%
1957 $24.$1.10.29%97%$103.39%
1958 $33.$1.38.35%51%$92.42 61%
1959 $33.42 $1.77%80%$96.60%
1960 $39.$1.21.84%64%$102.06%
1961 $49.$1.28.89%66%$99.25%
1962 $48.$1.70%33%$104.39%
1963 $51.$1.10.29%51%$97.49 82%
1964 $58.$1.15.36%4.47%$100.10%
1965 $58,$1.99%86%$94.82%
1966 $53.49 $2.34%61%$90.55%
1967 $49.$2.67%50%$89.-4,78%
1968 $51.$2.66%01%$94.75%
1969 $42.$2.13.42%8 .43%$85.7.11%
1970 $45.$2.12.59%8.44%$99,34%
1971 $44.$2.47 26%70%$107.16.22%
1972 $43.$2.19%74%$99.37%
1973 $32.$2.18.71%10%$96.98%
1974 $22.$2.25.36%25%$89.63%
1975 $30.$2.50.39%63%$96.89%
1976 $35.$2.23.53%37%$112.22.21%
1977 $35.$2.21%81%$95.08%
1978 $31.$2.78%75%$91.36%
1979 $28.$3.51%11.47%$86.94%
1980 $27.$3.86%13.39%$86,05%
1981 $29.$3.42 20.45%15.66%$86.-0,54%
1982 $36.$3.35.59%12.21%$126.41.86%
1983 $37.$3.13.36%12.95%$94.83%
1984 $42.$4.24.72%12.39%$104.17,11%
1985 $48.$4.25.34%10.54%$115.28,16%
1986 $58.$4.28.06%12%$113.23.90%
1987 $49.$4.31%10.09%$91.49 61%
1988 $53.$4.17.16%10.02%$100.10.71%
1989 $66.$4.31.48%36%$106.16,13"k
1990 $63.$4.06%60%$97.18%
1991 $77.25 $4.28.91%93%$106.16.01%
1992 $76.$4.45%64%$102.11.77%
1993 $81.$4.12.56%74%$99.67%
1994 $66.$4.13.17%68%$100.33%
1995 $81.$4.30.15%97%$107.16.00%
1996 $76.$4.-0.32%57%$104.12.23%
1997 $91.$4.25.03%07%$105.13.12%
1998'$100.$4.15.04%00%$100.85%
1999 $77.42 $4.18.93%25%$87.61%
2000 $113.$4.51.67%8.40%$98.76%
2001 $92.$3.14.78%8.46%$99.40 80%
2002 $75.08 $4.14.41%82%$106.15.16%
AVERAGE 1946-2002 10.28%27%
REALIZED RATE OF RETURN
S&P ELECTRIC COMPANIES 10.28%EXHBIIT NO.
SINGLE-A PUBLIC UTILITY BONDS 27%CASE NO. IPC-E-O3-
EQUITY RISK PREMIUM 01%W. AVERA, IPCa
PAGE 1 OF 1
(a) S&P'Seeur~Y Price Index Record (1992), The Analvsts' Handbook (1967, 1999, 2001 , Monthly Supplement March 2002).
(b) S&P'Security Price Index Record (1996). Current Statistics (Jan. 1 ' Mar, 1998 . Dec. 1999, Feb. 2001, Jan. 2002, & Jan. 2003).
(e) Computed by adding gain or loss (ending stock price - beginning stocK rice) to annual dividends and dividing by beginning stock price.
(d) Computed as sum of cap~aI gain or loss plus interest income, divided b beginning price.
Note: Dividend data not available prior to 1946.
RISK PREMIUM METHOD
CAPIT AL ASSET PRICING MODEL
Market Rate of Return (a)
Dividend Yield
Growth Rate
Market Return
Risk-Free Rate (b)
August 2003 Average 20-Year Treasury Bond Yield
Market Risk Premium (c)
Electric Utility Proxy Group Beta (d)
Electric Utility Proxy Group Risk Premium (e)
Implied Cost of Equity (f)
70%
12.54%
Exhibit WEA-10
Page 1 of 1
14.24%
39%
85%
28%
11.67%
(a) Average for the stocks in the S&P 500 Index at June 15, 2003. Dividend yield for month-end June
2003 from www.standardandpoors.com. Individual company growth rates based on IBES growth
projections reported in Standard & Poor Earninas Guide (June 2003).
(b) Average yield on Long-term (::-25 years) government bonds for August 2003 reported by the U.
Department of the Treasury at www.treas.gov.
(c) (a) - (b).
(d) The Value Line Investment Survey (August 15, 2003).
(e) (c) x (d).(f) (b) + (e).EXHBIIT NO.1 0
CASE NO. IPC-03-
W. AVERA, IPCo
PAGE 1 OF 1
WILLIAM E. AVERA
FINCAP, 1Ne.
Financial Concepts and Applications
Economic and Financial Counsel
Page 1 of 6
WilliAM E. AVERA
3907 Red River
Austin, Texas 78751
[phone]
FAX [phone]
fmcap (g) texas.net
Summary of Qualifications
Ph.D. in economics and finance; Chartered Financial Analyst (CF A (6)) designation; extensive expert
witness testimony before courts, alternative dispute resolution panels, regulatory agencies and
legislative committees; lectured in executive education programs around the world on ethics
investment analysis, and regulation; undergraduate and graduate teaching in business and economics;
appointed to leadership positions in government, industry, academia, and the military.
Emplovment
Principal,
FINCAP, Inc.
(Sep. 1979 to present)
Director, Economic Research
Division
Public Utility Commission of Texas
(Dec. 1977 to Aug. 1979)
Manager, Financial Education,
International Paper Company
New York City
(Feb. 1977 to Nov. 1977)
Financial, economic and policy consulting to business
and government. Perform business and public policy
research, costlbenefit analyses and financial modeling,
valuation of businesses (over 100 entities valued),
estimation of damages, statistical and industry studies.
Provide strategy advice and educational services in public
and private sectors, and serve as expert witness before
regulatory agencies, legislative committees, arbitration
panels, and courts.
Responsible for research and testimony preparation on
rate of return, rate structure, and econometric analysis
dealing with energy, telecommunications, water and
sewer utilities. Testified in major rate cases and appeared
before legislative committees and served as Chief
Economist for agency. Administered state and federal
grant funds. Communicated frequently with political
leaders and representatives from consumer groups
media, and investment community.
Directed corporate education programs in accounting,
finance, and economics. Developed course materials,
recruited and trained instructors , liaison within the
company and with academic institutions. Prepared
operating budget and designed financial controls for
corporate professional development program.
EXHIBIT NO. 11
CASE NO.IPC-O3-
W. AVERA, IPCo
PAGE 1 OF 6
WILLIAM E. AVERA
Lecturer in Finance
The University of Texas at Austin
(Sep. 1979 to May 1981)
Assistant Professor of Finance
(Sep. 1975 to May 1977)
Assistant Professor of Business
University of North Carolina at
Chapel Hill
(Sep. 1972 to Jul. 1975)
Education
Ph., Economics and Finance
University of North Carolina at
Chapel Hill
(Jan. 1969 to Aug. 1972)
B.A., Economics,
Emory University, Atlanta, Georgia
(Sep. 1961 to Jun. 1965)
Page 2 of 6
Taught graduate and undergraduate courses in financial
management and investment theory. Conducted research
in business and public policy. Named Outstanding
Graduate Business Professor and received various
administrati ve appointments.
Taught in BBA, MBA, and Ph.D. programs. Created
project course in finance, Financial Management for
Women, and participated in developing Small Business
Management sequence. Organized the North Carolina
Institute for Investment Research, a group of financial
institutions that supported academic research. Faculty
advisor to the Media Board, which funds student
publications and broadcast stations.
Elective courses included financial management, public
finance, monetary theory, and econometrics. Awarded
the Stonier Fellowship by the American Bankers
Association and University Teaching Fellowship. Taught
statistics, macroeconomics, and microeconomics.
Dissertation: The Geometric Mean Strategy as a
Theory of Multiperiod Portfolio Choice
Active in extracunicular activities, president of the
Barkley Forum (debate team), Emory Religious
Association, and Delta Tau Delta chapter. Individual
awards and team championships at national 'collegiate
debate tournaments.
Professional Associations
Received Chartered Financial Analyst (CF A) designation in 1977; Vice President for Membership,
Financial Management Association; President, Austin Chapter of Planning Executives Institute;
Board of Directors, North Carolina Society of Financial Analysts; Candidate Cuniculum Committee,
Association for Investment Management and Research; Executive Committee of Southern Finance
Association; Vice Chair, Staff Subcommittee on Economics and National Association of Regulatory
Utility Commissioners (NARUC); Appointed to NARUC Technical Subcommittee on the National
Energy Act.
EXHIBIT NO. 11
CASE NO. IPC-03-
W. AVERA, IPCo
PAGE 2 OF 6
WILLIAM E. AVERA Page 3 of 6
Teachina in Executive Education Proarams
University-Sponsored Prof!rams:Central Michigan University, Duke University, Louisiana State
University, National Defense University, National University of Singapore, Texas A&MUniversity,
University of Kansas, University of North Carolina, University of Texas.
Business and Government-Sponsored Programs:Advanced Seminar on Earnings Regulation
American Public Welfare Association, Association for Investment Management and Research
Congressional Fellows Program, Cost of Capital Workshop, Electricity Consumers Resource
Council, Financial Analysts Association of Indonesia, Financial Analysts Review, Financial Analysts
Seminar at Northwestern University, Governor s Executive Development Program of Texas
Louisiana Association of Business and Industry, National Association of Purchasing Management,
National Association of Tire Dealers, Planning Executives Institute, School of Banking of the South
State of Wisconsin Investment Board, Stock Exchange of Thailand, Texas Association of State
Sponsored Computer Centers, Texas Bankers' Association, Texas Bar Association, Texas Savings
and Loan League, Texas Society of CP As, Tokyo Association of Foreign Banks, Union Bank of
Switzerland, U.S. Department of State, U.S. Navy, u.S. Veterans Administration, in addition to
Texas state agencies and major corporations.
Presented papers for Mills B. Lane Lecture Series at the University of Georgia and Heubner Lectures
at the University of Pennsylvania. Taught graduate courses in finance and economics in evening
program at St. Edward's University in Austin from January 1979 through 1998.
Expert Witness Testimony
Testified in nearly 200 cases before regulatory agencies addressing cost of capital, rate design, and
other economic and financial issues.
Federal AJ!encies:Federal Communications Commission, Federal Energy Regulatory Commission,
Surface Transportation Board Interstate Commerce Commission, and the Canadian
Radio-Television and Telecommunications Commission.
State ReJ!ulatorv AJ!encies:Alaska, Arizona, Arkansas, California, Colorado, Connecticut
Delaware, Florida, Hawaii, Idaho, lllinois, Indiana, Kansas, Maryland, Michigan, Missouri
Nevada, New Mexico, North Carolina, Ohio, Oklahoma, Oregon, Pennsylvania, South Carolina,
Texas, Virginia, Washington, West Virginia, and Wisconsin.
Testified in over 30 cases before federal and state courts, arbitration panels, and alternative dispute
tribunals (over 60 depositions given) regarding damages, valuation, antitrust liability, fiduciary
duties, and other economic and financial issues.
Board Positions and Other Professional Activities
Audit Committee and Outside Director, Georgia System Operations Corporation (electric system
operator for member-owned electric cooperatives in Georgia); Chainnan, Board of Print Depot, Inc.
and FINCAP, Inc.; Co-chair, Synchronous Interconnection Committee, appointed by Governor
George Bush and Public Utility Commission of Texas; Operator of AAA Ranch, a certified organic
producer of agricultural products; Appointed to Organic Livestock Advisory Committee by Texas
Agricultural Commissioner Susan Combs; Appointed by Texas Railroad Commissioners to study
group for The UP/SP Merger: An Assessment of the Impacts on the State of Texas; Appointed by
EXHIBIT NO. 11
CASE NO. IPC-O3-
W. AVERA, IPCo
PAGE 3 OF 6
WILLIAM E. AVERA Page 4 of 6
Hawaii Public Utilities Commission to team reviewing affiliate relationships of Hawaiian Electric
Industries; Chairman, Energy Task Force, Greater Austin-San Antonio Conidor Council; Consultant
to Public Utility Commission of Texas on cogeneration policy and other matters; Consultant to
Public Service Commission of New Mexico on cogeneration policy; Evaluator of Energy Research
Grant Proposals for Texas Higher Education Coordinating Board.
Community Activities
Board Member, Sustainable Food Center; Chair, Board of Deacons, Finance Committee, and Elder,
Central Presbyterian Church of Austin; Founding Member, Orange-Chatham County (N.c.) Legal
Aid Screening Committee.
Militarv
Captain, u.S. Naval Reserve (retired after 28 years service); Commanding Officer, Naval Special
Warfare (SEAL) Engineering Support Unit; Officer-in-charge of SWIFT patrol boat in Vietnam;
Enlisted service as weather analyst (advanced to second class petty officer).
BiblioQraphv
Monographs
Ethics and the Investment Professional (video, workbook, and instructor s guide) and Ethics
Challenge Today (video), Association for Investment Management and Research (1995)
Definition of Industry Ethics and Development of a Code" and "Applying Ethics in the Real
World," in Good Ethics: The Essential Element ofa Firm s Success, Association for Investment
Management and Research (1994)
On the Use of Security Analysts' Growth Projections in the DCF Model," with Bruce H. Fairchild
in Earnings Regulation Under Inflation J. R. Foster and S. R. Holmberg, eels. Institute for Study
of Regulation (1982)
An Examination of the Concept of Using Relative Customer Class Risk to Set Target Rates of Return
in Electric Cost-oj-Service Studies, with Bruce H. Fairchild, Electricity Consumers Resource
Council (ELCON) (1981); portions reprinted in Public Utilities Fortnightly (Nov. 11, 1982)
Usefulness of CulTent Values to Investors and Creditors Research Study on Current-Value
Accounting Measurements and Utility, George M. Scott, ed., Touche Ross Foundation (1978)
The Geometric Mean Strategy and Common Stock Investment Management " with Henry A.
Latane in Life Insurance Investment Policies David Cummins, ed. (1977)
Investment Companies: Analysis of Current Operations and Future Prospects with J. Finley Lee
and Glenn L. Wood, American College ofUfe Underwriters (1975)
Articles
Should Analysts Own the Stocks they Cover?" The Financial Journalist (March 2002)
Liquidity, Exchange Listing, and Common Stock Performance " with John C. Groth and Kerry
Cooper, Journal of Economics and Business (Spring 1985); reprinted by National Association of
Security Dealers
EXHIBIT NO. 11
CASE NO. IPC-O3-
W. AVERA, IPCo
PAGE 4 OF 6
WILLIAM E. AVERA Page 5 of 6
The Energy Crisis and the Homeowner: The Grief Process,Texas Business Review (Jan.Feb.
1980); reprinted in The Energy Picture: Problems and Prospects, J. E. Pluta, ed., Bureau of
Business Research (1980)
Use oflFPS at the Public Utility Commission of Texas,Proceedings of the IFPS Users Group
Annual Meeting (1979)
Production Capacity Allocation: Conversion, CWIP, and One-Anned Economics,Proceedings of
the NARUC Biennial Regulatory Information Conference (1978)
Some Thoughts on the Rate of Return to Public Utility Companies," with Bruce H. Fairchild in
Proceedings of the NARUC Biennial Regulatory Information Conference (1978)
A New Capital Budgeting Measure: The Integration of Time, Liquidity, and Uncertainty," with
David Cordell in Proceedings of the Southwestern Finance Association (1977)
Usefulness of Current Values to Investors and Creditors," in Inflation Accountingflndexing and
Stock Behavior (1977)
Consumer Expectations and the Economy,Texas Business Review (Nov. 1976)
Portfolio Performance Evaluation and Long-run Capital Growth " with Henry A. Latane
Proceedings of the Eastern Finance Association (1973)
Book reviews in Journal of Finance and Financial Review. Abstracts for CFA Digest. Articles in
Carolina Financial Times.
Selected Papers and Presentations
The Who, What, When, How, and Why of Ethics , San Antonio Financial Analysts Society (Jan.
16,2002). Similar presentation given to the Austin Society of Financial Analysts (Jan. 17 2002)
Ethics for Financial Analysts " Sponsored by Canadian Council of Financial Analysts: delivered in
Calgary, Edmonton, Regina, and Winnipeg, June 1997. Similar presentations given to Austin
Society of Financial Analysts (Mar. 1994), San Antonio Society of Financial Analysts (Nov.
1985), and St. Louis Society of Financial Analysts (Feb. 1986)
Cost of Capital for Multi-Divisional Corporations," Financial Management Association, New
Orleans, Louisiana (Oct. 1996)
Ethics and the Treasury Function " Government Treasurers Organization of Texas, Corpus Christi
Texas (Jun. 1996)
A Cooperative Future " Iowa Association of Electric Cooperatives, Des Moines (December 1995).
Similar presentations given to National G & T Conference, Irving, Texas (June 1995), Kentucky
Association of Electric Cooperatives Annual Meeting, Louisville (Nov. 1994), Virginia,
Maryland, and Delaware Association of Electric Cooperatives Annual Meeting, Richmond (July
1994), and Carolina Electric Cooperatives Annual Meeting, R~eigh (Mar. 1994)
Information Superhighway Warnings: Speed Bumps on Wall Street and Detours from the
Economy," Texas Society of Certified Public Accountants Natural Gas, Telecommunications and
Electric Industries Conference, Austin (Apr. 1995)
EconomiclWall Street Outlook," Carolinas Council of the Institute of Management Accountants
Myrtle Beach, South Carolina (May 1994). Similar presentation given to Bell Operating Company
Accounting Witness Conference, Santa Fe, New Mexico (Apr. 1993)
EXHIBIT NO. 11
CASE NO. IPC-O3-
W. AVERA, IPCo
PAGE 5 OF6
WILLIAM E. AVERA Page 6 of 6
Regulatory Developments in Telecommunications " Regional Holding Company Financial and
Accounting Conference, San Antonio (Sep. 1993)
Estimating the Cost of Capital During the 1990s: Issues and Directions," The National Society of
Rate of Return Analysts, Washington, D.C. (May 1992)
Making Utility Regulation Work at the Public Utility Commission of Texas," Center for Legal and
Regulatory Studies, University of Texas, Austin (June 1991)
Can Regulation Compete for the Hearts and Minds of Industrial Customers," Emerging Issues of
Competition in the Electric Utility Industry Conference, Austin (May 1988)
The Role of Utilities in Fostering New Energy Technologies," Emerging Energy Technologies in
Texas Conference, Austin (Mar. 1988)
The Regulators' Perspective," Bellcore Economic Analysis Conference , San Antonio (Nov. 1987)
Public Utility Commissions and the Nuclear Plant Contractor," Construction Litigation
Superconference, Laguna Beach, California (Dec. 1986)
Development of Cogeneration Policies in Texas," University of Georgia Fifth Annual Public
Utilities Conference, Atlanta (Sep. 1985)
Wheeling for Power Sales " Energy Bureau Cogeneration Conference, Houston (Nov. 1985).
Asymmetric Discounting of Infonnation and Relative Liquidity: Some Empirical Evidence for
Common Stocks" (with John Groth and Kerry Cooper), Southern Finance Association, New
Orleans (Nov. 1982)
Used and Useful Planning Models," Planning Executive Institute, 27th Corporate Planning
Conference, Los Angeles (Nov. 1979)
Staff Input to Commission Rate of Return Decisions," The National Society of Rate of Return
Analysts, New York (Oct. 1979)
Electric Rate Design in Texas," Southwestern Economics Association, Fort Worth (Mar. 1979)
Discounted Cash Life: A New Measure of the Time Dimension in Capital Budgeting," with David
Cordell, Southern Finance Association, New Orleans (Nov. 1978)
The Relative Value of Statistics of Ex Post Common Stock Distributions to Explain Variance
with Charles G. Martin, Southern Finance Association, Atlanta (Nov. 1977)
An ANOV A Representation of Common Stock Returns as a Framework for the Allocation of
Portfolio Management Effort " with Charles G. Martin, Financial Management Association,
Montreal (Oct. 1976)
A Growth-Optimal Portfolio Selection Model with Finite Horizon," with Henry A. Latane
American Finance Association, San Francisco (Dec. 1974)
An Optimal Approach to the Finance Decision," with Henry A. Latane, Southern Finance
Association, Atlanta (Nov. 1974)
A Pragmatic Approach to the Capital Structure Decision Based on Long-Run Growth," with Henry
A. Latane, Financial Management Association, San Diego (Oct. 1974)
Multi-period Wealth Distributions and Portfolio Theory," Southern Finance Association, Houston
(Nov. 1973)
Growth Rates, Expected Returns, and Variance in Portfolio Selection and Petfonnance
Evaluation," with Henry A. Latane, Econometric Society, Oslo, Norway (Aug. 1973)
EXHIBIT NO. 11
CASE NO. IPC-O3-
W. AVERA, IPCo
PAGE 6 OF 6
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-O3-13
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS INTERIM
AND BASE RATES AND CHARGES FOR
ELECTRIC SERVICE.
IDAHO POWER COMPANY
DIRECT REBUTTAL TESTIMONY
WILLIAM E. AVERA
Texas,78751.
INTRODUCTION
Please state your name and business address.
William E. Avera, 3907 Red River, Austin,
Are you the same William E. Avera that
previously submitted direct testimony in this case?
Yes, I am.
What is the purpose of your rebuttal
testimony?
The purpose of my testimony is to respond to
the direct testimony of Ms. Terri Carlock, submitted on
behalf of the staff of the Idaho Public utilities
Commission ("IPUC"In addition, I will also rebut the
recommendations contained in the direct testimony of Mr.
Dennis E. Peseau testimony, on behalf of Micron Technology,
Inc., concerning the cost of equity for Idaho Power Company
Idaho Power" or "the Company"
) .
Please summarize the conclusions of your
rebuttal testimony.
With respect to the testimony of Ms.
Carlock, I concluded that her discounted cash flow ("DCF"
results were biased because of her exclusive reliance on
AVERA, Di -Reb
Idaho Power Company
IDACORP, Inc.IDACORP"), whose recent dividend cut
violates the assumptions of this method.Additionally, Ms.
Carlock's approach ignored other accepted methods of
estimating the cost of equity, as well as the flotation
costs necessary to raise equity capital.Finally, Ms.
Carlock's assessment of Idaho Power s relative risks
focused exclusively on the Company's low rates, while
ignoring the substantial uncertainties that investors must
bear in order to provide the benefits of lower electricity
costs to Idaho Power s customers.After excluding Ms.
Carlock's flawed DCF results and considering investors'
risk perceptions and an adjustment for flotation costs, the
resul ts of Ms. Carlock's comparable earnings approach
support Idaho Power's requested fair rate of return on
equity in this case.
Meanwhile, Mr. Peseau did not conduct any
independent analyses of the cost of equity to Idaho Power.
Instead, his recommendations were based entirely on
updates" and "revisions" to my analyses.Much like the
Holy Roman Empire, however, neither of these two terms
accurately describes Mr. Peseau ' s selective - and baseless
- alteration of my original analyses, which must be
AVERA, Di -Reb
Idaho Power Company
rej ected in their entirety.
II.TERRI CARLOCK
How did Ms. Carlock arrive at her 10.
percent cost of equity recommendation for Idaho Power?
Ms. Carlock estimated the cost of equity by
applying the constant growth DCF model directly to Idaho
Power's parent, IDACORP.She concluded that the results of
this single DCF application indicated a cost of equity in
the 7.4 to 8. 8 percent range.Ms. Carlock also applied the
comparable earnings approach, which resulted in an
indicated cost of equity in the 10.0 percent to 11.
percent range.Based on these two analyses, Ms. Carlock
concluded that the cost of equity was in the 9.5 to 10.
percent range, selecting the 10.0 percent midpoint as her
recommendations for Idaho Power.
Do the results of Ms. Carlock' s DCF analysis
represent a reliable basis on which to establish Idaho
Power s rate of return on equity?
No.Because she restricted her DCF analysis
to a single company - IDACORP - Ms. Carlock's results are
extremely susceptible to measurement error and bias.As I
discussed at length in my direct testimony, estimating the
AVERA, Di-Reb
Idaho Power Company
cost of equity is a stochastic process.In other words,
because the cost of equity is unobservable, it can only be
inferred by indirect reference to other available data in
the capital markets.But for any single cost of equity
estimate, there is always the potential that the data used
to apply the DCF model will not reflect the expectations
and required returns that investors considered in arriving
at the stock prices we can observe in the capital markets.
As a result, it is essential to insulate against this bias
by referencing a proxy group or electric utilities with
comparable risks.
Why is this particularly critical in the
case of IDACORP?
As discussed in my direct testimony, Idaho
Power and, in turn, IDACORP recently elected to cut common
dividend payments significantly in order to improve cash
flow and help maintain the strong credit ratings necessary
to support the Company's capital expansion plan.Under the
DCF approach, observable stock prices are a function of the
cash flows that investors' expected to receive, discounted
at their required rate of return.Because dividend
payments are a key parameter required to apply DCF methods,
AVERA, Di -Reb
Idaho Power Company
this approach is not well-suited for firms that do not pay
common dividends or have recently cut their payout.
Indeed, Ms. Carlock recognized in her testimony that
changes in the markets and the dividend cut for IDACORP"
complicated any assessment of representative data for the
DCF model.
Indeed, IDACORP's decision to reduce annual common
di vidends by some 35 percent severely violates the
assumptions underlying the constant growth DCF model that
Ms. Carlock used to estimate the cost of equity.
explained in my direct testimony, this approach is based on
the presumption of stable conditions, with earnings
dividends, and book value all growing at a constant rate.
Such is hardly the case for IDACORP in light of its
decision to substantially alter its dividend payout.
Ms. Carlock recognized the importance of matchin~
the growth rate with a consistent dividend yield "so that
investor expectations are accurately reflects.But by
choosing to focus only on IDACORP in implementing the DCF
model, Ms. Carlock needlessly introduced significant
additional complexity into an already challenging process.
Indeed, the fact that the 8.1 percent midpoint of Ms.
AVERA, Di -Reb
Idaho Power Company
Carlock's DCF range falls almost 200 basis points below the
lower bound of her comparable earnings analysis illustrates
the problems of bias associated with her limited DCF
analysis.The proxy group of western electric utilities
referenced in my analyses is consistent not only with the
shared circumstances of electric power markets in the west,
but also with the need to ensure against the potential that
a single cost of equity estimate may not reflect investors'
required rate of return.
Did Ms. Carlock apply the risk premium
approach to estimate the cost of equity for Idaho Power?
No.While Ms. Carlock stated that "much of
the theoretical approach" that she used was consistent with
my testimony, Ms. Carlock did not use the risk premium
approach to estimate the cost of equity.The risk premium
method is widely recognized as a meaningful approach to
estimate the cost of equity.No single method or model
should be relied upon to determine a utility's cost of
equity because no single approach can be regarded as wholly
reliable.This is especially the case in light of the fact
that Ms. Carlock's DCF range was based on the results of a
single company.Indeed, as documented in my direct
AVERA, Di -Reb
Idaho Power Company
testimony, applications of the risk premium approach
provide further evidence of the downward bias inherent in
Ms. Carlock's DCF results.
Did Ms. Carlock recognize that the
investment risks associated with electric utilities have
increased?
Yes.Ms. Carlock noted that a plethora of
changes have impacted investors ' risk perceptions,
observing that:
The competitive risks for electric utilities have
changed with increasing non-utility generation,
deregulation in some states, open transmission access, and
changes in electricity markets.
Ms. Carlock concluded that, because of these greater
uncertainties, the difference in risk between industrial
firms operating in a competitive market and electric
utilities "is not as great as it used to be.
Did Ms. Carlock consider this increase in
risk in her analysis of the cost of equity for Idaho Power?
No.Ms. Carlock ignored this trend in
investment risks for electric utilities, asserting instead
that Idaho Power s "competitive risks" are lower because of
AVERA, Di-Reb
Idaho Power Company
its "low-cost source of power and the low retail rates.
Ms. Carlock also asserted that the Power Cost Adjustment
mechanism ("PCA") reduces Idaho Power's risks relative to
other electric utilities.
Does this represent an accurate assessment
of the investment risks investors' associate with Idaho
Power?
No.While I agree with Ms. Carlock that
Idaho Power s relatively low rates provide benefits to
customers and may improve the Company's competitive
position, this one-sided view ignores the substantial
uncertainties that Idaho Power assumes to realize these
benefits.As explained in detail in my direct testimony,
because approximately one-half of Idaho Power's total
energy requirements are provided by hydroelectric
facilities, the Company is exposed to a level of
uncertainty not faced by other utilities, which are less
dependent on hydro generation.While hydropower confers
advantages in terms of fuel cost savings and diversity,
investors also associated hydro facilities with risks that
are not encountered with other sources of generation.
Reduced hydroelectric generation due to below-
AVERA, Di -Reb
Idaho Power Company
average water conditions forces Idaho Power to rely on less
efficient thermal generating capacity and purchased power
to meet its resource needs.As the Commission has noted,
there are no guarantees about future stream flows or
market prices,7 and in light of the recent past, this
dependence on wholesale markets entails significant risk in
the minds of investors, especially for a utility located in
the west.Investors recognize that volatile markets,
unpredictable stream flows, and Idaho Power's dependence on
wholesale purchases to meet the needs of its customers
exposes the Company to the risk of reduced cash flows and
unrecovered power supply costs.
Apart from exposure to market uncertainties, Idaho
Power also confronts the complexities associated with
obtaining the necessary licenses to operate its
hydroelectric stations.The process of relicensing is
prolonged and involved and often includes the
implementation of various measures to address environmental
and stakeholder concerns.These measures can impose
significant additional costs and/or lead to reduced
generating capacity and flexibility.
Does the fact that Idaho Power has a PCA
AVERA, Di -Reb
Idaho Power Company
absolve investors from risks of volatility in wholesale
power markets, as Ms. Carlock seems to imply?
No.The fact that Idaho Power has been
granted a PCA does not translate into lower risk vis-a-vis
other electric utilities.First, adjustment mechanisms to
account for changes in power supply costs are the rule,
rather than the except ion,so that Idaho Power PCA merely
moves its risks closer to those of other utilities.
Second,the PCA does not prevent the lag bet ween the time
Idaho Power actually incurs power supply expenses and when
it is actually recovered from ratepayers.Investors are
well aware that the significant reduction in cash flows
associated with mounting deferrals can have a debilitating
impact on a utility s financial position.
Moreover, the PCA does not apply to 100 percent of
the difference between the actual cost of purchased power
and the amount collected through rates, with Idaho Power
shareholders remaining at risk for 10 percent of any
discrepancy.Indeed, Idaho Power and its investors has
already experienced the impact that chaotic market
conditions can have when the Company is forced to rely on
wholesale purchases to meet the gap in its resource needs
AVERA, Di -Reb
Idaho Power Company
created by reduced hydro generation.Investors cannot
afford to discount the continuing prospect of further
turmoil in western power markets.Ms. Carlock's focus on
"low retail rates " entirely ignores market realities and
the substantial risks that investors must assume to provide
customers with the resulting benefits.
Did Ms. Carlock adj ust the results of her
quantitative methods to reflect flotation costs?
No.Ms. Carlock entirely failed to address
the issue of flotation costs, which, as discussed in my
direct testimony are a necessary cost incurred in
connection with raising common equity capital.When equity
is raised through the sale of common stock, there are costs
associated with "floating" the new equity securities.
Unlike debt flotation costs, which are recorded on the
books of the utility, amortized over the life of the issue,
there is no established mechanism for a utility to
recognize equity issuance costs. Unless some provision is
made to recognize these issuance costs, a utility s revenue
requirements will not fully reflect all of the costs
incurred for the use of investors' funds and investors will
not have the opportunity to earn their required rate of
AVERA, Di -Reb
Idaho Power Company
return.Because there is no accounting convention to
accumulate the flotation costs associated with equity
issues, I recommended a minimum upward adjustment to the
cost of equity of 20 basis points.
In light of the shortfalls in Ms. Carlock'
DCF approach and her failure to meaningfully address Idaho
Power's relative investment risks or the issue of flotation
costs, what is your conclusion regarding her
recommendations in this case?
In my opinion, Ms. Carlock's recommended
10.0 percent cost of equity significantly understates the
rate of return that investors require from Idaho Power.
Idaho Power plans to add significant plant investment , such
as the Mountain Home generating facility, to ensure that
the energy needs of its service territory are met.To meet
these challenges successfully and economically, it is
crucial that the Company receive adequate support for its
credit standing.Because of the shortfalls in her
analyses, Ms. Carlock's recommended cost of equity is
inadequate to meet this goal.
At the very least, the Commission should rej ect the
result of Ms. Carlock's DCF analyses, which is unreliable
AVERA, Di -Reb
Idaho Power Company
and downward biased because of its focus on a single
company - IDACORP - that has significantly cut its common
di vidends .Meanwhile, Ms. Carlock's comparable earnings
approach resulted in a cost of equity range of 10.0 to 11.
percent, with Ms. Carlock noting that, in selecting a point
estimate from within a range, "any point within (the) range
is reasonable. "Considering the ongoing risks associated
with Idaho Power's continued exposure to wholesale power
markets, a rate of return at the upper end of this range is
warranted.Combining the 11.0 percent upper end of Ms.
Carlock's comparable earnings range with a 20 basis point
minimum allowance for flotation costs results in a rate of
return on equity of 11.2 percent, which is equal to what
Idaho Power has requested in this case.
III. DENNIS E. PESEAU
How did Dr. Peseau evaluate the cost of
equity for Idaho Power?
It is important to note that Dr. Peseau'
opinions were not based on any independent analyses of the
cost of equity to Idaho Power.Rather , he arrived at his
recommendations based on a purported "update " of my
analyses by making "revisions" to my methods.
AVERA, Di -Reb
Idaho Power Company
What updates"and "modifications"did Dr.
Peseau make to your cost equity analyses?
Apart from conducting no analyses of his
own, Dr. Peseau did not actually update my analyses.
Rather, he "simply plugs in an updated figure for dividend
yieldn1O to my DCF model.Thus, Dr. Peseau' s "update"
completely ignored the other half of the constant growth
DCF equation; namely, the growth rate.To the extent that
investors' expectations for growth increase, this would
serve to offset any decline in dividend yields.Apart from
this incomplete "update", Dr. Peseau s remaining
modifications consisted of ignoring historical trends in
earnings growth in applying the DCF model, using
alternative bond yields to apply my risk premium
approaches, and substituting a lower market return in the
CAPM.Finally, Dr. Peseau completely ignored the flotation
cost adjustment supported in my direct testimony.
What was the basis for Dr. Peseau
revision" to exclude historical growth rates from his
update " of your DCF analyses?
While Dr. Peseau granted that my
methodology is not unreasonable, "11 he asserted that
AVERA, Di -Reb
Idaho Power Company
historical growth rates should be discarded because I
excluded firms rated below investment grade from my
comparable group.
Does your decision to exclude utilities with
junk bond ratings from your proxy group represent an
"implementation flaw," as Dr. Peseau asserts (p. 15)?
Absolutely not.The purpose of employing a
proxy group to estimate the cost of equity is to avoid
potential bias by focusing on firms facing comparable risks
and prospects.As I noted in my direct testimony, the
financial stress and lack of stability that accompanies
below investment grade bond ratings greatly complicates any
determination of investors' long-term expectations required
to implement the DCF model.Moreover, the move from
investment grade to junk bond ratings implies a quantum
increase in investment risks.It is hypocritical for Dr.
Peseau to assert that my proxy group is "not
representative" of electric utilities in the west, while
simultaneously arguing that firms with junk bond ratings
should be considered comparable to Idaho Power.
What about Dr. Peseau ' s contention that the
companies in your group "are not really a sample of
AVERA, Di-Reb
Idaho Power Company
electric utilities" (p. 16)?
The fact that these firms may- be engaged in
other lines of business is hardly remarkable, as the same
can be said about virtually every electric utility
operating in the U. S .Nevertheless, the fact that
investors regard these firms as electric utilities is
evidenced by the fact that The Value Line Investment Survey
Value Line") classifies them in its Electric Utility
(West) industry group.Moreover, the statistics cited by
Dr. Peseau do not convey an accurate portrayal of the
importance of utility operations to the firms in my proxy
Consider Black Hills, for example.While Dr.group.
Peseau reports that electricity sales accounted for 38
percent of total revenues, he failed to report that Black
Hills ' electric power generation and utility operations
accounted for approximately 84 percent and 65 percent of
operating earnings and total assets, respectively, for
2003.Contrary to Dr. Peseau's assertions, the firms
included in my proxy group provide a reasonable basis on
which to estimate the cost of equity for an electric
utility in the western region.
Does Dr. Peseau' s reference to earnings
AVERA, Di -Reb
Idaho Power Company
growth trends for PNM Resources ("PNM") provide any basis
to exclude historical growth rates from your DCF analysis?
No.Dr. Peseau simply notes that PNM'
earnings per share in 1987 of $2.00 are equal to what Value
Line is projecting for 2004.But this observation says
nothing about what investors might reasonably expect for
future growth based on more recent historical trends.
fact, Dr. Peseau s observation implies that investors would
anticipate zero growth, which would produce a cost of
equity for PNM equal to its dividend yield, or 3.2 percent.
Of course, this is clearly a nonsensical result that is
unrelated to a determination of investors' future
expectations.In fact, variability in historical earnings
serves to illustrate the increasing risks associated with
an investment in electric utility common stocks.But given
the unsettled conditions over the near-term direction of
the economy and the spate of challenges faced in the
electric power industry, the historical growth trends
reported by Value Line provide a meaningful benchmark in
implementing the DCF model.As a result, when assessing
investors' expectations of future growth it is entirely
appropriate to consider historical trends in earnings,
AVERA, Di -Reb
Idaho Power Company
along with securities analysts' projections, as I have
done.
Is there any basis for Dr. Peseau ' s
statement that Idaho Power's requested 11.2 percent cost of
equity is "unreasonable on its face" (p. 18)?
No.Based on changes in bond yields, Dr.
Peseau impl ies that the cost of equity for Idaho Power has
dropped "by 200 basis points or more. ,,But Dr. Peseau' s
observation is meaningless.First, he ignores the dramatic
increase in the level of risks that investors now associate
with electric utilities.As discussed in my direct
testimony, these uncertainties are heightened for a utility
operating in the western U. S., especially given Idaho
Power s ongoing exposure to potential volatility in
wholesale power markets.Moreover, as I also explained in
my direct testimony, there is considerable evidence tha~
when interest rates are relatively low, equity risk
premiums widen. Accordingly, the cost of equity does not
move in lockstep with interest rates.In fact, the only
way to assess the relative impact of changes in risks and
capital market conditions since the Commission s last
decision in 1995 is to conduct an independent analysis of
AVERA, Di-Reb
Idaho Power Company
the cost of equity - something Dr. Peseau did not even
attempt.
Is there any merit to Dr. Peseau' s
suggestion that there are inconsistencies in your risk
premium approaches that lead to an upward bias in your
results (pp. 13-14)?
No.The bond yields used in my applications
of the risk premium method were consistent with the
underlying data sources used to compute the equity risk
premiums, as well as with the investment risks
corresponding to Idaho Power's single-A grade credit
rating.In developing risk premiums based on authorized
rates of return on equity on Exhibit WEA-B, I matched the
average allowed rates of return in each year with the
average yield on public utility bonds reported by Moody
Investors Service ("Moody This composite interest
rate reflects the average risk profile of the electric
utility industry, and there is simply no basis for Dr.
Peseau s insinuation that this somehow results in upward
bias.Similarly, my analysis of realized rates of return
reported on Exhibit WEA-9 was based on a consistent set of
data, as reported by Standard & Poor's Corporation ("S&P"
AVERA, Di-Reb
Idaho Power Company
Because S&P does not publish an average public utility bond
yield, my analyses relied on the yield on single-A rated
issues as a proxy for the average risk of the industry.
Moreover, the interest rates that Dr. Peseau cites in his
update" to not correspond to other published sources.For
example, Moody s reported that the average yield on single-
A public utility bonds for February 2004 was 6.15 percent,
considerably higher than the 5. 7 percent rate cited by Dr.
Peseau.
How did Dr. peseau "update" your application
of the Capital Asset Pricing Model ("CAPM"
Dr. Peseau did not update or otherwise
address my CAPM approach.Rather, he ignored it entirely
and instead substituted a market risk premium into my
analysis that was based on an entirely different method.
As explained in my direct testimony, I applied the CAPM
based on a forward-looking estimate of the market risk
premium that relied on investors' current expectations in
the capital markets.Meanwhile, Dr. Peseau simply asserted
that " (t) he correct market risk premium to use at this
time " is 7.00 percent. In fact, however, this 7.
percent risk premium is based on historical realized
AVERA, Di-Reb
Idaho Power Company
returns, not on the forward-looking expectations that drive
investors' required rate of return in today ' ~ capital
markets.The end result of Dr. Peseau's thinly veiled
shell game is not an update or revision to my analysis, but
instead a CAPM cost of equity that fails to reflect
investors ' current required rate of return.
Did Dr. peseau consider the need to account
for past flotation costs?
No.Dr. Peseau does not take issue with my
testimony that an adjustment for flotation costs is
reasonable in establishing a fair rate of return for Idaho
Like Ms. Carlock, however, Dr. Peseau entirelyPower.
ignored the issue of flotation costs in conducting his
As discussedrevisionsn and "updates n to my analyses.
earlier and in my direct testimony, flotation costs are
legi timate and necessary, and unless an adj ustment is made
to the cost of equity, investors will not have the
opportunity to earn their fair rate of return.
I s there any meri t to Dr. Peseau ' s
contention that your characterization of conditions within
the electric utility industry is "too bleakn (p. II)?
No.It is curious that Dr. Peseau takes
AVERA, Di -Reb
Idaho Power Company
issue with my description of the challenges that investors
have confronted in the electric power industry, while
simul taneously granting that "all of these observations are
accurate enough." 16 Moreover, the simple fact that the
majority of utilities have "weathered the recent
disasters"17 says nothing about the risks that investors now
associate with the industry.As I documented in my direct
testimony, observable measures such as bond ratings clearly
illustrate the revised perceptions of the risks in the
industry and the weakened finances of the utilities
themselves.Moreover, while Dr. Peseau suggests that this
assessment just reflects a pessimistic bias on my part, my
personal opinions are irrelevant and were not the basis of
my analyses.What matters are the opinions of investors,
who, demonstrated in my direct testimony, recognize that
the risks inherent in the electric utility industry have
increased significantly.Indeed, as noted earlier, Ms.
Carlock also granted that electric utilities now face
greater uncertainties than in the past.
Does Dr. Peseau ' s reference to a single
earned rate of return (p. 11) provide any meaningful basis
to evaluate investors risk perceptions or their required
AVERA, Di-Reb
Idaho Power Company
rate of return?
No.The fact that Idaho Power'
shareholders may have earned positive returns in a single,
historical period says nothing about their forward -looking
assessment of investment risks or their return
requirements.In fact, as Dr. Peseau grants, "the previous
few years produced some negative returns. "Dr. Peseau'
observations regarding the seemingly high variability of
returns to Idaho Power s shareholders are more supportive
of my contention that the investment risks associated with
electric utilities, including Idaho Power, have increased.
Indeed, Dr. Peseau grants that the recent "boom and bust"
has "produced wildly erratic year to year results ... for
most of the utilities in the western United States. "For
investors, "wildly erratic" is synonymous with a level of
investment risk far in excess of what Dr. peseau presumes.
Does this conclude your direct rebuttal
testimony in this case?
Yes, it does.
AVERA, Di -Reb
Idaho Power Company
ENDNOTES
Carlock Direct 11.
Id.
Carlock Direct
Id.
Id.6 Carlock Direct at 8 -
Idaho Power granted $256 million deferral, but bond plan
denied, Idaho Public Utilities Commission (May 13, 2002).
8 Carlock Direct at 13.
9 Peseau Direct at 13.
10 Id.11 peseau Direct at 15.
12 Peseau Direct at 18.
13 Moody s Investors Service,
2004) .
Credi Perspectives (Mar.
Peseau Direct 14.
Id.
peseau Direct 11.
Id.
Peseau Direct 11.
Peseau Direct 16.
AVERA, Di-Reb
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O7-
IDAHO POWER COMPANY
ATTACHMENT 1-
FitchRatings
KNOW YOUR RISK
FITCH AFFIRMS IDA & IPC'S RATINGS; OUTLOOK STABLE
Fitch Ratings-New York-15 June 2007: Fitch Ratings has affmned the ratings ofIDACORP, Inc. -
and its primary subsidiary, Idaho Power Company as follows:
IDACORP:
Long-term Issuer Default Rating (!DR) at 'BBB'
Short-term Issuer Default Rating (!DR) at 'F2'
Commercial paper rating at 'F2'
Idaho Power Co.
Long-term Issuer Default Rating (!DR) at 'BBB'
Short-term Issuer Default Rating (!DR) at 'F2'
Senior secured debt rating at '
Senior unsecured debt rating affnmed at 'BBB+'
Commercial paper rating affirmed at F2.
The Rating Outlook is Stable. Approximately $1.2 billion of debt securities are affected by the
rating action.
The IDA and IPC ratings affinnation and Stable Rating Outlook reflect IPC's earnings and cash
flow prospects, the beneficial effects of the utility's power cost adjustment mechanism and a
reasonable regulatory environment in Idaho. Fitch assumes constructive rate treatment of IPC'
2007 - 2009 capital investment in utility infrastructure, normal precipitation in 2008 and 2009 and
that external funding of its relatively large capital investment program will be supplied through a
balanced mix of new debt and equity.
While the negative effects of below-normal water conditions in five of the past six years and
anticipated drought conditions in 2007 are a source of concern, the impact is partially mitigated by
the utility's power cost adjustment (PCA) mechanism. IPC's PCA mechanism passes through 90%
of net power supply costslbenefits to ratepayers, which has, and is expected to continue to, offset a
significant proportion of the negative impact of higher production costs during periods of below
normal hydrogeneration output.
The primary concern for IDA and IPC fixed income investors is potential lower earnings and cash
flow as the result of regulatory disallowance of investment in utility plant in pending and
anticipated rate proceedings andlor significant cost over-runs. A continuation of prolonged drought
conditions in the region is also a concern for investors on a secular basis. Fitch expects IDA will
reach a reasonable settlement in the company s appeal of the IRS disallowance of approximately
$45 million of tax deductions related to the capitalized cost methodology.
Contact: Philip Smyth, CFA [phone] or Robert Hornick [phone], New York.
Media Relations: Brian Bertsch, New York, Tel: [phone].
Fitch's rating definitions and the terms of use of such ratings are available on the agency s public
site
, '
www.fitchratings.com . Published ratings, criteria and methodologies are available from this
site, at all times. Fitch's code of conduct, confidentiality, conflicts of interest, affiliate fIrewall
compliance and other relevant policies and procedures are also available from the 'Code of Conduct'
section of this site.
F i tchRa ti11gS
KNOW YOUR RISK
FITCH RATES IDAHO POWER'S $140MM SECURED MTNS '
OUTLOOK STABLE
Fitch Ratings-New York-2l June 2007: Fitch Ratings has assigned an '' rating to Idaho Power
Company s (IPC) anticipated $140 million issuance of 6.30% First Mortgage Bonds (FMB) due
June 2037, secured medium term notes (MTN), series F. Proceeds from the offering will be used to
repay short-term debt and for general corporate purposes. The Rating Outlook is Stable. IPC is a
wholly-owned subsidiary of IDACORP, Inc. (IDA; issuer default rating (IDR) 'BBB'; Outlook
Stable)
Idaho Power Company s (IPC) ratings and Stable Outlook consider the earnings and cash flow
volatility associated with the company s largely hydro-based generating portfolio, the beneficial
effects of the utility's power cost adjustment (PCA) mechanism and a reasonable regulatory
environment in Idaho.
The PCA mechanism allows IPC to pass through 90% of net power supply costs/benefits to retail
ratepayers in Idaho. The effectiveness of the PCA during a string of below normal water years has
offset a significant portion of the negative impact of higher thennal production costs allowing IPC
to maintain a relatively stable financial profile. However, below nonnal winter 2006-2007 snow
pack is likely to result in reduced hydro output and lower 2007 earnings and cash flow.
The inability of IPC to recover its large projected capital investment program on a timely basis
through rates is a primary source of concern of IPC investors, along with the potential continuation
of drought conditions in the longer term.
For further information, please refer to the IDACORP, Inc. press release dated June 15, 2007, titled
Fitch Affirms IDA & IPC's Ratings; Outlook Stable' on Fitch's web site 'www.fitchratings.com
Contact: Philip Smyth, CFA + 1-212-908-0531 or Robert Hornick [phone], New York.
Media Relations: Brian Bertsch, New York, Tel: [phone].
Fitch's rating definitions and the tenns of use of such ratings are available on the agency s public
site
, '
www.fitchratings.com . Published ratings, criteria and methodologies are available from this
site, at all times. Fitch's code of conduct, confidentiality, conflicts of interest, aff11iate firewall
compliance and other relevant policies and procedures are also available from the 'Code of Conduct'
section of this site.
FitchRatings
KNOW YOUR RISK
Corporate Finance
Global Power/North America
Credit Analysis IDACORP, Inc.
Ratings
Security
Class
Long-Term IDR
Short-Term IDR
CorrmeroialPaper F2
IDR - Issuer default rating. NR - Not rated
RaUngWatch................................................ None
RBtIng ,Outlook............................................ Stable
CUrrent PrevIous DateRaUng RatIng Ch81g8d
121&Q5F2 NR 1:?J6.00
5t1 002
Analysts
Philip W. Smyth, CFA
+ 121290&-0531
phili p. sm~fitc hratings.com
Robert Hornick
+ 1 21290&-0523
robert.hornic~tchratings.com
Profile
IDA's primary subsidiary, IPC, provides
integrated electric service to more than
472,000 customers in a 24,000 square-mile
service territory in southern Idaho and eastern
Oregon. Approximately 95% of IPC's retail
utility revenue is from its Idaho service
territory. IDA's strategy is focused on the core
utility business, and it has exited several
unregulated operations in recent years, Its
remaining unregulated businesses are IFS and
Ida-West Energy. In 2006, utility operations
accounted for 99% of IDA's consolidated
revenues and all of its operating earnings.
Key Credit Strengths
Recovery of 90% of net power
supply costs through PCA.
Competitive IPC rates.
. Above-industry average utility
growth prospects.
Key Credit Concerns
Potential capital expenditure cost
over-runs and or prudence
disallowance.
Continuation of poor hydro
generation conditions in the longer
term.
July 9, 2007
Rating Rationale
IDACORP, Inc.'s (IDA) ratings and Stable Rating Outlook, which
were affnmed by Fitch Ratings on Jme 15 2007, primarily reflect the
earnings and cash flow volatility of its core operating utility subsidiary,
Idaho Power Co. (IPC, issuer default rating (!DR) 'BBB', Stable
Rating Outlook), as the result of its significant reliance on
hydrogeneration to meet its load requirements. The ratings and Stable
Rating Outlook also consider the reasonable regulatory environment in
Idaho and assume timely recovery of !pc's 2007-2009 capital
investment in utility infrastructure and normal precipitation in 2008
and 2009, following a below normal water year in 2007. In addition,
Fitch assumes that IDA will fimd its external capital investment
requirements with a balanced mix of new debt and equity.
While the negative effects of below-normal water conditions in five of
the past six years and anticipated drought conditions in 2007 are a
source of concern for IDA's core electric utility subsidiary, IPC , the
effect is partially mitigated by the utility's power cost adjustment
(PeA) mechanism. !pc's PCA mechanism passes through 90% of net
power supply costslbenefits to retail ratepayers in Idaho, which has
and is expected to continue to, offset a significant proportion of the
negative effect of higher production costs during periods of below-
normal hydrogeneration output.
Primary concerns for IDA fixed-income investors include potential
lower earnings and cash flow as the result of regulatory disallowance
of investment in utility plant in pending and anticipated rate
proceedings as well as significant cost over-runs. A continuation of
prolonged drought conditions in the region is also a concern for
investors on a secular basis. The ratings also assume a reasonable
outcome regarding the company s appeal of an Internal Revenue
Service (IRS) disallowance of $45 million of tax deductions related to
the capitalized cost methodology.
Recent Developments
Regulatory Update
On Jme 8, 2007, IPC f1led a general rate case (GRC) with the Idaho
Public Utility Commission (IPUC) seeking to increase rates
$63.9 million (10.3%) based on an 11.5% return on equity (ROE) and
a 50.3% equity ratio. The requested rate increase is needed to recover
investments in IPC's electric system to enhance reliability and meet
service tenitory growth. Since !pc's last GRC in 2005, the company
estimates that it will have placed in service an additional $300 million
in its electric system dming 2006 and 2007. Of the $300 million,
approximately $200 million was invested in transmission and
distribution (T &D) improvements, including 650 miles of new T &D
V'NNI.fitchratings.com
FitchR,ati n gs
KNOW YOUR RISK
Corporate Finance
Debt Maturity
($ Mil.
2007
2008
2009
2010
2011
Source: Company reports,
121
lines and 10 new substations. In addition, !PC
invested approximately $80 million to improve
existing power plants including environmental
protections, equipment upgrades and relicensing of
its hydroelectric projects.
Hydrogen.ratlon Conditions
The latest available snow pack data indicates snow
pack in the Snake River Basin at 45% of normal and
another below-normal year of hydro output in 2007.
Stream flows into the Brownlee Reservoir are
projected to be 2.7 million acre feet during April
through July 2007, 57% below the 6.3 million acre
feet 30-year average inflow for the April through July
period. As a result. hydro generation output is
estimated at 5.5 million-0 million megawatt-hours
(mwh), which is 15%-33% below the 8.25 million
mwh of total output produced by lPC's hydro
resources in a normal water year. All else equal
greater reliance on relatively expensive thermal and
purchase power resources result in lower earnings
and cash flows at IPC. Secular drought conditions in
southern Idaho beyond 2007 could have negative
ramifications for IDA's credit quality.
Liquidity and Debt Structure
At March 31, 2007, IDA had cash and cash
equivalents of $3.6 million. Short- and long-term
debt at the end of the fast quarter of 2007 was
$251 million and $927 million, respectively, for a
total of $1.178 billion.
IDA renegotiated its five-year corporate credit
facility, reducing its bon-owing capacity to
$100 million from $150 million. The new revolver
matures on April 25, 2012.
Maturities appear manageable, with approximately
$318 million of debt scheduled to mature during
2007-2011. See the Debt Maturity table below for
details.
Capital Expenditure Program
IDA's capital program will be driven by investmentby the core utility operations. IPC'capital
expenditures are expected to be meaningfully higher
in 2007-2009 compared to 2004-2006, reflecting the
need to replace and update aging plant while meeting
growth and reliability requirements. The remaining
nonutility operations are expected to be self-fimding.
Projected IPC 2007-2009 capital expenditures are
expected to average $282 million per annmn, a 42%
increase compared to the $199 million average
annual run rate during 2004-2006. Approximately
47% of projected 2007-2009 capital expenditures is
earmarked for T &D projects and 39% for generation
investment. accoooting for more than 86% of the
total budget
The capital program includes upgrades and
component replacement at IPC's aging hydroelectric
facilities, new high-voltage transmission and
distribution lines and a 170-megawatt (mw)
combustion turbine facility scheduled to enter
commercial operation in 2008.
The company s planned build-out is not expected to
be funded entirely with internal resources and will
likely require meaningful debt and equity issuance
over the next few years.
The effect on the IDA's credit quality will turn, in
Fitch's opinion, on the utility's ability to recover its
prospective investment in rates on a timely basis. The
inability of IPC to recover its prudently incurred
investment in rates on a timely basis could weaken
IDA's earnings, cash flows and credit quality.
Equity Issuance
In the fourth quarter of 2006, IDA issued 536 518
shares of common stock at an average price of $39.
per share (approximately $21 million). The shares
were issued ooder a sales agency agreement entered
into by the company with BNY Capital Markets, Inc.
(BNY) on Dec. 15, 2005. Factoring in dividend
reinvestment, 401K and other stock issuance plans
IDA raised approximately $41.5 million of common
stock in total during 2006 (1.2 million shares).
Proceeds from the common stock sales were used to
fimd lPC's capital expenditure program. In December
2004, IDA issued 4 million shares of common stock
raising $120 million before transaction costs.
IDACORP, Inc.
FitchR.atings
KNOW YOUR RISK
Corporate Finance
Nonutility Operations
IDA's l.U11"egulated operations consist of IDACORP
Financial Services (IPS) and Ida- West Energy.
IPS, with total assets of $132 million (4% of total
assets), is self-funding and provides tax benefits to
IDA. IPS' contribution to IDA's consolidated per
share 2006 earnings of $2., before discontinued
operations, was $0.22.
Ida-West Energy owns and operates nine small hydro
generation projects in Idaho totaling 45 mw of
capacity. Ida-West contributed $0.06 to 2006
consolidated IDA per share earnings. No further
investment in Ida-West Energy is anticipated.
IDA completed the sale of IDACORP Technologies
IDc" its fuel cell business, in the second quarter of
2006, booking a gain of $12 million after tax. In the
fll'St quarter of 2007 , IDA closed on the sale of
IDACOMM.
Rating Outlook Rationale
The Stable Rating Outlook assumes a return to
normal hydrogeneration output following
drought conditions in 2007 and continued
management focus the core utility operation. The
Stable Rating Outlook also assumes efficient
execution of its capital expenditure program and
timely recovery ofIPC's investment in rates.
What Could Lead to Positive Rating
Action?
. A prolonged period of above-normal water
conditions.
What Could Lead to Negative Rating
Action?
Lower cash flow and earnings due to cost
over-fWlS and/or disallowances related to
IPC's relatively large capital program.
Continuation of poor hydro generation
conditions in the longer teml.
IDACORP, Inc.
FitchR.atings Corporate Finance
KNOW YOUR RISK
Financial Summary - IDACORP, Inc.
($ Mil., Years Ended Dec. 31)
LTM
3/31107 2006 2006 2004 2003 2002
Fundamental Ratios (x)
Funds from Operationsllnterest Expense
Cash from Operetionsllnterest Expense
Debt/Funds from Operations
Operating EBITllnterest Expense
Operating EBITDAllnterest Expense
Debt/Operating EBITDA
Common Dividend Payout (%)48.47.79.62.139.113.
Intemal Cash/Capital Expenditures (%)32,52.57.74.165.206.
Capital Expenditures/Depreciation (%)224.4 225.4 190.198.153.146.
Profitability
Revenues 859 926 843 844 823 929
Net Revenues 557 557 520 506 501 513
O&M Expense 272 264 241 256 221 207
Operating EBITDA 263 262 256 194 182 169
Depreciation and Amortization Expense 101 100 101 101
Operating EBIT 163 163 155
Interest Expense
Net Income for Common 107 107
O&M % of Net Revenues 48.47.46.50.44.40.
Operating EBIT % of Net Revenues 29.29.29.18.4 16,14.
Cash Flow
Cash Flow from Operations 125 170 161 195 313 353
Change in Working Capital (16)(1)
Funds from Operations 140 171 153 185 256 326
Dividends (52)(51)(51)(46)(65)(70)
Capital Expenditures (226)(225)(193)(200)(150)(137)
Free Cash Flow (153)(107)(83)(51)146
Net Other Investment Cash Flow (61)(61)(2), (0)
Net Change in Debt (32)(57)(76)
Net Change in Equity (36)
Capital Structure
Short-Term Debt 156 129 176
Long-Term Debt 021 024 040 058 014 988
Total Debt 178 153 100 094 107 164
Preferred and Minority Equity
Common Equity 153 124 025 008 864 875
Total Capital 330 277 125 103 024 093
Total DebtITotal Capital (%)50.50.51,52.54.55.
Preferred and Minority EquitylTotal Capital (0/0)
Common EquitylTotal Capital (%)49.49.48.48.42.41.
L TM - Latest 12 months. Operating EBIT - Operating income before nonrecurring items. Operating EBITDA - Operating incorre before nonrecurring
Items plus depreciation and amortization experse. O&M - Operations and rrairtenarce. Note: Numbers rray not add due to rounding and are adjusted
for interest and principal payments on transition j:fOpBrty securitization certificates. Long-term debt includes trust preferred securities. Source: Rrancial
data obtained from SNL Energy Information System, provided under licerse I:1f SNL Financial, LC of Ctarlottesville, Va,
Copyright C 2007 by Fi1cl1, Inc., Fi1l:l1 Ratiog. Ltd. and;lo 01Ib0idiaDe0. ODe S1BIe Street Plaza, NY, NY 10004.
Te!ejilone: 1-800-753-4824, [phone]. FlOC [phone]. Reproduction ar retI1msIIUsaion in whole or in part is jmln1rited except by peuniAion. All rightB ""erved. All of1he
infomullion co11IBiDed heroin is booed CI1 infarmation obtained fum ioooen, o1her obligors, underwri1sn, BOd other ooorces whioh Fitch believes to be reliable. F'1Id1 does JWt oodil ar veriJY the
truth er occmacy of my ond1 infoanation. M a reml~ the infmmlllion in tbiJ roport is provided ..", isft without anyreplellentBlion ar wmanty of any kind. A Fitdt m1ing is m opDrion .. 10 1he
creditwortbin... ofasecmity. ThonIiDg doe8 notaddlOll81herilkoflOl8 due '" riob other1han creditriok, unl....uchriokis opeciIical1ymmlioned. Fitch is nol eJJgBgOdin tho olferoroa1e
any security. A roport ~dirJg a Fib:h m1ing is neither a prospectno ncr a oubotimm for the infcomation -....bled, verified muI preoenIed to iIMatoro by 1he iB8IIer md;lo &genlo in amnedion
with the oa1e of the oecurities. Ratingo may be changed, ousponded, ar withdrawn at anytime far my reooon in the sole _on of F'rtdL Fib:h does not prcMde investment advice of lilY oar!.
RaIiogo "",notarocommenda1ion to buy, oeD, or hold any security. RaIinp do DOlcanment on tho adequacy ofDllllutprice, the mitabiJityofanyoecmity far a psrticolar investor. ar1he1Bx-
exempt nature er taxa1ility of
~-
mode in '" any .ecarity. H1I:I1 receiveo Ieeo Iian ioooen, in8omB, gomardoro, olber oliigon, and undenvritm far m1ing oecoritieo. Such Mo
gemnlly VIIIY Iian USSI OOO '" USS750 OOO (ar 1he applicable cmrmcy equivalent) per iowe. In certain coo... F'1Id1 willmte all ar a number ofimleo io&ued by a particnlar ioouer, ar inoured
ar guomnteed by a particular inomur er gaarantcr, fer a oiDgle IIIIIIDII1 fee. Such
"'" "'"
to VIIIY from USSIO OOO '" USSI,sOO,OOO (ar 1he appicable cmrau:y equivalent). The
..oignmart, pnliicotion, or diooemination of a mting by Fitch ohaIl not COII81iIo12 by F'1Id1 '" uoe i1o name .. m eotperI in ~CI1 any fe!!iBtmtion otaI:ement filod 1II1der the
United S1Bteo ......me. laW1J, 1he Financial Servi... and Marketo Act of 2000 of Oreal Britain, or 1he securiti.. I..... of any particuIBr joriodiction. Doe '" 1he nIlative efficimcy of electronic
publiohing muI diotribulion, Fitch reoearch mIY be available to elec1lonic oubocriben up '" three days earlier 1han '" print onbsaiben.
IDACORP, Inc.
I STAND,ARD. 0 P IrSlJl IRATINGSDIRECT
RESEARCH
\..
lmmary: IDACORP Inc.
08-Feb-2006
Swami Venkataraman, CFA, San Francisco (1) 415-371-5071;
swam i - ven katara man em sta n dardand poors. co m
Michael Scheider, San Francisco 415-371-5013;
michael- scholderemstandarda ndpoors. co m
Publication date:
Primary Credit Analyst:
Secondary Credit Analyst:
Credit Rating:BBB+/Stable/A-
Rationale
The credit quality of IDACORP Inc. is based on the consolidated credit quality of IDACORP and its
subsidiaries, primarily Idaho Power Co. Small, unregulated operations, such as the IDATECH fuel cell
business and the IDACOMM communications business, do not have a material impact on Idaho Power
credit quality.
The ratings reflect the stability provided by:
. A generally supportive state regulatory regime
. A strong power cost adjustment (PCA) mechanism
. An efficient, low-cost generating fleet, and
. The absence of material, unregulated businesses.
e strengths are tempered by:
Significant exposure to hydrological variations on the Snake River and poor water flows in the past
six years that have reduced hydroelectric production and increased deferred power costs, and
. More than $500 million in capital expenditure requirements primarily for new generation and hydro
relicensing in the next two years.
The PCA mechanism allows Idaho Power to set annual power costs and then pass through to customers
90% of the cost that exceeds that planned power costs level. Also, resource planning rules allow the
company to use 70th percentile water and load levels for planning, rather than a median level approach
that was applied previously. So water and load conditions could, on a probability basis, be worse than
expected only 30% of the time , rather than 50%.
In an average year, hydroelectric resources provide about 56% of total generation needs, significantly
exposing Idaho Power to water flow variations. Following the western U.S. power crisis, Idaho Power
financial recovery was hampered by the drought that adversely impacted stream flows in the Snake River
for six consecutive years , substantially reducing low-cost hydroelectric generation, and requiring
purchases of more expensive replacement power. As a result, deferred revenues have not been
eliminated since the power crisis. Although 90% of the Idaho jurisdiction costs are recovered through the
PCA, these higher costs and the high current gas price environment may contribute a to reluctance on the
part of the Idaho Public Utilities Commission to raise rates as may be requested in its latest rate case
where Idaho Power is seeking a 7.8% general rate increase.
The latest information for Idaho Power s hydroelectric generation watershed appears favorable. Early
reports indicate that this is not a drought year and the anticipated water-flows may help to start refilling the
reservoirs in 2006.
Inl~lovement in its financial profile is essential for the utility to maintain its rating. The benefits of its
December 2004 equity issue were expected to be realized in 2005 and onwards, with funds from
operations coverage of interest and debt expected to improve to about 4.0x and 18.5%, respectively.
However, for the rolling 12-month period ended Sept. 30, 2005, IDACORP's funds from operations
coverage of interest and debt were only 3.2x and 13., respectively, Those ratios are weak for the
BBB+' rating. Further, IDACORP has more than $500 million in capital requirements in the next two years
for which siqnificant external fundinQ wililikeiv be required,
The potential impact on Idaho Power of the IRS' new uniform capitalization rules for Internal Revenue
Code s!Jction 263A poses additional financial risk. The previous interpretation had enabled Idaho Power to
, reduce its tax liability by about $60 million for the fiscals 2002-2004.
S.....,rt-term credit factors
2' rating on its short-term debt reflects the consolidated short-term credit quality at IDACORP and
incorporates adequate liquidity, moderate need to access external capital to fund capital expenditure
requirements, and the expectation for Idaho Power to continue to generate stable cash flow.
The PCA mechanism in Idaho, as well as the integrated resource plan that allows Idaho Power to make
forecasts based on 70th percentile load and water levels rather than average conditions, as was the policy
in 2000 and 2001 significantly mitigate the risks that price spikes could result in another build-up
deferred power costs and deplete liquidity. The 90-MW peaking plant built in 2001 and the new gas-fired,
simple cycle plant also contribute to decrease exposure to wholesale power prices and mitigate short-term
risks.
The consolidated liquidity position is adequate, In March 2004 IDACORP replaced a $175 million, one-
year revolver and a $140 million , three-year revolver with a single $150 million, five-year facility, reflecting
the lower liquidity requirements at IDACORP following its exit from energy trading. Idaho Power also
replaced its $200 million , one-year credit facility with a five-year facility of equal amount in March 2004.
IDACORP's cash on hand as of Sept. 30, 2005 totaled $13.3 million. Debt maturities are moderate at $81
million in 2006 and 2007, IDACORP has more than $500 million in capital requirements in the next two
years, forwhich significant external funding will likely be required,
Outlook
The stable outlook reflects Standard & Poor s expectation for stable cash generation from the utility and
the absence of any significant unregulated businesses. However, continued poor hydro conditions have
prevented IDACORP from achieving financial ratios consistent with benchmarks for the 'BBB+' rating. A
substantial debt financed capital expenditure program and the risks posed by the IRS ruling could pose a
thro::lt to IDACORP's rating or outlook over the near term, especially if general rate case revenues come in
. than expected. Upside potential is limited at this time since the length of the drought has significantly
depleted storage reservoirs; however, a return to average water conditions for a few successive years
would increase margins from wholesale sales, expedite deferred cost recovery, and lay the foundation for
a stronger financial profile.
Analytic services provided by Standard & Poor s Ratings Services (Ratings Services) are the result of separate activities
designed to preserve the independence and objectivity of ratings opinions. The credit ratings and observations contained herein
are solely statements of opinion and not statements of fact or recommendations to purchase, hold , or sell any securities or make
any other investment decisions. Accordingly, any user of the information contained herein should not rely on any credit rating or
other opinion contained herein in making any investment decision. Ratings are based on information received by Ratings
Services. Other divisions of Standard & Poor s may have information that is not available to Ratings Services. Standard & Poor
has established policies and procedures to maintain the confidentiality of non-public information received during the ratings
process.
Ratings Services receives compensation for its ratings. Such compensation is normally paid either by the issuers of such
securities or third parties participating in marketing the securities. While Standard & Poor s reserves the right to disseminate the
rating, it receives no payment for doing so, except for subscriptions to its publications. Additional information about our ratings
fees is available at www.standardandpoors.com/usratingsfees.
Copyright ~ 1994-2006 Standard & Poor , a division of The McGraw-Hili Companies.
All Rights Reserved. Privacy Notice
/;:.j;;
TheMcGraw'H1UJmpan~ ,;;ii..~'
, "'~ .
STANDARD
&POOR'S I RATtNGSDIRECT
RESEARCH
Research Update: IDACORP , Subsidiary Idaho Power
Co. Rating Outlook Revised To Negative; '888+' CCR
Affirmed
Publication date:
Primary Credit Analyst:
27-Mar-2006
Michael Scholder, San Francisco 415-371-5013;
michael scholder(1i2standardandpoors.com
Credit Rating: BBB+/Negative/A-
Rationale
On March 27 , 2006, Standard & Poor s revised its rating outlook to
negative from stable on IDACORP and its primary subsidiary, Idaho PowerCo. (IPC). Additionally, Standard & Poor s affirmed its 'BBB+' corporate
credit ratings on IDACORP and IPC, and its '' rating on IPC's seniorsecured' debt. Additionally, IDACORP and IPC '' BBB I senior unsecured debt
rating and I A-2' CP rating debt were affirmed.
The ' BBB+' rating reflects the stability provided by a generally
supportive regulatory regime in Idaho, a strong power cost adjustment
(PCA) mechanism, an efficient, low-cost generating fleet, and the absence
of significant unregulated businesses. Offsetting factors include
significant exposure to hydrological variations in the Snake River and
substantial upcoming capital expenditures for new generation and hydrorelicensing.
IPC filed a general rate case in October 2005, requesting the Idaho
Public Utili ties Commission (I PUC) to approve an annual increase to its
Idaho retail base rates of $44 million, although actual results subsequent
developments lowered the revenue requirement significantly. In late
February 2006, the IPC, the IPUC staff, and representatives of customer
groups filed a proposed stipulation with the IPUC that, if approved, they
would settle this case. The stipulation calls for an $18.1 millionincrease, or 3.2%, in IPC' s annual electric rates. The financial
projections include the impact of this proposed settlement.After a six-year drought, the 2006 precipitation into IPC' s
hydroelectric generation watershed appeared to provide the opportunity for
significant excess generation. However, the Idaho House of Representatives
voted for legislation, House Bill 800, which would allow the state to take
some water from the Snake River available to generate power and instead
recharge an eastern Idaho aquifer, which has been depleted through drought
and groundwater pumping. The measure has gone to the Senate. An estimate
by IPC sets the potential worst-case financial impact of such water
diversion to ratepayers at $120 million per year. Although compensation
for diverted water through the PCA mechanism is likely, IPC would likely
have to pursue a general rate case increase to cover the deficiency, i. e. ,
the 10% ($12 million) not covered by the PCA. The passage of the measure
could also have negative long-term implications for IPC' s water rights.
IPC filed a general rate case in October 2005, requesting the IPUC to
approve an annual increase to its Idaho retail base rates of $44 million,
al though actual results lowered the revenue requirement significantly. In
late February 2006, the IPC, the IPUC staff, and representatives of
customer groups filed a proposed stipulation with the IPUC that, if
approved, they would settle this case. The stipulation calls for an $18.million increase, or 3.2%, in IPC' s annual electric rates. The financial
proj ections include the impact of this proposed settlement.
New IRS guidance on Internal Revenue Code Section 263A uniform
capitalization rules has created the potential for a full or partial
return of previous tax benefits from many electric utili ties. For its
fiscals 2002 through 2004, the simplified service cost (SSC) method
decreased IPC I S income tax expense by approximately $ 60 million and
resulted in cash refunds from federal and state tax authorities of
approximately $75 million. Because these previous tax savings benefited
the ratepayers, it is expected that the ratepayers would absorb the costs
of any adverse tax determinations. However, to the extent that any adverse
tax costs are not allocated to the ratepayers, the IPC could be negatively
impacted.
Finally, IDACORP expects to receive $10.25 million from a recentsettlement with California utili ties, state agencies, and FERC enforcement
staff, although the pending settlement calls for IDACORP to forgo $24.
million in unpaid receivables from California spot markets during
2000-200l.
IPC's service territory exhibits good economic characteristics
overall and IPC achieved a record for annual general business customer
growth in 2005 with a gain of 16,737 customers, which represents a 3.
increase year-over-year. IPC served this load with 3,004 MW including 17
hydroelectric plants with a total nameplate capacity of 1,731 MW,coal-fired generation of 1,023 MW, a 90-MW gas-fired peaking resource, and
its new 160-MW gas-fired generating plant. In a median year, hydroelectric
sources are expected to deliver about 55% of total generation needs,
thereby exposing IPC to substantial volumetric and replacement power price
risk in the event of adverse water flows.
The PCA mechanism allows IPC to set annual power costs and then pass
through 90% of the cost that exceeds this amount, together with interest,
to its customers. It also requires refunds when costs are below forecasts.
Resource planning rules allow the company to use 70th percentile water and
load levels for planning, rather than a median level approach. This means
that, on average, only 30% of the time the water and load conditions will
be worse than planned, rather than 50%.
IDACORP's financial profile has improved since the power crisis,
aided by the IPUC' s decision to let IPC recover all its deferred energy
costs in slightly more than a year. However, a combination of factors
delayed full financial recovery. The drought in the Snake River area,
which continued for the six consecutive years, raised costs for customers
by depressing hydro output and slowing collection of deferred revenues
(leaving a balance $43.5 million for Idaho and Oregon customers as of Dec.
31, 2005). For 2005, IDACORP realized weaker financial ratios, adjusted
funds from operations (FFO) coverage of interest of 2. 8x, FFO coverage of
average total debt of about 12%, and debt to total capitalization at 55%.
The drought has finally abated in 2006 and $28 million of deferrals
in Idaho are planned for recovery during the 2006-2007 PCA rate year.
Gi ven the proposed new rate settlement and upcoming capital expenditures,
Standard & Poor s expects IDACORP to achieve adj usted funds fromoperations (FFO) coverage of interest of 3. 8x on a three-year average
annual basis. While this FFO coverage of interest is consistent with the
BBB+ I rating, the FFO coverage of average total debt and debt to total
capitalization are expected to be somewhat weak at about 17% and moderate
at 56%, respectively.
Short-Term Credit Factors
IDACORP's short-term rating is '2 " reflecting adequate liquidity,
a moderate need to access external capital to fund capital
expenditure requirements, and the expectation for IPC to continue to
generate stable cash flow.
IDACORP's liquidity position is adequate. In May 2005, IDACORP
replaced a $150 million facility scheduled to expire on March 2007
with a $150 million, five-year credit agreement. Also, in May 2005,
IPC replaced a $200 million credit agreement ending in March 2007
with a $200 million, five-year credit facility. Both of the credit
facilities expire on March 31, 2010. Debt maturities are moderate at$16.6 million in 2006 and $95.2 million in 2007. However , IPC has
more than $720 million in capital requirements in the next three
years, for which moderate external fundinq will be required.
Outlook
IDACORP's 2005 results were slightly weaker than forecast and several
recent developments could strain its prospective financial ratios to
levels that are not sufficient to support the current rating. The negative
outlook reflects the potential for weakened financial metrics as a result
of several factors, including possible passage of the water diversion
legislation and uncertainty regarding the final federal and state tax
treatment and allocation of previous refunds of about $75 million. A
further but less substantial concern is the cost uncertainty for the
relicensing of the 1, 167-MW Hells Canyon Complex, which IPC is operating
under annual license renewals after the expiration of the proj ect '
license in 2005.
A downward rating action could occur if IPC is unable to achieve its
projected financial metrics. Possible cost pressures include the inability
to recover, or a significant delay in the recovery of, substantial costs
arising from the passage of Idaho House Bill 800 or other similar water
diversion legislation, a substantial tax liability from the prior SSC
method related cash tax refunds, or other negative circumstances.
A return to rating stability will depend on the restoration of
adequate financial performance, sufficient rate adj ustments with modest
reliance on power cost deferrals and financial exposure, related to any
water diversion legislation or changes in the tax treatment of the prior
SSC method related tax benefits.
Ratings List
IDACORP
Corporate Credit Rating BBB+/Negative/A-Senior Unsecured Debt BBB
Commercial Paper A-
From
BBB+/Stable/A-2
Idaho Power Corp.
CCR
Senior Secured Debt
Senior Unsecured Debt
BBB+/Negative/A-
BBB
BBB+ / Stable/A-
Complete ratings information is available to subscribers of RatingsDirect,
Standard & Poor s Web-based credit analysis system, at
www.ratingsdirect. com. All ratings affected by this rating action can be
found on Standard & Poor s public Web site at www. standardandpoors. com;
under Credit Ratings in the left navigation bar, select Find a Rating,
then Credit Ratings Search.
Analytic services provided by Standard & Poor's Ratings Services (Ratings Services) are the result of separate activities
designed to preserve the independence and objectivity of ratings opinions. The credit ratings and observations contained herein
are solely statements of opinion and not statements of fact or recommendations to purchase, hold, or sell any securities or make
any other investment decisions. Accordingly, any user of the information contained herein should not rely on any credit rating or
other opinion contained herein in making any investment decision. Ratings are based on information received by Ratings
Services. Other divisions of Standard & Poor's may have information that is not available to Ratings Services. Standard & Poor's
has established policies and procedures to maintain the confidentiality of non-public information received during the ratings -
process.
Ratings Services receives compensation for its ratings. Such compensation is normally paid either by the issuers of such
securities or third parties participating in marketing the securities. While Standard & Poor's reserves the right to disseminate the
rating, it receives no payment for doing so, except for subscriptions to its publications. Additional information about our ratings
fees is available at www.standardandpoors.com/usratingsfees.
(31-Mar-2006) BULLETIN: Defeat Of Water Rights Bill Favorable But Credit Neutral T...Page I of
I S
TAN
POQR'S
I RATINGS DIRECT
RESEARCH
BULLETIN: Defeat Of Water Rights Bill Favorable But
Credit Neutral To IDACORP, IPC
Publication date:
Primary Credit Analyst:
Secondary Credit Analyst:
31-Mar-2006
Michael Scholder, San Francisco 415-371-5013;
michael- scholder~standardandpoors.com
Swami Venkataraman, CFA, San Francisco (1) 415-371-5071;
swamL venkataraman~standardandpoors.com
SAN FRANCISCO (Standard & Poor s) March 31, 2006--Standard & Poor s Ratings
Services said today that its ratings on IDACORP and Idaho Power Co. (IPC)
remain unchanged after the Idaho Senate voted yesterday to stop a bill that
would have allowed the state to take some water from the Snake River available
to IPC for power generation and instead recharge a depleted eastern Idaho
aquifer. IPC had estimated the potential worst-case financial impact of such
water diversion to ratepayers at $120 million per year with 90% of IPC's costs
recoverable through its power cost adjustment mechanism. The passage of the
measure could also have had negative long-term implications for IPC' s waterrights.
This legislation and other factors had led to a rating outlook change to
negative from stable on March 27, 2006. While the defeat of the legislation
removes a significant near-term credit concern for IDACORP and IPC, the
outlook remains negative due to other factors, including a
weaker-than-expected financial profile and an unresolved outcome for
approximately $75 million in cash refunds from federal and state tax
authorities from the simplified service cost method that is now disallowed.
Analytic services provided by Standard & Poor's Ratings Services (Ratings Services) are the result of separate activities
designed to preserve the independence and objectivity of ratings opinions. The credit ratings and observations contained herein
are solely statements of opinion and not statements of fact or recommendations to purchase, hold, or sell any securities or make
any other investment decisions. Accordingly, any user of the information contained herein should not rely on any credit rating or
other opinion contained herein in making any investment decision. Ratings are based on information received by Ratings
Services. Other divisions of Standard & Poor's may have information that is not available to Ratings Services, Standard & Poor's
has established policies and procedures to maintain the confidentiality of non-public information received during the ratings
process.
Ratings Services receives compensation for its ratings. Such compensation is normally paid either by the issuers of such
securities or third parties participating in marketing the securities. While Standard & Poor's reserves the right to disseminate the
rating, it receives no payment for doing so, except for subscriptions to its publications. Additional information about our ratings
fees is available at www.standardandpoors.com/usratingsfees.
Copyright (g 1994-2006 Standard & Poor s, a division of The McGraw-Hili Companies.
All Rights Reserved. Privacy Notice
httn'//UTUTUr Tl'lt;no~iI;TP.C'.t C'.oml Anm:/RD/controllerl Artic1e?id=501317&tvue=&oumutTVDe=
...
4/2/2006
RESEARCH
Bulletin:
Extended Heat Wave Unlikely To Affect Idacorp And
Idaho Power s Credit Ratings
Publication date:
Primary Credit Analyst:
18-Jul-2007
Antonio Bettinelli, San Francisco (1) 415-371-5067;
antonio - bettinell i(g)standardand poors.com
SAN FRANCISCO (Standard & Poor s) July 18, 2007--Standard & Poor s Ratings
Services said today that while the ongoing heat wave and record breaking
temperatures in Idaho, which have led to all-time high demands for electricity
and an increased reliance on more-expensive imported electricity, represents a
credit risk, it does not expect these events to trigger a rating change for
Idacorp (BBB+/Negative/A-2) or Idaho Power Co. (BBB+/Negative/A-2).
Unanticipated wholesale purchases are not included in baseline rates that the
utility charges but are usually collected the following year, subject to a
sharing mechanism. However, the company bears the power costs as it awaits
customer collections, representing a near-term liquidity risk and temporary
weakening of financial metrics-
Standard & Poor I s anticipates that 90% of unexpected power costs will be
passed through the companies ' power cost adjustment mechanism. Through this
mechanism, an annual rate increase or decrease is filed each year to true-up
actual power costs with revenues collected. The company s ability to pass
unanticipated power costs through to customers mitigates the impact on its
long-term financial performance - The current deferral balance of approximately
$40 million may increase or decrease by year end-
Idaho Power set a new system record last Friday when usage reached 3,193
megawatts at about 4 p.m., marking the third power usage record this month.
Records are typically set in July as air conditioning usage coincides with
irrigation demand. At times, up to 33% of the energy was acquired throughoff-system purchases -- more than would have been purchased if poor
hydrological conditions were not hampering the company s baseload capacity-
Analytic services provided by Standard & Poors Ratings Services (Ratings Services) are the result of separate activities
designed to preserve the independence and objectivity of ratings opinions. The credit ratings and observations contained herein
are solely statements of opinion and not statements of fact or recommendations to purchase, hold, or sell any securities or make
any other investment decisions. Accordingly, any user of the information contained herein should not rely on any credit rating or
other opinion contained herein in making any Investment decision. Ratings are based on information received by Ratings
Services, Other divisions of Standard & Poor's may have information that is not available to Ratings Services. Standard & Poor's
has established policies and procedures to maintain the confidentiality of non-public information received during the ratings
process.
Ratings Services receives compensation for its ratings- Such compensation is normally paid either by the issuers of such
securities or third parties participating in marketing the securities. While Standard & Poor s reserves the right to disseminate the
rating, it receives no payment for doing so, except for subscriptions to its publications. Additional information about our ratings
fees is available at www.standardandpoors.com/usratingsfees.
Copyright ~ 2007 Standard & Poor s, a division of The McGraw-Hili Companies. All
Rights Reserved. Privacy Notice 11re McGraw-Hili \i*I~'
Idaho Power Co.
Credit Rating:
BBB+/NegativclA-
The 'BBB+' coIpOI3.te credit rnting on Idaho Power Co. (IPC) is based on its satisfactory business profile
5' on a 10-point scale , where '1' is excellent) and an intermediate financial risk profile. Additionally,
IPC' s senior secured debt is rnted 'A,.' while the senior unsecured debt is rnted 'BBB'
Primaty CretDI Analysts.
Michael Scholder
San Francisco
415-371-5013
michael scholder(1!)
standardandpoors.com
Secondary Credit Analysts.
Swami Venkataraman CFA
San Francisco
(1) 415-371-5071
swamLvenkataraman(1!)
standardandpoors.com
The rntings on IDACORP and subsidiaxy IPC are based on its vertically integrated electric utility
ope~tions in Idaho and an improving financial profile. The 'BBB+' rnting reflects the stability provided
by a generally supportive regulatory regime in Idaho, a strong power cost adjustment (PeA) mechanism,
an efficient, low.cost genernting fleet, and the absence of significant unregulated businesses, Offsetting
factors include significant exposure to hydrological variations in the Snake River and substantial
upcoming capital expenditures for new generntion and hydro relicensing.
RatingsDirect
PIAI/ication Date
Jan. 9, 2007
IDACORP Inc.'s financial rntios continue to improve to levels conunensurnte with its 'BBB+' rnting
primarily due to the financial results for its primary subsidiaxy, IPC, following the regional drought' s
end. Power sales revenues increased along with opernting income, the latter by almost 30% in the first
nine months of 2006 versus 2005 results. Also, IDACORP continued to divest unprofitable, non.core
assets, agreeing to sell IDACOMM to American Fiber Systems, Inc. No significant financial impact is
expected from the closing of that tJ:ansaction.
Some unresolved issues that could pressure the rnting include the ultimate treatment of the
disallowed tax accounting methodology, the potential reduction in water rights from aquifer recharging
negatively effecting hydroelectric generation, and possible adverse customer late changes from the
application of benefits accounting rules.
For its fiscal ~rs 2002 through 2004, the simplified service cost (SSC) capitalization method
decreased IPC' s income tax expense by approximately $60 million and resulted in cash refunds from
federal and state tax authorities of approximately $75 million. The Internal Revenue SeIVice (IRS) began
a routine examination ofIDACORP'staxretums for 2001-2003 in March 2005.
ldalw Power Co.
In August 2005, the IRS and the T reasUlY Department issued guidance inteIpreting the meaning of "routine-
and repetitive" for putpOses of the SSC and simplified production methods, effectively disallowing th~ sSC as
previously utilized by many utilities. In October 2006, the IRS issued its report and assessment for lOACO RP'
200 1-2003 tax )'ears resulting in a federal tax assessment of $45 million. lOACO RP disagreed with this
conclusion and plans to appeal the issue. Since these previous tax savings benefited the ratepa~rs, it is expected
that the ratepayers would absorb the costs of any final adverse tax determinations, However, to the extent that any
adverse tax costs are not allocated to the ratepa~rs, then !PC could be negatively affected.
Another rating consideration is the effort to divert from the Snake River water available for power generation
in order to recharge an eastern Idaho aquifer depleted through drought and groundwater pumping. IPC and the
state of Idaho entered into a stipulation agreement in which IPC and the state recognized that IPC's water rights
are subordinate to these water right permits. IPC cannot calculate the financial impact of the stipulation
agreement on !PC and its customers until recharge programs under the two water pennits are established. IPC
estimated that the potential maximum impact in a median water vmr could be about $30 million. Although
compensation for diverted water through the PCA mechanism is likdy, !PC would then have to pursue a general
rate case increase to cover the 10% not covered by the PCA.
Further, there could be adverse consequences from the application of benefits accounting rules. lOACORP is
required to recognize the funded status of its defined benefit postretirement plan and to provide the required
disclosures in its Dec. 31, 2006, financial statements. The provisions of Statement of Financial Accounting
Standards (S FAS) No. 158 will increase lOACO RP' s and IPC's liabilities and reduce each company s common
equity when adopted in the fourth quarter of 2006. Since their plans' benefit obligations exceeded the plans
assets, SFAS 158 reduced their equity by $80 million as ofJan. 1, 2006. An equity reduction could in turn
decrease their customer rates since IPC's conunon equity balance is a component in the determination of retail
rates. !PC expects to pursue special ratemaking treatment to offset any adverse rate impact,
The previous drought in the Snake River area, which continued for six consecutive vmrs, raised costs for
customers by depressing h)dro output and slowing collection of deferred revenues. For 2005, on a consolidated
basis with its parent, IDACORP, IPC realized weaker financial ratios, adjusted funds from operations (FFO)
coverage of interest of 2.8x, FFO coverage of ave~ total debt of about 12%, and debt to total capitalization at
55%.
The drought finally abated in 2006 and $28 million of deferrals in Idaho are planned for recovery during the
2006-2007 PCA rate~. Some financial metrics stabilized or improved in the 12-month period ending Sept. 30
2006. The adjusted FFO coverage of interest improved to 3x, while FFO coverage of average total debt slide to
11% with debt to total capitalization rising slightly to 56%.
liquidity
lOACORP's liquidity is satisfactory, with $8.4 million in cash and a $150 million revolver plus a $200 million
revolver at Idaho Power, neither with any draws, offset by $32 million of conunercial paper outstanding as of
Sept. 30, 2006. The $150 million, five~ credit agreement in place at IDACORP and a $200 million, five-)'ear
credit facility at IPC, both mature in March 2010.
Outlook
The negative outlook reflects the potential for weakened financial metrics as a result of several factors, including
the effects of any recharge programs under the stipulation agreement until they are clarified, uncertainty regarding
Standard Poor I ANALYSJS
Idaho Power Co.
the final federnl and state tax treatment and allocation of previous refunds of about $ 7 5 million, and reductions
in customer rates due to the pension accounting rules.
A downward rating action could occur if I.PC is unable to achieve its projected financial metrics. Conversely, an
oudook or a rating improvement will depend on the restoration of adequate financial performance, sufficient rate
adjustments with modest reliance on power cost defenals, and minimal or no ultimate financial consequences
from the aquifer recharge program or other new or existing issues
www.standardandpoors.com
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 S€lVices: (1) 212-4311-7280. Cop)fight 2007 by The McGraw-Hili Companies, Inc.
RelJ'oWctIon in whole or in part 1J'0hibited except by permission. All IighlS reserved. InFormation has been obtained by Standard & Poors from SlUces
believed to be reliable. Ho_, becaJse of the possibility of tIm1an or mechanical error by 011' sa.rces. Standard & Poors or others, Sta1dard & Poor
does notgU1l'antee the accuracy, adequacy, or completeness of any inFormation and is not responsible for any errors a omissiofE or tl1e result obtained
From the use of such inFormation. Ratings are statements of opinion, not statements of Fact a rerommendations to buy, hold, or sell any setll"ities.
Standard & Poor's uses billing and contact data collected from subscribers For billing and order fulfillment pl6pOSe5, and occasionally to inFam subscribers
about fIOWcts or services from Standard & Poa's. 011' parent. The McQaw-Hili Companies. and reputable third parties that may be of interest to them. All
subscriber billing and contact data collected is stored in a setlJ'e database in the U.S. and aa:ess is limited to authorized persons. IF you would prefer not to
have ytU inFormation used as outlined in tl1is notice, iF you wish to review yOII' inFmnation For accuracy, or for more information on 0lI' lJ'ivacy lJ'actices,
please call us at (1) 212.4311-7280 or vvrite us at lJ'ivacy\!!'standardandpoors.com. For more information about The McQaw-Hili Companies Privacy Policy
please visit www.mcgraw-hill.comIprivacy.html.
Analytic services provided by Standard & Poor s Ratings Services ("Ratings Services ) are the result of separate activities designed to
preserve the independence and ol1jectivity of ratings opinions. Credit ratings issued by Ratings Services are solely statements of opinion
and not statements of fact or recommendations to purchase, hold, or sell any securities or make any other investment decisions.
Accordingly, any user of aedit ratings issued by Ratings Services should not rely on any such ratings or other opinion issued by Ratings
Services in making any investment decision. Ratings are based on information received by Ratings Services, Other divisions of Standard
& Poor s may have information that is not available to Ratings Services. Standard & Poors has established policies and procedures to
maintain the confidentiality of non-public information received during the ratings process.
Ratings Services receives compensation for its ratings. Such compensation is normally paid either by the issuers of such 5eClJ'ities or by
the underwriters participating in the distribution thereof. The fees generally vary from US$2,OOO to over US$l,500,OOO. While Standard
& Poors reserves the right to disseminate the rating, it receives no payment for doing so, except for subscriptions to its publications,
Permissions: To reprint. translate, or quote Standard & Poors publications, contact: Client Services, 55 Water Street, New York, NY
10041; (1) 212-438,9823; or by e-maii to: research request~standardandpoors.com.
The McGraw'HiII (ompan~'XWl~'
RESEARCH
IDACORP Inc.
Publication date:
Primary Credit Analyst:
Secondary Credit Analyst:
11-May-2007
Antonio Bettinelli, San Francisco (1) 415-371-5067;
anton io - bettinelli(!j) standardand poors.com
Masako Kuwahara, New York (1) 212-438-7916;
masako - kuwah ara(g) stan d ard and poors . co
Major Rating Factors
Strengths;
. A generally supportive state regulatory regime;
. A strong power cost adjustment (PCA) mechanism;
. An efficient, low-cost generating fleet; and
. The absence of material, unregulated businesses.
Corporate Credit Rating
BBB+/Negative/A-
Weaknesses;
Significant exposure to hydrological variations on the Snake River and poor water flows in the past
six years that have reduced hydroelectric production and deferred power costs recovery, and
. More than $820 million in capital expenditure requirements for IPC based on the companies
Integrated Resource Plan (IRP) primarily for new generation and delivery in the next three years.
Rationale
Standard & Poor s Ratings Services affirmed the corporate credit ratings on IDACORP and its primary
subsidiary, IPC, at 'BBB+. The rating on the senior secured debt at IPC is affirmed at '' and on senior
unsecured debt at IDACORP and IPC is affirmed at 'BBB'. The CP rating at both companies is affirmed at
. Based on recent developments, the outlook on all ratings is negative.
The 'BBB+' rating reflects the stability provided by a generally supportive regulatory regime in Idaho; a
strong PCA mechanism; an efficient, low-cost generating fleet; and the absence of significant unregulated
businesses. Offsetting factors include significant exposure to hydrological variations in the Snake River
and substantial upcoming capital expenditures for new generation and hydro relicensing, The PCA
mechanism allows IPC to set annual power costs and then pass 90% of the cost that exceeds this amount,
together with interest, to its customers. It also requires refunds when costs are below forecasts. Resource
planning rules allow the company to use 70th percentile water and load levels for planning, rather than a
median level approach. This means that, on average, only 30% of the time the water and load conditions
will be worse than planned, rather than 50%. Idaho Power's business risk profile score is '5' (satisfactory).
(Utility business risk profiles are categorized from '1' (excellent) to '10' (vulnerable)).
IPC's service territory exhibits good economic characteristics overall. IPC achieved a record for annual
general business customer growth in 2006 with a gain of 16,149 customers, which represents a 3.
increase year-over-year. The peak summer demand in 2006 was 3,084 MW while the peak winter demand
was2 318MW.
IPC served this load with 3,085 MW, substantially by using its own generation capacity, including 17
hydroelectric plants on the Snake River and its tributaries with a total nameplate capacity of 1 707 MW.
The company also owns 1 110 MW of coal-fired generation; a 90 MW gas-fired peaking resource; and its
new $61 million, 160 MW gas-fired generating plant In a median year, hydroelectric sources are expected
to deliver about 55% of total generation needs, thereby exposing IPC to substantial volumetric and
replacement power price risk in the event of adverse water flows.
IDACORP's financial profile has rebounded since the power crisis, aided by the Idaho Public Utilities
Commission s (IPUC's) decision to let IPC recover all its deferred energy costs in just over a year.
However, a combination of factors delayed full financial recovery. Expected lower water in the medium
term will increase its use of generally more expensive thermal generation resource and purchase power.
At the same time, continuing decline in Snake River base flow and over-appropriation of water might
reduce hydroelectric generation and revenue and increase costs. Although 90% of the Idaho jurisdiction
costs are recovered through the PCA, higher costs might have contributed to a reluctance on the part of
the IPUC to raise rates under the prior general rate case. Given the proposed new settlement and
upcoming capital expenditures, Standard & Poor's expects that IDACORP should achieve adjusted funds
from operations (FFO) coverage of interest of 3.8x on a three-year average annual basis. While FFO
coverage of interest is consistent with the '888+' rating, the forecast ratio of FFO-to-average total debt and
debt-to-total capitalization ratios will be somewhat weak for the rating level, at about 14% at 57%,
respectively.
Liquidity
IDACORP's short-term rating is ', reflecting adequate liquidity, a moderate need to access external
capital to fund capital expenditure requirements, and the expectation for IPC to continue to generate stable
cash flow.
The PCA mechanism in Idaho and the lAP allow IPC to plan based on 70th percentile load and water
levels rather than average conditions, which was the policy in 2000 and 2001. This higher benchmark
significantly mitigates the risk that price spikes could result in another buildup of deferred power costs and
deplete liquidity. The 90 MW peaking plant built in 2001 and the new 160 MW gas-fired combined cycle
plant further mitigate the hydrology risk and decrease exposure to wholesale power prices and short-term
liquidity needs,
IDACORP's liquidity position is adequate. In addition to cash flows, support is provided by a $100 million
five-year credit agreement at IDACORP and a $300 million, five-year credit facility at Idaho Power
Company (IPC). Debt maturities are moderate at $95.2 million in 2007 and $11.5 million in 2008. However
IPC has more than $828 million in capital requirements in the next three years, for which moderate
external funding will be required.
Outlook
The negative outlook reflects the potential for weakened financial metrics in accordance with expected
large capital expenditures and increase generation cost. Also the uncertainty of the effect of the recharge
programs under the stipulation agreement and uncertainty regarding the IRS's assessment of a $45 million
tax liability are factors.
A downward rating action could occur if IPC is unable to achieve its projected financial metrics.
Conversely, an outlook or a rating improvement will depend on the restoration of adequate financial
performance, with modest reliance on power cost deferrals, and minimal or no ultimate financial
consequences from the aquifer recharge program.
Accounting
IDACORP's financial statements are prepared in accordance with U.S. GMP. These statements received
an unqualified opinion by IDACORP's independent auditor Deloitte & Touche LLP in 2006. IACORP
prepares its financial statements according to SFAS No. 71 "Accounting for Effects of Certain Types of
Regulation." Subject to SFAS No. 71 , IDACORP has recorded certain regulatory assets and liabilities at
Dec. 31 2006 in the amount of $425.0 million and $294.8 million, respectively.
When calculating credit measures, Standard & Poor's considers off-balance-sheet (OBS) obligations such
as operating lease to fixed commitments, imputed debt, and interest components, including these amounts
in adjusted financial ratios.
With respect to operating leases, Standard & Poor's calculates an 08S amount for debt, interest expense,
and depreciation and includes these amounts when calculating its adjusted ratios. The present value of the
companys operating leases is treated as a debt equivalent and determined using a 5.8% discount rate,
which is Standard & Poor s estimate of the company s average cost of debt in 2006. Operating lease
interest expense and depreciation expense are also computed. The amounts relating to operating leases
that were included in IDACORP's adjusted ratios as of Dec. 31 2006, were $18.6 million for CBS debt,
$1.1 million for imputed interest, and $4.4 million for depreciation.
Standard & Poor's also calculates a purchased power debt equivalent by taking the net present value of
future annual capacity payments (discounted at the companies' average cost of debt). Standard & Poor
will add to the balance sheet only a portion of this amount, recognizing that such contractual arrangements
are not entirely the equivalent of debt. The percentage that is added is a function of Standard & Poor's
qualitative analysis of the specific contracts and the extent to which market, operating, and regulatory risks
are borne by the utility. As of Dec. 31, 2006, Standard & Poor's had assigned a risk factor of 30% to IPC'
power purchase agreements, which translates into a debt equivalent of $154.8 million. Risk factors are
subject to change based on revisions to Standard & Poor s rating criteria, which could affect the level of
debt imputation ascribed to purchased power obligations.
We also adjust reported financial result for pension and postretirement obligations(on tax-adjusted basis).
For IDACORP, this increase adjusted debt by $62.9 million for unfunded pension bond obligations and
reduces FFO by $6.6 million.
Table 1
iDACORP !nc.Peer Comparison
Industry Sector: INTEGRATED
Average of past three fiscal years
Portland General Electric
IDACORP Inc. puget Energy Inc. Avista Corp. Co.
BBB+/Negative/A-2 BBB-/Stable/-- BB+/Pos~iveIB-1 BBB+/Negative/A-Rating as of May 9, 2007
($ Mil.
Revenues
Net income from cont. oper.
Funds from operations (FFO)
Capital expenditures
Cash and investments
Debt
Preferred stock
Common equity
Total capital
Adjusted raUos
EBIT interest coverage (x)
FFO into coV. (X)
FFO/debt ('Yo)
Discretionary cash flow/debt (%)
Net Cash Flow / Capex (%)
DebVtMal capn~ (o/~
Return on common equity ('Yo)
Common dividend payout ratio (un-adj.
) (%)
Fully adjusted (including postretirement obligations).
Table 2
IDACORP (nc.Financial Summary
Industry Sector: INTEGRATED
Rating history
($ Mil.
Revenues
Net income from continuing operations
Funds from operations (FFO)
Capit~ expenditures
Cash and Investments
Debt
Preferred stock
Common equity
Total capital
Adjusted ratios
EBIT interest coverage (x)
FFO into coV. (x)
FFO/debt ('Yo)
Discretionary cash flow/debt (%)
Net Cash Flow / Capex (%)
DebVtotal capit~ ('Yo)
Return on common equity ('Yo)
865.
88.
171.8
205.
28.
303.
016.
320.
339.
51.
194.
168.
56.
399.
18.
787.
205,
473.
75.
285.
278.
112.
249.
182.
431.
682.
126.
428.
669.
21.
295.
889.
190.
13.
(6.0016)
59.
56.
55.4
13.
(12.6457)
50.
63.
73.
13.
(3.1109)
100.
63.
51.
22.
(7.1590)
81.
51.4
78.
Fiscal year ended Dec. 312006 2005 2004 2003 2002
BBB+lNegativelA-2 BBB+/Stable/A-2 BBB+/Stable/A-2 A-/Stable/A-2 A-/Positive/A-
926.842.827.823.928.
100.85.SO.46.61,
133.195.186.238.315.
225,192.196.153.134.
52.23.75.42.
389.347,175,179.235.
52.53.
124.967.5 956.818.822.
513.314.132.049.111.
14.15.20.25.
(8.703)(4.940)(4.026)11.
36.74.71.113.182.
55.58.55.57.58.
Common dividend payout ratio (un-adj.
) (%)
Fully adjusted (including postretirement obligations).
Table 3
51.59.56.139.113.
Reconciliation Of IDACORP Inc. Reported Amounts 'With S1andard & Poor s Adjusted Amounts($ MiL) Fiscal year ended Dec. 31 , 2006
IDACORP Inc. reported amounts
Operating OperatingIncome Income
Debt (before D&A) (before D&A)
152.8 269.5 269.Reported
Standard & Poor's adjustments
Operating leases 18,
Postretirement benefit 62.
obligations
Capitalized interest
Power purchase
agreements
Reclassification of
nonoperating income
(expenses)
Reclassification of
working-capijal cash
flow changes
Total adjustments
(1.048)(1.048)
154.
13.236.
Operating Cash flow Cash flowIncome Interest from from Capital
(after D&A) expense operations operations expenditures
169.7 61.0 162.5 162.5 225.
4.4
(1.048)(6.605)(6.605)
(4.000)(4.000)
(22.735)
15.14.(6.(29,
(4.000)
Standard & Poor's adjusted amountsOperating Cash flow FundsIncome Interest from from CapitalDebt (before D&A) EBITDA EBIT expense operations operations expendituresAdjusted 1,389.1 282.8 278.185.4 75.0 156.2 133.5 225.
IDACORP Inc. reported amounts shown are taken from the company? financial statements but might include adjustments made by data
providers or reclassifications made by Standard & Poors analysts. Please note that two reported amounts (operating income before D&A
and cash flow from operations) are used to derive more than one Standard & Poor adjusted amount (operating income before D&A and
EBITDA, and cash flow from operations and funds from operations, respectively). Consequently, the first section in some tables may feature
duplicate descriptions and amounts.
Ratings Detail (As Of 11-May-2007) *q'. 0"0 --..
IDACORP Inc.
Corporate Credit Rating
Commercial Paper
Local Cu"sncy
Senior Unsecured
~9aJ9J."-f!,,(;Y
Corporate Credit Ratings History
27-Mar-2006
29-NoY-2004
15-Jun-2004
03-Oct-2003
27-Jun-2002
........ '....
Business Risk Profile
Related Entities
Idaho Power Co.
Issuer Credit Rating
Commercial Paper
Local CU"sncy
Preferred Stock
Local Cu"sncy
Senior Secured
Local Currency
Senior Unsecured
Local Currency BBB
Unless otherwise noted, all ratings In this report are global scale ratings. Standard & Poo~s credit ra~ngs on the global scale are comparable across
countries, Standard & Poors credit ratings on a national scale are relative to obligors or obligations within that specific country.
BBB+/Negative/A-
BBB
BBB+/Negative/A-
BBB+/StablelA-
lWatch Neg/A-
A-/Stable/ A-
/Positive/A-
1 2 3 4 5 6 7 8 9 10
BBB+/Negative/A-
BBB-
Analytic services provided by Standard & Poor s Ratings Services (Ratings Services) are the result of separate activities
designed to preserve the independence and objectivity of ratings opinions. The credit ratings and observations contained herein
are solely statements of opinion and not statements of fact or recommendations to purchase, hold. or sell any securities or make
any other investment decisions. Accordingly. any user of the information contained herein should not rely on any credit rating or
other opinion contained herein in making any investment decision. Ratings are based on infonnation received by Ratings
Services. Other divisions of Standard & Poor s may have information that is not available to Ratings Services. Standard & Poor
has established policies and procedures to maintain the confidentiality of non-public infonnation received during the ratings
process.
Ratings Services receives compensation for its ratings. Such compensation is nonnally paid either by the issuers of such
securities or third parties participating in marketing the securities. While Standard & Poor s reserves the right to disseminate the
rating, it receives no payment for doing so, except for subscriptions to its publications. Additional information about our ratings
fees is available at www.standardandpoors.com/usratingsfees.
Copyright ~ 2007 Standard & Poors, a division of The McGraw-Hili Companies. All
Rights Reserved. Privacy Notice The McGraw' Hill CcmpaJile$tifi!iJ~;
~;,;'
"'!!:;,,
Global Credit Research
Summary Opinion
06 Oct 2006
Moody s Investors Service
Summary Opinion: Idaho Power Company
Idaho Power Company
Opinion
Company Profile
Idaho Power Company (IPC) is a regulated investor-owned utility and the principal wholly-owned subsidiary of IDACORP, Inc., a holding
company which also serves as parent for other modest-sized non-utility businesses. As an all-electric utility, IPC provides retail electric
service to more than 464 000 residential, irrigation, commercial and industrial customers within a 24,OOO-square mile service area
encompassing southwestern Idaho and eastern Oregon. IPC generates nearly half of the electricity it sells from 17 hydroelectric
developments on the Snake River and its tributaries. IPC also serves a portion of its electric load from three coal-fired power plants in
Wyoming, Nevada, and Oregon and from the natural gas-fired Bennett Mountain Power Plant and Evander Andrews Power Complex in
Mountain Home, Idaho. The utility also buys electricity from the regional wholesale market to meet its customers' needs for electricity.
On a stand-alone basis, IPC represents over 90% of IDACORP's consolidated revenues, net income, and asse1s. IPC's customers have
been weighted tDwsrd the residential class, with about 44.9% of 2005 general business revenues derived from sales tD residential
customers, which are typically more predictable and stable sources of revenue. We do not expect this to change materially in the foreseeable
future, The remainder of IPC's 2005 revenues was derived from electricity sales to commercial customers (26%), industrial customers
(17.7%), and irrigation customers (11.4%).
IPC's retail rates are subject tD the regulatory jurisdiction of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility
Commission. Wholesale activities and interstate activities are subject to the jurisdiction of the Federal Energy RegulatDry Commission.
Rating Rationale
Key factors affecting IPC's Baa1 senior unsecured debt rating indude its generally low business risk profile, reasonably supportive
regulatory treatment of late, increasing capital expenditures to add capacity, financial metries within an acceptable range for a regulated
electric utility in the Baa rating category, and access to sufficient liquidity. IPC's ratings also take into account that IPC's retail rates remain
below national averages, and that it is pursuing strategies to control operating expenses and conservatively finance utility investments.
Significantly Higher Utility Capital Expenditures To Be Met With Cash Plus External Funding
IPC will face significantly higher capital expenditure needs over the next few years, primarily to meet customer and demand growth. IPC
expects tD continue financing its large utility construction program and other capital requirements, estimated at $720 million over the next
three years, with internally generated funds and externally financed capital. Its internally generated cash after dividends is expected tD
provide approximately 58% of its 2006 capital requirements. In the face of external financing needs, it is possible that IPC will seek to
maintain capitalization ratios close to the June 30, 2006 level through periodic additional common equity infusions from its parent company.
Balanced RegulatDry Treatment In A SetUed Rate Case Uesln Contrast To Less Supportive 2004 Litigated Decision
Need for further general rate increases at IPC:
The 3.2% general rate case setUement increase to IPC's Idaho retail base rates implemented on June 1, 2006 was a partirolarly
encouraging sign of a more transparent working relationship between the IPUC and IPC, The setUed outcome was much more supportive of
IPC's need for rate relief to address certain cost pressures and lies in significant contrast to IPC's 2004 general rate case decision in Idaho
when the IPUC (through a fully litigated decision) only approved a litUe more than half of the company s requested rate increase. We also
note that the utility's management is adhering to a conservative financing plan that should help produce reasonable financial resuits going
forward, especially given the return tD above nonnal hydro conditions. Moreover, management has shown a greater willingness to
collaborate with the IPUC by undertaking smaller and more frequent general rate increases to temper any potential rate shock to custDmers
when cost pressures arise. Consistent with this tendency, we would not be surprised to see management approach the IPUC for additional
albeit smaller rate increases, as uti&ty capital spending plans continue tD unfold.
Rate reduction for nonnalized hydro conditions:
IPC's credit quality also reflects the end of drought conditions that had persisted in Idaho for about six years until this past spring.
Improved water conditions in the Snake River Basin this year enabled IPC to make better use of its hydroelectric generating system and
helped to reduce net power supply costs. Our ratings take into consideration the longstanding existence of a Power Cost Adjustment (PCA)
mechanism in Idaho. Under the terms of the PCA, (PC annually adjusts its rates charged to Idaho retail customers for 90% of the difference
(with interest) between the actual and forecasted costs of fuel and purchased power less off-system sales. We generally view the existence
of PCA mechanisms to be beneficial to a utility's overall credit profile because such a mechanism can help minimize the negative 'effects on
earnings and cash flow when net power supply costs exceed forecast levels in existing rates. This is especially so when the cash recovery
period is relatively short We note that IPC's most recent PCA filing resulted in a 19% PCA credit, reflecting the reduced net power costs due
to improved hydro conditions. This credit more than offsets the impact on customers' bills due to the 3.2% general rate increase noted above.
IPC and State of Idaho sign aquifer recharge agreement:
Earlier concerns about potential toss of benefits from operating IPC's significant hydroelecbic system were placated when IPC and the
State of Idaho signed a stipulation agreement on April 11 , 2006, that positions the state to move folWard with efforts to provide water for
aquifer recharge to agricultural interests under two permits that protect the utility's water rights while reducing the impact of recharge on its
customers to an estimated potential maximum of $30 million. A proposed Idaho bill, House Bill 800, would have rolled back an Idaho Law
passed in 1994 containing protections for the public benefit of low-cost hydroelectric generation but was defeated in the Idaho Senate on
March 30.
FInancial Memes
For the trailing 12-months ended June 30, 2006, IPC's cash flow from operations exclusive of working capital changes (hereafter referred
to as FFO) provided coverage of interest and debt by 3.8x and 15.6%, respectively, reflecting improvement over levels reported for fiscal
year end 2005. These metrics are still considered marginally acceptable relative to IPC's Baa1 senior unsecured debt rating. Looking ahead,
IPC's financial performance will likely remain subject to the vagaries of water flow conditions, the adequacy and timeliness of rate relief
afforded to IPC by the IPUC in likely future general rate case proceedings, and higher than historical utility capital expenditures for the near
term. Our ratings assume that the IPUC will address any future regulatory filings by IPC in a way that allows for supportive rate base
treatment of utility capital spending, thus supporting improvement in IPC's FFO coverage of interest and debt over the next couple of years
that would strengthen its standing within the Baa1 senior unsecured rating category.
Sale of sulfur emission allowances generates cash:
In late 2005 and early 2006, (PC sold 78,000 sulfur dioxide emission allowances on the open market for approximately $81.6 million. In
accordance with a stipulation by the IPUC, IPC may retain only 10%, or $4.7 million after-tax, of emission allowance net proceeds as a
shareholder benefit, while the remaining 90% was recorded as a customer benefit and included in its annual PCA true-up. This one-time
cash windfall lifted second quarter earnings and will also be reflected in next year s annual PCA filing. IPC retains about 32,000 excess
allowances, which it intends to keep for now just in case it may need them in conjunction with new planned coal-fired generation plants.
After considering Moody's standard adjustments, IPC has benefited from a modest reduction in its overaH debt leverage ratio from 422%
at December 31, 2003 to 41,5% as of June 30, 2006. The calculation of this ratio includes deferred income taxes as part of capitalization.
The adjusted debt ratio leaves IPC comfortably positioned relative to the range typically expected for a Baa-rated regulated electric utility
company. The improvement in IPC's debt ratio is partly attributable to higher retained earnings resulting from a 35% reduction in the parent'
dividend payout level in 2003. Against the backdrop of higher than historical capital spending at IPC over the near term, we have factored
into existing ratings the possibility that prospective debt leverage could creep slightly higher.
Uquidity
On balance, IPC has sufficient liquidity, including cash on hand and its ample unused capacity under its bank facility.IPC's bank facility,
which is sized at $200 million, expires March 31 , 2010 and contains less restrictive telTTlS and conditions than its former agreement Cash
proceeds from the sale of non-regulated businesses have enabled IDA to infuse additional equity into IPC in support of the utility's capital
expenditures. Management still may decide to further support IPC's capital program and bolster consolidated capitalization and cash flow
coverage of debt metrics by periodic issuances of additional common equity. Meanwhile, we continue to believe that management's future
strategies will focus on a back-to-basics core energy-related and largely regulated utility business.
Rating OuUook
IPC's stable rating outlook refIecIs 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 canadequately cope with its remaining challenges, including through prudent management of its large capital program such that state regulators
are likely to be supportive of IPC's future 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 continued normaized hydro conditions, greater regulatory support in
future rate proceedings, and reduced capital spending that results in positive free cash flow being used to significantly reduce debt.
What Could Change the Rating. Down
Lower than anticipated eamings and cash flow, perhaps due to the recommencement of drought conditions or lack of regulatory support
in rate proceedings related to impending capital invesbnents, could JeSuit in a negative rating action, Additionally, negative pressure could
stem from one or more of the following: significant increases in relicensing costs and/or stringent operational constraints imposed as part of--
the license renewal process; 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.
(9 Copyright 2002 by Moody s Investors Service, 99 Church Street, New York, NY 10007. All rights reserved.
Copyright 2006, Moody s Investors Service, Inc. and/or its licensors and affiliates induding Moody's Assurance Company, Inc. (together,
MOODY'). All rights reserved.
MDDrIy'S lnveat- Service .
Global Credit Research
Liquidity Risk Assessment
15 NOV 2006
~i'
-:;;;;::-
Liquidity Risk Assessment: Idaho Power Company
Idaho Power Company
Boise, Idaho, United States
Broad Industry:
Specific Industry:
Short Tenn Rating:
Contacts
Public Utility
Integrated Electric Utility
Analyst
Kevin G. Rose/New York
J. SabatellelNew York
William L. Hess/New York
Phone
212.553.1653
Opinion
Idaho Power Company's (IPC) Prime-2 short-term debt rating for commercial paper reflects management'
proactive approach to ensuring the company has sufficient liquidity to meet its needs. The company's long-term
ratings include its A3 rating for senior secured debt and its Baa1 rating for senior unsecured debt. The utility'
rating outlook is stable.
IPC is following a disciplined strategy to minimize its reliance on short-term debt in the future. This strategy
includes cost control efforts and takes into account the effects that below normal water conditions (albeit finally
abated after persisting at severe levels for six consecutive years) can often times have on forward looking
wholesale prices for power purchases in the region. We expect that IPC will continue to be the principal source of
cash flow for its parent holding company, IDACORP (Baa2 Issuer Rating; stable rating outlook), to pay modest
parent-company short-term debt obligations and the roughly $51 million annual dividend to common
shareholders.
IPC's commercial paper balances outstanding for the trailing 12-months ended September 30 2006 averaged
$0.9 million, compared to $8.2 million for the trailing 12-rnonths ended September 30 2005. During the 12-
months ended September 30, 2006,IPC experienced a peak short-term debt borrowing of $27.2 million in
September 2006, which was incurred to meet short-term working capital needs. Moody's notes that the utility
reported $27.2 million of short-term debt outstanding and a $4.4 million unrestricted cash balance as of
September 30, 2006. The cash on hand has steadily declined from the level of $49.3 million reported at
December 31 , 2005, largely reflecting use of a significant portion of the remaining proceeds from earlier sales of a
portion of IPC's emission allowance credits to supplement operating cash flow and meet short-term capital
requirements. We expect the modest cash balances at IPC to remain the norm over the next 12 months.
IPC has only modest sinking fund payments starting in 2007 and its next material scheduled long-term debt
maturity is $80 million of first mortgage bonds, which are due in December 2007.
Although IPC had $27.2 million of commercial paper outstanding at September 30, 2006 (compared to zero
earlier this year), this amount could increase to as much as $150 million over the next 12 to 18 months. Whether
IPC's commercial paper issuance actually reaches the high point of $150 million will depend in part on weather
conditions during the upcoming winter and summer seasons, as well as the extent to which improved hydro
conditions favorably impact the wholesale market, thereby reducing IPC's net power supply costs. The amount of
reliance on commercial paper could also be influenced by the timing of IPC's tax payments and dividends to
IDACORP and the pace of 2007 capital spending related to generation and energy delivery infrastructure
construction projects. IPC periodically relies on issuance of short-term debt as a bridge to long-term funding of a
portion of its capital program.
We note that IPC's peak borrowings usually occur in the first or fourth quarter due to seasonal influences. IPC
currently has approval from the IPUC to issue unsecured short-term debt in an aggregate principal amount up to
$250 million. IPC may issue commercial paper up to the amount supported by its $200 million in bank credit
facilities. Moody's notes that the 5-year facility has a March 31 , 2010 expiration and can be increased by up to
$100 million at any time, subject to certain conditions. Also, the facility does not require IPC to represent and
warranty that no material adverse change (MAC) has occurred as a prerequisite to any funding beyond the initial
closing date, does not contain any rating triggers that would cause default, acceleration, or puts, and still contains
a maximum 65% debt to total capitalization ratio covenant. Moody s believes that the change related to the MAC
clause when this facility was negotiated is a particularly significant improvement in IPC's altemate liquidity
because the change removes earlier concems that IPC's access to the facility could have been jeopardized at a
time of greatest need. We note that there was ample cushion with respect to the financial covenant as of
September 30, 2006 when IPC's leverage as defined in the credit facility was 51%.
~ Copyright 2006, Moody's Investors Service, Inc. and/or its licensors including Moody s Assurance Company, Inc.
(together
, "
MOODY'S"). All rights reserved.
:' ',;', '
,c,
." ,.,
, i,
: ,
c '
'..' , . ''.., ,, ,', ,,,;,,' """,,'
'r,o
, '
:':c: ,
," " '" '.,," '" ," ,' ;: .":::', ,",:: ;,'
.o,,':.., , I'
':""':;"
0" :'
"\'::
, l, ", 'o~ ,
" '~" ::;':);", ,",,:',:,(' , '" ,. ',...., ,. ""':"
;i;"
, ,
' f";"
"" ,,", ;)
O'i
, "', ,;: ",';;'' ,~ , ,:-
,e :'
" .., ",,;,
'i -
" ' , ",:;, ;'"
"il ", c"
':',:':, ",,:: '
" I' : , ,.
' -' -, :'
.:c, Ir"
, ,
'co "
.-",."..,.. "."
:,':C"'
",;, ", ,: /" '," '
,c-
" ~"" - ,;,:",:-' , '
cc,
": ,
c, ;'
:!, '' ::~,
,: c",iI, "
: I :Co
", ,, '
C' ,'
",,, "
1"'
" ". ,':";,", ,".. ';;,,.., ,,"," ',:,,..
, " ':1 'i
,' ,:' ~
, :' c,", c"i"C , '.I 'co' """-':"1,
;.;' ..., :' !, -
, 'f:'",., r ",
, ,;'," '" "." "
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O7-
IDAHO POWER COMPANY
ATTACHMENT 1-
RESEARCH
IDACORP Inc.
Publication da1e:
Primary Credit Analyst:
Secondary Credit Analyst:
11-May-2007
Antonio Bettinelli, San Francisco (1) 415-371-5067;
antonio - bettinelfi(g)standardandpoors.com
Masako Kuwahara, New York (1) 212-438-7916;
masako - kuwahara(g) stand ardand poors .com
Major Rating Factors
Strengths :
. A generaRy supportive slate regulatory regime;
. A strong power cost adjustment (PCA) mechanism;
. An efficient, low-cost generating fleet; and
. The absence of material, unregulated businesses.
Corporate Credit RatIng
BB8+JNega1iveI A -
Weaknesses ;
SignifICant exposure to hydrological variations on the Snake River and poor water flows in the past
six years that have reduced hydroelectric production and deferred power costs recovery. and
. More than $820 million in capital expenditure requirements for IPC based on the companies
Integrated Resource Plan (IRP) primarily for new generation and delivery in the next three years.
Rationale
Standard & Poor's Ratings Services affirmed the corporate credit ratings on IDACORP and i8s primary
subsidiary. IPC. at '8BB+. The rating on the senior secured debt at IPC is affirmed at '' and on senior
unsecured debt at IDACORP and IPC is affirmed at 'BBB'. The CP rating at both companies is affirmed at
Z. Based on recent developments, the outlook on all ratings is negative.
The '888+' rating reflects the stability provided by a generally supportive regulatory regime in Idaho; a
strong PCA mechanism; an efticie~ Iow-cost generating fleet; and the absence of significant unregulated
businesses. OffseUing factors include significant exposure to hydrological variations in the Snake River
and substantial upcoming capital expenditures for new generation and hydro relicensing. The PCA
mechanism allows IPC to set annual power costs and then pass 90% of the cost that exceeds this amount.
together with interest, to its customers. It also requires refunds when costs are below forecasts. Resource
planning rules allow the company to use 70th percentile water and load levels for planning. rather than a
median level approach. This means that. on average. only 30% of the time the water and load conditions
will be worse than planned. rather than 50%. Idaho Power's business risk profile score is '5' (satisfactory).
(Utility business risk profiles are categorized from '1' (excellent) to '10' (vulnerable)).
;:::::::::.
::t
IPC's service territory exhibits good economic characteristics ovEKaH. IPC achieved a record for annual
general business customer growth in 2006 with a gain of 16,149 customers, which represents a 3.
increase year-over-year. The peak summer demand in 2006 was 3,084 MW while the peak winter demand
was 2.318 MW.
IPC served this load with 3.085 MW. substantially by using its own generation capacity, including 17
hydroelectric plants on the Snake River and its tributaries with a total nameplate capacity of 1 707 MW.
The company also owns 1 110 MW of coaHired generation; a 90 MW gas-fired peaking resource; and its
new $61 million. 160 MW gas-fired generating plant In a median year. hydroelectric sources are expected
to deliver about 55% of total generation needs, thereby exposing IPC to substantial volumetric and
replacement power price risk in the event of adverse water flows.
IDACORP's financial profIle has rebounded since the power crisis. aided by the Idaho Public Utilities
Commissions (IPUC's) decision to let IPC recover all its deferred energy costs in just over a year.
However. a combination of factors delayed full financial recovery. Expected lower water in the medium
term will increase its use of generally more expensive thermal generation resource and purchase power.
At the same time. continuing decline in Snake River base flow and over-appropriation of water mightreduce hydroelectric generation and revenue and increase costs. Although 90% of the Idaho jurisdiction
costs are recovered through the PCA, higher costs migtt have contributed to a reluctance on the part of
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-O7-
IDAHO POWER COMPANY
TT A CHMENT 1-
iI '
....
(I.)
(I.)
....
..c:
(.)....
Or
g
a
n
i
z
a
t
i
o
n

S
t
r
u
c
t
u
r
e
20
0
6
--

ID
A
H
O
a.
:
!
!

PO
W
E
R

An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Re
g
u
l
a
t
e
d

No
n
-
Re
g
u
l
a
t
e
d
ID
A
H
O
a.
:
!
!

PO
W
E
R

An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
L'
E
I
r
ID
A
C
O
M
M
An

I
D
A
C
D
R
P

c
o
m
p
a
n
y
An

I
D
A
C
O
R
P

c
o
m
p
a
n
y
~~
u
u
.
ID
A
T
E
C
H
~
An

I
D
A
C
O
R
P

c
o
m
p
a
n
y
ID
A
H
O
~P
O
W
E
R
0
Or
g
a
n
i
z
a
t
i
o
n

S
t
r
u
c
t
u
r
e
20
0
7
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
DA
C
O
R
P
.
Re
g
u
l
a
t
e
d

No
n
-
Re
g
u
l
a
t
e
d
ID
A
H
O

1D
A
a
R
'

ID
A
.
W
E
S
T
-.
:
!
!

PO
U
V
E

R

-.
:
!
!

F
I

NA
N
C

I
A
L

EN
E

R
C
Y
An

I
D
A
C
O
R
P

co
m
p
a
n
y
An

I
D
A
C
O
R
P

co
m
p
a
n
y
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Ba
c
k
-
t
e
-
Ba
s
i
c
s
Ba
c
k
-
to
-
ba
s
i
c
s

s
t
r
a
t
e
g
y

e
m
p
h
a
s
i
z
e
s

I
d
a
h
o

P
o
w
e
r

a
s

I
D
A
C
O
R
P
'
s
c
o
r
e
bu
s
i
n
e
s
s
Re
g
u
l
a
t
e
d
,
v
e
r
t
i
c
a
l
l
y

i
n
t
e
g
r
a
t
e
d

u
t
i
l
i
t
y
70
7
11
0
26
8
08
5
Mw

H
y
d
r
o
Mw

C
o
a
l
Mw

O
t
h
e
r
As

o
f

D
e
c
e
m
b
e
r

3
1
,
20
0
6
mo
r
e

t
h
a
n

4
7
1
,
77
6

g
e
n
e
r
a
l
bu
s
i
n
e
s
s

c
u
s
t
o
m
e
r
s
Se
c
o
n
d
a
r
y
Di
s
t
r
i
b
u
t
i
o
n
Tr
a
n
s
m
i
s
s
i
o
n
Su
b
s
t
a
t
i
o
n
Ho
u
s
e
ID
A
H
O
~P
O
W
E
R
0
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Vi
s
i
o
n
Va
l
u
e
s
Mi
s
s
i
o
n
To

b
e

R
e
g
a
r
d
e
d

a
s

a
n
Ex
c
e
p
t
i
o
n
a
l

U
t
i
l
i
t
y
In
t
e
g
r
i
t
y
,

S
a
f
e
t
y

a
n
d

R
e
s
p
e
c
t
Pr
o
s
p
e
r

b
y

p
r
o
v
i
d
i
n
g

r
e
l
i
a
b
l
e
re
s
p
o
n
s
i
b
l
e
,

f
a
i
r
-
pr
i
c
e
d

e
n
e
r
g
y
se
r
v
i
c
e
s
,

t
o
d
a
y

a
n
d

t
o
m
o
r
r
o
w
.
Cr
i
t
i
c
a
l

S
u
c
c
e
s
s

F
a
c
t
o
r
s
Fi
n
a
n
c
i
a
l

S
t
r
e
n
g
t
h
Ql
s
t
Q
'
me
"
f'
!
,
$
a
l
l
s
f
a
e
t
l
.
i .
.
.

"
."
"
"
.
'
" "
"
,
..
,
./
"
..
"
..
.
."
,
./
.
,.
/
i
i
/
"
LV
"
t.
l
l
i
~
I
~
~
~
~
~
~
I
~
~
/
~2
2
X
~
J
~
!
~
J
~
~
J
l
l
r
!
i
l
l
l
i
l
l
~~
~
~
;~
i
~
i
:
~
+
J
s~
~
~
~
~
t
i
v
e
)~

+i
'
~
~
~
f
~
/
)
~
X
\
/
~
d
i
t
,
~
En
h
a
n
c
e

R
e
l
a
t
i
o
n
s
h
i
p
s

a
n
d

C
o
m
m
u
n
i
c
a
t
i
o
n

w
i
t
h

a
l
l

o
u
r

S
t
a
k
e
h
o
l
d
e
r
s
ID
A
H
O
~P
O
W
E
R
~
Th

r
e
e
-
pa
r
t
Ca
p
i
t
a
l

P
r
o
g
r
a
m
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Cu
s
t
o
m
e
r

g
r
o
w
t
h
~
E
x
p
a
n
d
e
d

re
l
i
a
b
i
l
i
t
y

s
t
a
n
d
a
r
d
s
~~

Ma
i
n
t
a
i
n
i
n
g

o
u
r

r
e
s
o
u
r
c
e

b
a
s
e
-
H
y
d
r
o

pr
o
j
e
c
t

r
e
l
i
c
e
n
s
i
n
g
En
v
i
r
o
n
m
e
n
t
a
l

u
p
g
r
a
d
e
s

a
t

t
h
e
r
m
a
l

f
a
c
i
l
i
t
i
e
s
ID
A
H
O
~P
O
W
E
R
0
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Re
s
o
u
r
c
e

C
o
r
n
e
r
s
t
o
n
e
s
Pr
e
s
e
r
v
e

t
h
e

b
a
s
e
~
E
n
e
r
g
y

ef
f
i
c
i
e
n
c
y
.
R
e
n
e
w
a
b
l
e

en
e
r
g
y

r
e
s
o
u
r
c
e
s
Co
n
v
e
n
t
i
o
n
a
l

b
a
s
e

l
o
a
d

r
e
s
o
u
r
c
e
s
ID
A
H
O
.:
!
!

PO
W
E
R

An

I
D
A
C
O
R
P

co
m
p
a
n
y
He
l
l
s

C
a
n
y
o
n

R
e
l
i
c
e
n
s
i
n
g
Fi
n
a
l

t
w
o

r
e
l
i
c
e
n
s
i
n
g

c
o
m
p
o
n
e
n
t
s

ES
A

c
o
n
s
u
l
t
a
t
i
o
n

a
n
d

40
1
wa
t
e
r

q
u
a
l
i
t
y

c
e
r
t
i
f
i
c
a
t
i
o
n
-
C
o
m
p
a
n
y

is

w
o
r
k
i
n
g

w
i
t
h

N
O
A
A

F
i
s
h
e
r
i
e
s

&

U
.
S.

f
i
s
h

a
n
d

W
i
l
d
l
i
f
e
Se
r
v
i
c
e

t
o

s
a
t
i
s
f
y

E
S
A

re
q
u
i
r
e
m
e
n
t
s

f
o
r

a
n
a
d
r
o
m
o
u
s

f
i
s
h

&

b
u
l
l

t
r
o
u
t
Go
a
l

-

r
e
n
d
e
r

a

bi
o
l
o
g
i
c
a
l

o
p
i
n
i
o
n

f
o
r

F
E
R
C

l
i
c
e
n
s
e

o
r
d
e
r
~,

I
P
C

f
i
l
e
d

r
e
v
i
s
e
d

'
40
1
'

a
p
p
l
i
c
a
t
i
o
n
s

w
i
t
h

I
d
a
h
o

&

O
r
e
g
o
n

i
n
Ja
n
u
a
r
y

2
0
0
7
-
'
Re
s
p
e
c
t
i
v
e

D
E
Q
s

a
r
e

r
e
v
i
e
w
i
n
g

t
h
e
s
e

a
p
p
l
i
c
a
t
i
o
n
s
~)

F
E
R
C

i
s

n
o
w

e
x
p
e
c
t
i
n
g

t
o

i
s
s
u
e

i
t
s

f
i
n
a
l

e
n
v
i
r
o
n
m
e
n
t
a
l

i
m
p
a
c
t
st
a
t
e
m
e
n
t

i
n

t
h
e

s
u
m
m
e
r

2
0
0
7
De
p
e
n
d
e
n
t

u
p
o
n

o
u
t
c
o
m
e

o
f

b
o
t
h

E
S
A

c
o
n
s
u
l
t
a
t
i
o
n

a
n
d

40
1

c
e
r
t
i
f
i
c
a
t
i
o
n
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

co
m
p
a
n
y
He
l
l
s

C
a
n
y
o
n

R
e
l
i
c
e
n
s
i
n
g
Se
c
t
i
o
n

7

E
S
A

C
o
n
s
u
l
t
a
t
i
o
n
40
1

W
a
t
e
r

Q
u
a
l
i
t
y

C
e
r
t
i
f
i
c
a
t
i
o
n
Au
g
u
s
t

2
0
0
6
:

F
E
R
C

i
s
s
u
e
s

D
E
I
S

a
n
d

l
e
t
t
e
r
in
i
t
i
a
t
i
n
g

f
o
r
m
a
l

E
S
A

c
o
n
s
u
l
t
a
t
i
o
n
.
Ja
n
u
a
r
y

2
0
0
7
:

I
P
C

f
i
l
e
d

r
e
v
i
s
e
d

4
0
1
ce
r
t
i
f
i
c
a
t
i
o
n

r
e
q
u
e
s
t
s

w
i
t
h

I
d
a
h
o

a
n
d
Or
e
g
o
n

D
E
Q
s
.
Se
p
t
e
m
b
e
r

2
0
0
6
:

F
W
S

a
n
d

N
M
F
S

a
d
v
i
s
e
FE
R
C

t
h
a
t

t
h
e

a
g
e
n
c
i
e
s

n
e
e
d

a
d
d
i
t
i
o
n
a
l
in
f
o
r
m
a
t
i
o
n

t
o

i
n
i
t
i
a
t
e

c
o
n
s
u
l
t
a
t
i
o
n
.
Ja
n
u
a
r
y

2
0
0
7

t
o

P
r
e
s
e
n
t
:

4
0
1

c
e
r
t
i
f
i
c
a
t
i
o
n
re
q
u
e
s
t

u
n
d
e
r

r
e
v
i
e
w

b
y

I
d
a
h
o

a
n
d

O
r
e
g
o
n
DE
Q
s
.
Se
p
t
e
m
b
e
r

2
0
0
6

t
o

P
r
e
s
e
n
t
:

I
P
C
,
F
W
S
NM
F
S
,

a
n
d

F
E
R
C

a
r
e

w
o
r
k
i
n
g
co
o
p
e
r
a
t
i
v
e
l
y

t
o

a
d
d
r
e
s
s

E
S
A

c
o
n
c
e
r
n
s
,
re
s
u
l
t
i
n
g

i
n

a

B
i
o
l
o
g
i
c
a
l

O
p
i
n
i
o
n
.
FE
R
C

i
s
s
u
e
s

f
i
n
a
l

N
E
P
A

d
o
c
u
m
e
n
t
,
w
h
i
c
h
in
c
o
r
p
o
r
a
t
e
s

4
0
1

c
e
r
t
i
f
i
c
a
t
i
o
n
s

f
r
o
m

I
d
a
h
o

a
n
d
Or
e
g
o
n
,
a
l
o
n
g

w
i
t
h

t
h
e

r
e
s
u
l
t

o
f

t
h
e

f
o
r
m
a
l

E
S
A
co
n
s
u
l
t
a
t
i
o
n
.

D
a
t
e

d
e
p
e
n
d
s

o
n

t
i
m
i
n
g

o
f

E
S
A
co
n
s
u
l
t
a
t
i
o
n

a
n
d

4
0
1

w
a
t
e
r

q
u
a
l
i
t
y

c
e
r
t
i
f
i
c
a
t
i
o
n
.
II
1
I
\
H
O
PO
W
E
R
~
An

I
D
A
C
O
R
P

Co
m
p
a
n
y
$,"
"
"
/'

' "
,
"
,
'
,
"
'
Re
g
u
l
a
t
o
r
y

O
v
e
r
v
i
e
w
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
Id
a
h
o

R
e
t
a
i
l

J
u
r
i
s
d
i
c
t
i
o
n
St
a
t
e
m
e
n
t

o
f

P
o
l
i
c
y

a
n
d

C
o
d
e

o
f

C
o
n
d
u
c
t
DS
M

i
n
c
e
n
t
i
v
e

p
r
o
g
r
a
m
Ac
c
o
u
n
t
i
n
g

o
r
d
e
r

r
e
g
a
r
d
i
n
g

p
e
n
s
i
o
n

a
n
d

p
o
s
t
r
e
t
i
r
e
m
e
n
t

b
e
n
e
f
i
t
s
20
0
6

I
n
t
e
g
r
a
t
e
d

R
e
s
o
u
r
c
e

P
l
a
n

(
I
R
P
)
Fi
x
e
d

C
o
s
t

A
d
j
u
s
t
m
e
n
t

(
F
C
A
)

m
e
c
h
a
n
i
s
m
ID
A
H
O
.:
!
!

PO
W
E
R

Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
co
n
t
i
n
u
e
d
)
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
~,

O
r
e
g
o
n

R
e
t
a
i
l

J
u
r
i
s
d
i
c
t
i
o
n
De
f
e
r
r
e
d

a
c
c
o
u
n
t
i
n
g

r
e
q
u
e
s
t

(
p
o
w
e
r

s
u
p
p
l
y

e
x
p
e
n
s
e
s
)
-
P
U
R
P

20
0
6

I
R
P
FE
R
C

J
u
r
i
s
d
i
c
t
i
o
n
-
O
p
e
n

Ac
c
e
s
s

T
r
a
n
s
m
i
s
s
i
o
n

T
a
r
i
f
f

(
O
A
T
T
)

f
i
l
i
n
g
St
a
n
d
a
r
d

o
f

C
o
n
d
u
c
t

N
O
P
R
ID
A
H
O
~P
O
W
E
R
0
Id
a
h
o

P
o
w
e
r
Hi
s
t
o
r
y

o
f

t
h
e

PC
A
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
~i
PC
A

a
p
p
r
o
v
e
d

i
n

19
9
2
19
9
3

t
o

2
0
0
0

A
d
j
l
l
s
t
m
e
n
t
s
Fi
v
e

i
n
c
r
e
a
s
e
s

a
m
o
u
n
t
i
n
g

t
o

$
6
1
.
1
m
i
l
l
i
o
n
Th
r
e
e

d
e
c
r
e
a
s
e
s

a
m
o
u
n
t
i
n
g

t
o

$
5
7
.
6
m
i
l
l
i
o
n
20
0
1

T
w
o

I
n
c
r
e
a
s
e
s
:
-
M
a
y

$
1
6
8
M

(1

y
e
a
r
)
-
'
Oc
t
o
b
e
r

$
4
9
M

(1

y
e
a
r
)
~
2
0
0
2

in
c
r
e
a
s
e

o
v
e
r

b
a
s
e

r
a
t
e
s

o
f

$
2
4
0
.
5
m
i
l
l
i
o
n
20
0
3

i
n
c
r
e
a
s
e

o
v
e
r

b
a
s
e

r
a
t
e
s

o
f

$
8
1
.
0
m
i
l
l
i
o
n
ID
A
H
O
~P
O
W
E
R
~
Po
w
e
r

C
o
s
t
Ad
j
u
s
t
m
e
n
t

Me
c
h
a
n
i
s
m
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
An
n
u
a
l

a
d
j

us
t
m
e
n
t

t
o

I
d
a
h
o

j
u
r
i
s
d
i
c
t
i
o
n
a
l

r
a
t
e
s

t
o

c
r
e
a
t
e

a

r
e
v
e
n
u
e

s
t
r
e
a
m

t
h
a
t

m
o
r
e
cl
o
s
e
l
y

m
a
t
c
h
e
s

p
o
w
e
r

s
u
p
p
l
y

e
x
p
e
n
s
e
s

i
n
c
l
u
d
i
n
g

f
u
e
l

a
n
d

p
u
r
c
h
a
s
e
d

p
o
w
e
r

n
e
t

o
f

o
f
f
-
sy
s
t
e
m

s
a
l
e
s
.
PC
A

a
l
l
o
w
s

I
d
a
h
o

P
o
w
e
r

t
o

s
e
t

a
n
n
u
a
l

p
o
w
e
r

c
o
s
t
s

i
n

I
d
a
h
o

a
n
d

p
a
s
s

9
0
%

o
f

t
h
e

c
o
s
t
th
a
t

e
x
c
e
e
d
s

t
h
i
s

a
m
o
u
n
t

o
n

t
o

c
u
s
t
o
m
e
r
s
.

M
e
c
h
a
n
i
s
m

m
i
t
i
g
a
t
e
s

h
y
d
r
o

p
r
e
c
i
p
i
t
a
t
i
o
n
va
r
i
a
t
i
o
n
.
PC
A

I
n
c
r
e
a
s
e
s

O
v
e
r

B
a
s
e

R
a
t
e
s

(
P
C
A

Y
e
a
r
)
30
0
25
0
20
0
15
0
10
0
25
5
19
9
3

19
9
4

19
9
5

19
9
6

19
9
7

19
9
8

19
9
9

20
0
0

2
0
0
1

20
0
2

2
0
0
3

20
0
4

2
0
0
5

20
0
6
Mo
o
d
y
s
I
n
v
e
s
t
o
r

Se
r
v
i
c
e
s

Me
e
t
i
n
g
Ma
r
c
h

2
2
,
2
0
0
7
ID
A
H
O
~P
O
W
E
R
~
Or
g
a
n

i
z
a
t
i
o
n

St
r
u
c
t
u

r
e
20
0
6
Re
g
u
l
a
t
e
d
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
No
n
-
Re
g
u
l
a
t
e
d
LT
E
r
An

I
D
A
C
D
R
P

C
o
m
p
a
n
y
~~
u
u
.
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
ID
A
C
O
M
M
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
ID
A
1
E
C
H
~
An

I
D
A
C
O
R
P

c
o
m
p
a
n
y
ID
A
H
O
~P
O
W
E
R
~
Or
g
a
n

i
z
a
t
i
o
n

St
r
u
c
t
u

r
e
20
0
7
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
ID
A
H
O
~P
O
W
E
R
~
DA
C
O
R
P
.
Re
g
u
l
a
t
e
d

No
n
-
Re
g
u
l
a
t
e
d
w.
~T
E
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
An

I
D
A
C
O
R
P

co
m
p
a
n
y
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Ba
c
k
-
I
e
-
Ba
s
i
c
s
Ba
c
k
-
to
-
ba
s
i
c
s

s
t
r
a
t
e
g
y

e
m
p
h
a
s
i
z
e
s

I
d
a
h
o

P
o
w
e
r

a
s

I
D
A
C
O
R
P
'
s
c
o
r
e
bu
s
i
n
e
s
s
Re
g
u
l
a
t
e
d
,
v
e
r
t
i
c
a
l
l
y

i
n
t
e
g
r
a
t
e
d

u
t
i
l
i
t
y
;;"
,
70
7
11
0
26
8
08
5
Mw

H
y
d
r
o
Mw

C
o
a
l
Mw

O
t
h
e
r
62
9

m
i
l
e
s

o
f
hi
g
h
-
v
o
l
t
a
g
e
tr
a
n
s
m
i
s
s
i
o
n

l
i
n
e
s
Pr
i
m
a
r
y
Di
s
t
r
i
b
u
t
i
o
n
~-
-
-
-
Se
c
o
n
d
a
r
y

"
-
.
.
Di
s
t
r
i
b
u
t
i
o
n

'
,-
,
Tr
a
n
s
m
i
s
s
i
o
n
Su
b
s
t
a
t
i
o
n
Ho
u
s
e
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

co
m
p
a
n
y
Vi
s
i
o
n
Va
l
u
e
s
Mi
s
s
i
o
n
To

b
e

R
e
g
a
r
d
e
d

a
s

a
n
Ex
c
e
p
t
i
o
n
a
l

U
t
i
l
i
t
y
In
t
e
g
r
i
t
y
,

S
a
f
e
t
y

a
n
d

R
e
s
p
e
c
t
Pr
o
s
p
e
r

b
y

p
r
o
v
i
d
i
n
g

r
e
l
i
a
b
l
e
,
re
s
p
o
n
s
i
b
l
e
,
f
a
i
r
-
pr
i
c
e
d

e
n
e
r
g
y
se
r
v
i
c
e
s
,

t
o
d
a
y

a
n
d

t
o
m
o
r
r
o
w
.
Cr
i
t
i
c
a
l

S
u
c
c
e
s
s

F
a
c
t
o
r
s
Fi
n
a
n
c
i
a
l

S
t
r
e
n
g
t
h
IC
u
s
'
t
o
m
'
er
S
a
,
tl
s
f
a
c
t
I
Q
R
"
,
"
, "
..,
.,
,

"
...
.
.
.
'
..
'
."

'
.'
i
i
:.
;
,
"
,
,;
j
"
,
,
,
'
'
,
"
, "
"
,
,
I
'
,
"
t~
a
f
~

,
I:
q
g
~

~e
d
&
i

E
f
f
e

ct
i

ve
E
m
p
l
Q
y
e
e
s

i.
.
..
i
.
./
i
ii
"
.i
J
,
"

"

,

'

,
"

.
'

" ,
,
'

,
"

,
,
'
"
"
' ,

,
"
'
"
"
,
,
"
,
,
,
,
' ,
,'

,
,
,
"
,
~:

,
:,
,
En
h
a
n
c
e

R
e
l
a
t
i
o
n
s
h
i
p
s

a
n
d

C
o
m
m
u
n
i
c
a
t
i
o
n

w
i
t
h

a
l
l

o
u
r

S
t
a
k
e
h
o
l
d
e
r
s
ID
A
H
O
-.
:
!
!

PO
W
E
R

Th
r
e
e
-
pa
r
t
Ca
p
i
t
a
l

P
r
o
g
r
a
m
An

I
D
A
C
O
R
P

co
m
p
a
n
y
1f
f
p

Cu
s
t
o
m
e
r

g
r
o
w
t
h
.
E
x
p
a
n
d
e
d

re
l
i
a
b
i
l
i
t
y

s
t
a
n
d
a
r
d
s
Ma
i
n
t
a
i
n
i
n
g

o
u
r

r
e
s
o
u
r
c
e

b
a
s
e
-
H
y
d
r
o

pr
o
j
e
c
t

r
e
l
i
c
e
n
s
i
n
g
En
v
i
r
o
n
m
e
n
t
a
l

u
p
g
r
a
d
e
s

a
t

t
h
e
r
m
a
l

f
a
c
i
l
i
t
i
e
s
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Re
s
o
u
r
c
e

C
o
r
n
e
r
s
t
o
n
e
s
\W
t

Pr
e
s
e
r
v
e

t
h
e

b
a
s
e
e
E
n
e
r
g
y

ef
f
i
c
i
e
n
c
y
'"

R
e
n
e
w
a
b
l
e

e
n
e
r
g
y

re
s
o
u
r
c
e
s
~1
j

Co
n
v
e
n
t
i
o
n
a
l

b
a
s
e

l
o
a
d

r
e
s
o
u
r
c
e
s
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
He
l
l
s

C
a
n
y
o
n

R
e
l
i
c
e
n
s
i
n
g
;O
J
!

Fi
n
a
l

t
w
o

r
e
l
i
c
e
n
s
i
n
g

c
o
m
p
o
n
e
n
t
s

ES
A

c
o
n
s
u
l
t
a
t
i
o
n

a
n
d

40
1
wa
t
e
r

q
u
a
l
i
t
y

c
e
r
t
i
f
i
c
a
t
i
o
n
-
C
o
m
p
a
n
y

is

w
o
r
k
i
n
g

w
i
t
h

N
O
A
A

F
i
s
h
e
r
i
e
s

&

U
.
S.

f
i
s
h

a
n
d

W
i
l
d
l
i
f
e
Se
r
v
i
c
e

t
o

s
a
t
i
s
f
y

E
S
A

re
q
u
i
r
e
m
e
n
t
s

f
o
r

a
n
a
d
r
o
m
o
u
s

f
i
s
h

&

b
u
l
l

t
r
o
u
t
Go
a
l

-

r
e
n
d
e
r

a

bi
o
l
o
g
i
c
a
l

o
p
i
n
i
o
n

f
o
r

F
E
R
C

l
i
c
e
n
s
e

o
r
d
e
r
~
I
P
C

fi
l
e
d

r
e
v
i
s
e
d
40
1
'

a
p
p
l
i
c
a
t
i
o
n
s

w
i
t
h

I
d
a
h
o

&

O
r
e
g
o
n

i
n
Ja
n
u
a
r
y

2
0
0
7
Re
s
p
e
c
t
i
v
e

D
E
Q
s

a
r
e

r
e
v
i
e
w
i
n
g

t
h
e
s
e

a
p
p
l
i
c
a
t
i
o
n
s
~
F
E
R
C

is

n
o
w

e
x
p
e
c
t
i
n
g

t
o

i
s
s
u
e

i
t
s

f
i
n
a
l

e
n
v
i
r
o
n
m
e
n
t
a
l

i
m
p
a
c
t
st
a
t
e
m
e
n
t

i
n

t
h
e

s
u
m
m
e
r

2
0
0
7
De
p
e
n
d
e
n
t

u
p
o
n

o
u
t
c
o
m
e

o
f

b
o
t
h

E
S
A

c
o
n
s
u
l
t
a
t
i
o
n

a
n
d

40
1

c
e
r
t
i
f
i
c
a
t
i
o
n
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
He
l
l
s

C
a
n
y
o
n

R
e
l
i
c
e
n
s
i
n
g
Se
c
t
i
o
n

7

E
S
A

C
o
n
s
u
l
t
a
t
i
o
n
40
1

W
a
t
e
r

Q
u
a
l
i
t
y

C
e
r
t
i
f
i
c
a
t
i
o
n
Au
g
u
s
t

2
0
0
6
:

F
E
R
C

i
s
s
u
e
s

D
E
I
S

a
n
d

l
e
t
t
e
r
in
i
t
i
a
t
i
n
g

f
o
r
m
a
l

E
S
A

c
o
n
s
u
l
t
a
t
i
o
n
.
Ja
n
u
a
r
y

2
0
0
7
:

I
P
C

f
i
l
e
d

r
e
v
i
s
e
d

4
0
1
ce
r
t
i
f
i
c
a
t
i
o
n

r
e
q
u
e
s
t
s

w
i
t
h

I
d
a
h
o

a
n
d
Or
e
g
o
n

D
E
Q
s
.
Se
p
t
e
m
b
e
r

2
0
0
6
:

F
W
S

a
n
d

N
M
F
S

a
d
v
i
s
e
FE
R
C

t
h
a
t

t
h
e

a
g
e
n
c
i
e
s

n
e
e
d

a
d
d
i
t
i
o
n
a
l
in
f
o
r
m
a
t
i
o
n

t
o

i
n
i
t
i
a
t
e

c
o
n
s
u
l
t
a
t
i
o
n
.
Ja
n
u
a
r
y

2
0
0
7

t
o

P
r
e
s
e
n
t
:

4
0
1

c
e
r
t
i
f
i
c
a
t
i
o
n
re
q
u
e
s
t

u
n
d
e
r

r
e
v
i
e
w

b
y

I
d
a
h
o

a
n
d

O
r
e
g
o
n
DE
Q
s
.
Se
p
t
e
m
b
e
r

2
0
0
6

t
o

P
r
e
s
e
n
t
:

I
P
C
,

F
W
S
,
NM
F
S
,

a
n
d

F
E
R
C

a
r
e

w
o
r
k
i
n
g
co
o
p
e
r
a
t
i
v
e
l
y

t
o

a
d
d
r
e
s
s

E
S
A

c
o
n
c
e
r
n
s
re
s
u
l
t
i
n
g

i
n

a

B
i
o
l
o
g
i
c
a
l

O
p
i
n
i
o
n
.
FE
R
C

i
s
s
u
e
s

f
i
n
a
l

N
E
P
A

d
o
c
u
m
e
n
t
,
w
h
i
c
h
in
c
o
r
p
o
r
a
t
e
s

4
0
1

c
e
r
t
i
f
i
c
a
t
i
o
n
s

f
r
o
m

I
d
a
h
o

a
n
d
Or
e
g
o
n
,
a
l
o
n
g

w
i
t
h

t
h
e

r
e
s
u
l
t

o
f

t
h
e

f
o
r
m
a
l

E
S
A
co
n
s
u
l
t
a
t
i
o
n
.

D
a
t
e

d
e
p
e
n
d
s

o
n

t
i
m
i
n
g

o
f

E
S
A
co
n
s
u
l
t
a
t
i
o
n

a
n
d

4
0
1

w
a
t
e
r

q
u
a
l
i
t
y

c
e
r
t
i
f
i
c
a
t
i
o
n
.
-D
A
t
I
)
PO
W
E
R

An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
"f
e
Re
g
u
l
a
t
o
r
y

O
v
e
r
v
i
e
w
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
Id
a
h
o

R
e
t
a
i
l

J
u
r
i
s
d
i
c
t
i
o
n
St
a
t
e
m
e
n
t

o
f

P
o
l
i
c
y

a
n
d

C
o
d
e

o
f

C
o
n
d
u
c
t
DS
M

i
n
c
e
n
t
i
v
e

p
r
o
g
r
a
m
Ac
c
o
u
n
t
i
n
g

o
r
d
e
r

r
e
g
a
r
d
i
n
g

p
e
n
s
i
o
n

a
n
d

p
o
s
t
r
e
t
i
r
e
m
e
n
t

b
e
n
e
f
i
t
s
20
0
6

I
n
t
e
g
r
a
t
e
d

R
e
s
o
u
r
c
e

P
l
a
n

(
I
R
P
)
Fi
x
e
d

C
o
s
t

A
d
j
u
s
t
m
e
n
t

(
F
C
A
)

m
e
c
h
a
n
i
s
m
ID
A
H
O
~P
O
W
E
R
~
Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
co
n
t
i
n
u
e
d
)
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
~
O
r
e
g
o
n

Re
t
a
i
l

J
u
r
i
s
d
i
c
t
i
o
n
De
f
e
l
T
e
d

a
c
c
o
u
n
t
i
n
g

r
e
q
u
e
s
t

(
p
o
w
e
r

s
u
p
p
l
y

ex
p
e
n
s
e
s
)
-
P
U
R
P

20
0
6

I
R
P
~
F
E
R
C

Ju
r
i
s
d
i
c
t
i
o
n
-
'
Op
e
n

A
c
c
e
s
s

T
r
a
n
s
m
i
s
s
i
o
n

T
a
r
i
f
f

(
O
A
T
T
)

f
i
l
i
n
g
St
a
n
d
a
r
d

o
f

C
o
n
d
u
c
t

N
O
P
R
ID
A
H
O
~P
O
W
E
R
~
Id
a
h
o

P
o
w
e
r
Hi
s
t
o
r
y

o
f

t
h
e

PC
A
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
$.

P
C
A

a
p
p
r
o
v
e
d

i
n

19
9
2
19
9
3

t
o

2
0
0
0

A
d
j
u
s
t
m
e
n
t
s
Fi
v
e

i
n
c
r
e
a
s
e
s

a
m
o
u
n
t
i
n
g

t
o

$
6
1
.
1
m
i
l
l
i
o
n
Th
r
e
e

d
e
c
r
e
a
s
e
s

a
m
o
u
n
t
i
n
g

t
o

$
5
7
.
6
m
i
l
l
i
o
n
20
0
1

T
w
o

I
n
c
r
e
a
s
e
s
:
-
M
a
y

$
1
6
8
M

(1

y
e
a
r
)
Oc
t
o
b
e
r

$
4
9
M

(1

y
e
a
r
)
~
2
0
0
2

in
c
r
e
a
s
e

o
v
e
r

b
a
s
e

r
a
t
e
s

o
f

$
2
4
0
.
5
m
i
l
l
i
o
n
\1
A
i

20
0
3

i
n
c
r
e
a
s
e

o
v
e
r

b
a
s
e

r
a
t
e
s

o
f

$
8
1
.
0
m
i
l
l
i
o
n
ID
A
H
O
PC
M
I
E
R
0
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Po
w
e
r

C
o
s
t
Ad
j
u
s
t
m
e
n
t

Me
c
h
a
n
i
s
m
An
n
u
a
l

a
d
j

u
s
t
m
e
n
t

t
o

I
d
a
h
o

j
u
r
i
s
d
i
c
t
i
o
n
a
l

r
a
t
e
s

to

c
r
e
a
t
e

a

r
e
v
e
n
u
e

s
t
r
e
a
m

t
h
a
t

m
o
r
e
cl
o
s
e
l
y

m
a
t
c
h
e
s

p
o
w
e
r

s
u
p
p
l
y

e
x
p
e
n
s
e
s

i
n
c
l
u
d
i
n
g

f
u
e
l

a
n
d

p
u
r
c
h
a
s
e
d

p
o
w
e
r

n
e
t

o
f

o
f
f
-
sy
s
t
e
m

s
a
l
e
s
.
PC
A

a
l
l
o
w
s

I
d
a
h
o

P
o
w
e
r

t
o

s
e
t

a
n
n
u
a
l

p
o
w
e
r

c
o
s
t
s

i
n

I
d
a
h
o

a
n
d

p
a
s
s

9
0
%

o
f

t
h
e

c
o
s
t
th
a
t

e
x
c
e
e
d
s

t
h
i
s

a
m
o
u
n
t

o
n

t
o

c
u
s
t
o
m
e
r
s
.

M
e
c
h
a
n
i
s
m

m
i
t
i
g
a
t
e
s

h
y
d
r
o

p
r
e
c
i
p
i
t
a
t
i
o
n
va
r
i
a
t
i
o
n
.
oi!
i
PC
A

I
n
c
r
e
a
s
e
s

O
v
e
r

B
a
s
e

R
a
t
e
s

(
P
C
A

Y
e
a
r
)
30
0
25
0
20
0
15
0
10
0
25
5
19
9
3

19
9
4

19
9
5

19
9
6

19
9
7

19
9
8

19
9
9

20
0
0

20
0
1

20
0
2

2
0
0
3

20
0
4

2
0
0
5

20
0
6
DA
C
O
R
P
.
St
a
n
d
a
r
d

&

P
o
o
r
s
M
e
e
t
i
n
g
La
M
o
n
t

K
e
e
n
Pr
e
s
i
d
e
n
t

&

C
E
O
Ma
r
c
h

7
,
2
0
0
7
Or
g
a
n
i
z
a
t
i
o
n

S
t
r
u
c
t
u
r
e
20
0
6
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Re
g
u
l
a
t
e
d
ID
A
H
O
~P
O
W
E
R
~
"
N
o
n
-
Re
g
u
l
a
t
e
d
An

1
0
A
C
O
R
P

C
o
m
p
a
n
y
LT
E
m
r
ID
A
C
O
M
M
An

I
D
A
C
D
R
P

c
o
m
p
a
n
y
An

I
D
A
C
O
R
P

c
o
m
p
a
n
y
II
I
F

In
q
c
O
R
P
FI
N
A
N
C
I
A
L
ID
A
T
E
C
H
~
An

I
D
A
C
O
R
P

c
o
m
p
a
n
y
ID
A
H
O
PO
U
V
E
R
~
Or
g
a
n

i
z
a
t
i
o
n

St
r
u
c
t
u

r
e
20
0
7
An

I
D
A
C
O
R
P

co
m
p
a
n
y
ID
A
H
O
a3
!

PO
W
E

R

DA
C
O
R
P
.
Re
g
u
l
a
t
e
d

No
n
-
Re
g
u
l
a
t
e
d
w.
~T
E
~
An

I
D
A
C
O
R
P

co
m
p
a
n
y
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
ID
A
H
O
~P
O
W
E
R
~
An

I
O
A
C
O
R
P

C
o
m
p
a
n
y
Ba
c
k
-
t
o
-
Ba
s
i
c
s
Ba
c
k
-
to
-
ba
s
i
c
s

s
t
r
a
t
e
g
y

e
m
p
h
a
s
i
z
e
s

I
d
a
h
o

P
o
w
e
r

a
s

I
D
A
C
O
R
P
'
s
c
o
r
e
bu
s
i
n
e
s
s
Re
g
u
l
a
t
e
d
,
v
e
r
t
i
c
a
l
l
y

i
n
t
e
g
r
a
t
e
d

u
t
i
l
i
t
y
i!
j
As

o
f

D
e
c
e
m
b
e
r

3
1
,

2
0
0
6
47
1
,
77
6

g
e
n
e
r
a
l
bu
s
i
n
e
s
s

c
u
s
t
o
m
e
r
s
Pr
i
m
a
r
y
Di
s
t
r
i
b
u
t
i
o
n
Se
c
o
n
d
a
r
y
Di
s
t
r
i
b
u
t
i
o
n
Tr
a
n
s
m
i
s
s
i
o
n
Su
b
s
t
a
t
i
o
n
Ho
u
s
e
Vi
s
i
o
n
Va
l
u
e
s
Mi
s
s
i
o
n
To

b
e

R
e
g
a
r
d
e
d

a
s

a
n
Ex
c
e
p
t
i
o
n
a
l

U
t
i
l
i
t
y
In
t
e
g
r
i
t
y
,

S
a
f
e
t
y

a
n
d

R
e
s
p
e
c
t
Pr
o
s
p
e
r

b
y

p
r
o
v
i
d
i
n
g

r
e
l
i
a
b
l
e
,
re
s
p
o
n
s
i
b
l
e
,

f
a
i
r
-
pr
i
c
e
d

e
n
e
r
g
y
se
r
v
i
c
e
s
,

t
o
d
a
y

a
n
d

t
o
m
o
r
r
o
w
.
Cr
i
t
i
c
a
l

S
u
c
c
e
s
s

F
a
c
t
o
r
s
Fi
n
a
n
c
i
a
l

S
t
r
e
n
g
t
h
'
'
..
.
'
,
.
,
'
'
,
..

'
..
'
.
.
.
'
'
.
'
"
"
'
'
!$
a
f
e
,
En
g
a
g
e
d
.E
f
f
e
c
t
i
v
e
Em
p
l
o
y
e
e
s
i.'
.."
/
.
.
'
...
.i.

'
..
'
En
h
a
n
c
e

R
e
l
a
t
i
o
n
s
h
i
p
s

a
n
d

C
o
m
m
u
n
i
c
a
t
i
o
n

w
i
t
h

a
l
l

o
u
r

S
t
a
k
e
h
o
l
d
e
r
s
ID
A
H
O
.:
!
!

PO
W
E
R

Th

r
e
e
-
pa
r
t
Ca
p
i
t
a
l

P
r
o
g
r
a
m
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Cu
s
t
o
m
e
r

g
r
o
w
t
h
~
E
x
p
a
n
d
e
d

re
l
i
a
b
i
l
i
t
y

s
t
a
n
d
a
r
d
s
Ma
i
n
t
a
i
n
i
n
g

o
u
r

r
e
s
o
u
r
c
e

b
a
s
e
-
H
y
d
r
o

pr
o
j
e
c
t

r
e
l
i
c
e
n
s
i
n
g
En
v
i
r
o
n
m
e
n
t
a
l

u
p
g
r
a
d
e
s

a
t

t
h
e
r
m
a
l

f
a
c
i
l
i
t
i
e
s
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

co
m
p
a
n
y
Re
s
o
u

r
c
e

Co
r
n
e
r
s
t
o
n
e
s
;2
)

Pr
e
s
e
r
v
e

t
h
e

b
a
s
e
~
E
n
e
r
g
y

ef
f
i
c
i
e
n
c
y
~
R
e
n
e
w
a
b
l
e

en
e
r
g
y

r
e
s
o
u
r
c
e
s
Co
n
v
e
n
t
i
o
n
a
l

b
a
s
e

l
o
a
d

r
e
s
o
u
r
c
e
s
ID
A
H
O
PO
W
E
R

An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
;;
;
f
,
~
"
Y';
'
" .
f;
g
~

:

.
St
a
n
d
a
r
d

&

P
o
o
r
Me
e
t
i

n
g
Ri
c

G
a
l
e
VP

R
e
g
u
l
a
t
o
r
y

A
f
f
a
i
r
s
Ma
r
c
h

7
,
2
0
0
7
ID
A
H
O
~P
O
W
E
R
~
An

I
D
A
C
O
R
P

co
m
p
a
n
y
Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
1$
'

Id
a
h
o

R
e
t
a
i
l

J
u
r
i
s
d
i
c
t
i
o
n
St
a
t
e
m
e
n
t

o
f

P
o
l
i
c
y

a
n
d

C
o
d
e

o
f

C
o
n
d
u
c
t
DS
M

i
n
c
e
n
t
i
v
e

p
r
o
g
r
a
m
Ac
c
o
u
n
t
i
n
g

o
r
d
e
r

r
e
g
a
r
d
i
n
g

p
e
n
s
i
o
n

a
n
d

p
o
s
t
r
e
t
i
r
e
m
e
n
t

b
e
n
e
f
i
t
s
20
0
6

I
n
t
e
g
r
a
t
e
d

R
e
s
o
u
r
c
e

P
l
a
n

(
I
R
P
)
Fi
x
e
d

C
o
s
t

A
d
j
u
s
t
m
e
n
t

(
F
C
A
)

m
e
c
h
a
n
i
s
m
Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
(c
o
n
t
i
n
u
e
d
)
ID
A
H
O
~P
O
W
E
R
0
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
~
O
r
e
g
o
n

Re
t
a
i
l

J

ll
r
i
s
d
i
c
t
i
o
n
De
f
e
l
T
e
d

a
c
c
o
u
n
t
i
n
g

r
e
q
u
e
s
t

(
p
o
w
e
r

s
u
p
p
l
y

ex
p
e
n
s
e
s
)
-
P
U
R
P

20
0
6

I
R
P
~
F
E
R
C

Ju
r
i
s
d
i
c
t
i
o
n
-
'
Op
e
n

A
c
c
e
s
s

T
r
a
n
s
m
i
s
s
i
o
n

T
a
r
i
f
f

(
O
A

TT
)

f
i
l
i
n
g
St
a
n
d
a
r
d

o
f

C
o
n
d
u
c
t

N
O
P
R
ID
A
H
O
~P
O
W
E
R
0
Id
a
h
o

P
o
w
e
r
Hi
s
t
o
r
y

o
f

t
h
e

PC
A
An

I
D
A
C
O
R
P

co
m
p
a
n
y
PC
A

a
p
p
r
o
v
e
d

i
n

19
9
2
19
9
3

t
o

20
0
0

Ad
j
u
s
t
m
e
n
t
s
Fi
v
e

i
n
c
r
e
a
s
e
s

a
m
o
u
n
t
i
n
g

t
o

$
6
1
.
1
m
i
l
l
i
o
n
Th
r
e
e

d
e
c
r
e
a
s
e
s

a
m
o
u
n
t
i
n
g

t
o

$
5
7
.
6
m
i
l
l
i
o
n
20
0
1

Tw
o

I
n
c
r
e
a
s
e
s
:
-
M
a
y

$
1
6
8
M

(1

y
e
a
r
)
-
'
Oc
t
o
b
e
r

$
4
9
M

(1

y
e
a
r
)
20
0
2

in
c
r
e
a
s
e

o
v
e
r

b
a
s
e

r
a
t
e
s

o
f

$
2
4
0
.
5
m
i
l
l
i
o
n
20
0
3

in
c
r
e
a
s
e

o
v
e
r

b
a
s
e

r
a
t
e
s

o
f

$
8
1
.
0
m
i
l
l
i
o
n
ID
A
H
O
~P
O
W
E
R
e
An

I
D
A
C
O
R
P

C
o
m
p
a
n
y
Po
w
e
r

C
o
s
t
Ad
j
u
s
t
m
e
n
t

Me
c
h
a
n
i
s
m
An
n
u
a
l

a
d
j

us
t
m
e
n
t

t
o

I
d
a
h
o

j
u
r
i
s
d
i
c
t
i
o
n
a
l

r
a
t
e
s

t
o

c
r
e
a
t
e

a

r
e
v
e
n
u
e

s
t
r
e
a
m

t
h
a
t

m
o
r
e
cl
o
s
e
l
y

m
a
t
c
h
e
s

p
o
w
e
r

s
u
p
p
l
y

e
x
p
e
n
s
e
s

i
n
c
l
u
d
i
n
g

f
u
e
l

a
n
d

p
u
r
c
h
a
s
e
d

p
o
w
e
r

n
e
t

o
f

o
f
f
-
sy
s
t
e
m

s
a
l
e
s
.
PC
A

a
l
l
o
w
s

I
d
a
h
o

P
o
w
e
r

t
o

s
e
t

a
n
n
u
a
l

p
o
w
e
r

c
o
s
t
s

i
n

I
d
a
h
o

a
n
d

p
a
s
s

9
0
%

o
f

t
h
e

c
o
s
t
th
a
t

e
x
c
e
e
d
s

t
h
i
s

a
m
o
u
n
t

o
n

t
o

c
u
s
t
o
m
e
r
s
.

M
e
c
h
a
n
i
s
m

m
i
t
i
g
a
t
e
s

h
y
d
r
o

p
r
e
c
i
p
i
t
a
t
i
o
n
va
r
i
a
t
i
o
n
.
'0
;
PC
A

I
n
c
r
e
a
s
e
s

O
v
e
r

B
a
s
e

R
a
t
e
s

(
P
C
A

Y
e
a
r
)
30
0
25
0
20
0
15
0
10
0
25
5
19
9
3

19
9
4

19
9
5

19
9
6

19
9
7

19
9
8

19
9
9

20
0
0

2
0
0
1

20
0
2

2
0
0
3

20
0
4

20
0
5

20
0
6
:t
:
-
:I
:
"t
J
:t
:
-
('
)
:I
:
:t
:
-
('
)
"t
J
"t
J
('
)
('
)
:I
:
('
)
"t
J
'"
"
-
J
:t
:
-
..

..
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

..
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

..
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

..
.
.
.

.
.
.
.
.

.
.
.
.

..
.
.
.

.
.
.
.

..
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

..
.
.
.

.
.
.
.

.
.
.
.

..
.

..
.
.

.
.
.
.

.
.
.
.

..
.
.
.

.
.
.
.

.
.
.
.

.
.
.
.

.
.
EE
l

F
i
n
a
n
c
i
a
l

C
o
n
f
e
r
e
n
c
e
An
a
l
y
s
t

I
n
f
o
r
m
a
t
i
o
n
La
s

V
e
g
a
s
,
N
e
v
a
d
a
No
v
e
m
b
e
r

2
0
0
6
.~

~..
.
.
.

..
.

~..
.
.
.
.
.

w
w

..
.
.
.

.
.
.

~..
.
.

..
.

..
.
.
.
.
.
DA
C
O
R
P
.
Fo
r
w
a
r
d

L
o
o
k
i
n
g
In
f
o
r
m
a
t
i
o
n
Bo
i
s
e
,
I
d
i
i
h
o
-
ba
s
l
'
d

I
D
A
C
O
R
P
,

I'
o
r
m
e
d

i
n

1
9
9
8
,

i
s

a

h
o
l
d
i
n
g

c
o
m
p
a
n
y

c
o
m
p
r
i
s
e
d

o
r

I
d
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
,

a

r
e
g
u
l
a
t
e
d

e
l
e
c
t
r
i
c

ut
i
l
i
t
y
;

I
D
A
C
O
R
P
Fi
n
a
n
c
i
a
l
,

a

h
o
l
d
e
r

o
r

a
f
f
o
r
d
a
b
l
e

h
o
u
s
i
n
g

p
r
o
j
e
c
t
s

a
n
d

o
t
h
e
r

r
e
a
l

es
t
i
i
t
e

i
n
v
e
s
t
m
e
n
t
s
;

I
D
A
C
O
M
M
.

a

p
r
o
v
i
d
e
r

o
r

t
e
l
e
c
o
m
m
u
n
i
c
a
t
i
o
n

s
e
r
v
i
c
e
s

a
n
d
co
m
m
e
r
c
i
a
l
l
n
t
e
r
n
l
'
!

s
e
r
v
i
c
e
s
;

a
n
d

I
L
i
a
-
We
s
t

E
n
e
r
g
y
.

a
n

o
p
e
r
a
t
o
r

o
r

s
m
a
l
l

h
y
d
r
o
e
l
e
c
t
r
i
c

g
e
n
e
r
a
t
i
o
n

p
r
o
j
e
c
t
s

t
h
a
t

s
a
t
i
s
l
'
y

th
e

r
e
q
u
i
r
e
m
e
n
t
s

o
r

L
h
e

P
u
b
l
i
c
Ut
i
l
i
t
y

R
e
g
u
l
a
t
o
r
y

P
o
l
i
c
i
e
s

A
c
t

o
r

19
7
'
1
'
"
Ce
r
t
a
i
n

s
L
a
t
e
m
e
n
t
s

c
o
n
t
a
i
n
e
d

i
n

t
h
i
s

p
r
e
s
e
n
t
a
t
i
o
n
.

i
n
c
l
u
d
i
n
g

s
t
a
l
e
m
e
n
t
s

w
i
t
h

r
e
s
p
e
c
t

t
o

r
u
t
u
r
e

e
a
r
n
i
n
g
s
.
o
n
g
o
i
n
g

o
p
e
r
a
t
i
o
n
s
.

a
n
d

l'i
n
a
n
c
i
a
1

c
o
n
d
i
t
i
o
n
s
ar
c

"
I'
o
r
w
a
r
d
-
Io
o
k
i
n
g

s
l
a
t
e
m
e
n
(
s
"
w
i
l
h
i
n
t
h
e

m
e
a
n
i
n
g

o
r

I'
~
d
e
r
a
l

s
e
c
u
r
i
t
i
e
s

l
a
w
s
.

Al
l
h
o
u
g
h

I
D
A
C
O
R
P

a
n
J
l
(
h
~
l
O

P
o
w
e
r

b
e
l
i
e
v
e

t
h
a
t

t
h
e

e
x
p
e
c
t
a
t
i
o
,
an
d

a
s
s
u
m
p
t
i
o
n
s

r
e
l
k
c
t
e
d

i
n

t
h
e
s
e

r
o
r
w
a
r
d
-
Io
o
k
i
n
g

s
t
a
t
e
m
e
n
t
s

a
r
c

r
e
a
s
o
n
a
b
l
e
,
t
h
e
s
e

s
l
a
t
e
m
e
n
t
s

i
n
v
o
l
v
e

a

n
u
m
b
e
r

o
r

r
i
s
k
s

a
n
d

u
n
c
e
r
t
a
i
n
t
i
e
s
,
a
n
d

a
c
t
u
a
l
re
s
u
l
t
s

m
a
y

d
i
l
l
e
I
'

m
a
t
e
r
i
a
l
l
y

I
'
r
o
m
l
h
e

r
e
s
u
l
t
s

d
i
s
c
u
s
s
e
d

i
n

t
h
e

s
t
a
t
e
m
e
n
t
s
.

F
a
c
(
o
r
s

t
h
a
t

c
o
u
l
d

c
a
u
s
e

ac
t
u
e
d

r
e
s
u
l
t
s

1
0

e
l
i
/
l
e
I
'

m
a
t
e
r
i
a
l
l
y

I'r
o
m

t
h
e

I
'
o
r
w
a
r
d
-
!o
o
k
i
n
g

s
t
a
t
e
m
e
n
t
s

i
n
c
l
u
d
e
:

c
h
a
n
g
e
s

i
n

g
o
v
e
r
n
m
e
n
t
a
l

p
o
l
i
c
i
e
s
,
i
n
c
l
u
d
i
n
g

n
e
w

i
n
t
e
r
p
r
e
t
a
t
i
o
n
s

o
r

e
x
i
s
t
i
n
g

p
o
l
i
c
i
e
s
,

an
e
l

r
e
g
u
l
a
t
o
r
y

a
c
t
i
o
n
s

a
n
d
re
g
u
l
a
t
o
r
y

a
u
d
i
t
s
,

i
n
c
l
u
d
i
n
g

t
h
o
s
e

o
r

t
h
e

F
e
d
e
r
a
l

E
n
e
r
g
y

R
e
g
u
l
a
l
o
r
y

C
o
m
m
i
s
s
i
o
n
,
t
h
e

I
d
a
h
o

P
u
b
l
i
c

U
t
i
l
i
t
i
e
s

C
o
m
m
i
s
s
i
o
n
.

(
h
e

O
r
e
g
o
n

P
u
b
l
i
c

U
t
i
l
i
t
y
Co
m
m
i
s
s
i
o
n

a
n
d

I
h
e

I
n
t
e
r
n
a
l

R
e
v
e
n
u
e

S
e
r
v
i
c
e

w
i
t
h

r
e
s
p
e
c
l
l
o

a
l
l
o
w
e
d

r
a
t
e
s

o
r

r
e
t
u
r
n
,

i
n
d
u
s
t
r
y

el
i
l
d

r
a
t
e

s
t
r
u
c
t
u
r
e
.

c
l
a
y
-
eo
-
cl
a
y

b
u
s
i
n
e
s
s

o
p
e
r
u
t
i
o
n
s
el
c
l
J
u
i
s
i
t
i
o
n

a
n
d

d
i
s
p
o
,
sa
l

o
r

a
s
s
e
t
s

a
n
d

I
'
a
e
i
l
i
t
i
e
s
,
o
p
e
r
a
t
i
o
n

a
n
d

c
o
n
s
t
r
u
c
t
i
o
n

o
f

p
l
a
n
t

f
a
c
i
l
i
t
i
e
s
,
r
e
l
i
c
e
n
s
i
n
g

o
r

h
y
d
r
o
e
l
e
c
t
r
i
c

p
r
o
j
e
c
t
s
,

r
e
c
o
v
e
r
y

o
r
pu
r
c
h
a
s
e
d

p
o
w
e
r

e
x
p
e
n
s
e
s
.

r
e
c
o
v
e
r
y

o
r

o
t
h
e
r

c
a
p
i
t
a
l

i
n
v
e
s
t
m
e
n
t
s
,
p
r
e
s
e
n
t

o
r

p
r
o
s
p
e
c
t
i
v
e

w
h
o
l
e
s
a
l
e

a
n
d

r
e
t
a
i
l

c
o
m
p
e
t
i
t
i
o
n

(
i
n
c
l
u
d
i
n
g

b
u
t

n
o
t
l
i
m
i
(
e
d

t
o
re
t
a
i
l

w
h
e
e
l
i
n
g

a
n
d

t
r
a
n
s
m
i
s
s
i
o
n

c
o
s
t
s
)

a
n
d

o
t
h
e
r

r
e
r
u
n
d

p
r
o
c
e
e
d
i
n
g
s
;

c
h
a
n
g
e
s

a
r
i
s
i
n
g

f
r
o
m

(
h
e

E
n
e
r
g
y

P
o
l
i
c
y

A
c
t

o
r

2(
)
(
)
5
:

l
i
t
i
g
a
t
i
o
n

a
n
d

r
e
g
u
l
a
t
o
r
y
pr
o
c
e
e
d
i
n
g
s
.

i
~
l
c
l
u
d
i
n
g

t
h
o
s
e

r
e
s
u
!
(
i
n
g

I
'
r
o
m
t
h
e

e
n
e
r
g
y

s
i
t
u
a
t
i
o
n

i
n

t
h
e

w
e
s
te
r
n

U
n
i
t
e
~
1

S
t
a
t
e
s
,
a
n
d

,
tt
l
e
m
e
n
t
s

t
h
a
t

i
n
f
l
u
e
n
c
e

b
L
~s
i
n
e
s
s

a
n
d

p
r
o
f
i
t
a
b
i
l
i
t
y
;
ch
a
n
g
e
s

i
n

a
n
d

c
o
m
p
l
i
a
n
c
e

w
i
t
h

e
n
v
i
r
o
n
m
e
n
t
a
l
,

e
n
d
a
n
g
e
r
e
d

s
p
e
c
i
e
s

a
n
d

s
a
f
e
t
y

l
a
w
s

a
n
d

p
o
l
i
c
i
e
s
;

w
e
a
t
h
e
r

v
a
r
i
a
t
i
o
n
s

a
f
f
e
c
t
i
n
g

h
y
d
r
o
e
l
e
c
t
r
i
c
ge
n
e
r
a
t
i
n
g

c
o
n
d
i
t
i
o
n
s

a
n
d

c
u
s
t
o
m
e
r

e
n
e
r
g
y

u
s
a
g
e
:

o
v
e
r
-
a
p
p
r
o
p
r
i
a
t
i
o
n

o
f

su
r
l
'
a
c
e

a
n
d

g
r
o
u
n
d
w
a
t
e
r

i
n

t
h
e

S
n
a
k
e

Ri
v
e
r

B
a
s
i
n

r
e
s
u
l
t
i
n
g

i
n

r
e
d
u
c
e
d
ge
n
e
r
a
t
i
o
n

a
t

h
y
d
r
o
e
l
L
'
c
t
r
i
c

r
a
c
i
l
i
t
i
e
s
:

c
o
n
s
t
r
u
c
t
i
o
n

o
r

p
o
w
e
r

g
e
n
e
r
a
t
i
n
g

f
a
c
i
l
i
t
i
e
s

i
n
c
l
u
d
i
n
g

in
a
b
i
l
i
t
y

t
o

o
b
t
a
i
n

r
e
q
u
i
r
e
d

g
o
v
e
r
n
m
e
n
t
a
l

p
e
r
m
i
t
s

a
n
d
ap
p
r
o
v
a
l
s
,
a
n
d

r
i
s
k
s

r
e
l
a
t
e
d

t
o

c
o
n
t
r
a
c
t
i
n
g
,

c
o
n
s
t
r
u
c
t
i
o
n

a
n
d

s
t
a
r
t
-
u
p
:

o
p
e
r
a
t
i
o
n

o
f

p
o
w
e
r

g
e
n
e
r
a
t
i
n
g

f
a
c
i
l
i
t
i
e
s

i
n
c
l
u
d
i
n
g

b
r
e
a
k
d
o
w
n

o
r

f
a
i
l
l
i
r
e

o
f
eq
u
i
p
m
e
n
t
,

p
e
r
r
o
r
m
a
n
c
e

b
e
l
o
w

e
x
p
e
c
t
e
d

l
e
v
e
l
s
,
c
o
m
p
e
t
i
t
i
o
n
,

f
u
e
l

s
u
p
p
l
y
.

i
n
c
l
u
d
i
n
g

a
v
a
i
l
a
b
i
l
i
t
y
,

t
r
a
n
s
p
o
r
t
a
t
i
o
n

a
n
d

p
r
i
c
e
s
,
a
n
d

t
r
a
n
s
m
i
s
s
i
o
n
:

i
m
p
a
c
t
s
I'r
o
m

t
h
e

p
o
t
e
n
t
i
a
l

I
'
o
r
m
a
t
i
o
n

o
f

a

r
e
g
i
o
n
a
l

t
r
a
n
s
m
i
s
s
i
o
n

o
r
g
a
n
i
z
a
t
i
o
n

a
n
d

t
h
e

d
i
s
s
o
l
u
t
i
o
n

o
f

G
r
i
d

W
e
s
t
;

po
p
u
l
a
t
i
o
n

g
r
o
w
t
h

r
a
t
e
s

a
n
d

d
e
m
o
g
r
a
p
h
i
c
pa
t
t
e
r
n
,
s;

m
a
r
k
e
t

d
e
m
a
n
d

a
m
i

p
r
i
c
e
s

f
o
r

e
n
e
r
g
y
,

i
n
c
l
u
d
i
n
g

s
t
r
u
c
t
u
r
a
l

m
a
r
k
e
t

c
h
a
n
g
e
s
;

c
h
a
n
g
e
s

i
n

o
p
e
r
a
t
i
n
g

e
x
p
e
n
s
e
s

a
n
d

c
a
p
i
t
a
l

e
x
p
e
n
d
i
t
u
r
e
s

a
n
d
rl
u
c
t
u
a
t
i
o
n
,
s
i
n

s
o
u
r
c
e
s

a
n
d

u
s
e
s

o
r

c
a
s
h
;

r
e
s
u
l
t
s

0
1
'
f
i
n
a
n
c
i
n
g

e
l
T
o
r
t
s
,
i
n
c
l
u
d
i
n
g

t
h
e

a
b
i
l
i
t
y

t
o

o
b
t
a
i
n

I'
i
n
a
n
c
i
n
g

o
n

f
a
v
o
r
a
b
l
e

t
e
r
m
s
.

w
h
i
c
h

c
a
n

b
e
;t
l
l
e
c
t
e
d

b
y

I
'
a
c
l
o
r
,
s
s
u
c
b

a
s

c
r
e
d
i
t

r
a
t
i
n
g
s

a
n
d

g
e
n
e
r
a
l

e
c
o
n
o
m
i
c

c
o
n
d
i
t
i
o
n
s
:

a
c
t
i
o
n
s

b
y

c
r
e
d
i
t

r
a
t
i
n
g

a
g
e
n
c
i
e
s
.

i
n
c
l
u
d
i
n
g

c
h
a
n
g
e
s

i
n

r
a
t
i
n
g

c
r
i
t
e
r
i
a

a
n
d
ne
w

i
n
t
e
r
p
r
d
a
t
i
o
n
s

o
r

e
x
i
s
t
i
n
g

c
r
i
t
e
r
i
a
:

h
o
m
e
l
a
n
d

s
e
c
u
r
i
t
y
.

na
t
u
r
a
l

d
i
s
a
s
t
e
r
s
,
a
c
t
s

o
r

w
a
r

o
r

t
e
r
r
o
r
i
s
m
;

m
a
r
k
e
t

c
o
n
d
i
t
i
o
n
s

a
n
d

t
e
c
h
n
o
l
o
g
i
c
a
l
de
v
e
l
o
p
m
e
n
t
s

t
h
a
t

c
o
u
l
d

a
l
l
e
e
t

t
h
e

o
p
e
r
a
t
i
o
n
s

a
n
d

p
r
o
,
sp
e
c
t
s

o
r

I
D
A
C
O
R
P
'
s
s
u
b
s
i
d
i
a
r
i
e
s

o
r

t
h
e
i
r

c
o
m
p
e
t
i
t
o
r
s
;

i
n
c
r
e
a
s
i
n
g

h
e
a
l
t
h

c
a
r
e

c
o
s
t
s

a
n
d

t
h
e
re
s
u
l
t
i
n
g

e
l
T
e
c
t

o
n

h
e
a
l
t
h

i
n
s
u
r
a
n
c
e

p
r
e
m
i
u
m
s

p
a
i
d

I
'
o
r

em
p
l
o
y
e
e
s
;

p
e
r
l
'
o
r
m
a
n
c
e

o
f

t
h
e

s
t
o
c
k

m
a
r
k
e
t

a
n
d

t
h
e

c
h
a
n
g
i
n
g

i
n
t
e
r
e
s
t

r
a
t
e

e
n
v
i
r
o
n
m
e
n
t
.

wh
i
c
h
al
T
e
c
l
t
h
e

a
m
o
u
n
t

o
f

r
e
q
u
i
r
e
d

c
o
n
t
r
i
b
u
t
i
o
n
s

t
o

p
e
n
s
i
o
n

p
l
a
n
s
.

a
s

w
e
l
l

a
s

t
h
e

r
e
p
o
r
t
e
d

c
o
s
t
s

o
r

p
r
o
v
i
d
i
n
g

p
e
n
s
i
o
n

a
n
d

o
t
h
e
r

p
o
s
t
r
e
t
i
r
e
m
e
n
t

b
e
n
e
f
i
t
s
;
in
c
r
e
a
s
i
n
g

c
o
s
t
s

o
r

i
n
s
u
r
a
n
c
e
,

c
h
a
n
g
e
s

i
n

c
o
v
e
r
a
g
e

t
e
r
m
s

a
n
d

t
h
e

a
b
i
l
i
t
y

t
o

o
b
t
a
i
n

i
n
s
u
r
a
n
c
e
;

c
h
a
n
g
e
s

i
n

t
a
x

r
a
t
e
s

o
r

p
o
l
i
c
i
e
s
,
i
n
t
e
r
e
s
t

r
a
t
e
s

o
r

r
a
t
e
s

o
r
in
f
l
a
t
i
o
n
:
;l
d
o
p
t
i
o
n

o
f

o
r

c
h
a
n
g
e
s

i
n
'
c
r
i
t
i
c
a
l

a
c
c
o
~l
I
l
t
i
n
g

p
o
l
i
c
i
e
s

o
r

e
s
t
i
m
a
t
e
s
;

a
n
d

n
e
w

a
c
c
o
u
n
t
i
n
g

~)
r

S
e
c
u
r
i
t
i
e
s

a
n
d

E
x
c
h
a
n
g
e

C
o
m
m
i
s
s
i
o
n
re
q
u
i
r
e
m
e
n
t
s
.

o
r

n
e
w

i
n
t
e
r
p
r
e
t
a
t
i
o
n

o
r

a
p
p
l
i
c
a
t
i
o
n

o
r

e
x
i
s
t
i
n
g

r
e
q
u
i
r
e
m
e
n
t
s
.

A
n
y

f
o
r
w
a
r
d
-
lo
o
k
i
n
g

s
t
a
t
e
m
e
n
t

s
p
e
a
k
s

o
n
l
y

a
s

o
r

t
h
e

d
a
t
e

o
n

w
h
i
c
h

s
u
c
h
st
a
t
e
m
e
n
t

i
s

m
a
d
e
.

N
e
w

I'
a
c
t
o
r
s

e
m
e
r
g
e

r
r
o
m

t
i
m
e

t
o

t
i
m
e

a
n
d

it

i
s

n
o
(

p
o
s
s
i
b
l
e

f
o
r

m
a
n
a
g
e
m
e
n
t

t
o

p
r
e
d
i
c
t

a
l
l

s
u
c
h

I'
a
c
t
o
r
s
.

n
o
r

c
a
n

i
t

a
s
s
e
s
s

th
e
im
p
a
c
t

o
r

a
n
y

s
u
c
h

r
a
c
t
o
r

o
n

t
h
e

b
u
s
i
n
e
s
s

o
r

t
h
e

e
x
t
e
n
t

t
o

w
h
i
c
h

a
n
y

f
a
c
t
o
r
,

o
r

c
o
m
b
i
n
a
t
i
o
n

o
f

I
'
a
c
t
o
r
s
,
m
a
y

c
a
u
s
e

r
e
s
u
l
t
s

t
o

d
i
f
f
e
r

m
a
t
e
r
i
a
l
l
y

f
r
o
m
tb
o
s
e

c
o
n
t
a
i
n
e
d

i
n

a
n
y

f
o
r
w
a
r
d
-
lo
o
k
i
n
g

s
t
a
t
e
m
c
n
t
.
.~

..
.
.
.
.

~.~
.
.
.

._
~
.
~
_
.
.
.

-..

~_
.
.
.
_
.
_
.
_
-

.-
-
-
-
-
.
Ta
b
l
e

o
f

C
o
n
t
e
n
t
s
.
"
"
,
,
,
~
.
,
.
.
.
-
,
p
,
'
~f
f
'~
;
i
,
tJ
:
, .
'
DA
C
O
R
P
.
~~
'
Ov
e
r
v
i
e
w
Or
g
a
n
i
z
a
t
i
o
n

s
t
r
u
c
t
u
r
e
'-
,
Ou
r

c
o
r
e

b
u
s
i
n
e
s
s
Se
r
v
i
c
e

t
e
r
r
i
t
o
r
y
20
0
6

a
c
c
o
m
p
l
i
s
h
m
e
n
t
s

t
o

d
a
t
e
St
o
c
k

p
r
i
c
e

c
o
m
p
a
r
i
s
o
n
To
t
a
l

s
h
a
r
e
h
o
l
d
e
r

r
e
t
u
r
n
ID
A
C
O
R
P

s
u
b
s
i
d
i
a
r
y

c
o
n
t
r
i
b
u
t
i
o
n
s
Cr
e
d
i
t

r
a
t
i
n
g
s
Id
a
h
o

P
o
w
e
r

o
v
e
r
v
i
e
w
Id
a
h
o

P
o
w
e
r

b
i
l
l
i
n
g

c
o
m
p
a
r
i
s
o
n
s
Re
g
u
l
a
t
o
r
y

p
r
o
c
e
e
d
i
n
g
s

-

r
e
t
a
i
l
In
t
e
g
r
a
t
e
d

R
e
s
o
u
r
c
e

P
l
a
n

(
I
R
P
)

2
0
0
6

p
r
e
f
e
r
r
e
d

p
o
r
t
f
o
l
i
o
20
0
6

I
R
P

g
o
a
l
s
IR
P

p
u
b
l
i
c

p
o
l
i
c
y

i
s
s
u
e
s
Hy
d
r
o
p
o
w
e
r

p
r
o
j
e
c
t

r
e
l
i
c
e
n
s
i
n
g

s
c
h
e
d
u
l
e
Hy
d
r
o

s
y
s
t
e
m

m
a
p
FE
R
C
'
s
c
u
r
r
e
n
t

s
c
h
e
d
u
l
e
Br
o
w
n
l
e
e

r
e
s
e
r
v
o
i
r

i
n
f
l
o
w
s
30

&

9
0
-
da
y

t
e
m
p
e
r
a
t
u
r
e

f
o
r
e
c
a
s
t
30

&

9
0
-
da
y

p
r
e
c
i
p
i
t
a
t
i
o
n

f
o
r
e
c
a
s
t
I
1
r-
-~
~
-
~

~
-

~-

-

-

-

-~
~
-
-
~

~
-
~

~~
-

--
~
-
-
~
-

~-
~
~
-
~

-
~
-
-
.
81
8
DA
C
O
R
P
.
Ov
e
r
v
i
e
w
Ve
r
t
i
c
a
l
l
y

i
n
t
e
g
r
a
t
e
d

r
e
g
u
l
a
t
e
d

e
l
e
c
t
r
i
c

u
t
i
l
i
t
y
Ra
t
e
s

a
n
d

p
r
o
d
u
c
t
i
o
n

c
o
s
t
s

a
n
l
o
n
g

l
o
w
e
s
t

i
n

n
a
t
i
o
n
So
l
i
d

i
n
v
e
s
t
m
e
n
t

g
r
a
d
e

r
a
t
i
n
g
Re
g
u
l
a
t
o
r
y

a
c
h
i
e
v
e
m
e
n
t
s
Fo
c
u
s

o
n

c
o
r
e

u
t
i
l
i
t
y
Du
a
l

g
o
a
l
s
:
Re
l
i
a
b
l
e

e
l
e
c
t
r
i
c

s
e
r
v
i
c
e

a
t

f
a
i
r

p
r
i
c
e
s

f
o
r

t
h
e

c
l
l
s
t
o
l
n
e
r
s
Co
n
s
i
s
t
e
n
t
l
y

r
e
g
i
s
t
e
r

s
t
r
o
n
g

f
i
n
a
n
c
i
a
l

p
e
r
f
o
n
n
a
n
c
e

f
o
r

t
h
e

s
h
a
r
e
o
w
n
e
r
s
r
-

-
-

-

-

-

-

-

-

-

-

-

-

-

~
-

-

--

~
-

-
-

~

-
-

-

-

-

-

-

-

-

-

~
-

-
-

-

~

DA
C
O
R
P
.
Or
g
a
n
i
z
a
t
i
o
n

S
t
r
u
c
t
u
r
e
DA
C
O
R
P
.
Re
g
u
l
a
t
e
d
DA
I
-
I
)
~P
O
W
E
R
$
An

I
D
A
C
O
R
P

co
m
p
a
n
y
.
C
o
m
b
i
n
a
t
i
o
n

h
y
d
r
o
-
th
e
r
m
a
l

u
t
i
l
i
t
y
.
C
u
s
t
o
m
e
r

g
r
o
w
t
h

3
.
2%

C
A
G
R
.
O
v
e
r

4
6
4
00
0

r
e
t
a
i
l

c
u
s
t
o
m
e
r
s

i
n

I
d
a
h
o
/
Or
e
g
o
n
.2
4
00
0

s
q

m
i
l
e

s
e
r
v
i
c
e

t
e
r
r
i
t
o
r
y
.3
,
08
5

M
W

o
f

g
e
n
e
r
a
t
i
o
n

c
a
p
a
c
i
t
y
ID
A
-
W
E
S
T
EN
E
R
G
Y
No
n
-
Re
g
u
l
a
t
e
d
An

I
D
A
C
O
R
P

co
m
p
a
n
y
.
T
o
t
a
l

p
o
r
t
f
o
l
i
o

c
o
n
s
i
s
t
s

o
f

7
0
0
pr
o
p
e
r
t
i
e
s

l
o
c
a
t
e
d

i
n

P
u
e
r
t
o
Ri
c
o
,
t
h
e

U
S

V
i
r
g
i
n

I
s
l
a
n
d
s
an
d

a
l
l

U
S

s
t
a
t
e
s

e
x
c
e
p
t
Al
a
s
k
a
.
.
$
1
7
5

m
i
l
l
i
o
n

p
o
r
t
f
o
l
i
o
.
.
O
w
n
s

&

o
p
e
r
a
t
e
s

9

h
y
d
r
o
e
l
e
c
t
r
i
c
pr
o
j
e
c
t
s

i
n

I
d
a
h
o

a
n
d

C
a
l
i
f
o
r
n
i
a
wi
t
h

a

t
o
t
a
l

g
e
n
e
r
a
t
i
o
n

c
a
p
a
c
i
t
y
of

a
p
p
r
o
x
i
m
a
t
e
l
y

4
5

M
W
.
No
t
e
:

ID
A
C
O
M
M

c
l
a
s
s
i
f
i
e
d

a
s

d
i
s
c
o
n
t
i
n
u
e
d

o
p
e
r
a
t
i
o
n
s
p~

~~
~
~
~
~
~
~
~

~
~
~

~~
~
~
~
~
~
~
~
W
~
~
~
~
~
~
~
~
~
.
~
.
W

~~
~
~
.
~
.
.,
.
DA
C
O
R
P
.
Ou
r

C
o
r
e

B
u
s
i
n
e
s
s
At

D
e
c
e
m
b
e
r

3
1
,
2
0
0
5
70
7
11
0
26
8
08
5
Mw

H
y
d
r
o
Mw

C
o
a
l
Mw

O
t
h
e
r
69
1

m
i
l
e
s

o
f
hi
g
h
-
v
o
l
t
a
g
e
tr
a
n
s
m
i
s
s
i
o
n

l
i
n
e
s
63
,
36
5

m
i
l
e
s

o
f
di
s
t
r
i
b
u
t
i
o
n

l
i
n
e
s
(w
i
r
e
)
At

J
u
n
e

3
0
,

2
0
0
6
mo
r
e

t
h
a
n

4
6
4
,
00
0
ge
n
e
r
a
l

b
u
s
i
n
e
s
s
cu
s
t
o
m
e
r
s
Tr
a
n
s
m
i
s
s
i
o
n
20

t
r
a
n
s
m
i
s
s
i
o
n
su
b
s
t
a
t
i
o
n
s

/
~
"
'
"
/
.
'
-
~
/
~;
:
,
-~
'
-

"

_
/
;
/
/
.
/;
'
/
::
~
--
-
. .
-:
/
:
-
:
:
/
--
-
;~
.
,
.
"
.
~
'
~
Pr
i
m
a
r
y
Di
s
t
r
i
b
u
t
i
o
n
Se
c
o
n
d
a
r
y
Di
s
t
r
i
b
u
t
i
o
n
u-

_
.
.
_~
,
Su
b
s
t
a
t
i
o
n
Ho
u
s
e
.~

~
~
~
~
~
~
~
~

~
~

~

~

~

~~
~

~
~

~
~
~

~~
~
~
~
~
~
~
~
~
~
~
~
~

~
-
~
~
~
~
.
DA
C
O
R
P
.
Id
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
Se
r
v
i
c
e

T
e
r
r
i
t
o
r
y
WA
S
H
l
N
(
;
'
I
'
O
N
mA
I
I
O
I.,
.
..
,
OR
E
(
;
O
N
Pa
y
e
t
t
e
Bo
i
s
e

.
.
.
..
.

*
..
.NE
V
A
D
A
I ,
OW
e
i
'

S
a
l
m
o
n
lI
e
l
l
s

(
;
a
l
l
"
o
l
l
MO
N
T
A
N
A
WY
O
M
I
N
(
;
Hy
d
r
o
e
l
e
c
t
r
i
c

F
a
c
i
l
i
t
i
e
s

a
n
d
Na
m
e
p
l
a
t
e

C
a
p
a
c
i
t
i
e
s
17

F
a
c
i
l
i
t
i
e
s

w
i
t
h

1
,
70
7

M
w

C
a
p
a
c
i
t
y
Th
e
r
m
a
l

F
a
c
i
l
i
t
i
e
s

a
n
d
Na
m
e
p
l
a
t
e

C
a
p
a
c
i
t
i
e
s
..
.

6

F
a
c
i
l
i
t
i
e
s

wi
t
h

1
37
8

M
w

C
a
p
a
c
i
t
y
Pla
n
n
e
d

1
7
0

M
w

N
a
t
u
r
a
l

G
a
s

T
u
r
b
i
n
e
-
O
n
-
li
n
e

2
0
0
8
..
.
""
'
,
:
J

I
I
r

Po
c
a
t
e
l
l
o
Tw
i
n

F
a
l
l
s
UT
A
H
Sh
o
s
h
o
l
l
t
~

F
a
l
l
s
r
-

-
~
~

~
-

~

-

-

-

-

~

-

-

~

-
-

~

~
-

--

~-

-

-

--
-
-

~

-
-

-
~

-

-

~
-

--
-
.
20
0
6

Ac
c
o
m
p
l
i
s
h
m
e
n
t
s
To

Da
t
e
DA
O
O
R
P
.
Cu
s
t
o
m
e
r

g
r
o
w
t
h

r
e
m
a
i
n
s

s
t
r
o
n
g
Cu
s
t
o
m
e
r

s
a
t
i
s
f
a
c
t
i
o
n

s
o
u
n
d
Il
1
c
r
e
a
s
e
d

b
a
s
e

r
a
t
e
s

i
n

Id
a
h
o

3
.
2
p
e
r
c
e
n
t

-
e
f
f
e
c
t
i
v
e

Ju
n
e

1
,
2
0
0
6
He
l
l
s

C
a
n
y
o
n

r
e
l
i
c
e
n
s
i
n
g

-
o
n

t
r
a
c
k
So
l
d

SO
l

ex
c
e
s
s

e
m
i
s
s
i
o
n

a
l
l
o
w
a
n
c
e
s
...
.
,
Re
t
a
i
n
e
d

a

p
o
r
t
i
o
n

o
f

e
m
i
s
s
i
o
n

a
l
l
o
w
a
n
c
e
s

f
o
r

f
u
t
u
r
e

f
l
e
x
i
b
i
l
i
t
y
.
M
a
n
a
g
e
d

el
e
c
t
r
i
c

s
y
s
t
e
m

t
h
r
o
u
g
h

s
e
r
i
e
s

o
f

n
e
w

p
e
a
k
s
-
N
e
w

sy
s
t
e
n
l

p
e
a
k

-
3
08
4

M
w

-
J
u
l
y

2
4
,
2
0
0
6
So
l
d

I
D
A
C
O
R
P

T
e
c
h
n
o
l
o
g
i
e
s
Co
n
t
r
a
c
t

t
o

s
e
l
l

I
D
A
C
O
M
M
r~

~.
.
~
~
.
~
~

~
~

~

~~

~~
~
~
.
~
~
~

~
~
.

~~
~
~
~
~

~~
.

~~
~

~

~~
~
~
DA
C
O
R
P
.
St
o
c
k

P
r
i
c
e

C
o
m
p
a
r
i
s
o
n
Ja
n
u
a
r
y

1
-

Se
p
t
e
m
b
e
r

2
9
,
2
0
0
6
14
5
.
14
0
.
00

-
-

-I
D
A
-D
J
U
A
S&
P
5
0
0
13
0
.
00

-

-P
E
E
R
S
-A
V
A
12
5
.
00

-
-

-P
S
D
"-

-
.
-
-
,
13
5
.
00

-
12
0
.
11
5
,
00

-
11
0
,
00

-
10
5
.
00

10
0
.
00

-
95
.
00

-
90
.
00

-
85
,
Ja
n
-
Fe
b
-
Ma
r
-
Ap
r
-
Ma
y
-
Ju
n
-
Ju
l
-
Au
g
-
Se
p
-
..

..
.
.
.
.

.
.
.

..
.
.
.
.
.
.
.

..
.
.
.
.

.
.
.

..
.
.
.
.
.
.

.
.
.
.
.
.
.
DA
C
O
R
P
.
To
t
a
l

S
h
a
r
e
h
o
l
d
e
r

Re
t
u
r
n
10

Y
e
a
r
9/
2
9
/
9
6
-
9/
2
9
/
0
6
5
Y
e
a
r
9/
2
9
/
0
1
-
9/
2
9
/
0
6
1
Y
e
a
r
9/
2
9
/
0
5
-
9/
2
9
/
0
6
1
0
0
15
0
EJ

I
D
A
S&
P

5
0
0

.

D
o
w

Jo
n
e
s

U
t
i
l
i
t
i
e
s
12
.
29
,
20
0
25
0
30
0
35
0
40
0
..

..
.
.
.
.

..
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.

..
.
.

.
.
.
,
DA
C
a
F
.
ID
A
C
O
R
P
Su
b
s
i
d
i
a
r
y

C
o
n
t
r
i
b
u
t
i
o
n
s
12

M
o
n
t
h
s
En
d
e
d
CY

2
0
0
2
CY

2
0
0
3
CY

2
0
0
4
CY

2
0
0
5
Ju
n
e

3
0
,

2
0
0
6
Id
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
$
2
.
1.
7
1
1.
7
0
1.
9
9
ID
A
C
O
R
P

E
n
e
r
g
y
c(
O
.
39
:
:
:
-
c(
O
.
25
:
:
:
-
ID

A

C
O

R
P

Fi
n
a
n
c
i
a
l
Id
a
-

W
e
s
t

E
n
e
r
g
y
c(
O
.
14
:
:
:
-
c:
:
0
.
13
:
:
:
-
Id
a
-
Te
c
h
,
I
D
A
C
O
M
M
,
e
t
c
c:
:
0
.
31
:
:
:
-
c:
:
O
.
ll
:
:
:
-
c:
:
0
.
30
:
:
:
-
c:
:
0
.
64
~
*
c:
:
0
.
62
:
:
:
-

(
*
To
t
a
l
1.
6
3
1.
2
2
1.
5
0
1.
8
0
)
I
n
c
l
u
d
e
s

w
r
i
t
e
-
o
f
f

o
f

G
o
o
d
w
i
l
l

I
m
p
a
i
r
m
e
n
t

C
h
a
r
g
e
..

..
.
.
.
.

..
.
.

..
.
.
.
.
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.

.
.
.

..
.

DA
m
R
P
.
Cr
e
d
i
t

R
a
t
i
n
g
s
Co
r
p
o
r
a
t
e

C
r
e
d
i
t

R
a
t
i
n
g
Se
n
i
o
r

S
e
c
u
r
e
d

D
e
b
t
Se
n
i
o
r

U
n
s
e
c
u
r
e
d

D
e
b
t
Co
m
m
e
r
c
i
a
l

P
a
p
e
r
Ra
t
i
n
g

O
u
t
l
o
o
k
Da
t
e

o
f

L
a
s
t

A
c
t
i
o
n
St
a
n
d
a
r
d

a
n
d

P
o
o
r
Mo
o
d
y
Fi
t
c
h

m
C
A
Id
a
h
o

P
o
w
e
r
ID
A
C
O
R
P
Id
a
h
o

P
o
w
e
r
ID
A
C
O
R
P
Id
a
h
o

P
o
w
e
r
ID
A
C
O
R
P
BB
B
+
BB
B
+
Ba
a
l
Ba
a
2
No
n
c
No
l
l
c
;\
-
No
l
l
e
N
O
I
l
C
/\
-
No
l
l
e
BB
B
BB
B
Ba
a
l
Ba
a
2
BB
B
+
BB
B
/\
-
/\
-
1"
-
Ne
g
a
t
i
v
e
Ne
g
a
t
i
v
e
St
a
b
l
e
St
a
b
l
e
St
a
b
l
e
St
a
b
l
e
Ma
r
c
h

2
(
)
(
)
6
De
c
e
m
b
e
r

2
0
0
4
Ja
l
l
u
a
r
y

2
(
)
(
)
)
Th
e
s
e

s
e
c
u
r
i
t
y

r
a
t
i
n
g
s

r
e
f
l
e
c
t

t
h
e

v
i
e
w
s

o
f

t
h
e

r
a
t
i
n
g

a
g
e
n
c
i
e
s
.

A
n
y

r
a
t
i
n
g

c
a
n

b
e

r
e
v
i
s
e
d
up
w
a
r
d

o
r

d
o
w
n
w
a
r
d

o
r

w
i
t
h
d
r
a
w
n

a
t

a
n
y

t
i
m
e

b
y

a

r
a
t
i
n
g

a
g
e
n
c
y

i
f

i
t

d
e
c
i
d
e
s

t
h
a
t

t
h
e
ci
r
c
u
m
s
t
a
n
c
e
s

w
a
r
r
a
n
t

t
h
e

c
h
a
n
g
e
.
..

..
.
.
.
.

..
.
.
.

.
.
.

..
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.
.

..
.
.
.

Id
a
h
o

P
o
w
e
r

O
v
e
r
v
i
e
w
Id
a
h
o

P
o
w
e
r

C
o
n
l
p
e
t
i
t
i
v
e

R
e
t
a
i
l

R
a
t
e
s
(f
/
k
W
h
)
10
.
Re
s
i
d
e
n
t
i
a
l

C
o
m
m
e
r
c
i
a
l
In
d
u
s

t
r
i
a
l
Id
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
Na
t
i
o
n
a
l

A
v
e
r
a
g
e
DA
C
O
R
P
.
St
r
o
n
g

C
u
s
t
o
l
n
e
r

G
r
o
w
t
h
(O
O
O
s
)
47
0
46
4
45
0
43
0
41
0
39
0
37
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6

a
t
Ju
n
e

3
0
So
u
r
c
e
:

E
E
l

T
y
p
i
c
a
l

B
i
l
l
s

a
n
d

A
v
e
r
a
g
e

R
a
t
e
s

(
R
e
p
o
r
t

a
s

o
f

J
a
n
u
a
r
y

1
,
2
0
0
6
)
..

..
.
.
.
.
.
.
.
.
.
.
.
.

.
.
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.

..
.
.
.
.

Id
a
h
o

P
o
w
e
r
Bi
l
l
i
n
g

Co
m
p
a
r
i
s
o
n
s
Re
s
i
d
e
n
t
i
a
l

E
l
e
c
t
r
i
c

S
e
n
'
i
c
e
Mo
n
t
h
l
y

C
a
s
t

f
e
r

1
.
0
0
0

k
w
h
As

o
f

J
a
n
u
a
r
y

1
,

2
0
0
6
pO

lI
o
n
"
"
,
l
u
'k
I
'
9
S
.
DA
C
O
R
P
.
Me
d
i
u
n
l

C
o
m
m
e
r
c
i
a
l

E
l
e
c
t
r
i
c

S
e
n
'
i
c
e
Mo
n
t
h
t
y

C
a
s
t

f
o
r

40

kW

a
n
d

1
4
,
00
0
.

k
W
h
As

o
f

J
a
n
u
a
r
y

1
,

2
0
0
6
.0

II
o
n
a
l
u
l
u
Sm
a
l
l

I
n
d
u
s
t
r
i
a
l

E
l
e
c
t
r
i
c

S
e
n
i
c
e
Mo
n
t
h
l
y

C
o
s
t

f
o
r

1
,
00
0

k
W

a
n
d

4
0
0
,
00
0

k
W
h
As

o
f

J
a
n
U
i
l
I
Y

1
,

2
0
0
6
.0

ll
o
n
o
l
u
i
u
~1
G
7
,
()
.
So
u
,
.
"
,

f
f
l

R
e
,
I
~
"
,
"
'
~

c
"
m
m
e
r
c
b
l
,

"
"
,
.
"
,
1
3
1

~I
I
I
"

""
"
"
"
"
"
"
'
"
"

L
O
l
l
"

Ie
,
.
..
.
.
.
.
.
.
.
.

..
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.

.
.
.
.
.
.
.
.
.

..
.
.
.
.
.
4
DA
C
O
R
P
.
Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
Re
t
a
i

Id
a
h
o
Ce
r
t
i
f
i
c
a
t
e

o
f

P
u
b
l
i
c

C
o
n
v
e
n
i
e
n
c
e

a
n
d

N
e
c
e
s
s
i
t
y

17
0
M
w
In
t
e
g
r
a
t
e
d

R
e
s
o
u
r
c
e

P
l
a
n

-

2
0
0
6
.
P
C

A
-

Lo
a
d

g
r
o
w
t
h

ad
j
u
s
t
l
l
1
e
n
t

f
a
c
t
o
r
.
N
e
w

PU
R
P
A

S
t
a
n
d
a
r
d
s
Ne
t

l1
1
e
t
e
r
i
n
g
Fu
e
l

s
o
u
r
c
e
s
Fo
s
s
i
l

f
u
e
l

e
f
f
i
c
i
e
n
c
y
Sl
1
1
a
r
t

l
1
1
e
t
e
r
i
n
g
In
t
e
r
c
o
n
n
e
c
t
i
o
n
Fi
x
e
d

C
o
s
t

A
d
j
u
s
t
l
l
1
e
n
t

11
1
e
c
h
a
n
i
s
1
1
1

(F
C
A
)
Gr
i
d

W
e
s
t

d
e
f
e
r
r
a
l
...
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.

DA
C
O
R
P
.
Re
g
u
l
a
t
o
r
y

P
r
o
c
e
e
d
i
n
g
s
Re
t
a
i

Or
e
g
o
n
De
f
e
r
r
e
d

a
c
c
o
u
n
t
i
n
g

r
e
q
u
e
s
t

(
p
o
w
e
r

s
u
p
p
l
y

e
x
p
e
n
s
e
s
)
Em
i
s
s
i
o
n

a
l
l
o
w
a
n
c
e
s

(
e
x
c
e
s
s

S
O
.
P
U
R
P

Id
a
h
o

P
o
w
e
r

g
e
n
e
r
a
l

r
a
t
e

c
a
s
e
Gr
i
d

W
e
s
t

d
e
f
e
r
r
a
l
..
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.

.
.
.
.
.
.
.
.
.
.

..
.
.

..
.
.
.
.

In
t
e
g
r
a
t
e
d

R
e
s
o
u
r
c
e

Pl
a
n
(I
R
P
)

2
0
0
6

P
r
e
f
e
r
r
e
d

P
o
r
t
f
o
l
i
o
(2
0
0
6
-
20
2
5
)
Ul
n
n
1
a
r
y
Re
s
o
u
r
c
e
Wi
n
d
25
0
Ge
o
t
h
e
r
m
a
l

(
B
i
n
a
r
y
)
15
0
CI
-
I
P
15
0
Tr
a
n
s
m
i
s
s
I
o
n
28
5
Co
a
l
25
0
Re
g
i
o
n
a
l

I
G
C
C

C
o
a
l
25
0
Nu
c
l
e
a
r
25
0
To
t
a
l

N
m
n
e
p
l
a
t
e
58
5
DA
a
R
'
.
Ti
I
n
e
l
i
n
e
Ye
a
.
"
Re
s
o
u
r
c
e
M\
V
20
0
8
Wi
n
d

(
2
0
0
5

R
F
P
)
10
0
20
0
9
20
1
0
20
1
2
20
1
2
20
l
J
20
1
7
20
1
9
20
2
0
20
2
1
20
2
2
20
2
J
Ge
o
t
h
e
r
m
a
l

(:
2
0
0
6

R
F
P
)
CH
P
Wi
n
d
!5
0
Tr
a
n
s
m
i
s
s
i
o
n

M
c
N
a
r
y
-
Bo
i
s
e
22
5
Wy
o
m
i
n
g

Pl
l
l
v
c
r
i
z
.
c
c
l

C
o
a
l
25
0
Re
g
i
o
n
a
l

I
G
C
C

C
o
a
l
25
0
Tr
a
n
s
m
i
s
s
i
o
n

L
o
l
a
-
IP
C
CH
P
10
0
Ge
o
t
h
e
r
m
a
l
Ge
o
t

h
e
n
n
a
l
lN
L

N
u
c
l
e
a
r
25
0
To
t
a
l

N
a
m
e
p
l
a
t
e
58
5
*
A
s

f
i
l
e
d

w
i
t
h

I
d
a
h
o

P
u
b
l
i
c

U
t
i
l
i
t
i
e
s

C
o
m
m
i
s
s
i
o
n

o
n

S
e
p
t
.

2
9
.
20
0
6
,
n
o
t

y
e
t

a
c
k
n
o
w
l
e
d
g
e
d
.
..

..
.
.
.
.
.
.

..
.
.
.
.
.

.
.
.
.

..
.
.
.
.
.
.
.
.
.
.

.
.
.
.

..
.
.
.
.

DA
C
O
R
P
.
20
0
6

I
R
P

G
o
a
l
s
Pr
i
m
a
r
y

G
o
a
l
s
Id
e
n
t
i
f
y

s
u
f
f
i
c
i
e
n
t

r
e
s
o
u
r
c
e
s

t
o

r
e
l
i
a
b
l
y

s
e
r
v
e

t
h
e

g
r
o
w
i
n
g

d
e
n
l
a
n
d

f
o
r

e
n
e
r
g
y
wi
t
h
i
n

I
d
a
h
o

P
o
w
e
r
s
s
e
r
v
i
c
e

a
r
e
a

t
h
r
o
u
g
h
o
u
t

t
h
e

2
0
-
ye
a
r

p
l
a
n
n
i
n
g

p
e
r
i
o
d
En
s
u
r
e

t
h
e

p
o
r
t
f
o
l
i
o

o
f

s
e
l
e
c
t
e
d

r
e
s
o
u
r
c
e
s

b
a
l
a
n
c
e
s

c
o
s
t
,
r
i
s
k
,
a
n
d
en
v
i
r
o
n
l
l
1
e
n
t
a
l

c
o
n
c
e
r
n
s
Se
c
o
n
d
a
r
y

G
o
a
l
s
Gi
v
e

e
q
u
a
l

a
n
d

b
a
l
a
n
c
e
d

t
r
e
a
t
n
l
e
n
t

t
o

b
o
t
h

s
u
p
p
l
y
-
s
i
d
e

r
e
s
o
u
r
c
e
s

a
n
d
de
m
a
n
d
-
s
i
d
e

m
e
a
s
u
r
e
s
In
v
o
l
v
e

t
h
e

p
u
b
l
i
c

i
n

t
h
e

p
l
a
n
n
i
n
g

p
r
o
c
e
s
s

i
n

a

m
e
a
n
i
n
g
f
u
l

w
a
y
Ex
p
l
o
r
e

t
r
a
n
s
m
i
s
s
i
o
n

a
l
t
e
r
n
a
t
i
v
e
s
In
v
e
s
t
i
g
a
t
e

a
n
d

e
v
a
l
u
a
t
e

c
l
e
a
n
-
c
o
a
l

t
e
c
h
n
o
l
o
g
i
e
s
..

..
.
.
.

..
.
.
.
.
.
.
.
.

..
.
.
.
.

..
.
.
.
.
.
.
.
.

..
.
.
.
.
.
.

..
.
IR
P

P
u
b
l
i
c

P
o
l
i
c
y

Is
s
u
e
s
DA
C
O
R
P
.
We

w
i
l
l

u
s
e

t
h
e

2
0
0
6

I
R
P

t
o

c
o
m
m
u
n
i
c
a
t
e

I
d
a
h
o

P
o
w
e
r
s
p
o
s
i
t
i
o
n
in
v
i
t
e

c
o
m
m
e
n
t
s
,
a
s
s
e
s
s

l
e
v
e
l

o
f

p
u
b
l
i
c

s
u
p
p
o
r
t

a
n
d

l
a
u
n
c
h

e
f
f
o
r
t
s

t
o
re
s
o
l
v
e

t
h
e
s
e

i
s
s
u
e
s
:
En
v
i
r
o
n
m
e
n
t
a
l

a
t
t
r
i
b
u
t
e
s

o
r

g
r
e
e
n

t
a
g
s
Em
i
s
s
i
o
n

o
f
f
s
e
t
s
Fi
n
a
n
c
i
a
l

d
i
s
i
n
c
e
n
t
i
v
e
s

f
o
r

D
S
M

p
r
o
g
r
a
m
s
.
I
G
C
C

te
c
h
n
o
l
o
g
y

r
i
s
k
As
s
e
t

o
w
n
e
r
s
h
i
p
..
.

..
.
.
.
.
.
.
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.
.
.
.

..
.
.
.
.
.
.
.

..
.
DA
C
O
R
P
.
Hy
d
r
o
p
o
w
e
r

P
r
o
j
e
c
t
Re
l
i
c
e
n
s
i
n
g

S
c
h
e
d
u
l
e
FE
R
C
Na
m
e
p
l
a
t
e
Cu
r
r
e
n
t
Fi
l
e

F
E
R
C
Li
c
e
n
s
e
Ca
p
a
c
i
t
y
Li
c
e
n
s
e
Li
c
e
n
s
e
Pr
o
j
e
c
t
Nu
m
b
e
r
(M
w
)
Ex
p
i

r
e
s
Ap
p
l
i
c
a
t
i
o
n
He
l
l
s

C
a
n
y
o
n

C
o
m
p
l
e
x
19
7
1
1
,
16
7
Ju
l
y

2
0
0
5
*
Ju
l
y

2
0
0
3
Sw
a
n

F
a
l
l
s
50
3
Ju
n
e

2
0
1
0
Ju
n
e

2
0
0
8
Bl
i
s
s
19
7
5
Au
g
.

2
0
3
4
Ju
l
y

2
0
3
2
Lo
w
e
r

S
a
l

m
o
n
20
6
1
Au
g
.

2
0
3
4
Ju
l
y

2
0
3
2
Up
p
e
r

S
a
l

m
o
n

A
27
7
7
Au
g
.

2
0
3
4

Ju
l
y

2
0
3
2
Up
p
e
r

S
a
l
m
o
n

B
27
7
7
Au
g
.

2
0
3
4
Ju
l
y

2
0
3
2
Sh
o
s
h
o
n
e

F
a
l
l
s
27
7
8
Au
g
.

2
0
3
4
Ju
l
y

2
0
3
2
J.

S
t
r
i
k
e
20
5
5
Au
g
.

2
0
3
4
Ju
l
y

2
0
3
2
Up
p
e
r
/
L
o
w
e
r

M
a
l
a
d
27
2
6
Ma
r
c
h

2
0
3
5
Fe
b
.

2
0
3
3
:;
:

Op
e
r
a
t
i
n
g

u
n
c
l
e
r

a
n
n
u
a
l

r
e
n
e
w
a
l

o
f

e
x
i
s
t
i
n
g

l
i
c
e
n
s
e
..

..
.
.

..
.
.
.
.

.
.
.

..
.
.
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.
.
.
.
.
.
.
.
DA
a
R
'
.
Hy
d
r
o

S
y
s
t
e
m

Ma
p
1J
l
~
~
N

/\
)
'l

(.
'
R
R

~
'
!
t
'
I
"U
N
N

'

'L

s,
D

~
~
-
-
"
.
~
AR
'
O
W

,.
.
.
"
,

f
~
R
'
W
A
N
T

-
")

lf
;
ET
A

,.
r
~~

,
'
.'N
'fo
N
='
'.

'
LJ
'

I

.
-
,
9

U'B
Y

~
~
~
~
~

HO
R
n
'
MO
N
T
A
N
A
-/

~
1
&
M
r:.
~
E
T

OX
O
H

...
"
,

F.

0/
.

aO
R
D
'

-
,
,
:,
.
'

O"
"
O
H

F
A
L
L
S

n

t
,
~
r-
.
(

~
,
U"
R
R

t
-
~
--
"
~,

"
--
-
-
.

r
~
:
.
-
..
.
,
UP
P
E
R

S
A
L
M
O
N

R
I
V
E
R
FI
S
H

P
L
A
N
T
I
N
G

A
R
E
A
""

-
d
-
L"
"
'
"

L
O
'
,
MO
H
U
M
'
N
T
A
L

0
"
"

t'
C
:
.
.
.
.
.
.
n
~
f
l

r

l'

,
.
.
.
N
'
-"
'
-

~

wr

N

" ~
F-
'

"
"'
\
.

I
t
-
"
.m
e
,

(Ir
,
Im
.
.
H
.
.

,
c
~l.
r
!
.

.

0
"
6
2

DO
O
S
'

l:
:
~
J
IC
'

H
A
R
D
O
R

"
~
-

,
,
-
;
-
~"
'
~r
l
t
'-
-
-
-
-
.
.
BR
I
T
I
S
H
;,
-
CO
L
U
M
B
I
A
WA
S
H
I
N
G
T
O
N
\
AI
"
.
'

"
"

c
"
1::
~
:
&
~~
"

c
o
f:
j
~
;
J
:
'
m
"

"
"
"
,.,

c
o
,
Io
m
h
l

"
"
"
::
:
r
,
c
;
.
m
m
"'
"""
'
m
_
'

"
,
W
t
""
'

C
,
""
"

"
""
"
"
"
c
,
,
vo
,
.
,

c
o
,
W."

F
,
"
.
0
.
.

F
~
'
VO
,
.
.
.

F
,

"
'
m
"
RI.
.
H..
.
C
O
,
""
"
c
o
,
0..

c
o
,
"'
.
"

c
"
,.
.

co
,
'~
"

c
o
,
Ho
"

t
,

,
.
,

"
,
""
"
'
~
.
c
o
,
-
.
.
-
b
OR
E
G
O
N
LE
G
E
N
D
ID
A
H
O

P
O
W
E
R

D
A
M
S
FE
D
E
R
A
L

O
A
M
S
A
L
l

A
G
E
N
C
I
E
S
OT
H
E
R

D
A
M
S
ID
A
H
O

P
O
W
E
R

F
I
S
H

FA
C
I
L
I
T
I
E
S
...
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.

DA
C
O
R
P
.
FE
R
C
'
s
C
u
r
r
e
n
t

S
c
h
e
d
u
l
e
Da
v
s
FE
R
C
:
'
!
sg
u
~
r
'
~
~
~
~
~
~
~
~
in
i
t
i
a
t
i
n
g

f
o
r
m
a
l

c
o
n
s
u
l
t
a
t
i
o
n
.
Au
g
u
s
t

1
,

2
0
0
6
30

d
a
y
s
,
'
('
"
'
FW
S
7
~
M
F
S
'
iS
s
u
'
~s
:
"
ft
~
\
f
;
li
l
i
'
""

"
ad
e
q
u
a
c
y

o
f

i
n
f
o
r
m
a
t
i
o
n
.
Se
p
t
e
m
b
e
r

1
,

2
0
0
6
60

ra
y
s
..
,
.
.
,
,
,

"
~"
"
"
"
"
"
,
,
,
!
:
;
-
"
'
~"
"
"
'
"
"
"
"
"
9
"
;
"
Fo
r
m
a
l

c
o
n
s
u
l
t
a
t
i
o
n

c
o
m
p
l
e
t
e
.
No
v
e
m
b
e
r

1
,

20
0
6
45

d
a
y
s
10
5
12
0
"
~
!
~
!
1
'
,
J
(
*
~
~
~
W
'
.
l
'
;
i
(
;
'
l"
p
r
:
'
!
!
"
-
W
'
o
/
i
l
'
;
'
,
'
I'
!
'
~
"':
"
FW
S
/
N
M
F
S
i
s
s
u
e
s

'
'
"
,
'
bi
o
l
o
g
i
c
a
l

o
p
i
n
i
o
n
.
De
c
e
m
b
e
r

1
,

2
0
0
6
13
5
:~
"

"
"
)
"
'
",
"
"
i
"
""
"
"
",
,
'
.
'
;
!
f
i
.
.
e
D
r
u
a
r
y
"
2
0
U
7
!
C
"

"
"
~
i
"
"
"
,
:"
:
.
.."
.
, '
'
"
'
FE
R
C

i
s
s
u
e
s

fi
n
a
l

NE
P
A

d
o
c
u
m
e
n
t
.
40

1

W
/
Q
C
;
~
?
?
~
.
:t
~
~
..

..
.
.
.
.
.
.

..
.
.
.
.
.
.
.
.

.
.
.

..
.
.
.
.
.
.

.
.
.

..
.
.
.
.
.
.
.
4
DA
C
O
R
P
.
Br
o
w
n
l
e
e

R
e
s
e
r
v
o
i
r
In
f
l
o
w
s
10
.1.
0
19
9
9
Ap
r
i
l

t
o

J
u
l
y
(M
i
l
l
i
o
n

A
c
r
e
-
Fe
e
t
)
No
r
m
a
l

6
.
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
*
N
o
r
t
h
w
e
s
t

R
i
v
e
r

F
o
r
e
c
a
s
t

C
e
n
t
e
r
..
.
.
.
.
.
.
.
.
.
.
.
.
.

.
.
.
.
.

..
.

..
.
.
.
.
.
.

.
.
.

..
.
.

..
.
.
.
4
8:
8
DA
C
O
R
P
.
Br
o
w
n
l
e
e

R
e
s
e
r
v
o
i
r
In
f
l
o
w
s
19
6
0

t
o

2
0
0
6
Ap
r
i
l

t
o

J
u
l
y
(M
i
l
l
i
o
n

A
c
r
e
-
Fe
e
t
)
19
6
0
19
7
0
19
8
0
19
9
0
20
0
0
20
0
6
..
.
.
.
.

..
.
.
.
.

..
.
.
.
.
.
.

..
.
.
.
.
.

.
.
.
.

..
.

..
.
.

..
.
.
.
4
NW
S

3
0

&

g
O
-
Da
y
Te
m
p
e
r
a
t
u
r
e

F
o
r
e
c
a
s
t
Oc
t
o
b
e
r

2
0
0
6
DA
C
O
R
P
.
Oc
t
o
b
e
r
-
De
c
e
m
b
e
r

2
0
0
6
No
t
e
s

o
n

f
o
r
e
c
a
s
t

m
a
p
s
:
1.

EC

=

e
q
u
a
l

c
h
a
n
c
e
s

(
3
3
%
)

o
f

b
e
l
o
w

n
o
r
m
a
l
,

n
o
r
m
a
l
,
a
n
d

a
b
o
v
e

n
o
r
m
a
l

t
e
m
p
e
r
a
t
u
r
e
s
2.

A
=

e
l
e
v
a
t
e
d

c
h
a
n
c
e

(
g
r
e
a
t
e
r

t
h
a
n

3
3
%
)

o
f

a
b
o
v
e

n
o
r
m
a
l

t
e
m
p
e
r
a
t
u
r
e
s

w
i
t
h

a
s
s
o
c
i
a
t
e
d

pr
o
b
a
b
i
l
i
t
y

c
o
n
t
o
u
r
s
3.

B
=

e
l
e
v
a
t
e
d

c
h
a
n
c
e

(
g
r
e
a
t
e
r

t
h
a
n

3
3
%
)

o
f

b
e
l
o
w

n
o
r
m
a
l

t
e
m
p
e
r
a
t
u
r
e
s

w
i
t
h

as
s
o
c
i
a
t
e
d

p
r
o
b
a
b
i
l
i
t
y

c
o
n
t
o
u
r
s
4,

N
=

e
l
e
v
a
t
e
d

c
h
a
n
c
e

o
f

n
o
r
m
a
l

t
e
m
p
e
r
a
t
u
r
e
s
Ma
p
s

i
s
s
u
e
d

b
y

N
W
S

S
e
p
t
e
m
b
e
r

2
1
,
2
0
0
6
..

..
.
.
.
.

..
.
.
.
.
.

..
.
.
.
.
.
.
.

..
.
.
.
.
.
.
.
.

..
.
.
.
.
.

..
.
DA
C
O
R
P
.
NW
S

3
0

&

g
O
-
Da
y
Pr
e
c
i
p
i
t
a
t
i
o
n

F
o
r
e
c
a
s
t
Oc
t
o
b
e
r

2
0
0
6
No
t
e
s

o
n

f
o
r
e
c
a
s
t

m
a
p
s
:
Oc
t
o
b
e
r
-
De
c
e
m
b
e
r

2
0
0
6
EC

=

e
q
u
a
l

c
h
a
n
c
e
s

(
3
3
%
)

o
f

b
e
l
o
w

n
o
r
m
a
l
,
n
o
r
m
a
l
,
a
n
d

a
b
o
v
e

n
o
r
m
a
l

p
r
e
c
i
p
i
t
a
t
i
o
n
A
=

e
l
e
v
a
t
e
d

c
h
a
n
c
e

(
g
r
e
a
t
e
r

t
h
a
n

3
3
%
)

o
f

a
b
o
v
e

n
o
r
m
a
l

pr
e
c
i
p
i
t
a
t
i
o
n

w
i
t
h

a
s
s
o
c
i
a
t
e
d

p
r
o
b
a
b
i
l
i
t
y

c
o
n
t
o
u
r
s
B
=

e
l
e
v
a
t
e
d

c
h
a
n
c
e

(
g
r
e
a
t
e
r

t
h
a
n

3
3
%
)

o
f

b
e
l
o
w

n
o
r
m
a
l

pr
e
c
i
p
i
t
a
t
i
o
n

w
i
t
h

a
s
s
o
c
i
a
t
e
d

p
r
o
b
a
b
i
l
i
t
y

c
o
n
t
o
u
r
s
Ma
p
s

i
s
s
u
e
d

b
y

N
W
S

S
e
p
t
e
m
b
e
r

2
1
,
2
0
0
6
..

..
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.

..
.

..
.
.

.
.
.
.
.
.
.
.
.
.
.
8
8
4
Fo
r

Ad
d
i
t
i
o
n
a
l

I
n
f
o
r
m
a
t
i
o
n
DA
a
J
R
P
.
La
w
r
e
n
c
e

F
.

S
p
e
n
c
e
r
Di
r
e
c
t
o
r

o
f

I
n
v
e
s
t
o
r

R
e
l
a
t
i
o
n
s
(2
0
8
)

3
8
8
-
26
6
4
LS

p
e
n
c
e
r

&J

id
a
h
o
p
o
w
e
r
.

c
o
m
St
e
v
e
n

R
.

K
e
e
n
Vi
c
e

P
r
e
s
i
d
e
n
t

a
n
d

T
r
e
a
s
u
r
e
r
(2
0
8
)

3
8
8
-
26
0
0
SK
e
e
n

&
J
i
d
a
h
o
p
o
w
e
r
.
c
o
m
Da
r
r
e
l

T
.

A
n
d
e
r
s
o
n
Sr
.

V
i
c
e

P
r
e
s
i
d
e
n
t
-
Ad
m
i
n
i
s
t
r
a
t
i
v
e

S
e
r
v
i
c
e
s
Ch
i
e
f

F
i
n
a
n
c
i
a
l

O
f
f
i
c
e
r
(2
0
8
)

3
8
8
-
26
5
0
An
d
e
r
s
o
n

&J

id
a
h
o
p
o
w
e
r
.

c
o
m